2010Annual Report.pdf

, THIS FILING IS
Item 1: 00 An Initial (Original)
Submission
OR 0 Resubmission No.
Avu- E-
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, Secions 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
Form 1 Approved
OMS No. 1902-0021
(Expires 12131/2011)
Form 1-F Approved
OMS No. 1902-0029
(Expires 12/31/2011)
Form 3-0 Approved
OMS No. 1902-0205
(Expires 1/31/2012)
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Exact Legal Name of Respondent (Company)
Avista Corporation End of
Year/Period of Report
2010/04
FERC FORM NO.1/3-Q (REV. 02-0)
FERC FORM NO. 1/3-Q:
REPORT OF MAJOR ELECTRIC UTILITIES LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent 02 Year/Period of Report
Avista Corporation End of 2010/04
03 Previous Name and Date of Change (if name changed during year)/ /
04 Address of Principal Offce 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,lncluding 09 This Report Is 10 Date of Report
Area Code (1) IX An Original (2) 0 A Resubmission (Mo, Da, Yr)
[phone] 04/15/2011
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned offcer certes 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 affirs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Unifrm System of Accounts.
01 Name 03 Signa,:z:l ~
IJ
04 Date Signed
Christy Burmeister-Smith /'(~- ~-..(Mo,Da, Yr)
02 Title ..,~ ~
VP, Controller, Prin. Accg Offcer Chr' Burmeister-Smith 0411512011
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willngly to make to any Agency or Departent of the United States any
false, fictitious or frudulent statements as to any matter within its jurisdiction.
FERC FORM No.1/3-Q (REV. 02-04)Page 1
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corpration (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 0411512011
LIST OF SCHEDULES (Electric Utilit)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropnate, 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)
1 General Information 101
2 Control Over Respondent 102 N/A
3 Corporations Controlled by Respondent 103
4 Offcers 104
5 Directors 105
6 Information on Formula Rates 106(a)(b)
7 Important Changes During the Year 108-109
8 Còmparative 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 122(a)(b)
14 Summary of Utilit Plant & Accmulated 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 Utilty Plant 219
21 Investment of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowances 228(ab)-229(ab)N/A
24 Extraordinary Propert 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 Miscllaneous Deferred Debits 233
29 Accmulated 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 This 7!0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) CiA Resubmission 04/1512011
LI ST OF SCHEDULES (Electic 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)
37 Other Deferred Credits 269
38 Accumulated Deferred Income Taxes-Acclerated Amortization Propert 272-273 N/A
39 Accumulated Deferred Income Taxes-Other Propert 274-275
40 Accumulated Deferred Income Taxes-Other 276-277
41 Other Regulatory Liabilties 278
42 Electric Operating Revenues 300-301
43 Sales of Electricity by Rate Schedules 304
44 Sales for Resale 310-311
45 Electric Operation and Maintenance Expenses 320-323
46 Purchased Power 326.327
47 Transmission of Electricity for Others 328-330
48 Transmission of Electricity by ISO/RTOs 331 N/A
49 Transmission of Electricity by Others 332
50 Miscellaneous General Expenses-Electric 335
51 Depreciation and Amortization of Electric Plant 336-337
52 Regulatory Commission Expenses 350-351
53 Research, Development and Demonstration Activities 352-353 N/A
54 Distribution of Salaries and Wages 354-355
55 Common Utility Plant and Expenses 356
56 Amounts included in ISO/RTO Settlement Statements 397 N/A
57 Purchase and Sale of Ancilary Services 398
58 Monthly Transmission System Peak Load 400
59 Monthly ISOIRTO Transmission System Peak Load 400a N/A
60 Electric Energy Accunt 401
61 Monthly Peaks and Output 401
62 Steam Electric Generating Plant Statistics 402-403
63 Hydroelectric Generating Plant Statistics 406-407
64 Pumped Storage Generating Plant Statistics 408-409 N/A
65 Generating Plant Statistics Pages 410-411
66 Transmission Line Statistics Pages 422-423
FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) CiA Resubmission 04/15/2011
LI T OF SCHEDULES (Electric Utilit) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropnate, 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 Reference
Page No.
(b)
424-425
426-427
429
450
Remarks
(a)
67 Transmission Lines Added During the Year
68 Substations
69 Transactions with Associated (Affliated) Companies
70 Footnote Data
Stockholders' Reports Check appropriate box:
o Two copies wil be submited
o No annual report to stockholders is prepared
(c)
FERC FORM NO.1 (ED. 12-96)Page 4
Name of Respondent
Avista Corporation
This Report Is:
(1) 00 An Original
(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2011
Year/Period of Report
End of 2010/04
GENERAL INFORMATION
1. Provide name and title of offcer having custody of the general corporate books of account and address of
offce where the general corporate books are kept, and address of offce where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
C. Burmister-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 propert 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 Washington, 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) 0 Yes...Enter the date when such independent accountant was initially engaged:
(2) 00 No
FERC FORM NO.1 (ED. 12-87)PAGE 101
Name of Respondent This 'ì0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) 0 A Resubmission 04/15/2011
CORPORATIONS CONTROLLED BY R SPONDENT
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 nghts, 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 part 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 part.
line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
1 Avista Capital, Inc.Parent company to the 100
2 Company's subsidiaries.
3
4 Advantage 10, Inc.Provider of utilty bil 75.74 Subsidiary of
5 processing, payment and Avista Capital
6 information services to multi
7 site customers in North Amer.
8
9 Ecos 10, Inc.Formed in 2009 to acquire 100 by Advantage 10 Subsidiary of
10 Ecos Consulting, Inc., an Advantage 10
11 energy effciency solutions
12 provider.
13
14 Avista Development, Inc.Maintains an investment 100 Subsidiary of
15 portolio of real estate and Avista Capital
16 other investments.
17
18 Avista Energy, Inc.Inactive 100 Subsidiary of
19 Avista Capital
20
21 Avista Power, LLC Inactive 100 Affliate of
22 Avista Capital
23
24 Avista Turbine Power, Inc.Receives assignments of 100 Subsidiary of
25 purchase power agreements.Avista Capital
26
27 Avista Ventures, Inc.Inactive 100 Subsidiary of
.
FERC FORM NO.1 (ED. 12-96)Page 103
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) CiA Resubmission 04/15/2011
C RPORA TIONS 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 Accunts 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 part 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 part.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
1 Avista Capital
2
3 Pentzer Corporation Parent company of Bay Area 100 Subsidiary of
4 Manufacturing and Pentzer Avista Capital
5 Venture Holdings.
6
7 Pentzer Venture Holdings Inactive 100 Subsidiary of
8 Pentzer Corporation
9
10 Bay Area Manufacturing Holding Company 100 Subsidiary of
11 Pentzer Corporation
12
13 Advanced Manufacturing and Development, Inc.Performs custom sheet metal 82.95 Subsidiary of
14 dba Metalfx manufacturing of electronic Bay Area
15 enclosures, parts and systems Manufacturing.
16 for the computer, telecom and
17 medical industries. AM&D
18 also has a wood products
19 division.
20
21 Avista Receivables Corporation Acquires and sells accunts 100 Subsidiary of
22 receivable of Avista Corp.Avista Corp.
23
24 Spokane Energy, LLC Ows an electric capactiy 100 Affliate of
25 contract.Avista Corp.
26
27
FERC FORM NO.1 (ED. 12-96)Page 103.1
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/1512011
C )RPORATIONS CONTROLLED BY R SPONDENT
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 pnor 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 part 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 Accunts, regardless of the relative voting rights of each part.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
1 Avista Capital II An affliated business trust 100 Affliate of
2 formed by the Company.Avista Corp.
3 Issued Pref. Trust Securities
4
5 Avista Northwest Resources, LLC Formed in 2009 to own 100 Affliate of
6 an interest in a venture Avista Capital
7 fund investment
8
9 Steam Plant Square. LLC Commercial offce and retail 90 Affliate of
10 leasing.Avista Development
11
12 Courtard Ofce Center, LLC Commercial offce and retail 100 Affliate of
13 leasing.Avista Development
14
15
16
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO.1 (ED. 12-96)Page 103.2
This Page Intentionally Left Blank
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/15/2011
OFFICERS
1. Report below the name, title and salary for each executive offcer whose salary is $50,000 or more. An "executive offcet' of a
respondent indudes 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.
i Line Title Name of Officer ,sai.ary
No.for Year
(a)(b)(c)
1 Chairman of the Board, President S. L. Morris
2 and Chief Executive Ofcer
3
4 Senior Vice President and Chief Financial Offcer M. T. Thies
5
6 Senior Vice President, General Counsel M. M. Durkin
7 and Chief Compliance Offcer
8
9 Senior Vice President and Corporate Secretary K. S. Feltes
10 with responsibilty for Human Resources
11
12 Senior Vice President and Environmental D. P. Vermilion
13 Compliance Offcer
14
15 Vice President, Controller and C. M. Burmeister-Smith
16 Principal Accunting Offcer
17
18 Vice President and Chief Information Offcer J. M. Kensok
19
20 Vice President with responsibilty for Transmission D. F. Kopcznski
21 and Distribution Operations
22
23 Vice President and Chief Counsel for Regulatory and D. J. Meyer
24 Governmental Affairs
25
26 Vice President, with responsibilit for State and K. O. Norwood
27 Federal Regulation
28
29 Vice President, with responsibilty for R. D. Woodworth
30 Sustainable Energy Solutions
31
32 Vice President, Finance J. R. Thackston
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.1 (ED. 12-96)Page 104
Name of Respondent This 7!0rt Is:Date of Report YeadPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Ei A Resubmission 04/15/2011
DIRECTORS
1. Report below the information called for concerning each direcor of the respondent who held offce at any time during the year. Include in column (a), abbreviated
titles of the directors who are offcers 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.
L!l)e Name (ançi.l itie) Of Director ..rincipai tsusiness AooressNo.(a)(b)
1 Scott L. Morris..1411 E Mission Ave., Spokane, WA, 99202
2 (Chairman of the Board, President & CEO)
3
4 Erik J. Anderson 3720 Carilon Point, Kirkland, WA 98033
5
6 Kristianne Blake***P.O. Box 28338, Spokane, WA 99228
7
8 Brian W. Dunham (resigned 10/26/2010)5721 SE Columbia Way, Suite 200, Vancouver, WA 98661
9
10 Roy Lewis Eiguren (resigned 2/5/2011)702 W. Idaho St., Suite 1100, Boise, ID 83702
11
12 Jack W. Gustavel *** (retired 5/13/2010)1260 Riverstone Dr., 3rd Floor, Coeur d Alene, 10 83814
13
14 John F. Kelly*..142 Isla Dorada Blvd., Coral Gables, FL 33143
15
16 Michael L. Noel 11960 W. Six Shooter Rd., Prescott, AZ 86305
17
18 Heidi B. Stanley P.O. Box 8650, Spokane, WA 99203
19
20 R. John Taylor***111 Main Street, Lewiston, ID 83501
21
22 Marc F. Racicot 28013 Swan Cove Dr., Big Fork, MT 59911
23
24 Rebecca A. Klein (effective 5/13/2010)611 S. Congress Ave, Suite 125, Austin, TX 78704
25
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FERC FORM NO.1 (EO. 12-95)Page 105
Name of Respondent This 7!0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Ei A Resubmission 04/1512011
INFORMATION ON FORMULA RATES
FERC Rate SchedulelTarif Number FERC Proceeding
Does the respondent have formula rates?DYes
00 No
1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No)
accpting the rate(s) or changes in the accepted rate.
,Line
No.FERC Rate Schedule or Tariff Number FERC Proceeding
1 The Company has no formula rates.
2
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FERC FORM NO.1 (NEW. 12-08)Page 106
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) n A Resubmission 04115/2011
INFORMATION ON FORMULA RATES
FERC Rate SchedulelTariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent)DYesfilings containing the inputs to the formula rate(s)?
(Z No
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
Formula Rate FERC RateLineDocument Date Schedule Number or
No.Accssion No.\ Filed Date Docket No.Description Tariff Number
1 No formula rates
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FERC FORM NO.1 (NEW. 12-08)Page 106a
Name of Respondent This 'ì0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/1512011
INFORMTION 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 diffr from
amounts reported in the Form 1.
2. The footnote should provide a narrative description explaining how the "rate" (or billng) was derived if diffrent 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
1 No formula rates
2
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FERC FORM NO.1 (NEW. 12-08)Page 106b
Name of Respondent
Avista Corporation
Date of Report YearlPeriod of Report
End of 2010/Q4
This Report Is:
(1) 12 An Original
(2) 0 A Resubmission
IMPORTANT CHANGES DURING THE OUARTERIEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accrdance 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 Accunts
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 terntory 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 secunties or assumption of liabilties 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 authonzation, 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 offcer,
director, security holder reported on Page 106, voting trustee, associated company or known associate of any of these persons was a
party or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in offcers, 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 propnetary 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 affliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
04/15/2011
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 108
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Oa, Yr)
Avista Corporation i2) A Resubmission 0415/2011 2010/04
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
1. None
2. None
3. None
4. None
5. None
6. On December 30,2010, Avista Corp., Avista Receivables Corporation (ARC), Ban of America,
N.A. and Rager Funding Company, LLC terminted a Receivables Purchase Agreement at the direction of the
Company. ARC is a wholly owned, banptcy-remote subsidiar of the Company formed in 1997 for the
purose of acquig or purchasing interests in cert accounts receivable, both biled and unbiled, of the
Company. The Company elected to terminate the Receivables Purchae Agreement prior to its March 11,2011
expiration date based on the Company's forecasted liquidity needs. The Receivables Purchae Agreement was
originally entered into on May 29,2002 (and has been renewed on an anual basis) and provided the Company
with fuds for general corporate needs. Under the Receivables Purchase Agreement, the Company could
borrow up to $50.0 millon based on calculations of eligible receivables. The Company did not borrow any
fuds under ths revolving agreement in 2010.
At December 31, 2010, A vista Corp. ha a committed line of credit agreement with varous bans in the
tota amount of $320.0 millon with an expiration date of Apri 5, 2011. Under the credit agreement, the
Company could borrow or request the issuace of letters of credit in any combintion up to $320.0 millon. At
December 31, 2010, the Company had borrowed $ 110.0 milion under ths committed line of credit and therewere $27.1 millon of letters of credit outstading. .
Additionally, the Company had a committd line of credit agreement with varous bans in the total
amount of$75.0 millon with an expirtion date of April 5, 2011.
In Febru 2011, Avista Corp. entered into a new committed line of credit in the tota amount of $400.0
millon with an expiration date of Febru 2015 that replaced its $320.0 millon and $75.0 millon committed
lines of credit.
The committed lines of credit are secured by non-trferable First Mortgage Bonds of the Company
issued to the agent ban 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 commtted lines of credit.
In December 2010, Avista Corp. issued $52.0 milion of 3.89 percent First Mortgage Bonds due in
2020 and $35.0 millon of5.55 percent First Mortgage Bonds due in 2040. The tota net proceeds from the sale
of the new bonds of $86.6 millon (net of placement agent fees and before A vista Corp.' s expenses) were used
to redeem $45.0 millon of6.125 percent First Mortgage Bonds due in December 2013 and $30.0 millon of
7.25 percent First Mortgage Bonds due in September 2013.
In December 2010, Avista Corp. issued $50.0 milion of 1.68 percent First Mortgage Bonds (Bonds)
due in 2013. The net proceeds from the issuace of the Bonds of $49.8 millon (net of placement agent fees and
before Á vist Corp. ' s expenses) were used to repay a porton of the borrowigs outstading under the
Company's commtted line of credit.
These debt issuace was approved by the respective reguatory commissions as follows: WUTC
(Docket No. U-I01722 Order No. 1); IPUC (Case No. A VU-U-LO-02, Order No. 32120); and OPUC (Docket
UP 4267, Order No. 10-461).
In December 2010, $66.7 milion of the City of Forsyt, Montaa Pollution Control Revenue
Refuding Bonds (Avista Corporation Colstrp Project) due 2032, which had been held by Avista Corp. since
2008, were refuded by a new bond issue (Series 201 OA). The new bonds were not offered to the public and
were purchased by A vista Corp. due to market conditions. The Company expects that at a later date, subject to
IFERC FORM NO.1 (ED. 12-96) Page 109.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 0415/2011 2010/Q4
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
market conditions, these bonds will be remarketed to unafliated investors. So long as A vista Corp. is the
holder of these bonds, the bonds will not be reflected as an asset or a liabilty on A vista Corp. ' s Consolidated
Balance Sheet.
In December 2010, $17.0 millon of the City of Forsyt, Monta Pollution Control Revenue
Refudig Bonds, (Avista Corporation Colstrp Project) due 2034, which had been held by Avista Corp. since
2009, were refuded by a new bond issue (Series 2010B). The new bonds were not offered to the public and
were purchased by A vista Corp. due to market conditions. The Company expects tht at a later date, subject to
market conditions, the bonds wil be remaketed to unafliated investors. So long as A vista Corp. is the holder
of these bonds, the bonds will not be reflected as an asset or a liabilty on A vista Corp. ' s Consolidated Balance
Sheet.
The Pollution Control Revenue Bonds refuded owere approved by the respective reguatory
commssions as follows: WUTC (Docket No. UE-I01615 Order No.1); ¡PUC (Case No. AVU-U-08-03, Order
No. 30674); and OPUC (Docket UF 4253, Order No. 10-424).
7. None
8. Average anua wage increases were 2.5% for non-exempt employees effective March 1,2010. Average
anua wage increases were 3.1 % for exempt employees effective March 1, 2010. Offcers received average
increases of3.8% effective March 1,2010. Cert bargainig unit employees received increases of 2.0%
effective March 1,2010. For the majority of bargaig unt employees a new contract was implemented in
October 2010, which provided for a 3.5% increase retroactive to April 1, 2010.
9. Reference is made to Note 22 of the Notes to Fincial Statements.
10. None
11. Reserved
12. See page 123 of ths report.
13. On May 13,2010, the shareholders of Avista Corp. elected Rebecca A. Klein to serve as a director on the
board. Jack W. Gustavel, a director whose term expired on May 13,2010, retired from Avista Corp.'s Board of
Directors as he has reached the mandatory retirement age of 70 as outlined in the Company's Bylaws. On
October 26,2010, Brian W. Dunam provided notification of his resignation from Avista Corp.'s Board of
Directors. On Febru 4,2011, Roy L. Eiguen provided notification of his resignation from Avista Corp.'s
Board of Directors effective Febru 5, 2011.
14. Proprieta capita is not less than 30 percent.
IFERC FORM NO.1 (ED. 12-96) Page 109.2
This Report Is: Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/15/2011 End of 2010/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Name of Respondent
Avista Corporation
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
. 13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
Title of Accunt
(a)
UTILITY PLANT
Ref.
Page No.
(b)
Current Year
End of OuarterlYear
Balance
(c)
Prior Year
End Balance
12/31
(d)
3,707,841,308
60,766,153
3,768,607,461
1,284,830,029
2,483,777,432
o
o
o
o
o
o
o
2,483,777,432
o
2,577,031
3,546,192,091
57,217,478
3,603,409,569
1,219,877,922
2,383,531,647
o
o
o
o
o
o
o
2,383,531,647
o
o--~--- ~~~~-~
5,403,010
908,291
12,047,000
77,733,569
5,031,620
897,684
12,047,000
81,243,239---------~
o
21,346,633
o
o
o
12,397,507
o
15,260,734
o
143,280,162
o
23,798,439
o
o
o
11,558,301
o
45,482,748
o
178,263,663-----~-~---- ----~~---
o
- 1,722,379
7,981,895
762,784
17,455,810
226,712
197,906,612
8,919,486
3,846,839
o
211,095
6,288,853
o
o
23,335,143
o
o
o
o
o
2,462,480
1,630,323
848,613
652,010
629,625
188,271,550
6,484,963
3,710,770
o
101,231
4,294,013
o
o
18,386,509
o
o
o
o
Utilit Plant (101-106,114)
Construction Work in Progress (107)
TOTAL Utilty Plant (Enter Total of lines 2 and 3)
(Less) Accum. Provo for Depr. Amort. Depl. (108, 110, 111, 115)
Net Utilty Plant (Enter Total of line 4 less 5)
Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)
Nuclear Fuel Materials and Assemblies-Stock Accunt (120.2)
Nuclear Fuel Assemblies in Reactor (120.3)
Spent Nuclear Fuel (120.4)
Nuclear Fuel Under Capital Leases (120.6)
(Less) Accum. Provo for Amort. of Nucl. Fuel Assemblies (120.5)
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
Net Utiit Plant (Enter Total of lines 6 and 13)
Utilty Plant Adjustments (116)
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutilty Property (121)
(Less) Accum. Provo for Depr. and Amort. (122)
Investments in Associated Companies (123)
Investment in Subsidiary Companies (123.1)
(For Cost of Account 123.1, See Footnote Page 224, line 42)
Noncurrent Portion of Allowances
Other Investments (124)
Sinking Funds (125)
Depreciation Fund (126)
Amortization Fund - Federal (127)
Other Special Funds (128)
Special Funds (Non Major Only) (129)
Long-Term Portion of Derivative Assets (175)
Long-Term Portion of Derivative Assets - Hedges (176)
TOTAL Other Propert and Investments (Lines 18-21 and 23-31)
CURRENT AND ACCRUED ASSETS
Cash and Working Funds (Non-major Only) (130)
Cash (131)
Special Deposits (132-134)
Working Fund (135)
Temporary Cash Investments (136)
Notes Receivable (141)
Customer Accunts Receivable (142)
Other Accunts Receivable (143)
(Less) Accum. Provo for Uncollectible Acc.-Credit (144)
Notes Receivable from Associated Companies (145)
Accounts Receivable from Assoc. Companies (146)
Fuel Stock (151)
Fuel Stock Expenses Undistributed (152)
Residuals (Elec) and Extracted Products (153)
Plant Materials and Operating Supplies (154)
Merchandise (155)
Other Materials and Supplies (156)
Nuclear Materials Held for Sale (157)
Allowances (158.1 and 158.2)
200-201
200-201
200-201
202-203
202-203
224-225
228-229
227
227
227
227
227
227
202-203/227
228.229
FERC FORM NO.1 (REV. 12-03)Page 110
Name of Respondent
Avista Corporation
This Report Is: Date of Report Year/Period of Report
(1) iz An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/15/2011 End of 2010/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)continued)
Line
No.
Current Year
End of OuarterlYear
Balance
(c)
Prior Year
End Balance
12/31
(d)
Ref.
Page No.
(b)
Title of Accunt
(a)
(Less) Noncurrent Portion of Allowances
Stores Expense Undistributed (163)
Gas Stored Underground - Current (164.1)
Liquefied Natural Gas Stored and Held for Processing (1.64.2-164.3)
Prepayments (165)
Advances for Gas (166-167)
Interest and Dividends Receivable (171)
Rents Receivable (172)
Accrued Utilty Revenues (173)
Miscellaneous Current and Accrued Assets (174)
Derivative Instrument Assets (175)
(Less) Long-Term Portion of Derivative Instrument Assets (175)
Derivative Instrument Assets - Hedges (176)
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176
Total Current and Accrued Assets (Lines 34 through 66)
DEFERRED DEBITS
Unamortized Debt Expenses (181)
Extraordinary Propert Losses (182.1)
Unrecovered Plant and Regulatory Study Costs (182.2)
Other Regulatory Assets (182.3)
Prelim. Survey and Investigation Charges (Electric) (183)
Preliminary Natural Gas Survey and Investigation Charges 183.1)
Other Preliminary Survey and Investigation Charges (183.2)
Clearing Accounts (184)
Temporary Facilties (185)
Miscellaneous Deferred Debits (186)
Def. Losses from Disposition of Utilty Pit. (187)
Research, Devel. and Demonstration Expend. (188)
Unamortized Loss on Reaquired Debt (189)
Accumulated Deferred Income Taxes (190)
Unrecovered Purchased Gas Costs (191)
Total Deferred Debits (lines 69 through 83)
TOTAL ASSETS (lines 14-16, 32, 67, and 84)
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
o
o
17,242,935
o
12,832
12,706,763
o
9,985,760
o
197,040
553,237
o
454,418
53,240,001
45,482,748
o
o
251,717,850
227
10,754,149
o
o
1,488,593
o
213,064
17,852,716
15,260,734
243,221
o
293,497,874---~~~
12,854,887 15,732,877
230a 0 0
230b 0 0
232 429,832,794 352,616,516
3,946,461 3,346,452
0 0
0 0
0 0
0 0
233 17,414,947 26,105,547
0 0
352-353 0 0
25,454,075 15,196,145
234 119,988,041 91,975,547
-22,074,296 -39,952,004
587,416,909 465,021,080
3,510,549,408 3,278,534,240
FERC FORM NO.1 (REV. 12-03)Page 111
Name of Respondent This Report is:Date of Report Year/Period of Report
Avista corporation (1 )~An Original (mo, da, yr)
(2)0 A Resubmission 04/1512011 end of 2010/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201)250-251 805,656,943 759,057,747
3 Preferred Stock Issued (204)250-251 0 0
4 Capital Stock Subscribed (202, 205)0 0
5 Stock Liabilty for Conversion (203, 206)0 0
6 Premium on Capital Stock (207)0 0
7 Other Paid-In Capital (208-211)253 15,798,128 17,498,634
8 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 -6,137,359 -2,090,961
11 Retained Earnings (215, 215.1, 216)118-119 326,861,303 295,862,243
12 Unappropriated Undistributed Subsidiary Earnings (216.1)118-119 -24,343,433 -20,871,863
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)-4,325,953 -2,350,286
16 Total Proprietary Capital (lines 2 through 15)1,125,784,347 1,051,287,436
17 LONG-TERM DEBT
18 Bonds (221)256-257 1,098,148,636 1,070,256,423
19 (Less) Reaquired Bonds (222)256-257 0 0
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)222,084 230,967
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)2,013,529 2,167,570
24 Total Long-Term Debt (lines 18 through 23)1,147,904.191 1,119,866,820
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent (227)4,974,661 0
27 Accumulated Provision for Propert Insurance (228.1)0 0
28 Accumulated Provision for Injuries and Damages (228.2)2,684,975 1,650,500
29 Accumulated Provision for Pensions and Benefits (228.3)161,188,441 123,281,094
30 Accumulated Miscellaneous Operating Provisions (228.4)0 2,916,673
31 Accumulated Provision for Rate Refunds (229)0 0
32 Long-Term Portion of Derivative Instrument Liabilties 30,984,511 2,871,255
33 Long-Term Portion of Derivative Instrument Liabilties - Hedges 52,705 0
34 Asset Retirement Obligations (230)3,887,409 3,971,453
35 Total Other Noncurrent Liabilties (lines 26 through 34)203,772,702 134,690,975
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)110,000,000 87,000,000
38 Accounts Payable (232)121,798,025 114,930,110
39 Notes Payable to Associated Companies (233)7,374,317 6,882,247
40 Accunts Payable to Associated Companies (234)866,285 724,582
41 Customer Deposits (235).7,958,557 8,140,83
42 Taxes Accrued (236)262-263 -397,450 2,222,627
43 Interest Accrued (237)11,290,059 13,476,434
44 Dividends Declared (238)0 0
45 Matured Long-Term Debt (239)0 0
FERC FORM NO.1 (rev. 12-03)Page 112
Name of Respondent This Report is:Date of Report Year/Penod of Report
Avista Corporation (1 )!X An Original (mo, da, yr)
(2)0 A Resubmission 04/15/2011 end of 2010/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIT(5ntinued)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
46 Matured Interest (240)0 0
47 Tax Collections Payable (241)32,330 147,574
48 Miscellaneous Current and Accrued Liabilties (242)52,383,017 55,461,901
49 Obligations Under Capital Leases-Current (243)195,575 0
50 Derivative Instrument Liabilties (244)82,467,56 18,958,058
51 (Less) Long-Term Portion of Derivative Instrument Liabilties 30,984,511 2,871,255
52 Derivative Instrument Liabilties - Hedges (245)58,584 50,091
53 (Less) Long-Term Portion of Derivative Instrument Liabilties-Hedges 52,705 0
54 Total Current and Accrued Liabilties (lines 37 through 53)362,989,647 305,123,222
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)1,089,209 1,280,331
57 Accumulated Deferred Investment Tax Credits (255)266-267 7,842,362 5,632,508
58 Deferred Gains from Disposition of Utilit Plant (256)0 0
59 Other Deferred Credits (253)269 17,050,733 22,330,799
60 Other Regulatory Liabilties (254)278 31,545,561 61,709,913
61 Unamortized Gain on Reaquired Debt (257)2,655,731 2,957,426
62 Accum. Deferred Income Taxes-Accl. Amort.(281)272-277 0 0
63 Accum. Deferred Income Taxes-Other Propert (282)369,622,132 348,074,981
64 Accum. Deferred Income Taxes-Other (283)240,292,793 225,579,829
65 Total Deferred Credits (lines 56 through 64)670,098,521 667,565,787
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)3,510,549,408 3,278,534,240
FERC FORM NO.1 (rev. 12-03) Page 113
Name of Respondent This f!0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/15/2011
STATEMENT OF INCOME
Ouarterly
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 utilty function; in column (i) the quarter to date amounts for gas utilty, and in column (k)
the quarter to date amounts for other utilty function for the current year quarter.
4. Report in column (h) the quarter to date amounts for electric utilty function; in column 0) the quarter to date amounts for gas utilit, and in column (I)
the quarter tO,date amounts for other utilty function for the prior year quarter.
5. If additional columns are needed, place them in a footnote.
Annual or Ouarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accunts 412 and 413, Revenues and Expenses from Utilty Plant Leased to Others, in another utilty column in a similar manner to
a utilty 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 accunt 414, Other Utilty Operating Income, in the same manner as accounts 412 and 413 above.
Line Total Totl Currnt 3 Months Prior 3 Months
No.Currnt Year to Prior Year to Ended Ended
(Ref.)Date Balance for Date Balance for Quarterl Only Quartrl Only
Title of Account Page No.QuartrlY ear QuarterlY ear No 4th Quartr No 4th Quarter
(a)(b)(c)(d)(e)(n
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301 1,602,043,842 1,516,973,753
3 Operating Expenses
4 Operation Expenses (401)320.323 1,175,254,099 1,100,224,196
5 Maintenance Expenses (402)320-323 48,270,267 50,846,769
6 Depreiation Expense (403)336-337 92,936,677 87,089,835
7 Depreatin Expense for Asst Retirement Costs (403.1)336.337
8 Amort. & Depl. of Utilit Plant (404-405)336-337 10,067,620 9,143,602
9 Amort of Utilit Plant Acq. Adj. (406)336-337 99,047 99,047
10 Amort Propert Losses, Unrecov Plant and Regulatory Study Costs (407)
11 Amort of Conversion Expenses (407)
12 Regulatory Debits (407.3)919,134 3,718,504
13 (Les) Regulatory Credit (407.4)11,804,920 10,397,806
14 Taxes Otr Than Income Taxes (408.1)262.263 73,392,440 76,582,590
15 Income Taxes. Federal (409.1)262-263 10,616,573 30,223,259
16 -Other(409.1)262.263 469,639 2,111,405
17 Provision for Deferr Income Taxes (410.1)234, 272-277 41,454,197 23,050,105
18 (Less) Provision for Deferr Income Taxes-Gr. (411.1)234, 272-277 1,521,709 6,214,995
19 Investmnt Tax Credit Adj. - Net (411.4)266 -17,672 -93,914
20 (Les) Gains frm Disp. of Utility Plant (411.6)
21 Losses frm Disp. of Utilit Plant (411.7)
22 (Less) Gains from Dispositn of Allowances (411.8)
23 Losses from Dispositin of Allowance (411.9)
24 Accretion Expense (411.10)
25 TOTAL Utiit Operating Expenses (Enter Total of lines 4 thru 24)1,439,975,392 1,366,382,597
26 Net Util Oper Inc (Enter Tot line 2 less 25) Carr to Pg117,line 27 162,068,50 150,591,156
FERC FORM NO. 1/3-0 (REV. 02-04)Page 114
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2010/04
This ~ort Is: Date of Report(1) ~An Onginal (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for important notes regarding the statement of income for any accunt 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 utilit with respect to power or gas purchases. State for each year effcted
the gross revenues or costs to which the contingency relates and the tax effect together with an explanation of the major factors which affect the rights
of the utilty to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning signifcant 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 preceing year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous yeats/auartets figures are diffrent from that reported in prior reports.
15. If the columns are insuffcient for reporting additional utilty departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(g) (h)
GAS UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(i) (j)
Line
No.
934,185,315
135,768,832
826,294,570
124,734,689
505,790,077
26,299,618
540,088,027
25,856,467
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
724,521,516 621,221,944 450,732,583 479,002,252
39,000,254 42.044,915 9,270,013 8,801,854
75,862,701 71,109,022 17,073,976 15,980,813
8,110,496 7,467,875 1,957,124 1,675,727
99,047 99,047
-1,799,835 947,939 2,718,969 2,770,565
9,787,351 7,405,420 2,017,569 2,992,386
54,037,916 51,664,659 19,354,524 24,917,931
22,733,087 23,099,627 -12,116,514 7,123,632
686,110 1,263,060 -216,471 848,345
22,478,586 20,060,696 18,975,611 2,989,409
1,625,776 5,234,188 -104,067 980,807
-131,436 -4,606 -46,236 -49,308
FERC FORM NO.1 (ED. 12-96)Page 115
~~ ~--~-~~-----~~~~--~-~--- - - ~ ~~ - ~
Name of Respondent
Avista Corporation
This ~ort Is:
(1) ~An Original
A Resubmission
Line
No.
Title of Accunt
(a)
(Ret)
Page No.
(b)
Current Year
(c)
27 Net Utilit Operating Income (Carred forward from page 114)
28 Other Income and Deductons
29 Oter Income
30 Nonutity Operating Income
31 Revenues From Merchandising, Jobbing and Contrct Work (415)
32 (Less) Costs and Exp. of Mercandising, Job. & Contrct Work (416)
33 Revenues From Nonutilit Operations (417)
34 (Les) Expenses of Nonutlit Operatins (417.1)
35 Nonoperating Rental Income (418)
36 Equit in Earnings of Subsidiary Companies (418.1)
37 Interest and Dividend Income (419)
38 Allowance for Oter Funds Used During Constrcton (419.1)
39 Misllaneous Nonoperating Income (421)
40 Gain on Dispositon of Propert (421.1)
41 TOTAL Oter Income (Enter Total of lines 31 thN 40)
42 Other Income Deductons
43 Loss on Dispositon of Propert (421.2)
44 Miscllaneous Amortzation (425)
45 Donatins (426.1)
46 Lffe Insurance (426.2)
47 Penaltes (426.3)
48 Exp. for Certin Civic, Political & Related Actvites (426.4)
49 Oter Deductns (426.5)
50 TOTAL Oter Income Deuctons (Total of lines 43 thN 49)
51 Taxes Applic. to Oter Income and Deductons
52 Taxes Oter Than Income Taxes (408.2)
53 Income Taxes-Federal (409.2)
54 Income TaxesOter (409.2)
55 Provision for Deferr Inc. Taxes (410.2)
56 (Less) Provision for Deferrd Income Taxes-Cr. (411.2)
57 InvestmentTax Credit Adj.-Net(411.5)
58 (Les) Investment Tax Credit (420)
59 TOTAL Taxes on Oter Income and Deductons (Total of lines 52-58)
60 Net Other Income and Deductons (Total oflines 41, 50, 59)
61 Interet Charges
62 Interes on Long.Tenn Debt (427)
63 Amort of Debt Disc. and Expense (428)
64 Amortzatin of Loss on Reaqulre Debt (428.1)
65 (Les) Amort of Premium on Debt-Creit (429)
66 (Les) Amortzation of Gain on Reaquire Debt-Creit (429.1)
67 Interet on Debt to Asso. Companies (430)
68 Oter Interet Expense (431)
69 (Less) Allowance for Borrwed Funds Used During Constrct-Cr. (432)
70 Net Interest Charges (Total of lines 62 thN 69)
71 Income Before Extrordinary Items (Total of lines 27, 60 and 70)
72 Extrordinary Items
73 Extordinary Income (434)
74 (Less) Extordinary Deductons (435)
75 Net Extrordinary Items (Total of line 73 less line 74)
76 Income Taxes-Federal and Oter (409.3)
77 Extordinary Items After Taxes (line 75 les line 76)
78 Net Income (Total of line 71 and 77)
162,068,450
Year/Period of Report
End of 2010/04
Previous Year
(d)
150,591,156
-10,997
5,58,722 5,249,706
.119,784 .3,024
119 6,092,992 827,451
1,800,338 5,906,409
3,352,964 3,078,244
402,632 54,105
6,059,423 4,613,479---~-~- --~~=----~~-~~~-~
,.~~-~~~~
3,938
1,110,572
4,164,132
2,236,551
287,129
1,167,774
776,184
9,746,280
.2,050
1,110,572
1,405,009
1,336,173
-19,900
1,347,809
1,686,420
6,864,033
262-263 -9,752 -8,841
262-263 1,419,985 -985,412
262-263 -188,221 -269,492
234, 27227 .1,578,031 .223,696
234, 272.27 4,255,497 3,386,934
-4,611,516 -4,874,375.
924,659 2,623,821~-~~-~-~-~
63,349,463 55,36,849
893,123 2,109,201
3,530,313 3,572,357
8,883 8,883
883,444 2,144,504
2,219,100 3,434,267
298,141 54,568
70,568,419 66,143,727
92,424,690 87,071,250-~---~--~~~~- --~-~-~~~--~--
262-263
92,424,690 87,071,250
FERC FORM NO. 1/3-0 (REV. 02-04)Page 117
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropnated retained eamings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit dunng the year should be identified as to the retained eamings accunt in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary accunt 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 Item~. 00
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Accunt 439)
4
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acc. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acc. 439)
16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
18
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acc. 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
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acc. 438)
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1,9, 15, 16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
Contra Primary
ccunt Affected
(b)
Current
QuarterlYear
Year to Date
Balance
(c)
Previous
OuarterlYear
Year to Date
Balance
(d)-- - -r-~-----~---- - ---.._F-~~~~~~
86,331,698--I~---------~---86,243.799
--------~~----------
-55,682,194
~~---
( 44,360,374)
-55,682,194
349,553
325,313,182
44,360,374)
500,486
294,314,122
FERC FORM NO. 1/3-0 (REV. 02-04)
~-------_._----
Page 118
Name of Responaent
Avista Corporation
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropnated 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 (Accunts 433, 436
- 439 inclusive). Show the contra primary accunt affected in column (b)
4. State the purpose and amount of each reservation or appropnation 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 appeanng in the report to stockholders are applicable to this statement, include them on pages 122-123.
Year/Period of Report
End of 2010/04
Item
(a)
Contra Primary
ccount Affected
(b)
Current
QuarterlYear
Year to Date
Balance
(c)
1,548,121
Line
No.
39
40
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Accunt 215.1)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acc. 215.1)
47 TOTAL Approp. Retained Earnings (Acc. 215, 215.1) (Total 45,46)
48 TOTAL Retained Earnings (Acc. 215, 215.1, 216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Ouarterly
49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Eamings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52 Equity transaction of subsidiaries
53 Balance-End of Year (Total lines 49 thru 52)
1,548,121
Previous
OuarterlYear
Year to Date
Balance
(d)
1,548,121
.~--_.~~~~.~--~- ~-~~1,548,121
1,548,121
326,861,303
1,548,121
295,862,243K--.--~-~-~-~---~
-20,871,863
6,092,992
-9,564,563
-24,343,434
3,789,583
20,871,863)
25,488,897)
827,451
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
Name of Respondent
Avista Corporation
This ~ort Is:(1) ~An Original
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/1512011
YearlPeriod of Report
End of 2010/04
(1) Codes to be use:(a) Net Proces or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercal paper; and (d) Identi separately such items as
investments. fixed assets, intangibles, etc.
(2) Information about noncash investing and financing actvities must be provided in the Notes to the Financial statements. Also provide a reconciliation been "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet
(3) Operating Actvities - Other: Include gains and losses pertining to operating actvities only. Gains and losses pertining to investing and financing actvities should be repoed
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taes paid.
(4) Investing Activities: Include at Other (line 31) net cash outow to acquire other companies. Provide a renciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a renciliatin of the
dollar amount of leases capitlized with the plant cost.
Line
No.
Description (See Instruction NO.1 for Explanation of Codes)Current Year to Date
OuarterlYear
(b)
Previous Year to Date
OuarterlYear
(c)(a)
1 Net Cash Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion
5 Amortization of deferred power and natural gas costs
6 Amortization of debt expense
7 Amortization of investment in exchange power
8 Deferred Income Taxes (Net)
9 Investment Tax Credit Adjustment (Net)
10 Net (Increase) Decrease in Receivables
11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Accrued Expenses
14 Net (Increase) Decrease in Other Regulatory Assets
15 Net Increase (Decrease) in Other Regulatory Liabilties
16 (Less) Allowance for Other Funds Used During Construction
17 (Less) Undistributed Earnings from Subsidiary Companies
18 Other (provide details in footnote):
19
20 Changes in other non-current assets and liabilties
21 Net change in receivables allowance
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utilty Plant (less nuclear fuel)
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utiit Plant
29 Gross Additions to Nonutilty Plant
30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33
34 Cash Outfows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
38 Federal grant payments received
39 Investments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of Investment Securities (a)
45 Proceds from Sales of Investment Securities (a)
103,004,297 96,233,438
-9,795,050 51,358,730
4,414,553 5,672,674
2,450,031 2,450,031
36,084,184 9,011,417
2,209,854 5,258,780
-11,666,672 18,733,830
-11,466,814 16,449,128
-1,486,305 -27,996,937
5,858,734 -10,391,960
-4,654,996 1,329,752
3,352,964 3,078,244
6,092,992 827,452
-2,996,589 338,032
-7,567,021 -20,200,944
136,069 -2,133,833
187,503,009 229,277,692
-206,800,158 -206,916,479
-206,800,158 -206,916,479
--- -- - - -- I - -- -- - -
592,582
7,585,367
128,775
523,909 4,689,731
- - - - - - r - - ---- --
FERC FORM NO.1 (ED. 12-96)Page 120
Name of Respondent
Avista Corporation
This ~ort Is:
(1) ~An Onginal
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/15/2011
Year/Period of Report
End of 2010/Q4
(1) Codes to be used:(a) Net Proceds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercal paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing actvities must be provided in the Notes to the Financial statements. Also provide a recnciliation been "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Actvities - Other. Include gains and losses pertining to operating activites only. Gains and losses pertining to investing and financing activities should be reported
in those actvities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taes paid.
(4) Investing Activities: Include at Other (line 31) net cash outfow to acquire other companies. Provide a renciliation of assets acquire with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitlized per the USofA General Instrction 20; instead provide a renciliation 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
OuarterlYear
(b)
Previous Year to Date
OuarterlYear
(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 Changes in other propert and investments
55
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68 Cash received for settlement of interest rate swap
69
70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote):
77 Long-term debt and short-term borrowing issuance costs
78 Net Decrease in Short-Term Debt (c)
79 Premium paid to repurchase long-term debt
80 Dividends on Preferred Stock
81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83)
87
88 Cash and Cash Equivalents at Beginning of Period
89
90 Cash and Cash Equivalents at End of period
-1,588,956 -1,000,477
136,365,000 249,425,000
46,235,329 2,621,946
23,000,000
10,776,222
205,600,329 262,823,168
- --_. .._...._-"1 .. -.-_.-..-
-110,129,764 .78,931,206
-916,100 -3,726,398
-163,000,000
-10,710,164
-55,682,184 -4,360,372
19,940,973 3,963,103
FERC FORM NO.1 (ED. 12-96)Page 121
Name of Respondent
Avista Corporation
Date of Report Year/Period of Report
End of 2010/Q4
This Report Is:
(1) ~ An Original
(2) 0 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 accunt 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 bnef 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 utilty. Give also a bnef explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 116, Utilty 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 Accunts.
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 suffcient 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.
04/15/2011
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 122
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
A vista Corporation (A vista Corp. or the Company) is an energy company engaged in the generation, transmission and distrbution of
energy, as well as other energy-related businesses. Avista Corp. generates, tranmits and distrbutes electrcity in par of eastern
Washington and nortern Idaho. In addition, Avista Corp. has electrc generating facilties in Montaa and nortern Oregon. Avista
Corp. also provides natual gas distrbution servce in par of eastern Washigton and nortern Idaho, as well as par of northeast and
southwest Oregon. Avista Capital, Inc. (Avista Capital), a wholly owned subsidiar of Avista Corp., is the parent company of all of
the subsidiar companies, except Spokane Energy, LLC. Avista Capital's subsidiaries include Advantage IQ, I~c. (Advantage IQ), a
76 percent owned subsidiary as of December 3 1,2010. Advantage IQ is a provider of energy effciency and other facility information
and cost management program and services for multi-~ite customers and utilities thoughout Nort 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 Commssion (FERC) as set fort in its applicable Uniform System
of Accounts and published accountig releases, which is a comprehensive basis of accounting other than accounting principles
generally accepted in the United States of America (U.S. GAA). As required by the FERC, the Company accounts for its investment
in majority-owned subsidiares on the equity method rather than consolidatig the assets, liabilities, revenues, and expenses of these
subsidiaries, as required by U.S. GAA. The accompanyig ficial statements include the Company's proportonate share of utility
plant and related operations resulting from its interests injoint1y owned plants. In addition, under the requirements of the FERC, there
are differences from U.S. GAA in the presentation of(l) curent portion oflong-term debt (2) assets and liabilities for cost of
removal of assets, (3) assets held for sale, (4) regulatory assets and liabilties, (5) deferred income taes 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. GAA) 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 liabilties,
· pension and other postretirement benefit plan obligations,
. contingent liabilities,
· recoverability of regulatory assets,
· stock-based compensation, and
· unbiled revenues.
Changes in these estiates 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 reportd 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 Commssion (FERC) and adopted by the state regulatory commssions in Washington,
Idao, Montana and Oregon.
Regulatin
The Company is subject to state regulation in Washington, Idaho, Montaa and Oregon. The Company is also subject to federal
regulation primarly by the FERC, as well as varous other federal agencies with regulatory oversight of paricular aspects of our
operations.
Operating Revenues
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 occur on a systematic basis thoughout 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 unbiIed energy revenues of
IFERC FORM NO.1 (ED. 12-88) Page 123.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued\
the followig amounts as of December 31 (dollars in thousands):
Unbiled accounts receivable
Advertiing Expenses
The Company expenses advertising costs as incured. Advertsing expenses were not a matenal portion of the Company's operating
expenses in 2010 and 2009.
2010
$84,073
2009
$89,558
Depreciatin
For utility operations, depreciation expense is estited by a method of depreciation accountig 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 propert was as follows for the years ended December 3 I:
2010 2009
Ratio of depreciation to average depreciable propert 2.84% 2.78%
The average service lives for the followig broad categories of utility plant in service are:
. electnc thermal production - 32 year,
. hydroelectnc production - 74 years,
. electnc transmission - 50 years,
. electnc distnbution - 38 years, and
. natual gas distrbution propert - 49 years.
Taxes Other Than Income Taxes
Taxes other th income taes include state excise taes, city occupational and franchise taes, real and personal propert taxes and
certain other taes not based on net income; These taes are generally based on revenues or the value of propert. Utilty related taes
collected from customers (prily state excise taes and city utity taes) are recorded as operatig revenue and expense and totaled
the followig amounts for the year ended December 3 i (dollar in thousands):
2010
$49,953
2009
$56,818Utility taxes
Allowance for Funds Used During Construction
The Allowance for Funds Used Dung Constrction (AFUDC) represents the cost of both the debt and equity fuds used to finance
utility plant additions dung the constrction period. As prescnbed by regulatory authonties, AFUDC is capitalized as a part of the
cost of utility plant and the debt related portion is credited curently against total interest expense in the Statements of Income The
Company is permtted, under established reguatory rate practices, to recover the capitalized AFUDC, and a reasonable return thereon,
though 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 servce and included in 'rate base. The effective AFUDC
rate was the followig for the years ended December 31:
2010 2009
Effective AFUDC rate 8.25% (1) 8.22%
(I) Rate was effective from January 1,2010 to November 30, 2010. Effective December 1,2010, rate was changed to 7.91%.
Income Taxes
A defered income ta asset or liability is determed based on the enacted tax rates tht will be in effect when the differences between
the fiancial statement carg amounts and ta basis of existig assets and liabilties are expecte to be reported in the Company's
consolidated income ta retu. The deferred income ta expense for the penod is equal to the net chage in the deferred income ta
asset and liability accounts from the begig to the end of the penod. The effect on deferred income taes from a chage in tax rates
is recognzed in income in the penod tht includes the enactment date. Defer income ta liabilities and regulatory assets are
established for income tax benefits flowed though to customers as prescribed by the respective reguatory commssions.
Stock-Based Compensation
Compensation cost relating to share-based payment tranactions is recognzed in the Company's fincial statements based on the fair
value of the equity or liability intrents issued. See Note 20 for fuer information.
Cash and Cash Equivalents
IFERC FORM NO.1 (ED. 12-88)Page 123.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
For the purposes of the Statements of Cash Flows, the Company considers all temporar investments with a matuty of thee month or
less when purchased to be cash equivalents. Cash and cash equivalents include cash deposits from counterpares.
Allowance for Doubtful Accounts
The Company maintains an allowance for doubtfl 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 wrte-offs as compared to
accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certin individual
accounts.
Utility Plant in Service
The cost of additions to utility plant in servce, including an allowance for fuds used durg constrction and replacements of units of
propert and improvements, is capitalized. The cost of depreciable unts of propert retired plus the cost of removal less salvage is
charged to accumulated depreciation.
Regulatory Deferred Charges and Credits
The Company prepares its financial statements in accordance with regulatory accountig practices because:
· rates for regulated servces are established by or subject to approval by independent thd-par regulators,
· the regulated rates are designed to recover the cost of providing the regulated servces, and
· in view of demand for the regulated servces 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 certin costs and/or obligations (such as incured power and natural gas costs not
curently included in rates, but expected to be recovered or refuded in the futu) are reflected as deferred charges or credits on the
Balance Sheets. These costs and/or obligations are not reflected in the Statements ofIncome until the period durg which matching
revenues are recognized. If at some point in the future the Company determes that it no longer meets the criteria for continued
application of regulatory accounting practices for all or a porton of its regulated operations, the Company could be:
· required to wrte off its regulatory assets, and
· precluded from the future deferral of costs not recovered though rates at the tie such costs are incurred, even if the
Company expected to recover such costs in the futue.
See Note 23 for furter details of regulatory assets and liabilties.
Investment in Exchange Power-Net
The investment in exchange power represents the Company's previous investment in Washington Public Power Supply System Project
3 (WN-3), a nuclear project that was terminated prior to completion. Under a settement agreement with the Bonnevile Power
Administration in 1985, Avista Corp. began receiving power in 1987, for a 32.5-year period, related to its investment in WN-3.
Though a settlement agreement with the Washigton Utilities and Tranporttion Commssion (WC) in the Washigton
jurisdiction, Avista Corp. is amortizing the recoverable porton of its investment in WN-3 (recorded as investment in exchange
power) over a 32.5-year period that began in 1987. For the Idao jursdiction, Avista Corp. fuly amortzed the recoverable porton of
its investment in exchage power.
Unamortzed Debt Expense
Unamortized debt expense includes debt issuce costs that are amortzed over the life of the related debt
Unamortzed Loss on Reacquired Debt
For the Company's Washington regulatory jurisdiction and for any debt repurchases begig in 2007 in all jurisdictions, premiums
paid to repurchase debt are amortized over the remainig life of the original debt that was repurchased or, if new debt is issued in
connection with the repurchase, these costs are amortzed over the life of the new debt. In the Company's other regulatory
jursdictions, 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 though retail rates as a
component of interest expense.
NOTE 2. NEW ACCOUNTING STANDARS
Effective January 1,2010, the Company adopted Accounting Stadads Update (ASU) No. 2009-16, "Transfers and Servicing" (ASC
Topic 860). This ASU amends certin provisions of ASC 860 related to accounting for tranfers of financial assets and a transferor's
I FERC FORM NO.1 (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 04115/2011 2010/04
NOTES TO FINANCIAL STATEMENTS (Continued)
continuing involvement in tranferred fiancial assets. In parcular, the Company evaluated its accounts receivable sales fiancing
facility (see Note 11) and detemied tht the tranactions no longer meet the criteria ofsales of ficial assets. As such, any
transactions will be -accounted for as secured borrowigs. Durg 2010, the Company did not borrw any fuds under the revolving
agreement. As such, the adoption of ths ASU did not have any imact on the Company's fiancial condition, results of operations and
cash flows.
Effective Janua 1, 2010, the Company adopted ASU No. 2009-17, "Consolidations (Topic 810) - Improvements to Financial
Reportg by Enterprises Involved with Varable Interest Entities (VIEs)." This ASU cares forward the scope of ASC 810, with the
addition of entities previously considered qualifyg special-purose entities, as the concept of these entities was eliminated in ASU
No. 2009-16 (ASC 860). The amendments required the Company to reconsider previous conclusions relating to the consolidation of
VIEs, whether the Company is the VIE's pri beneficiary, and what tye of financial statement disclosures are required. As
required by the FERC, the Company accounts for its investments in subsidiaries on the equity method rather than consolidatig the
assets, liabilities, revenues and expenses of subsidiares, as required by U.S. GAA. As such, the adoption of ASU No. 2009-17 did
not have any effect on the Company's fiancial condition, results of operations and cash flows as reported in ths report.
Effective January 1,2010, the Company adopted ASU No. 2010-06, "Fair Value Measurements and Disclosures (Topic 820):
Improving Disclosures about Fair Value Measurements." This AS U amends guidance related to the disclosures 0 f fair value
measurements. In particular, it amends ASC 820-10 to clarfy existing disclosures and provides for fuer disaggregation with
classes of assets and liabilities, and fuer disclosure about inuts and valuation technques. It also requires disclosure of signficant
transfers between Level i and Level 2 and separate disclosure of purchases, sales, issuances and settlements in the reconciliation of
Level 3 activity (this will be required beging in 2011). See Note 18 for the Company's fair value disclosures.
NOTE 3. DISPOSITION OF A VISTA ENERGY
On June 30, 2007, Avista Energy and A vista Energy Canda completed the sale of substatially all of their contracts and ongoing
operations to Shell Energy Nort America (U.S.), L.P. (Shell Energy), formerly known as Coral Energy Holding, L.P., as well as to
certin other subsidiares of Shell Energy. In connection with the tranaction, A vista Energy and its affliates entered into an
Indemnfication Agreement with Shell Energy and its affliates. Under the Indemnfication Agreement, A vista Energy and Shell
Energy each agree to provide indemnfication of the other and the other's affliates for certin events and matters described in the
purchase and sale agreement and certin other tranaction agreements. Such events and matters include, but are not linuted to, the
refud proceedings arsing out of the western energy markets in 2000 and 2001 (see Note 22), existing litigation, tax liabilties, and
matters related to natual gas storage rights. In general, such indemnfication is not required uness and unti a par's claim exceed
$150,000 and is limted to an aggregate amount of$30 nullion and a term of the years (except for agreements or tranactions with
term longer th thee years). These limtations do not apply to certin thd par claim.
Avista Energy's obligations under the Indemnfication Agrement ar guanteed by Avista Capital pursuant to a Guaranty dated June
30,2007. This Guaranty is linuted to an aggregate amount of$30 nullon plus certain fees and expenses. The Guaranty will termnate
April 30,201 i except for claims made prior to termtion. The Company has not recorded any liability related to ths guanty.
NOTE 4. ADVANTAGE IQ ACQUISITIONS
Effective July 2,2008, Advantage IQ completed the acquisition of Cadence Network, a privately held, Cincinnati-based energy and
expense management company. As consideration, the owners of Cadence Network received a 25 percent ownership interest in
Advantage IQ. The total value of the tranaction was $37 nuIIon.
The acquisition of Cadence Network was fuded with the issuance of Advantage IQ common stock. Under the tranaction agreement,
the previous owners of Cadence Network can exercise a right to have their shaes of Advantage IQ common stock redeemed durg
July 201 1 or July 2012 if Advantage IQ is not liquidated though either an intial public offerig or sale of the business to a thd part.
Their redemption rights expire July 31, 2012. The redemption price would be determed based on the fair maket value of
Advantage IQ at the tie of the redemption election as determed by cert independent paries. Additionally, the certain nunority
shareholders and option holders of Advantage IQ have the right to put their shares back to Advantage IQ at their discretion.
On Augut 31,2009, Advantage IQ acquird substatially all of the assets and liabilities ofEcos Consultig, Inc. (Ecos), a Portland,
Oregon-based energy effciency solutions provider. Under the terms of the tranaction, the assets and liabilities of Ecos were acquired
by a wholly owned subsidiar of Advantage IQ.
On December 31, 2010, Advantage IQ acquired substatially all of the assets and liabilities of The Loyalton Group, a
Mineapolis-based energy management fi known for its energy procurement and price risk management solutions.
I FERC FORM NO.1 (ED. 12-88) Page 123.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
In Januar 2011, Advantage IQ acquired substatially all of the assets and liabilities of Building Knowledge Networks, a Seattle-based
real-time building energy mangement servces provider.
NOTE 5. DERIATIVES AND RISK MANAGEMENT
Energy Commodity Derivatives
Avista Corp. is exposed to market risks relatig to changes in electrcity and natual gas commodity prices and certin other fuel prices.
Market risk is, in general, the risk of fluctution in the market price of the commodity being traded and is influenced prily by
supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity intrents. Market
risk may also be influenced by market parcipants' nonperformance of their contrctul obligations and commtments, which affects
the supply of, or demand for, the commodity. Avista Corp. utilizes derivative intrents, such as forwards, futues, swaps and
options in order to manage the varous risks relating to these commodity price exposurs. The Company has an energy resources risk
policy and control procedures to manage these riks. The Company's Risk Management Commtte establishes the Company's energy
resources risk policy and monitors compliance. The Risk Management Commttee is comprised of cerin Company offcers and other
management. The Audit Committee of the Company's Board of Directors periodically reviews and discusses risk assessment and risk
management policies, including the Company's material financial and accounting risk exposures and the steps mangement has
undertaken to control them.
As par of its resource procurement and management operations in the electrc business, A vista 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 captue available economic value. Avista Corp. sells and purchases wholesale electrc
capacity and energy and fuel as part of the process of acquiring and balancing resources to serve its load obligations. These
transactions range from terms of one hour up to multiple years.
Avista Corp. makes continuing projections of:
· electrc loads at varous points in time (rangig from one hour to multiple years) based on, among other things, estimates of
customer usage and weather, historical data and contract terms, and
· resource availabilty at these points in time based on, among other thngs, fuel choices and fuel markets, estiates of
streamflows, availability of generating units, historic and forward maket inormation, contract term, and experience.
On the basis of these proj ections, A vista Corp. maes purhaes and sales of electrc capacity and energy and fuel to match expected
resources to expected electrc load requirements. Resource optization involves generating plant dispatch and scheduling available
resources and also includes transactions such as:
. purchasing fuel for generation,
· when economical, sellng fuel and substitutig wholesale electrc purchass, and
· other wholesale transactions to captue the value of generation and tranmission resources and fuel delivery capacity
contracts.
A vista Corp. 's optimzation process includes enterig into hedgig transactions to manage risks.
As par of its resource procurement and management operations in the natual gas business, A vista Corp. makes continuing projections
of its natual gas loads and assesses available natual gas resources. Forward natul gas contracts are tyically for monthy delivery
periods. However. daily variations in natural gas demand can be signficantly different than montly demand projections. On the
basis of these projections, Avista Corp. plan and executes a series of transactions to hedge a signficant portion of its projected
natual gas requirements though forward market tranactions and derivative instrents. These transactions may extend as much as
four natual gas operating years (November though October) into the future. Avista Corp. also leaves a significant portion of its
natual gas supply requirements unedged for purchase in short-term and spot markets. Natual gas resource optimization activities
include:
· wholesale market sales of surlus natual gas supplies,
· optimization of interstate pipeline transporttion capacity not needed to serve daily load, and
. sales of excess natural gas storage capacity.
Derivatives are recorded as either assets or liabilities on the balance sheet measued at estiated fair value. In certin defined
conditions, a derivative may be specifically designated as a hedge for a parcular exposure. The accounting for derivatives depends
on the intended use of the derivatives and the resultig designation.
IFERC FORM NO.1 (ED. 12-88) Page 123.5
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
The WUTC and the IPUC issued accountig orders authonzing Avita Coip. to offet commodity derivative assets or liabilties with a
reguatory asset or liability. Ths accountig tratment is intended to defer the recogntion of mak-to-market gains and losses on
energy commodity transactions until the period of settlement. The orders provide for A vista Coip. to not recognze the unrealized gain
or loss on utility derivative commodity intrents in the Statements of Income. Realized gain or losses are recognzed in the period
of settlement, subject to approval for recovery though retail rates. Realied gain and losses, subject to regulatory approval, result in
adjustments to retail rates though purchased gas cost adjustments, the Energy Recovery Mechasm (ERM) in Washigtn, the Power
Cost Adjustment (PCA) mechansm in Idao, and periodic general rates cases. Regulatory assets are assessed regularly and are
probable for recovery though futue rates.
Substantially all forward contracts to purchae or sell power and natul gas are recorded as derivative assets or liabilities at estimted
fair value with an offsetting reguatory asset or liabilty. Contrcts tht ar not considered derivatives are accounted for on the accrual
basis until they are settled or realized, uness there is a decline in the fair value of the contract that is determined to be other than
temporar.
The following table presents the underlyig energy commodity derivative volumes as of December 3 i, 20 i ° that are expected to settle
in each respective year (in thousands ofMWhs and mmTUs):
Purchases
Electric Derivatives Gas Derivatives
Physical Financial Physical Finacial
MWH MWH mmTUs mmTUs
949 1,144 35,324 41,593
551 668 11,526 24,845368 6,008 6,275366 2,483 900379 675
1,315
Gas Derivatives
Physical Financial
mmTUs mmTUs
13,426 46,525
1,525 19,510
1,500 1,125
1,475
Year
201 i
2012
2013
2014
2015
Thereafter
Foreign Currency Exchange Contracts
A signficant porton of Avista Coip.'s natual gas supply (including fuel for power generation) is obtained from Canadian sources.
Most of those tranactions are executed in U.S. dollars, which avoids foreign curency risk. A porton of A vista Coip.' s short-term
natual gas tranactions and long-term Candian tranporttion contracts are commtted based on Canadian curency prices and settled
within sixty days with U.S. dollars. Avista Coip. economically hedges a portion of the foreign curency risk by purchasing Canadian
curency contracts when such commodity tranactions are intiated. Ths 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 curency fluctuations were included with natual
gas supply costs for ratemakig. The following table sumarzes the foreign curency 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)
Derivative amount
2010
29
$10,916
10,989
116
2009
24
$10,210
10,637
(50)
Interest Rate Swap Agreements
A vista Coip. enters into forward-staring interest rate swap agreements to manage the risk associated with changes in interest rates and
the impact on futue interest payments. These interest rate swap agreements relate to the interest payments for anticipated debt
issuaces. These interest rate swap agreements are considered economic hedges agait fluctutions in futue cash flows associated
with changes in interest rates.
The following table sumes the interest rate swaps that the Company has entered into as of December 3 1,2010 (dollars in
thousands):
Entered Notional
May/June 2010 $ 50,000
IFERC FORM NO.1 (ED. 12-88)
Number of
Contracts
2
Mandatory Cash
Settlement Date
July 2012
Page 123.6
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
The Company did not have any interest rate swap contrcts outstading as of December 31,2009. In September 2009, the Company
cash settled interest rate swap contracts (notional amount of $200.0 millon) and received a total of $ 1 0.8 millon. The interest rate
swap contracts were settled concurently with the issuance of $250.0 milion of First Mortgage Bonds (see Note 13). The settlement of
the interest rate swaps was deferred as a regulatory liability (included as par oflong-term debt) and is being amortzed as a component
of interest expense over the life of the associate debt issued in accordance with regulatory accountig practices.
Under the terms of the outstading interest rate swap agreements, the value of the interest rate swaps is determed based upon Avista
Corp. paying a fied rate and receivig a variable rate based on LffOR for a term of ten years. As of December 31, 2010, Avista
Corp. had a long-term derivative asset and an offsettg regulatory liability of $0. 1 milion, as well as a long-term derivative liability
and an offsettng regulatory asset ofless than $0.1 million on the Balance Sheet in accordace with regulatory accounting practices.
Upon settlement of the interest rate swaps, the regulatory asset or liabilty (included as part oflong-term debt) will be amortzed as a
component of interest expense over the life of the forecasted interest payments.
Derivative Instruments Summary
Thefollowing table presents the fair values and locations of derivative instrents recorded on the Balance Sheet as of December 31,
2010 (in thousands):
Balance Sheet Location
Derivative instrment assets -
Hedges
Derivative instrment assets -
Hedges
Long-term porton of derivative
instrent liabilities - Hedges
Derivative instrent assets
current
Long-term porton of
derivative assets
Derivative instrent liabilties
curent
Long-term porton of
derivative intrent liabilities
Total derivative instrments recorded on the balance sheet
Derivative
Foreign curency contracts
Interest rate contracts
Interest rate contracts
Commodity contracts
Commodity contracts
Commodity contracts
Commodity contracts
Fair Value
Net Asset
Asset Liability (Liability
$116 $$116
127 127
(53)(53)
6,293 (3,701)2,592
21,249 (5,988)15,261
5,934 (57,417)(51,483)-L (32,371)(30,985)
$35.105 $(99,530)$(64.425)
The following table presents the fair values and locations of derivative intrents recorded on the Balance Sheet as of December 31,
2009 (in thousands):
Balance Sheet Location
Derivative intrent liabilities -
Hedges
Derivative instrment assets
curnt
Long-term portion of
derivative assets
Derivative instrent liabilties
curent
Long-term porton of
derivative instrent liabilities
Total derivative instrents recorded on the balance sheet
Derivative
Foreign curency contracts
Commodity contracts
Commodity contracts
Commodity contracts
Commodity contracts
Exposure to Demands for Collateral
Fair Value
Net Asset
Asset Liability (Liability
$$(50)$(50)
8,976 (1,219)7,757
53,765 (8,282)45,483
5,783 (21,870)(16,087)
-M Q.(2,871)
$69,174 $(34,942)$34.232
I FERC FORM NO.1 (ED. 12-88)Page 123.7
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
The Company's derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or
reductions or termations of a porton of the contract though cash settement, in the event of a downgrade in the Company's credit
ratings or adverse chages in maket prices. In periods of price volatilty, the level of exposure can chage signficantly. As a result,
sudden and signficant demads may be made againt the Company's credit facilities and cash. The Company actively monitors the
exposure to possible collateral calls and taes steps to minimize capita requiements.
Certin of the Company's derivative intrents conta provisions tht require the Company to maintain an investment grade credit
rating from the major credit ratig agencies. If the Company's credit ratigs were to fall below "investment grade," it would be in
violation of these provisions, and the counterpares to the derivative intrents could request immediate payment or demand
imediate and ongoing collateralization on derivative intrents in net liability positions. The aggregate fair value of all derivative
intrments with credit-risk-related contingent featus tht are in a liability position as of December 31, 2010 was $62.1 millon. If
the credit-risk-related contingent featues underlyig these agreements were trggered on December 3 1,2010, the Company would be
required to post $42.1 millon of collateral to its counterpares.
Credit Risk
Credit risk relates to the potential losses tht the Company would incur as a result of non-performance by counterparies of their
contractul obligations to deliver energy or make ficial settements. The Company often extends credit to counterparties and
customers and is exposed to the risk tht it may not be able to collect amounts owed to the Company. Changes in market prices may
dramatically alter the size of credit risk with counterparies, even when conservative credit limits are established. Credit risk includes
potential counterpart default due to circumtaces:
. relating directly to it,
. caused by market price changes, and
. relating to other market paricipants that have a direct or indirect relationship with such counterpar.
Should a counterpar, customer or supplier fail to perform, the Company may be required to honor the underlyig commtment or to
replace existing contracts with contracts at then-curent market prices. The Company seeks to mitigate credit risk by:
. entering into bilateral contracts tht specify credit term and protetions againt default,
. applying credit limits and duration criteria to existing and prospective counterpares,
. actively monitorig curent credit exposures, and
. conducting some of its transactions on exchages with clearg arangements that essentially eliminte counterpar default
risk.
These credit policies include an evaluation of the ficial condition and credit ratigs of counterparies, collateral requirements or
other credit enhancements, such as letters of credit or parent company guarantees. The Company also uses standardized agreements
tht allow for the nettg or offsettg of positive and negative exposures associated with a single counterpart or affliated group.
The Company has concentrations of suppliers and customers in the electrc and natual gas industres including:
. electrc utilities,
. electrc generators and transmission providers,
. natual gas producers and pipelines,
. financial institutions, and
. energy marketing and trading companes.
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 counterpares and concentrations of geogrphic location may impact the Company's overall
exposure to credit risk, either positively or negatively, because the counterpares may be simlarly affected by changes in conditions.
As is common industr practice, Avista Corp. maintain magin agreements with certin counterpares. Margi calls are trggered
when exposures exceed predetermed contrctual limts or when there are changes in a counterpart's creditwortess. Price
movements in electrcity and natual gas can generate exposure levels in excess of these contractual limts. Margin calls are
periodically made and/or received by Avista Corp. Negotiatig for collateral in the form of cash, letters of credit, or performance
guarantees is common industr practice.
Cash deposits from counterpares totaled $1.2 millon as of December 31,2010 and $3.2 millon as of December 31,2009. These
fuds were held by Avista Corp. to mitigate the potential impact of counterpar default risk. These amounts are subject to retu if
IFERC FORM NO.1 (ED. 12-88) Page 123.8
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo. Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
conditions waant because of contiuing portolio value fluctutions with those pares or substitution of non-cash collateral.
NOTE 6. JOINTLY OWNED ELECTRIC FACILITIES
The Company has a 15 percent ownership interest in a tw-unt coal-fied generatig facilty, the Colstrp Generatig Project
(Colstrp) located in southeastern Monta and provides ficing for its ownership interest in the project. The Company's share of
related fuel costs as well as operatig expenses for plant in servce are included in the corresponding accounts in the Statements of
Income. The Company's share of utility plant in servce for Colstrp and accumulate depreciation were as follows as of December 31
(dollar in thousands):
Utility plant in servce
Accumulated depreciation
2010
$336,796
(219,770)
2009
$334,773
(209,587)
NOTE 7. ASSET RETIRMENT OBLIGATIONS
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incured. When the
liabilty is initially recorded, the associated costs of the asset retirement obligation are capitalized as part of the carrng 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 retiement 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
curently recovered in rates and asset retiement obligations recorded since asset retiement costs are recovered though rates charged
to customers. The regulatory assets do not earn a retu.
Specifically, the Company has recorded liabilities for futue asset retirement obligations to:
. restore ponds at Colstrp,
· cap a landfill at the Kettle Falls Plant,
· remove plant and restore the land at the Coyote Sprigs 2 site at the termation of the land lease,
· remove asbestos at the corporate offce building, and
. dispose of PCBs in certain trformers.
Due to an inability to estimate a range of settement dates, the Company canot estiate a liability for the:
· removal and disposal of certin transmission and distrbution assets, and
· abandonment and decommssioning of certin hydroelectrc generation and natual gas storage facilities.
The followig table documents the changes in the Company's asset retiement obligation durng the years ended December 31 (dollars
in thousands):
Asset retirement obligation at beginning of year
New liability recognized
Liability adjustment due to revision in estimated cash flows
Liabilty settled
Accretion expense
Asset retirement obligation at end of year
2010
$3,971
19
2009
$4,208
(460)
357~(499)
262
$3,971
NOTE 8. PENSION PLANS AND OTHER POSTRTIREMENT BENEFIT PLANS
The Company has a defined benefit pension plan coverig substatially all regular full-tie employees. Individual benefits under this
plan are based upon the employee's years of servce, date of hire and average compensation as specified in the plan. The Company's
fuding policy is to contrbute at least the minimum amounts that are required to be fuded under the Employee Retiement Income
Security Act, but not more than the maximum amounts tht ar curently deductible for income tax puroses. The Company
contrbuted $21 millon in cash to the pension plan in 2010 and $48 milion in 2009. . The Company expects to contrbute $26 milion
in cash to the pension plan in 2011.
The Company also has a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to executive
offcers of the Company. The SERP is intended to provide benefits to executive offcers whose benefits under the pension plan are
I FERC FORM NO.1 (ED. 12-88) Page 123.9
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred
compensation plan. The liability and expense for ths plan are included as pension benefits in the tables included in ths Note.
The Company expects that benefit payments under the pension plan and the SERP wil total (dollars in thousands):
Expected benefit payments
2011 2012 2013 2014 2015
$19,343 $20,521 $21.824 $23,105 $24,620
Tota 2016-2020
$145,063
The expected long-term rate of retu on plan assets is based on past performance and economic forecasts for the tyes of investments
held by the plan. In selectig a discount rate, the Company considers yield rates for highy rated corporate bond portolios with
matuities simlar to that of the expected term of pension benefits.
In 2009, the Company reviewed the mortity table utilied in the actual calculations. The Company determed that the RP-2000
combined healthy mortlity tables for males and femaes should be replaced with the RP-2000 combined healthy mortality tables for
males and females projected to 2010 using scale AA. The change resulted in an increase of$6.6 million to the pension benefit
obligation as of December 31,2009.
The Company provides certin health care and life inurance benefits for substantially all of its retired employees. The Company
accrues the estimated cost of postretirement benefit obligations durg the years that employees provide services. The Company
elected to amortize the transition obligation of$34.5 millon over a period of twenty years, begining in 1993.
The Company established a Health Reimbursement Argement to provide employees with tax-advantaged fuds to pay for allowable
medical expenses upon retirement. The amount eared by the employee is fixed on the retirement date based on the employee's year
of service and the ending salar. The liabilty and expense of this plan are included as other postretirement benefits.
The Company provides death benefits to beneficiares of executive offcers who die durg their term of offce or after retirement.
Under the plan, an executive offcer's designted beneficiary will receive a payment equal to twce the executive offcer's anual base
salar at the time of death (or if death occurs after retirement, a payment equal to twce the executive offcer's total anual pension
benefit). The liability and expense for ths plan are included as other postretiement benefits.
The Company expects tht benefit payments under other postretiement benefit plan will total (dollars in thousands):
2011 2012 2013 2014 2015 Tota 2016-2020 Expected benefit payments $4,695 ~ ~ ~ ~ $22.439
The Company expects to contrbute $4.7 miion to other postretiement benefit plan in 2011, representing eXpected benefit payments
to be paid durng the year.
The Company uses a December 31 measurement date for its pension and other postretirement benefit plan.
The followig table sets fort the pension and other postretiement benefit plan disclosures as of December 3 1, 2010 and 2009 and the
components of net periodic benefit costs for the year ended December 31,2010 and 2009 (dollars in thousands):
Pension Other
2010 2009 2010 2009
Change in benefi obligation:
Benefit obligation as of begining of year $378,235 $353,572 $39,560 $38,953
Servce cost 1l,609 10,496 684 803
Interest cost 23,231 21,770 2,624 2,364
Actuaral loss 38,547 9,610 21,657 1,676
Transfer of accrued vacation 367 98
Benefits paid (18.131)(17,213)(4,553)(4,334)
Benefit obligation as of end of year $433.491 $378,235 $60.339 $39.560
Change in plan assets:
Fair value of plan assets as of beginning of year $272,732 $190,637 $20,394 $16,048
Actual retu on plan assets 29,846 50,053 2,481 4,346
Employer contrbutions 21,000 48,000
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 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
Benefits paid 06,866)05,958)----
Fair value of plan assets as of end of year $306,712 $272,732 $22,875 $20.394
Funded statu $(126,779)$(105,503)$(37,464)$(19,166)
Unrecògnized net actuarial loss 149,819 126,926 35,149 15,772
Unrecognized prior servce cost 1,140 1,790 (1,154)(1,303)
Unrecognzed net transition obligation 1,011 1.16
Prepaid (accrued) benefit cost 24,180 23,213 (2,458)(3,181)
Additional liability 050,959)028,716)(35,006)05,985)
Accrued benefit liability $(126,779)$(105.503)$07,464)$(19.166)
Accumulated pension benefit obligation $377,606 $331.081
Accumulated postretirement benefit obligation:
For retirees $27,921 $18,377
For fully eligible employees $15,618 $9,290
For other partcipants $16,800 $11,893
Included in accumulated comprehensive loss (income) (net of tax):
Unrecognized net transition obligation $$$657 $985
Unrecognized prior servce cost 741 1,163 (750)(847)
Unrecognized net actuarial loss 97,382 82,502 22,847 10,252
Total 98,123 83,665 22,754 10,390
Less regulatory asset (92,570)(80,041)(23,981)(I 1,664)
Accumulated other comprehensive loss (income)~~$(1,227)$(1,274)
Weighted average assumptions as of December 31:
Discount rate for benefit obligation 5.69%6.29%5.50%6.00%
Discount rate for annual expense 6.28%6.25%6.00%6.25%
Expected long-tenn retu on plan assets 7.75%8.50%7.75%8.50%
Rate of compensation increase 4.72%4.65%
Medical cost trend pre-age 65 - initial 8.00%8.50%
Medical cost trend pre-age 65 - ultiate 5.00%5.00%
Ultimate medical cost trend year pre-age 65 2017 2017
Medical cost trend post-age 65 - initial 8.00%8.50%
Medical cost trend post-age 65 - ultimate 6.00%6.00%
Ultimate medical cost trend year post-age 65 2015 2015
Components of net periodic benefit cost:
Service cost $11,609 $10,496 $684 $803
Interest cost 23,23 I 21,770 2,624 2,364
Expected return on plan assets (21,38 i)(17,612)(1,581)(1,364)
Transition obligation recognition 505 505
Amortization of prior servce cost 650 654 (149)(149)
Net loss recognition 7,189 10,539 1,79 1.279
Net periodic benefit cost $21.298 $25,847 ~$3,438
Plan Assets
The Finance Committee of the Company's Board of Directors establishes 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
fuding policies.
The Company has contracted with investment consultats who are responsible for magig/monitorig the individual investment
managers. The investment mangers' pedonnance and related individual fud pedormce is periodically reviewed by an internal
benefits committee and by the Finance Committee to monitor compliance with investment policy objectives and strtegies.
Pension plan assets are invested primarily in marketable debt and equity securties. Pension plan assets may also be invested in real
estate, absolute return, ventue capital/private equity and commodity fuds. In seekig to obtain the desired retu to fud 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 Commttee has
established target investment allocation percentages by asset classes as indicated in the table below:
IFERC FORM NO.1 (ED. 12-88) Page 123.11
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avlsta Corporation (2)A Resubmission 04/15/2011 2010/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Equity securties
Debt securties
Real estate
Absolute return
Other
2010
51%
31%
5%
10%
3%
2009
51%
31%
5%
10%
3%
The market-related value of pension plan assets invested in debt and equity securties was based pnmarly on fair value (market
prices). The fair value of investment securties traded on a national securties exchange is determined based on the last reported sales
price; securties traded in the over-the-counter maket ar valued at the last reportd bid price. Investment securties for which market
prices are not readily available or for which maket prices do not represent the value at the time of pricing, are fair-valued by the
investment manger based upon other inuts (including valuations of securties tht are comparable in coupon, rating, matuty and
industr). Investments in common/collective trt fuds are presented at estimted fair value, which is determined based on the unt
value of the fud. Unit value is determed by an independent trtee, which sponsors the fud, by dividing the fud's net assets by its
unts outstadig at the valuation date. The fair value of the closely held investments and parership interests is based upon the
allocated share of the fair value of the unerlyig assets as well as the allocated shae of the undistrbuted profits and losses, including
realized and unealized gain and losses.
The market-related value of pension plan assets invested in real estate was determed by the investment manager based on thee basic
approaches:
. curent cost of reproducing a propert less deterioration and functional economic obsolescence,
. capitalization of the propert's net eargs power, and
. value indicated by recent sales of comparable propertes in the maket.
The market-related value of pension plan assets was determed as of December 31, 2010 and 2009.
The following table discloses by level with the fair value hierachy (refer to Note 18 for a description of the fair value hierarchy) of
the pension plan's assets measured and reported as of December 31, 2010 at fai value (dollar in thousands):
Levell Level 2 Level 3 Total$ 335 $ $ $ 335Cash equivalents
Mutul fuds:
Fixed income securties
U.S. equity securties
International equity securities
Absolute retu (1)
Commodities (2)
Common/collective trsts:
Fixed income securties
Absolute retu (I)
Real estate
Parership/closely held investments:
Absolute retu (I)
Private equity fuds (3)
Total
96,026
104,232
53,964
12,662
7,133
$274352
96,026
104,232
53,964
12,662
7,133
13,653 13,653
95
423
95
423
$13.653
16,917
1,272
$18.707
16,917
1,272
$306.712
The following table discloses by level with the fair value hierachy (refer to Note 18 for a description of the fair value hierarchy) of
the pension plan's assets measured and reported as of December 31,2009 at fair value (dollars in thousands):
Cash equivalents
Mutual fuds:
Fixed income securities
U.S. equity securities
Levell
$ 19
70,924
87,562
Level 2
$
Level 3
$
Total
$ 19
70,924
87,562
IFERC FORM NO.1 (ED. 12-88)Page 123.12
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Dar Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010/04
NOTES TO FINANCIAL STATEMENTS (Continued)
International equity securties
Absolute retu (1)
Commodities (2)
Common/collective trsts:
Fixed income securties
U.S. equity securities
Absolute retu (1)
Real estate
Partership/closely held investments:
Absolute return (l)
Private equity funds (3)
Total
46,548
11,671
5,870
14,840
11,070
46,548
11,671
5,870
844
6,029
14,840
11,070
844
6,029
15,794 15,794- ~ 1,561
$222.594 $25.910 $24.228 $272.732
(l) Ths 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 fied income, and
(d) market neutrl strategies. .
(2) The fund primarily invests in derivatives lined to commodity indices to gain exposure to the commodity markets. The fud
manager fully collateralizes these positions with debt securties.
(3) Ths category includes several private equity fuds that invest prily in U.S. companies.
The table below discloses the sum of chages in the fair value of the pension plan's Level 3 assets for the year ended December
31,2010 (dollars in thousands):
Common/collective trts
Balance, as of Januar 1, 2010
Realized gains (losses)
Unrealized gains (losses)
Purhases (sales), net
Balance, as of December 3 I, 20 10
Absolute
retu
$844
(233)
(193)
(323)
$ 95
Rea
estate
$6,029
630
(160)
(6,076)
$ 423
Parership/closely held investments
Absolute Private equity
retu fuds
$15,794 $1,561
(148)1,123 (48)- (93)
$16.917 $1.72
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, 2009 (dollars in thousands):
Common/collective trts
Balance, as of January i, 2009
Realized gains (losses)
Unrealized gains (losses)
Purchases (sales), net
Balance, as of December 31, 2009
Absoluteretu
$2,351
(415)
(21)1.~
Real
estate
$11,987
520
(4,310)
(2,168)~
Parership/closely held investments
Absolute Private equity
return fuds
$13,983 $1,316
3
1,811 223- -l$15.794 !L
The market-related value of other postretirement plan assets invested in debt and equity secuties was based priarly on fair value
(market prices). The fair value of investment securties trded on a national securties exchange is determned 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 manger based upon other inputs (including valuations of securties that are comparable in coupon,
rating, matuty and industr). The taget asset allocation was 62 percent equity securties and 38 percent debt securties in 2010 and
2009.
The market-related value of other postretirement plan assets was determined as of December 3 i, 20 I 0 and 2009.
The following table discloses by level within the fair value hierarchy (refer to Note 18 for a description of the fair value hierarchy) of
other postretirement plan assets measured and reported as of December 31, 20 10 at fair value (dollars in thousands):
IFERC FORM NO.1 (ED. 12-88)Page 123.13
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 041512011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Cash equivalents
Mutual fuds:
Debt secunties
U.S. equity secunties
International equity securties
Debt securties
U.S. equity securties
International equity securties
Total
Level I
$ 118
Level 2
$
Level 3
$
Total
$ 118
8,320
6,986
5,572
37
1,785--
$22.875 $$
8,320
6,986
5,572
37
1,785--
$22.875
The following table discloses by level with the fair value hierarchy (refer to Note 18 for a description of the fair value hierarchy) of
other postretirement plan assets measured and reported as of December 31, 2009 at fair value (dollars in thousands):
Cash equivalents
Mutul funds:
Debt securities
U.S. equity securties
International equity securties
Debt secunties
U.S. equity secunties
International equity secunties
Total
Level i
$ 96
Level 2
$
Level 3
$
Total
$ 96
7,742
5,927
5,077
25
1,456--
$20394 $$
7,742
5,927
5,077
25
1,456--
$20394
Assumed health care cost trend rates have a signficant 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, 2010 by $5.2 millon and the servce and interest cost by $0.3 million. A one-percentage-point
decrease in the assumed health care cost trend rate for each year would decrease the accumulated postrtirement benefit obligation as
of December 31,2010 by $4.4 millon and the service and interest cost by $0.2 millon.
The Company has a salar deferral 40 1 (k) plan that is a defied contribution plan and covers substantially all employees.
Employees can make contrbutions to their respective accounts in the plan on a pre-ta basis up to the maimum amount permtted by
law. The Company matches a portion of the salar deferred by each paricipant according to the schedule in the plan.
Employer matching contrbutions were as follows for the years ended December 3 i (dollars in thousands):
Employer 401 (k) matchig contrbutions
2010
$4,797
2009
$4,439
The Company has an Executive Deferral PLan Ths plan allows executive offcers and other key employees the opportty to defer
until the earlier of their retirement, termtion, disabilty or death up to 75 percent of their base salar andlorup to 100 percent of
their incentive payments. Deferred compensation fuds are held by the Company in a Rabbi Trut. There were deferred compensation
assets and corresponding deferred compenstion liabilities on the Balance Sheets of the followig amounts as of Decembet 31 (dollars
in thousands):
Deferred compensation assets and liabilties
2010
$9,285
2009
$9,437
NOTE 9. ACCOUNTING FOR INCOME TAXS
Deferred income taes reflect the net ta effects of temporar differences between the carrng amounts of assets and liabilties for
finacial reporting puroses and the amounts used for income tax puroses and tax credit carrorwards.
As of December 3 I, 2010, the Company had $11.2 million of state tax credit carorwards. State tax credits expire from 2015 to
2023. The Company recognzes the effect of state tax credits generated from utility plant as they are utilized.
IFERC FORM NO.1 (ED. 12-88)Page 123.14
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
The realization of deferred income ta assets is dependent upon the abilty to generate taable income in futu penods. The Company
evaluated available evidence supportng the realiztion of its deferrd income ta assets and determined it is more likely than not that
deferred income ta assets will be realized. .
The Company and its eligible subsidianes file consolidated federal income tax retu. The Company also files state income tax
returns in certin jursdictions, including Idao, Oregon and Montana. Subsidiares are chaged or credited with the ta effects of their
operations on a stad-alone basis. The Internal Revenue Service (IRS) has completed its examination of all ta years though 2007
and all issues were resolved related to these years. The IRS has not examined the Company's 2008 or 2009 federal income ta retu.
However, an estimate of the range of any such possible change canot be made at this tie. The Company does not believe that any
open tax years for federal or state income taes could result in any adjustments that would be signficant to the financial statements.
The Company did not incur any penalties on income ta positions in 2010 or 2009.
The Company had net regulatory assets related to the probable recovery of certin deferred income ta liabilties from customers
though futue rates as of December 3 I (dollars in thousands):
Regulatory assets for deferred income taes
2010
$90,025
2009
$97,945
NOTE 10. ENERGY PURCHASE CONTRACTS
Avista Corp. has contracts for the purchase of fuel for thermal generation, natual gas for resale and varous agreements for the
purchase or exchange of electrc energy with other entities. The termtion dates of the contracts range from one month to the year
2055. Total expenses for power purchased, natual gas purhaed, fuel for generation and other fuel costs were as follows for the years
ended December 3 i (dollars in thousands):
Utility power resources
2010
$649,408
2009
$704,886
The following table details Avista Corp.'s futu contractul commitments for power resources (including transmission contråcts) and
natual gas resources (including transporttion contracts) (dollars in thousands):
Power resources
Natural gas resources
Total
201 i
$217,093
138.917
$356,010
2012
$159,409
100.658
$260.067
2013
$119,250
83.908
$203.158
2014
$105,974
65,192
$171.66
20 i 5 Thereafter
$ 97,163 $ 666,752
56,514 631,946
$153.677 $1.298.698
Total
$1,365,641
1.077.135
$2.442,776
These energy purchase contracts were entered into as part of Avista Corp.'s obligation to serve its retail electrc and natural gas
customers' energy requirements. As a result, these costs are recovered either though base retail rates or adjustments to retail rates as
part of the power and natural gas cost deferrl and recovery mechansms.
In addition, A vista Corp. has operational agreements, settements and other contrctul obligations for its generation, tranmission and
distrbution facilties. The followig table details future contractual commtments for these agreements (dollars in thousands):
Contractual obligations
2011
$21.51
2012
$23.307
2013
$22.643
2014
$23.100
2015
$24,525
Thereafter
$252.015
Tota
$367,141
A vista Corp. has fied contracts with cert Public Utility Distrcts (PUD) to purchase portons of the output of certin generating
facilties. Although Avista Corp. has no investment in the PUD generatig facilties, the fied contracts obligate Avista Corp. to pay
certin minum amounts (based in par on the debt servce requirements of the PUD) whether or not the facilities are operating.
Expenses under these PUD contracts were as follows for the year ended December 3 i (dollars in thousands):
PUD contract costs
2010
$8,287
2009
$12,633
Information as of December 31,2010 pertining to these PUD contracts is summanzed in the following table (dollars in thousands):
IFERC FORM NO.1 (ED. 12-88)Page 123.15
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2. An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
Company's Cuent Shae of
Debt Expira-
Kilowatt Anual Service Bonds tion
Output Capabilty Costs (I)Costs (I)Outstading Date
Chelan County PUO:
Rocky Reach Project 2.9%37,000 $ 2,ln $1,013 $436 201 i
Douglas County PUD:
Wells Project 3.3%28,000 1,734 698 3,773 2018
Grant County PUD:
Priest Rapids and
Wanapum Projects 3.3%65,800 4,381 1,803 19,537 2055
Totals 130,800 ~al $23,746
(1) The anual costs will change in proportion to the percentage of output allocated to Avista Corp. in a particular year. Amounts
represent the operating costs for 20 i O. Debt servce costs are included in anual costs.
The estimated aggregate amounts of required mium payments (Avista Corp.'s shae of existig debt service costs) under these PUD
contracts are as follows (dollars in thousands):
Minum payments
20ll~2012~2013~2014~2015~Thereafter
$28,026
Total
$41.231
In addition, Avista Corp. will be required to pay its proportonate shae of the varable operating expenses of these projects.
NOTE 11. ACCOUNTS RECEIVABLE FINANCING FACILITY
On December 30,2010, Avista Corp., Avista Receivables Corporation (ARC), Ban of America, N.A. and Rager Funding Company,
LLC termated a Receivables Purchase Agreement at the diection of the Company. ARC is a wholly owned, banptcy-remote
subsidiar of the Company formed in 1997 for the purose of acquirg or purchaing interests in certin accounts receivable, both
biled and unbiled, of the Company. The Company elected to termte the Receivables Purchase Agreement prior to its March I 1,
2011 expiration date based on the Company's forecasted liquidity needs. The Receivables Purchase Agreement was originally entered
into on May 29,2002 (and has been renewed on an anual basis) and provided the Company with fuds for general corporate needs.
Under the Receivables Purchase Agreement, the Company could borrow up to $50.0 millon based on calculations of eligible
receivables. The Company did not borrow any fuds under ths revolving agreement in 2010.
NOTE 12, NOTES PAYABLE
At December 3 i, 2010, Avista Corp. had a commtted line of credit agreement with varous ban in the total amount of$320.0 milion
with an expiration date of AprilS, 2011. Under the credit agreement, the Company could borrow or request the issuance of letters of
credit in any combination up to $320.0 millon. Additionally, the Company had a commtted line of credit agreement with varous
bank in the total amount of $75.0 millon with an expiration date of Apri 5, 2011.
In Februry 20 I 1, A vista Corp. entered into a new commtted lie of credit in the total amount of $400.0 millon with an expiration
date ofFebruar 2015 tht replaced its $320,0 millon and $75.0 millon commtted lines of credit.
The commtted lines of credit are secured by non-trferable Firt Mortgage Bonds of the Company issued to the agent ban that
would only become due and payable in the event, and then only to the extent, tht the Company defaults on its obligations under the
committed lines of credit.
The commtted line of credit agreements contain customa covenants and default provisions. The $320.0 milion and $75.0 milion
credit agreements had a covenant that requied the ratio of "eargs before interest, taes, depreciation and amortation" to "interest
expense" of A vista Corp. for the preceding twelve-month period at the end of any fiscal quarer to be greater than 1.6 to 1. As of
December 31, 2010, the Company was in compliance with this covenant. The new $400.0 million committed line of credit does not
have ths covenant. The $320.0 million and $75.0 milion credit agreements also had a covenant which did not permit the ratio of
"consolidated total debt' to "consolidated total capitalization" of A vista Corp. to be greater than 70 percent at any time. As of
December 31, 2010, the Company was in compliance with ths covenant. Under the new $400.0 milion committed line of credit, ths
ratio must not be greater than 65 percent at any time.
IFERC FORM NO.1 (ED. 12-88) Page 123.16
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
Balances outstanding and interest rates of borrowigs (excluding letters of credit) under the Company's revolving committed lines of
credit were as follows as of and for the years ended December 31 (dollars in thousands):
Balance outstanding at end of period
Letters of credit outstanding at end of period
Average interest rate at end of period
2010
$110,000
$ 27,126
0.57%
2009
$ 87,000
$ 28,448
0.59%
NOTE 13. BONDS
The following details bonds outstading as of December 31 (dolla in thousands):
Matuty Interest
Year Description Rate 2010 2009
2010 Secured Medium-Term Notes 6.67%-8.02%$$ 35,000
2012 Secured Medium-Term Notes 7.37%7,000 7,000
2013 First Mortgage Bonds (1)6.13%45,000
2013 First Mortgage Bonds (1)7.25%30,000
2013 First Mortgage Bonds (2)1.68%50,000
2018 First Mortgage Bonds 5.95%250,000 250,000
2018 Secured Medium-Term Notes 7.390/0-7.45%22,500 22,500
2019 First Mortgage Bonds 5.45%90,000.90,000
2020 First Mortgage Bonds (1)3.89%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 (3)(3)66,700 66,700
2034 Secured Pollution Control Bonds (4)(4)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 (1)5.55%35,000
Total secured long-term debt 1,178,700 1,151,700
2023 Unsecured Pollution Control Bonds 6.00%4,100 4,100
Settled interest rate swaps (951)(1,844)Secured Pollution Control Bonds held by Avista
Corporation (3) (4)(83,700)(83,700)
Total bonds $1.098.149 $1.070,256
(1) In December 2010, Avista Corp. issued $52.0 millon 00.89 percent Firt Mortgage Bonds due in 2020 and $35.0 million of
5.55 percent Firt Mortgage Bonds due in 2040. The tota net proceeds from the sale of the new bonds of $86.6 millon (net
of placement agent fees and before Avista Corp.'s expenes) were used to redeem $45.0 millon of6. 125 percent First
Mortgage Bonds due in December 2013 and $30.0 millon of7.25 percent Firt Mortgage Bonds due in September 2013.
These First Mortgage Bonds were redeemed at par plus a make-whole redemption premium of $1 0.7 milion. In accordance
with regulatory accountig practices, the make-whole redemption premium will be amortized over the life of the new debt
issued.
(2) In December 2010, Avista Corp. issued $50.0 millon of 1.68 percent First Mortgage Bonds (Bonds) due in 2013. The net
proceeds from the issuance of the Bonds of$49.8 millon (net of placement agent fees and before Avista Corp.'s expenses)
were used to repay a porton of the borrowings outstading under the Company's committed line of credit.
(3) In December 2010, $66.7 milion of the City of Forsyt, Montaa Pollution Control Revenue Refuding Bonds (Avista
Corporation Colstrp Project) due 2032, which had been held by A vista Corp. since 2008, were refuded by a new bond issue
(Series 201 OA). The new bonds were not offered to the public and were purchased by A vista Corp. due to market conditions.
The Company expects that at a later date, subject to maket conditions, these bonds will be remarketed to unaffliated
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.
I FERC FORM NO.1 (ED. 12-88)Page 123.17
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) iç An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/15/2011 2010104
NOTES TO FINACIAL STATEMENTS (Continued)
(4) In December 2010, $17.0 millon of the City of Forsyt Monta Pollution Control Revenue Refuding Bonds, (Avista
Corporation Colstrp Project) due 2034, which had been held by Avista Corp. since 2009, were refuded by a new bond issue
(Series 20lOB). The new bonds were not offered to the public and were purhaed by Avista Corp. due to market conditions.
The Company expects tht at a later date, subject to market conditions, the bonds will be remarketed to unaffliated investors.
So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s
Balance Sheet.
The followig table details futue long-term debt matuties including advances from associated companies (see Note 14) (dollars in
thousands):
Debt matuties
2011$ -2012aQ 2013
$50.000
2014 2015$ - $ -Thereafter
$1.093,647
Total
$1,150,647
Substatially all utility properties owned by the Company are subject to the lien of the Company's mortgage indentue. 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: i) 70 percent of the cost or fair value
(whichever is lower) of propert 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 certin exceptions
in the case of bonds issued on the basis of retired bonds) uness the Company's "net earngs" (as defied in the Mortgage) for any
period of 12 consecutive calendar month out of the precedg i 8 calenda month were at least twce the anual interest requirements
on all mortgage securties at the time outstadig, including the Firt Mortgage Bonds to be issued, and on all indebtedness of prior
ran As of December 3 1,2010, propert additions and retied bonds would have allowed the Company to issue $795.3 million in
aggregate pricipal amount of additional First Mortgage Bonds. However, using an interest rate of 8 percent on additional First
Mortgage Bonds, and based on net eargs for the 12 month ended December 31,2010, the net eargs test would limt the
pricipal amount of additional bonds the Company could issue to $758.8 millon.
See Note 12 for inormation regarding First Mortgage Bonds issued to secure the Company's obligations under its committed lines of
credit agreements.
NOTE 14. ADVANCES FROM ASSOCIATED COMPANIES
In 1997, the Company issued Floatig Rate Junor Subordinted Deferrable Interest Debentures, Series B, with a principal amount of
$51.5 millon to Avista Capital II, an affliated business trt formed by the Company. Avista Capital II issued $50.0 millon of
Preferred Trust Securties with a floating distrbution rate of LIB OR plus 0.875 percent, calculated and reset quaerly. The
distrbution rates paid were as follows durng the years ended December 31:
2010
1.3%
1.41
1.7
Low distribution rate
High distribution rate
Distribution rate at the end of the year
2009
1.22%
3.06
1.22
Concurent with the issuace of the Preferred Trut Securties, A vista Capital II issued $ 1.5 millon of Common Trust Securties to the
Company. These debt securities may be redeemed at the option of A vita Capital II on or after June I, 2007 and matue on June I,
2037. In December 2000, the Company purchaed $10.0 millon of these Preferred Trut Securties.
The Company ha guaranteed the payment of distrbutions on, and redemption price and liquidation amount for, the Preferred Trut
Securties to the extent that Avista Capita II has fuds available for such payments from the respective debt securties. Upon matuty
or prior redemption of such debt securties, the Preferred Trut Securties will be mandatorily redeemed.
NOTE 15. LEASES
The Company ha multiple lease arangements involvig varous assets, with mium term ranging from one to fort-five years.
Renta expense under operating leases was as follows for the years ended December 3 i (dollars in thousands):
2010 2009Rental expense $2,885 $3,244
Futue minmum lease payments required under operating leases havig initial or remaining noncancelable lease term in excess of one
year as of December 31,2010 were as follows (dollars in thousands):
IFERC FORM NO.1 (ED. 12-88)Page 123.18
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
Minimum payments required
2011 2012
$1.480 am
2013 2014$1.259 ~2015
$437
Thereafter~Totalam
NOTE 16. GUARTEES
The Company has guaranteed the payment of distrbutions on, and redemption price and liquidation amount for, the Preferred Trust
Securties issued by its affliate, Avista Capital II, to the extent that ths entity ha fuds available for such payments from its debt
securties.
The output from the Lancaster Plant was contracted to Avista Turbine Power, Inc. (ATP), an affate of Avista Energy, though 2026
under a power purchase agreement (PP A). The majority of the rights and obligations of ths PP A were conveyed to Shell Energy
though the end of2009. Beging in Janua 2010, the rights and obligations under the PPA were conveyed to Avista Corp.
Effective December i, 2010, the PPA was assigned to A vista Corp. Prior to the assignent, A vista Corp. had provided Rathdru
Power LLC, the owner of the Lacaster Plant, a guantee under whichAvita Corp. has guanteed ATP's performance under the
PPA. This guarantee was terminted in connection with the assignent of the PPA to Avista Corp.
In connection with the transaction, on June 30, 2007, A vista Energy and its affliates entered into an Indemnfication Agreement with
Shell Energy and its affliates. Under the Indemnfication Agreement, Avista Energy and Shell Energy each agree to provide
indemnfication of the other and the other's affliates for certin events and mattrs described in the purchase and sale agreement
entered into on April 16, 2007 and certin other transaction agreements. Such events and matters include, but are not limited to, the
refud proceedings arising out of the western energy markets in 2000 and 2001 (see Note 22), existing litigation, tax liabilities, and
matters related to storage rights at Jackson Praire. In general, such indemnfication is not required unless and until a part's claims
exceed $150,000 and is limted to an aggregate amount of$30 millon and a term of thee year (except for agreements or transactions
with terms longer than thee years). These limitations do not apply to certin thrd par claims.
Avista Energy's obligations under the Indemnfication Agreement are guaranteed by Avista Capital pursuant to a Guaranty dated June
30,2007. This Guaranty is limited to an aggregate amount of$30 milion plus certin fees and expenses. The Guaranty will termate
April 30, 2011 except for claims made prior to termation. The Company has not recorded any liability related to this guaranty.
NOTE 17. PREFERRD STOCK-CUMULATIVE (SUBECT TO MADATORY REDEMPTION)
The Company has 10 milion authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of
December 31, 2010 and 2009.
NOTE 18. FAIR VALUE
Fair value represents the price that would be received to sell an asset or paid to tranfer a liabilty (an exit price) in an orderly
transaction between market participants at the measurement date. The carg values of cash and cash equivalents, special deposits,
accounts and notes receivable, accounts payable and notes payable are reasonable estiates of their fair values. . Bonds and advances
from associated companies are reported at carng value on the Balance Sheets.
The followig table sets fort the carg value and estiated fair value of the Company's financial intrents not reported at
estimated fair value on the Balance Sheets as of December 31 (dollars in thousands):
Bonds
Advances from associated companies
Carrg
Value
$1,099,100
51,547
2010
Estiated
Fair Value
$1,139,765
37,114
Carg
Value
$1,072,100
51,547
2009.
Estiated
Fair Value
$1,079,857
43,534
These estimates of fair value were primarly based on available market information.
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. U.S. GAA defines a
fair value hierarchy that prioritizes the inputs used to measur 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
IFERC FORM NO.1 (ED. 12-88)Page 123.19
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/15/2011 2010/Q4
NOTES TO FINACIAL STATEMENTS (Continued)
measurement).
The thee levels of the fair value hierarchy are defied as follows:
Level 1 - Quoted prices are avaiable in active markets for identical assets or liabilties. Active markets are those in which
tranactions for the asset or liability occur with suffcient frequency and volume to provide pricing informtion on an ongoing
basis.
Level 2 - Pricing inputs are other th quoted prices in active markets included in Level 1, which are either directly or
indirectly observable as of the reportg date. Level 2 includes those ficial intrents tht are valued using models or
other valuation methodologies. These models are prily industr-stadard models tht consider varous assumptions,
including quoted forward prices for commodities, time value, volatiity factors, and curent market and contrctual prices for
the underlying intrents, as well as other relevant economic measures. Substatially all of these assumptions are
observable in the marketplace thoughout the full term of the intrent, can be derived from observable data or are
supported by observable levels at which transactions are executed in the marketplace.
Level 3 - Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may
be used with internally developed methodologies tht 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 signficance 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 with the fair value hierarchy levels. The
determnation of the fair values incorporates varous factors tht not only include the credit stadig of the counterpares involved and
the impact of credit enhancements (such as cash deposits and lettrs of credit), but alo the imact of Avista Corp.'s nonpedormnce
risk on its liabilities.
The following table discloses by level with the fair value hierarchy the Company's assets and liabilities measured and reported on the
Balance Sheets as of December 31,2010 and 2009 at fair value on a reurg basis (dollars in thousands):
Counterpar
Levell Level 2 Level 3 Nettg (1) Total
December 31,2010
Assets:
Energy commodity derivatives $$15,124 $19,739 $(17,010)$17,853
Interest rate swaps 127 127
Foreign curency derivatives 116 116
Deferred compensation assets:
Fixed income securities (3)1,854 1,854
Equity securities (3)6,211 --6,211--
Total ~$15,367 $19,739 $07,010)$26.161
Liabilties:
Energy commodity derivatives $$93,198 $6,280 $(17,010)$82,468
Interest rate swaps -~--2--
Total $ -$93,251 ~$07,010)$82.521
December 31, 2009
Assets:
Energy commodity derivatives $$11,898 $57,276 $(15,934)$ 53,240
Dererred compensation a~ets:
Fixed income securties (3)2,011 2,011
Equity securties (3)5,863 --5,863--
Total ll $11.898 $57,276 $05,934)$61. 14
Liabilties:
Energy commodity derivatives $$27,086 $7,806 $(15,934)$18,958
Foreign currency derivatives --2 --2--
Total ~$27.136 ~$05.934)$19.008
I FERC FORM NO.1 (ED. 12-88)Page 123.20
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
(I) The Company is permitted to net derivative assets and derivative liabilties when a legally enforceable master nettg
agreement exists.
A vista Corp. enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or durng a specified
period, in the future. These contracts are entered into as part of Avista Corp.'s management ofloads and resources and certin
contracts are considered derivative instrments. The difference between the amount of derivative assets and liabilties disclosed in
respective levels and the amount of derivative assets and liabilties disclosed on the Balance Sheets is due to nettng arngements with
certin counterparies. The Company uses quoted maket prices and forward price cures to estiate the fair value of utility derivative
commodity instrents included in Level 2. In partcular, electrc derivative valuations are performed using broker quotes, adjusted
for periods in between quotable periods. Natul gas derivative valuations are estiate using New York Mercantile Exchage
(NMEX) pricing for simlar intrents, 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. The Cómpany also has certin
contracts that, primarily due to the lengt of the respective contract, require the use of intelly developed forward price estimates,
which include significant inputs that may not be observable or corroborated in the market. These derivative contracts are included in
Level 3. Refer to Note 5 for fuer discussion of the Company's energy commodity derivative assets and liabilities.
Deferred compensation assets and liabilities represent fuds held by the Company in a Rabbi Trut for an Executive Deferral Plan.
These fuds 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 $1.2 milion as of December 3 I, 20 i 0 and $ i .6 milion as of December 31, 2009.
The following table presents activity for energy commodity derivative assets and (liabilities) measured at fair value using significant
unobservable inputs (Level 3) for the years ended December 31 (dollars in thousands):
Balance as of Januaiy I
Total gains or losses (realized/unealized):
Included in net income
Included in other comprehensive income
Included in regulatoiy assets/liabilities (1)
Purchases, issuances, and settlements, net
Transfers to other categories
Ending balance as of December 31
Assets
2010 2009
$57,276 $68,047
Liabilties
2010 2009
$(7,806) $(16,085)
(34,943)
(2,594)
(7,202)
(3,569)
1,209
317
7,747
532
$19.739 $57,276 $(6,280)$(7.806)
(I) The WUC and the IPUC issued accountig orders authorizing A vista Corp. to offset commodity derivative assets or liabilities
with a regulatoiy asset or liabilty. This accountig treatment is intended to defer the recogntion of mark-ta-market gains and losses
on energy commodity transactions until the period of settlement. The orders provide for A vista Corp. to not recogne the unealized
gain or loss on utility derivative commodity intrents in the Statements ofIncome. Realized gain or lossès are recognzed in the
period of settlement, subject to approval for recoveiy thQugh retail rates. Realized gains and losses, subject to reguatoiy approval,
result in adjustments to retail rates though purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idao,
and periodic general rates cases.
NOTE 19. 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 curent
market value.
The payment of dividends on common stock is restrcted by provisions of certin covenants applicable to preferred stock contained in
the Company's Arcles of Incorporation, as amended.
In August 2010, the Company entered into an amended and restated sales agency agreement with a sales agent to issue up to 3,087,500
shares of its common stock from time to time. The Company origially entered into a sales agency agreement to issue up to 1,250,000
shares of its common stock in December 2009. Shares issued under sales agency agreements were as follows in the years ended
December 31 :
2010 2009
I FERC 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 0415/2011 2010/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Shares issued under sales agency agreement 2,054,110
NOTE 20. STOCK COMPENSATION PLANS
1998 Plan
In 1998, the Company adopted, and shaeholders approved, the Long-Term Incentive Plan (1998 Plan). Under the i 998 Plan, certain
key employees, offcers and non-employee diectors of the Company and its subsidiares may be granted stock options, stock
appreciation nghts, stock awards (including restrcted stock) an other stock-based awards and dividend equivalent nghts. In May
2010, the Company's shareholders approved an additiona 1 millon shares of Company common stock to be made available for grant
under ths plan. However, as of December 31, 20 i 0, the Company ha not received approvals from regulatory agencies to add these I
million share to the 1998 plan. The Company ha available a maum of 3.5 millon shaes of its common stock for grant under the
1998 Plan. As of December 31,2010,0.5 millon shes were remaing for grant under ths plan.
2000 Plan
In 2000, the Company adopted a Non-Offcer 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 offcers of the Company. The Company has available a maximum of2.5 milion
shares of its common stock for grant under the 2000 Plan. However, the Company curently does not plan to issue any fuer options
or securities under the 2000 Plan. As of December 3 I, 20 I 0, 1.9 millon shares were remaining for grant under this plan.
Stock Compensation
The Company records compensation cost relating to share-based payment tranactions in the ficial statements based on the fair
value of the equity or liability intrents issued. The Company recorded stock-based compensation expense (included in other
operatig expenses) and income ta benefits in the Statements ofIncome of the followig amounts for the years ended December 3 I
(dollars in thousands):
Stock-based compensation expense
Income ta benefits
2010
$4,916
1,720
2009
$2,906
1,017
Stock Options
The followig sumanzes stock options activity under the 1998 Plan and the 2000 Plan for the years ended December 31:
2010 2009
748,673
Number of shares under stock options:
Options outstanding at beging of yea
Options granted
Options exercised
Options canceled
Options outstanding and exercisable at end of year
Weighted average èxercise pnce:
Options exercised
Options canceled
Options outstanding and exercisable at end of year
Cash received from options exercised (in thousands)
Intrnsic value of options exercised (in thousands)
Intrinsic value of options outstading (in thousands)
523,973
(101,649)
(220,650)
201.674
$ 11.51
$22.60
$11.53
$2,179
$1,006
$2,217
Informtion for options outstading and exercisable as of December 31, 2010 is as follows:
Range of NumberExercise Pnces of Shares
$10.17-$12.41 186,674
I FERC FORM NO.1 (ED. 12-88)
Weighted
Average
Exercise
Pnce
$10.97
Weighted
Average
Remaing
Life (in year)
1.4
Page 123.22
(200,225)
(24,475)
523,973
$13.83
$22.69
$16.30
$2,770
$1,180
$2,774
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
$ 1 5.88-$ 1 9.34
$20.11-$23.00
Total
6,000
9,000
201.674
15.88
20.11
$11.53
1.4
0.4
1.4
As of December 31,2010 and 2009, the Company's stock options were fully vested and expensed.
Restricted Shares
Restrcted shares vest in equal thrds each year over a thee-year period and are payable in Avista Corp. common stock at the end of
each year if the servce condition is met. In addition to the servce condition, the Company must meet a retu on equity taget in
order for the CEO's restrcted shares to vest. Durg the vestig period, employees are entitled to dividend equivalents which are paid
when dividends on the Company's common stock are declared. Restrcted stock is valued at the close of market of the Company's
common stock on the grant date. The weighted average remaining vestig period for the Company's restrcted shares outstading as
of December 31, 2010 was 1.3 years. The followig table sumzes restrcte stock activity for the year ended December 31:
Unvested shares at begining of year
Shares granted
Shares cancelled
Shares vested
Unvested shares at end of year
Weighted average fair value at grant date
Unrecognized compensation expense at end of year (in thousads)
Intrnsic value, unvested shares at end of year (in thousands)
Intrnsic value, shares vested during the year (in thousands)
2010
71,904
43,800
(31,570)
84,134
$19.80
$735
$1,895
$682
2009
55,939
44,400
(10,000)
(18,435)
71.904
$18.18
$668
$1,552
$345
Performance Shares
Performance share grants have vesting periods of thee year. Performance awards entitle the recipients to dividend equivalent rights,
are subject to forfeiture under certin circumtaces, and are subject to meetig specific performance conditions. Based on the
attinment of the performce condition, the amount of cash paid or common stock issued will range from 0 to 150 percent of the
performance shares granted 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 shaes tht eventully vest.
Performance share awards entitle the grantee to shaes of common stock or cash payable once the servce condition is satisfied. Based
on attinment of the performance condition, grtees may reeive 0 to 150 percent of the origial shares granted. The performce
condition used is the Company's Total Shareholder Retu performance over a thee-year period as compared againt other utiities;
this is considered a market-based condition. Performance shares may be setted 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 contiue ths practice. These
awards vest at the end of the thee-year period. Performance shares are equity awads with a market-based condition, which results in
the compensation cost for these awards being recognized over the requisite servce 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 granted. 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
tagets based on historical returns relative to a peer group. Expected volatility was based on the historical volatility of Avista Corp.
common stock over a thee-year period. The expected term of the performance shares is the years based on the performance cycle.
The risk-free interest rate was based on the U.S. Treasur yield at the time of grant. The compensation expense on these awards will
only be adjusted for changes in forfeitures.
The following summarizes the weighted average assumptions used to determe the fair value of performance shares and related
compensation expense as well as the resulting estimated fair value of performance shares grnted:
Risk-free interest rate
Expected life, in years
Expected volatility
Dividend yield
IFERC FORM NO.1 (ED. 12-88)
2010
1.4%
3
27.8%
4.6%
Page 123.23
2009
1.%
3
25.8%
3,6%
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation '2)A Resubmission 04115/2011 2010/04
NOTES TO FINACIAL STATEMENTS (Continued)
Weighted average grant date fair value (per shae)$15.30 $17.22
The fair value includes both performance shaes and dividend equivalent rights.
The following sumarzes performce shae activity:2010 2009
Openig balance ofunvested performance shares 300,601 252,923Performance shaes granted 168,700 163,900Performance shares canceled (43,758)
Performance shares vested (143,601) (72,464)
Ending balance of unvested performance shaes 325,700 300,601
Intric value ofunvested performce shaes (in thousands) $7,335 $6,490
Unrecognzed compensation expense (in thousds) $2,330 $2,453
The weighted average remaing vestig period for the Company's performance shares outstading as of December 31, 2010 was 1.5
years. Unrecogned compensation expense as of December 31, 2010 will be recogned durg 201 1 and 2012. The followig
sumares the impact of the maket condition on the vested performce shaes:
2010 2009Performance shares vested 143,601 72,464
Impact of market condition on shares vested 21,540 (72,464)
Shares of common stock earned 165,141 =
Intrinsic value of common stock earned (in thousands) $3,719 $
Shares earned under this plan are distrbuted to paricipants in the quarer followig vestig.
Awards outstanding under the performce share grants 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 takig into
account the number of awards outstanding, historical dividend rate, and the chage in the value of the Company's common stock
relative to an external benchmark. Over the life of these awads, the cumulative amount of compensation expense recognzed will
match the acnial cash paid. As of December 3 i, 20 i 0 and 2009, the Company had recognzed compensation expense and a liability of
$0.9 millon and $0.4 millon related to the dividend component of performance she grants.
NOTE 21. COMMITMENTS AND CONTINGENCIES
In the course of its business, the Company becomes involved in varous clai, controversies, disputes and other contigent matters,
including the items described in ths Note. Some of these claim, controversies, diputes and other contigent 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 assurce can be given as to the ultiate outcome of any parcular matter because litigation and other
contested proceedigs are inerently subject to numerous uncertinties. After consultation with legal counel, the Company accrues a
loss contigency if it is probable that an asset is impaired or a liabilty ha been incured and the amount of the loss or impairent can
be reasonably estimated. For matters tht affect Avista Corp.'s operations, the Company intends to seek, to the extent appropriate,
recovery of incured costs though the ratemag process.
Federal Energy Regulatory Commission Inquiry
In April 2004, the Federal Energy Regulatory Commssion (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 imroper
trading strategy durg 2000 and 2001; (2) no evidence that Avista Corp. or Avista Energy engaged in any efforts to manipulate the
western energy makets durg 2000 and 2001; and (3) no fiding that Avista Corp. or Avista Energy witheld 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 Californa Electrcity Oversight Board, Californa Paries and the City of Tacoma, Washington
challenged the FERC's decisions approvig the Agreement in Resolution, which are now pending before the United States Cour 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 certin bids above
$250 per MW in the short-term energy makets operated by the Californa Independent System Operator (CalISO) and the Californa
I FERC FORM NO.1 (ED. 12-88) Page 123.24
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(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
Power Exchange (CaIPX) from May 1,2000 to October 2,2000 (Bidding Investigation). Tht matter is also pending before the Ninth
Circuit, after the California AG, Pacific Gas & Electrc (pG&E), Southern Californa Edson Company (SCE) and the Californa
Public Utilities Commission (CPUC) filed petitions for review in 2005.
Based on the FERC's order approvig the Agreement in Resolution and the FERC's denal of rehearg requests, the Company does
not expect tht this proceeding will have any material adverse effect on its fiancial condition, results of operations or cash flows.
Furermore, based on information curently known to the Company regarding the Bidding Investigation and the fact that the FERC
Staff did not fmd any evidence of manipulative behavior, the Company does not expect that this matter will have a material adverse
effect on its financial condition, results of operations or cash flows.
California Refund Proceeding
In July 2001, the FERC ordered an evidentiar 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 CalPX durng the period from October 2,2000 to June 20, 2001
(Refund Period). Proposed refuds are based on the calculation of mitigated market clearg 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 fiing claim
pursuant to the FERC's August 2005 order. That filing was accepted in orders issued by the FERC in January 2006 and November
2006. In June 2009, the FERC reversed, in par its previous decision and ordered a compliance filing requiring an adjustment to the
retu on investment component of A vista Energy's cost fiing. That compliance filing was made in July 2009. In March 2010, the
California AG, the CPUC, PG&E, and SCE filed a protest and comments on Avista Energy's compliance fiing. In April 2010, Avista
Energy filed a response and corrected a technical error from its July 2009 fiing. The correction increased its cost filing claim. The
California AG, CPUC, PG&E and SCE filed an anwer and protest to ths filing in April 2010, which Avista Energy answered in June
2010. In July 2010, the same paries again opposed Avista Energy's cost filing, and Avista Energy anwered that protest. The revised
compliance filing is pending before the FERC.
The CalISO continues to work on its compliance filing for the Refud Period, which will show ''wo owes what to whom." In April
2010 and May 20 I 0, the CalISO and CaIPX, respectively, filed update compliance report concerning preparatory re-ru activity.
The CalPX filing requested guidace from the FERC on issues related to completig the fil determation of "who owes what to
whom." The CalPX supplemented its compliance filing in October 2010. In June 2010, Avista Energy filed comments with the FERC
askig the FERC to assist the partes in briging ths mattr to a close by expeditiously: 1) approvig the compliance filings made by
the CalI SO and the CalPX; 2) ruling on the outstading issues presented by the CalX; and 3) settg milestones for next steps
regarding the fial compliance filing.
In July 2010, the CalISO filed its 45th status report on the California recalculation process confirming that the calculations related to
fuel cost allowance offsets and emission offsets are complete, and identifyng several open issues related to the refund rerun
calculations that need to be resolved by the FERC. The CalISO states that it will need to revise certin calculations related to
cost-recovery offsets and interest calculations. In addition, the CalISO stated that it is in the process of making adjustments to the
CalISO data to remove refunds associated with sales made by non-jursdictional entities. The CalISO also says that it will need to
work with parties to the various global settlements to make appropriate adjustments to the CalISO's data in order to properly reflect
those adjustments. In a March 2010 fiing, the CalI SO stated that it does not intend to make any compliance fiing until, inter alia, the
FERC resolves issues related to the Ninth Circuit's remand regarding possible remedies for alleged taff violations pursuant to Federal
Power Act (FPA) section 309, prior to the refund effective date in ths proceeding (discussed below).
The 2001 bankptcy ofPG&E resulted in a default on its payment obligations to the CalPX. As a result, Avista Energy has not been
paid for all of its energy sales durng the Refund Period. Those fuds are now in escrow accounts and will not be released until the
FERC issues an order directing such release in the Californa refud proceeding. As of December 3 t, 2010, Avista Energy's accounts
receivable outstanding related to defaulting partes in Californa were fully offet by reserves for uncollected amounts and fuds
collected from the defaulting parties.
Many of the orders that the FERC has issued in the California refud proceedings were appealed to the Ninth Circuit. In October
2004, the Ninth Circuit ordered that briefing proceed in two rounds. The fist round was limted to thee issues: (1) which paries are
subject to the FERC's refud jursdiction in light of the exemption for governent-owned utilities in section 201(t) of the FPA; (2) the
temporal scope of refunds under section 206 of the FP A; and (3) which categories of tranactions ar subject to refuds. The second
round of issues and their corresponding briefig schedules have Dot yet been set by the Ninth Circuit.
I FERC FORM NO.1 (ED. 12-88)Page 123.25
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(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/15/2011 2010104
NOTES TO FINACIAL STATEMENTS (Continued)
In September 2005, the Ninth Circuit held tht the FERC did not have the authority to order refuds for sales made by municipal
utilities in the Californa refund proceeding. In Augut 2006, the Ninth Circuit upheld October 2,2000 as the refund effective date for
the FP A section 206 refud proceeding, but remanded to the FERC its decision not to consider an FP A section 309 remedy for tarff
violations prior to that date. Petitions for rehearg were denied in April 2009. In July 2009, Avista Energy and Avista Corp. filed a
motion at the FERC, askig that the companies be dismised from any fuer proceedings arsing under section 309 pursuant to the
remand. The filing pointed out tht section 309 relief is based on taff violations of the seller, and as to Avista Energy and Avista
Corp., these allegations had already been fully adjudicated in the proceedig tht gave rise to the Agreement in Resolution, discussed
above. There, the FERC absolved both companes of all allegations of market mapulation or wrongdoing that would justify or
permit FPA sections 206 or 309 remedies dung 2000 and 2001. In November 2009, the FERC issued an order establishig an
evidentiar hearg before an admtrative law judge to address the issues remanded by the Ninth Circuit without addressing the
Company's pending motion. In December 2009, the Company again brought the issue to the FERC's attention but its motion remain
pending, as do a number of rehearg requests regarding the November 2009 hearg order. In September 2010, the FERC issued a
"Supplemental Order Solicitig Comments" on the scope of the hearg. The Company responded in filings made on September 22,
2010 and October 6, 20l0,'and the pares are awaitig fuer ruings by the FERC before the hearing commences.
Because the resolution of the California refud proceeding remain uncertin, legal counel canot express an opinion on the extent of
the Company's liability, if any. However, based on inormtion curently known, the Company does not expect that the refuds
ultimtely ordered for the Refud Period will have a material adverse effect on its fiancial condition, results of operations or cash
flows. This is priarly due to the fact tht the FERC orders have stated tht any refuds will be netted against unpaid amounts owed
to the respective pares and the Company does not believe that refuds would exceed unpaid amounts owed to the Company.
Pacifc Northwest Refund Proceeding
In July 2001, the FERC intiated a prelimar evidentiar hearg to develop a factual record as to whether prices for spot market
sales of wholesale energy in the Pacific Nortwest betwen December 25,2000 and June 20, 2001 were just and reasonable. In June
2003, the FERC terminated the Pacific Nortwest refund proceedings, after finding that the equities do not justify the imposition of
refuds. In August 2007, the Ninth Circuit found tht the FERC, in denyig the request for refunds, had failed to take into account
new evidence of market manipulation in the Californa energy market and its potential ties to the Pacific Nortwest energy market and
that such failure was aritrar 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 tht the FERC abused its discretion in denying
potential relief for transactions involving energy that was purchaed by the Californa Deparent of Water Resources (CERS) in the
Pacific Nortwest and ultiately consumed in Californa. The Ninth Circuit expressly declined to direct the FERC to grant refuds.
Requests by varous pares for rehearg on ths ruing were dened in April 2009.
In May 2009, the Californa AG fied a complaint againt both Avista Energy and Avista Corp. seekig refunds on sales made to
CERS dung the period Januar 18, 2001 to June 20,2001 under section 309 of the FPA (the Brown Complaint). The sales at issue
are limted: in scope and are duplicative of clai alrady at issue in the Pacific Nortwest proceeding, discussed above. In Augut
2009, the City of Tacoma and the Port of Seattle fied a motion askig the FERC to sumarly re-price sales of energy in the Pacific
Nortwest dung 2000 and 2001. In October 2009, Avista Corp. fied, as par of the Tranaction Finlity Group, an anwer to that
motion and, in addition, made its own recommendations for fuer proceedigs in ths docket. Those pleadings are pending before the
FERC.
Both Avista Corp. and Avista Energy were buyers and sellers of energy in the Pacific Nortwest energy maket durng the period
between December 25,2000 and June 20,2001 and, ifrefuds were ordered by the FERC, could be liable to make payments, but also
could be entitled to receive refuds from other FERC-jursdictional entities. The opportty to make claim against entities not
subject to the FERC's jursdiction may be limted based on existig law. The Company canot predict the outcome of this proceeding
or the amount of any refuds tht A vista Corp. or A vista Energy could be ordered to mae or could be entitled to receive. Therefore,
the Company canot predict the potential impact the outcome of ths matter could ultiately 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 Californa. The
complaint alleged that the FERC's adoption and implementation of market-based rate authority was flawed and, as a result, individual
sellers should refud the difference between the rate charged and a just and reasonable rate. In May 2002, the FERC issued an order
dismissing the complaint but dircting sellers to re-fie certin tranaction sumes. It was not clear that Avista Corp. and its
IFERC FORM NO.1 (ED. 12-88) Page 123.26
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(1 ) ó. An Original (Mo, Da, Yr)
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NOTES TO FINANCIAL STATEMENTS (Continued)
subsidiaries were subject to ths directive but the Company took the conservtive approach an re-filed certin tranactior¡ suaries
in June and July of 2002. In September 2004, the Ninth Circuit upheld the FERC's market-based rate authority, but held tht the
FERC erred in ruling that it lacked authority to order refuds for violations of its reporting requirment. The Cour remaded the case
for furter proceedings, but did not order any refuds, leavig it to the FERC to consider appropriate remedial options.
In March 2008, the FERC issued an order establishig a tral-tye hearng to address "whether any individual public utility seller's
violation of the FERC's market-based rate quarerly reportg requirment led to an unjust and uneasonable rate for that particular
seller in California durng the 2000-2001 period." Purchasers in the California markets will be allowed to present evidence that "any
seller that violated the quarterly reportng requirement failed to disclose an increased market share suffcient to give it the ability to
exercise market power and thus cause its market-based rates to be unjust and uneasonable." In particular, the parties were directed to
address whether the seller at any point reached a 20 percent generation market share theshold, and if the seller did reach a 20 percent
market share, whether other factors were present to indicate that the seller did not have the ability to exercise market power. The
California AG, CPUC, PG&E, and SCE filed their testimony in July 2009. Avista Corp. and Avista Energy's answering testimony was
fied in September 2009. On the same day, the FERC staff fied its answering testimony takig the position tht, using the test the
FERC directed to be applied in this proceeding, neither Avista Corp. nor Avista Energy had market power for the period in question.
Cross answering testimony and rebuttl testimony were filed in Novemb~r 2009. In Januar 2010, A vista Corp. and A vista Energy
fied a motion for summary disposition, as did other paries to the proceeding. In March 2010, the Presiding Administrative Law
Judge (AU) granted the motions for sumar disposition and found that a hearg was ''uecessar' because the Californa AG,
CPUC, PG&E and SCE "failed to apply the appropriate test to determine market power durg the relevant time period." The judge
determned that "( w Jithout a proper showig of maket power, the Californa Pares failed to establish a pria facie case." Briefs on
exceptions were filed in April 2010 and briefs opposing exceptions were filed in May 2010.
Based on information currently known to the Company's management, the fact tht neither Avista Corp. nor Avista Energy ever
reached a 20 percent generation market share durg 2000 or 2001 and the AI's grantig of Avista Corp. and Avista Energy's
sumary disposition motion, the Company does not expect tht ths matter will have a material adverse effect on its financial
condition, results of operations or cash flows.
Colstrip Generating Project Complaint
In March 2007, two famlies that own propert nea the holdig ponds from Units 3 & 4 of the Colstrp Generating Project (Colstrp)
fied a complaint against the owners of Colstrp and Hydrometrcs, Inc. in Montaa Distrct Cour. Avista Corp. owns a 15 percent
interest in Units 3 & 4 of Colstrp. The plaintiffs allege that the holding ponds and remediation activities have adversely impacted
their propert. They allege contamination, decrease in water tables, reduced flow of stream on their propert and other similar
impacts to their propert. They also seek puntive damges, attorney's fees, an order by the cour to remove certin ponds, and the
forfeitue of profits earned from the generation of Colstrp. In September 20 i 0, the owners of Colstrp filed a motion with the cour to
enforce a settlement agreement that would resolve all issues between the parties. Under the settlement, Avista Corp.'s porton of
payment (which was accrued in the second quarer of 201 0) to the plaintiffs was not material to its financial condition, results of
operations or cash flows. The plaintiffs have indicated that they wil contest the existence of any settlement, and will file a response to
the motion, with the matter to be decided by the cour. Although the fial resolution of ths complaint remains uncertin, based on
information curently known to the Company's management, the Company does not expect ths complaint will have a material adverse
effect on its financial condition, results of operations or cash flows.
Harbor Oil Inc. Site
A vista Corp. used Harbor Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB trformer oil in the late 1980s and early
i 990s. In June 2005, the Environmental Protection Agency (EPA) Region 10 provided notification to A vista Corp. and several other
paries, as customers of Harbor Oil, that the EPA had determed that hadous substaces were released at the Harbor Oil site in
Portland, Oregon and that A vista Corp. and several other paries may be liable for investigation and cleanup of the site under the
Comprehensive Environmental Response, Compensation, and Liabilty Act, commonly referred to as the federal "Superfd" law,
which provides for joint and several liabilty. The intial indication frm the EPA is that the site may be contaminated with PCBs,
petroleum hydrocarbons, chlorinated solvents and heavy metals. Six potentially responsible pares, including Avista Corp., signed an
Administrative Order on Consent with the EPA on May 3 i, 2007 to conduct a remedial investigation and feasibility study (RIS),
which is expected to be fialized in the fist half of 20 i i. The actul cleanup, if any, will not occur until the RIIFS is complete. Based
on the review of its records related to Harbor Oil, the Company does not believe it is a major contrbutor to this potential
environmental contamination based on the small volume of waste oil it delivered to the Harbor Oil site. However, there is currently
not enough information to allow the Company to assess the probabilty or amount of a liability, if any, being incured. The Company
IFERC FORM NO.1 (ED. 12-88) Page 123.27
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation /2) A Resubmission 04115/2011 2010/04
NOTES TO FINACIAL STATEMENTS (Continued)
has accrued its shae of the RIS ($0.5 millon) for'ths matter.
Spokane River Licensing
The Company own and operates six hydroelectrc plants on the Spokae River. Five of these (Long Lae, Nine Mile, Upper Falls,
Monroe Street, and Post Falls) are under one FERC license and are referred to as the Spokae River Project. The sixth, Little Falls, is
operated under separate Congressional authority and is not licensed by the FERC. The FERC issued a new 50-year license for the
Spokae River Project in June 2009. The license incorporated the 4(e) conditions tht were included in the December 2008
Settlement Agreement with the United States Deparent 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 Washigton 401 Water Quality Certification.
As par of the Settlement Agreement with the Washigton Deparent of Ecology (DOE), the Company paricipated in the Total
Maximum Daily Load (TMDL) process for the Spokae River and Lake Spokae, the reservoir created by Long Lake Dam. On May
20,2010, the EPA approved the TMDL and on May 27,2010, the DOE fied an amended 401 Water Quality Certfication with the
FERC for inclusion into the license. The amended 401 Water Quality Certfication includes the Company's level of responsibility, as
defined in the TMDL, for low dissolved oxygen levels in La Spokae. The Company has until May 27,2012 to develop mitigation
strategies to address the low levels of dissolved oxygen. It is not possible to provide cost estites at ths tie because the mitigation
measures have not been fully identified or approved by the DOE. On July 16,2010, the City of Post Falls and the Hayden Area
Regional Sewer Board filed an appeal with the United States Distrct Cour for the Distrct ofIdao with respect to the EPA's
approval of the TMDL. The Company, the City of Coeur d'Alene, Kaiser Alumum and the Spokae River Keeper subsequently
moved to intervene in the appeaL. The EPA, the City of Post F als and the Hayden Area Regional Sewer Board are curently in
settlement negotiations in an attempt to resolve the appeaL.
The Company is implementing the envionmenta and operationa conditions required in the license for the Spokae River Project.
The estimated cost to implement the license conditions, which is the result of more than a dozen separate settements, is $334 millon
over the 50-year license term. This will increase the Spokae River Project's cost of power by about 40 percent, while decreasing
anual generation by approximately one-half of one percent. Costs to imlement mitigation measures related to the TMDL are not
included in these cost estimates. The IPUC and the WUTC approved the recovery of licensing costs though the general rate case
settlements in 2009. The Company will continue to seek recovery, though the ratemakg process, of all operating and capitalized
costs related to implementing the license for the Spokane River Project.
Cabinet Gorge Total Dissolved Gas Abatement Plan
Dissolved atmospheric gas levels in the Clark Fork River exceed state ofIdao and federal water quality standards downtream of the
Cabinet Gorge Hydroelectrc Generatig Project (Cabinet Gorge) durg periods when excess river flows must be diverted over the
spilway. In 2002, the Company submitted a Gas Supersatuation Control Program (GSCP) to the Idao Deparent of Environmental
Quality (Idaho DEQ) and U.S. Fish and Wildlife Servce (USFWS). Th submission was par of the Clark Fork Settlement Agreement
for licensing the use of Cabinet Gorge. The GSCP provided for the openig and modification of possibly two diversion tuels around
Cabinet Gorge to allow streamflow to be diverted when flows are in excess of powerhouse capacity. In 2007, engineering studies
determned that the tuels would not suffciently reduce Total Dissolved Gas (TDG). In consultation with the Idaho DEQ and the
USFWS, the Company developed an addendum to the GSCP. The GSCP addendum abandons the concept to reopen the two diversion
tuels and requires the Company to evaluate a varety of different options to abate TOG over the next several years. In March 2010,
the FERC approved the GSCP addendum ofpreliiar design for alternative abatement measures. In May 2010, the Company
intiated prelimin feasibility assessments for several alterntive abatement measures, the results of which are anticipated in March
201 i. The Company will contiue to seek recovery, though the ratemag process, of all operating and capitalized costs related to
ths issue.
Fish Passage at Cabinet Gorge and Noxon Rapids
In 1999, the USFWS listed bull trout as theatened under the Endagered Species Act. The Clark Fork Settlement Agreement
describes program intended to help restore bull trout populations in the project area. Using the concept of adaptive management and
workig closely with the USFWS, the Company is evaluatig the feasibilty of fish passage at Cabinet Gorge and Noxon Rapids. The
results of these studies will help the Company and other pares determine the best use of fuds toward continuing fish passage effort
or other bull trout population enhancement measures. In the fall of 2009, the Company selected a contractor to design a permanent
upstream passage facility at Cabinet Gorge. The Company anticipates that the design and cost estimates will be completed by the end
of2011.
In Januar 20 i 0, the USFWS proposed to revise its 2005 designtion of critical habitat for the bull trout. The proposed revisions
IFERC FORM NO.1 (ED. 12-88)Page 123.28
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(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010/04
NOTES TO FINANCIAL STATEMENTS (Continued)
include the lower Clark Fork River as critical habitat. In April 2010, the Company submittd comments recommending the lower
Clark Fork River be excluded from critical habitat designation based in par on the extensive bull trout recovery effort the Company is
already undertking. The Company will contiue to seek recovery, though the ratemakig process, of all operatig and capitalized
costs related to fish passage at Cabinet Gorge and Noxon Rapids.
Aluminum Recycling Site
In October 2009, the Company (though its subsidiar Pentzer Ventue Holdings II, Inc. (pentzer)) received notice from the DOE
proposing to find Pentzer liable for a release of hazardous substaces under the Model Toxics Control Act, under Washington state
law. Pentzer own propert that adjoins land owned by the Union Pacific Railroad (UR). UPR leased their propert to operators of a
facility designated by DOE as "Aluminum Recycling - Trentwood." Operators of the UPR propert maintained piles of aluminum
"black dross," which can be designated as a state-only dangerous waste in Washigton State. In the coure of its business, the
operators placed a portion of the aluminum dross pile on the propert owned by Pentzer. Pentzer does not believe it is a contributor to
any envionmental contamination associated with the dross pile, and submitted a response to the DOE's proposed fidings in
November 2009. In December 2009, Pentzer received notice from the DOE tht it had been designated as a potentially liable par for
any hazardous substances located on this site. UPR complete a RIS Work Plan in June 2010. At that time, UPR requested a
con.trbutionfrom Pentzer towards the cost of performg the RIS and also an access agreement to investigate the material deposited
on the Pentzer propert. Pentzer concluded an access agreement with UPR in October 2010. UPR commenced the remedial
investigation durng the four quarter of2010, which is expected to be completed in 2011. There is curently not enough information
to allow the Company to ass~ss the probability or amount of a liability, if any, being incured.
Injury from Overhead Electric Line (Munderloh v. Avista)
On March 4, 2010, the plaintiff and his wife filed a complaint againt A vista Corp. in Spokae County Superior Cour. Plaintiffs
allege that while the plaintiff was employed by a thd par as a laborer at their constrction site, he came into contact with Avista
Corp.'s electrc line, was injured and suffered economic and non-economic dages. Plaintiff fuer allege that A vista Corp. was at
fault for failng to relocate the overhead electrc line whch it controlled and operated adjacent to the constrction site. In addition to
economic and non-economic damages, plaintiffs also seek damages for loss of consortium, attorney's fees and costs, prejudgment
interest and punitive damages. Trial has been scheduled to begi in September 2011. The case is in the early stage of discovery and
plaintiffs have not yet provided a statement specifyng damages. Because the resolutioñ of ths claim remains uncertin, legal counsel
cannot express an opinion on the extent, ifany, of the Company's liabilty. However, based on information currently known to the
Company's management, the Company does not expect ths complaint will have a material adverse effect on its financial condition,
results of operations or cash flows.
Natural Gas Line Safety Complaint
In June 2010, the WUTC staff fied a complaint against the Company related to a natual gas explosion and fire that occurred in
Odessa, Washington in December 2008 that injured two people. The WUC staffalleges certin violations related to the installation
of the low pressure natural gas distrbution line, as well as the removal of the line following the explosion and fire. The WUTC staff
made recommendations of fines that could exceed $ 1.1 millon and that the Company implement certin measures to ensure
compliance with WUTC laws and rules. In Januar 2011, the Company fied a settement agreement with the WUC that was
approved by the WUTC in Februar 2011, and resolved all issues in ths matter. As par of the settlement agreement, the Company
accrued a fine of$0.2 milion. In the four quarter of 2010, the Company reached separate legal settlement with the injured
individuals in an amount that was not material to the Company's ficial condition, results of operations or cash flows.
Damagesfrom Fire in Stevens County, Washingtn
In August 20 i 0, a fie in Stevens County, Washigton occured durg a wid storm. The apparent cause of the fie may be a tree
located outside of A vista Corp.' s right-of-way that came in contact with an electrc line owned by A vista Corp. The fire area is a rual
farm and timber landscape. The fie destroyed two residences and six outbuildings. The Company is not aware of any personal
injures resulting from the fire. Although no lawsuits have: bee fied, Avista Corp. ha received several claims and it is possible that
additional claims may be made and lawsuits may be filed agait the Company. Because the resolution of ths issue remains uncertin,
legal counsel cannot express an opinon on the extent, ifany, of the Company's liabilty. However, based on information curently
known to the Company's management, the Company does not expect ths complaint will have a material adverse effect on its financial
condition, results of operations or cash flows.
Collective Bargaining Agreements
The Company's collective bargainig agreement with the International Brotherhood of Electrcal 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
IFERC FORM NO.1 (ED. 12-88)Page 123.29
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(1) ~ An Original (Mo, Oa, Yr)
Avista Corporation (2) A Resubmission 04/15/2011 2010104
NOTES TO FINACIAL STATEMENTS (Continued)
(approximately 90 percent) of the bargaing unt employees expired on March 26, 2010. A new agreement was reached in October
2010 (expirg in March 2014). Two local agreements in Oregon, whch cover approxitely 50 employees, expired in April20io.
New agreements were reached in December 2010 (expirg in March 2014).
Other Contingencies
In the normal course of business, the Company has varous other legal claims and contingent matters outstading. The Company
believes that any ultimate liability arsing from these actions will not have a material advers 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 incured. Such a change, should it occur, could be signficant.
The Company routinely assesses, based on studies, expert analyses and legal reviews, its contingencies, obligations and commtments
for remediation of contamiated sites, including assessments of ranges and probabilities of recoveries from other responsible parties
who either have or have not agreed to a settement as well as recoveries from inurance cariers. The Company's policy is to accrue
and charge to curent expense identified exposures related to environmental remediation sites based on estimates of investigation,
cleanup and monitorig costs to be incured. For matters tht affect Avista Corp. 's operations, the Company seeks, to the extent
appropriate, recovery of incured costs though the rateing process.
The Company has potential liabilities under the Endagered Species Act for species of fish that have either already been added to the
endangered species list, listed as "theatened" or petitioned for listig. Thus far, measures adopted and implemented have had minl
impact on the Company. However, the Company will contiue to seek recovery, though the ratemakg process, of all operating and
capitalized costs related to th issue.
Under the federal licenses for its hydroelectrc projects, the Company is obligated to protect its propert rights, including water rights.
The state of Monta is examiing the statu of all water right claim with state boundares. Claim with the Clark Fork River
basin could adversely affect the energy production of the Company's Cabinet Gorge and Noxon Rapids hydroelectrc facilities. The
state of Idaho has intiated an adjudication in nortern Idao, which wil ultimately include the lower Clark Fork River, the Spokae
River and the Coeur d Alene basin. In addition, the state of Washigton has indicated its intent to initiate an adjudication for the
Spokae River basin in the next several year. The Company is and will contiue to be a participant in these adjudication processes.
The complexity of such adjudications makes each unely to be concluded in the foreseeable futue. As such, it is not possible for the
Company to estimate the impact of any outcome at ths tie.
NOTE 22. INFORMATION SERVICES CONTRACTS
The Company has information servces contrcts tht expire at varous times though 2017. The largest of these contracts provides for
increases due to changes in the cost of livig index and furter provides flexibility in the anual obligation from year-to-year subject to
a thee-year tre-up cycle. Total payments under these contracts were as follows for the years ended December 31 (dollars in
thousands):
Information servce contract payments
2010
$13,426
2009
$15,529
Minimum contractul obligations under the Company's information servces contracts are $12.8 millon in 2011, $11.8 millon in
2012, $9.3 milion in 2013, $7.5 million in 2014 and $7.0 millon in each of20l5, 2016 and 2017.
NOTE 23. REGULATORY MATTERS
Power Cost Deferrals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge on the Balance Sheets for futue review and recovery though retail
rates. The power supply costs deferred include cert differences between actual net power supply costs incured by Avista Corp. and
the costs included in base retail rates. Ths difference in net power supply costs priary results from changes in:
. short-term wholesale market prices and sales and purchase volumes,
. the level of hydroelectrc generation,
. the level of thermal generation (including changes in fuel prices), and
. retail loads.
In Washington, the Energy Recovery Mechansm (ERM) allows Avista Corp. to periodically increase or decrease electrc rates with
WUTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences
I FERC 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 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
between actual net power supply costs and the amount included in base retail rates for Washington customers. In the 20 I 0
Washigton general rate case settement, the pares agreed that there would be no deferrals under the ERM for 2010. Deferrals under
the ERM will resume in 201 i. The Company must make a filing (no sooner than June 201 i), to allow all interested paries the
opportnity to review the ERM, and make recommendations to the WUTC related to the contiuation, modification or elimination of
theERM.
The initial amount of power supply costs in excess or below the level in retail rates, which the Company either incurs the.cost of, or
receives the benefit from, is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0 millon. The
Company wil incur the cost of, or receive the benefit from, i 00 percent of this intial power supply cost varance. The Company
shares annual power supply cost varances between $4.0 millon and $ i 0.0 millon with its customers. There is a 50 percent
customers/50 percent Company sharig when actul power supply expenses are higher (sucharge to customers) than the amount
included in base retail rates within this band. There is a 75 percent customers/25 percent Company shanng when actual power supply
expenses are lower (rebate to customers) than the amount included in base retail rates with this band. To the extent that the annual
power supply cost varance from the amount included in base rates exceeds $10.0 millon, 90 percent of the cost varance is deferred
for future surcharge or rebate. The Company absorbs or receives the benefit in power supply costs of the remainng i 0 percent of the
annual varance beyond $ i 0.0 milion without affecting curent or futue customer rates.
The following is a summar of the ERM:
Anual Power Supply
Cost Varability
+/- $0 - $4 millon
+ between $4 millon - $ i 0 millon
- between $4 milion - $ i 0 million
+/- excess over $ i 0 milion
Deferred for Futue
Surchage or Rebate
to Customers
0%
50%
75%
90%
Expene or Benefit
to the Company
100%
50%
25%
10%
A vista Corp. has a Power Costs Adjustment (PCA) mechanism in Idao that allows it to modify electnc rates on October i of each
year with Idaho Public Utilities Commssion (IPUC) approvaL. Under the PCA mechanism, Avista Corp. defers 90 percent of the
difference between certin actual net power supply expenses and the amount included in base retail rates for its Idaho customers. In
June 2007, the IPUC approved continuation of the PCA mechanism with an anual rate adjustment provision. These annual October i
rate adjustments recover or rebate power costs deferred dunng the preceding July-June twelve-month period.
The following table shows activity in deferred power costs for Washington and Idaho dung 2008,2009 and 2010 (dollars in
thousands):
Washington Idaho Total
Deferred power costs as of J anuaiy i, 2009 $36,952 $20,655 $57,607
Activity from Januaiy 1 - December 31, 2009:
Power costs deferred 17,985 17,985
Interèst and other net additions 879 388 1,267
Recoveiy of deferred power costs though retail rates (31,567)07,521)(49,088)
Deferred power costs as of December 3 i, 2009 6,264 21,507 27,771
Activity from Januaiy i - December 31, 2010:
Power costs deferred 9,768 9,768
Interest and other net additions 538 26 564
Recoveiy of deferred power costs though retail rates (6,802)02,996)09,798)
Deferred power costs as of December 31, 2010 $ -$18,305 $18.305
Natural Gas Cost Deferrals and Recovery Mechanisms
A vista Corp. files a purchased gas cost adjustment (PGA) in all thee states it serves to adjust natual gas rates for: I) estimated
commodity and pipeline transporttion costs to serve natual gas customers for the coming year, and 2) the difference between actual
and estimated commodity and transporttion costs for the pnor year. These annual PGA filings in Washington and Idaho provide for
the deferral, and recoveiy or refund, of 100 percent of the difference between actul and estimated commodity and pipeline
transporttion costs, subject to applicable regulatoiy review. The annual PGA filing in Oregon provides for deferral, and recoveiy or
refund, of i 00 percent of the difference between actual and estimated pipeline transportation costs and commodity costs that are fixed
though hedge transactions. Commodity costs that are not hedged for Oregon customers are subject to a sharing mechanism whereby
Avista Corp. defers, and recovers or refuds, 90 percent of the difference between these actual and estimated costs. Total net deferred
I FERC FORM NO, 1 (ED. 12-88) Page 123.31
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04115/2011 2010/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
natual gas costs to be refuded to customers were a liabilty of$22.1 millon as of December 31, 2010 and $40.0 milion as of
December 31,2009.
General Rate Cases
The following is a sumar of the Company's authoried rates of retu in each jursdiction:
Jursdiction and service
Washigton electrc and natual gas
Idaho electrc and natual gas
Oregon natual gas
Implementation
Date
December 2010
October 2010
November 2009
Authoried
Overall Rate
of Retu
7.91%
(1)
8.19%
Authorized
Retu on
Equity
10.2%
(1)
10.1%
Authoried
Equity
Level
46.5%
(1 )
50.0%
(1) The rate adjustment implemented on October 1, 2010 resultig from the Idao electrc and natual gas general rate case
settlement did not have a specific authorized rate of retu, retu on equity or equity leveL. The prior rate case settlement
implemented in Augut 2009 had an authoried rate of retu of 8.55 percent, a retu on equity of i 0.5 percent and
authorized equity level of 50.0 percent
Washington General Rate Cases
In December 2009, the WUTC issued an order on Avista Corp.'s electrc and natual gas rate general rate cases that were fied with the
WUTC in Janua 2009. The WUC approved a base electrc rate increase for the Company's Washington customers of2.8 percent,
which was designed to increase anual revenues by $12.1 million. Base natul gas rates for the Company's Washington customers
increased by an average of 0.3 percent, which was designed to increae anual revenues by $0.6 milion. The new electrc and natul
gas rates became effective on Janua 1, 2010. In ths general rate case order, the WUC did not allow the Company to include the
costs associated with the power purchae agreement for the Lacaster Plant in rates. The Company subsequently filed for and received
approval for deferred accounting tratment for these net costs.
In Augut 20 i 0, the Company entered into an all-par settement agreement tht resolved all issues with respect to its general rate case
filed with the WUC in March 2010. This settement agreement was approved by the WUC in November 2010. As agreed to in the
settement stipulation, electrc rates for the Company's Washigton customers increased by an average of7.4 percent, which was
designed to increase anual revenues by $29.5 millon. Natual gas rates for the Company's Washigton customers increased by an
average of2.9 percent, which was designed to increase anual revenues by $4.6 million. The new electrc and natual gas rates became
effective on December 1, 2010. As par of the settement, the pares agreed that the Company would not fie a general rate case in the
Washigton jursdiction before April 1,2011.
The parties agreed that recovery of the deferred net costs associated with the power purchase agreement for the Lancaster Plant were
limited to $6.8 milion for 20 i O. These net deferred costs will be recovered over a five-year amortization period with a rate of retu
on the unamortized balance. The pares agreed tht the costs for the Lacaster Plant for 201 i and going forward are reasonable and
should be recovered in rates.
As par of the settement related to the 2010 Lacaster Plant deferred net costs, the paries agreed tht there would be no deferrals
under the ERM for 2010 in either the surcharge or rebate diection. For 2010, the Company received all of the benefit from the
amount of power supply costs below the level in retail rates in Washigton. Deferrals under the ERM will resume in 201 1.
Idaho General Rate Cases
In June 2009, the Company entered into an al-par settement stipulation in its electrc and natual gas general rate cases tht were
fied with the IPUC in Janua 2009. Ths settement stipulation was approved by the IPUC in July 2009. The new electrc and natual
gas rates became effective on Augut 1,2009. As agreed to in the settement, base electrc rates for the Company's Idaho customers
increased by an average of5.7 percent, which was designed to increase anual revenues by $12.5 millon. Offsetting the base electrc
rate increase was an overall 4.2 percent decrease in the PCA surchage, which was designed to decrease anual PCA revenues by $9.3
millon, resulting in a net increase in anual revenues of$3.2 milion. Base natual gas rates for the Company's Idaho customers
increased by an average of2.1 percent, whch was designed to increase anual revenues by $1.9 milion. Offsetting the natural gas rate
increase for residential customers was an equivalent PGA decrease of 2.1 percent. Lage general servces customers received a PGA
decrease of2.4 percent and intenuptible services customers received a PGA decrease of2.8 percent. The overall PGA decrease
resulted in a $2.0 millon decrease in annual PGA revenues, resultig in a net decrease in annual revenues of $0. i million. The PGAs
are designed to pass though changes in natual gas costs to customers with no change in gross margin or net income.
IFERC FORM NO.1 (ED. 12-88)Page 123.32
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)Avista Corporation (2)A Resubmission 04/15/2011 2010104
NOTES TO FINANCIAL STATEMENTS (Continued)
In September 2010, the IPUC approved a settlement agreement with respect to the Company's general rate case filed in March 2010.
The new electrc and natural gas rates became effective on October I, 2010. As agreed to in the settlement, base electrc rates for the
Company's Idaho customers increased by an average of9.3 percent, which was designed to increase annual revenues by $21.2 milion.
Base natural gas rates for the Company's Idaho customers increased by an average of2.6 percent, which was designed to increase
annual revenues by $1.8 milion.
The settlement agreement includes a rate mitigation plan under which the impact on customers of the new rates will be reduced by
amortizing $11. i milion ($17.5 millon when grossed up for income taes and other revenue-related items) of previously deferred
state income taes over a two-year period as a credit to customers. Whle the Company's cash collections from customers will be
reduced by this amortization durg the two-year period, the mitigation plan will have no impact on the Company's net income. Retail
rates will increase on October I, 2011 and October I, 2012 as the deferred state income ta balance is amortized to zero.
Oregon General Rate Cases
In September 2009, the Company entered intÒ an all-par settlement stipulation in its general rate case that was filed with the OPUC
in June 2009. This settlement stipulation was approved by the OPUC in October 2009. The new natual gas rates became effective on
November I, 2009. As agreed to in the settlement, base natual gal rates for Oregon customers increased by an average of 7.1 percent,
which was designed to increase anual revenues by $8.8 million. .
In Februry 20 Ii, the Company entered into an all-par settement stipulation in its general rate case that was filed with the OPUC in
September 2010. The settlement, which is subject to approval by the OPUC, provides for an overall rate increase of 3.1 percent for the
Company's Oregon customers, designed to increase anual revenues by $3.0 milion. Part of the rate increase would become effective
March 15,2011, with the remaining increase effective June 1,2011. The settlement is based on an overall rate of retu of8.0 percent,
with a common equity ratio of50.0 percent and a 10.1 percent retu on equity. The Company's original request was for an overall
rate increase of5.6 percent, designed to increase anual revenues by $5.4 milion. The Company's original request was based on an
overall rate of return of 8.61 percent, with a common equity ratio of 50.8 percent and a 10.9 percent return on equity.
NOTE 24. SUPPLEMENTAL CASH FLOW INFORMATION (in thousands)
Cash paid for interest
Cash paid for income taxes
2010
$68,638
10,641
2009
$58,197
22,695
Other Cash Flows from Operating Activities:
Power and natual gas deferrals
Change in special deposits
Change in other current assets
Non-cash stock compensation
Gain on sale of assets
$1,383
(6,352)
(1,509)
3,603
(122)
$(216)
(30)
(1,923)
2,596
(89)
I FERC FORM NO.1 (ED. 12-88)Page 123.33
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 041512011
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIV INCOME, All D HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-ta 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 accunted for as "fair value hedges", report the accunts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Line Item Unrealized Gains and Minimum Pension Foreign Currency Other
No.Losses on Available-Liabilty adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a)(b)(c)(d)(e)
1 Balance of Accunt 219 at Beginning of
Preceding Year (6,092,318)
2 Precding OtrlYr to Date Reclassifications
from Acct 219 to Net Income
3 Preceding OuarterlYear to Date Changes in
Fair Value 3,742,032
4 Total (lines 2 and 3)3,742,032
5 Balance of Account 219 at End of
Preceding OuarterlYear (2,350,286)
6 Balance of Account 219 at Beginning of
Current Year (2,350,286)
7 Currnt OtrlYr to Date Reclassifications
from Acct 219 to Net Income
8 Current OuarterlYear to Date Changes in
Fair Value (1,975,667)
9 Total (lines 7 and 8)(1,975,667)
10 Balance of Accunt 219 at End of Current
OuarterlYear (4,325,953)
FERC FORM NO.1 (NEW 06-02)Page 122a
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, A
YearlPeriod of Report
End of 2010/Q4
D HEDGING ACTIVITIES
Line
No.
Other Cash Flow
Hedges
Interest Rate Swaps
Other Cash Flow
Hedges
(Specify)
Totals for each
category of items
recorded in
Account 219
(h)
( 6,092,318)
(f)(g)
1
2
3
4
5
6
7
8
9
10
3,742,032
3,742,032
2,350,286)
2,350,286)
1,975,667)
1,975,667)
4,325,953)
Net Income (Carred
Forward from
Page 117, Line 78)
Total
Comprehensive
Income
(i)0)
FERC FORM NO.1 (NEW 06-02)Page 122b
aeo epo
(Mo, Da, Yr)
04/15/2011
SUMMA Y OF UTILITY PLANT AND ACCUM LATED 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 (specif) and in
column (h) common function.
End of
(a)
Total Company for the
Current YearlOuarter Ended
(b)
Electric
(c)
Line
No.
Classification
1 Utilty Plant
2 In Service
3 Plant in Service (Classified)
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassifed
8 Total (3 thru 7)
9 Leased to Others
10 Held for Future Use
11 Construction Work in Progress
12 Acquisition Adjustments
13 Total Utilty Plant (8 thru 12)
14 Accum Prov for Depr, Amort, & Depl
15 Net Utilty Plant (13 less 14)
16 Detail of Accum Prov for Depr, Amort & Depl
17 In Service:
18 Depreciation
19 Amort & Depl of Producing Nat Gas LandlLand Right
20 Amort of Underground Storage LandlLand Rights
21 Amort of Other Utilty Plant
22 Total In Service (18 thru 21)
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others (24 & 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31,32)
3,676,391,997
7,203,329
2,796,018,893
3,683,595,326 2,796,018,893
2,218,041
60,766,153
22,027,941
3,768,607,461
1,284,830,029
2,483,777,432
2,033,223
39,513,487
2,837,565,603
969,323,143
1,868,242,460---~- -- --- --- ~ - ---- -
21,600,847
1,284,830,029 969,323,143
FERC FORM NO.1 (ED. 12-89)Page 200
Name of Respondent
Avista Corporation
Gas
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Specify) Other (Specify Other (Specify)
YearlPeriod of Report
End of 2010/04
Common Line
No.(d)
712,126,860
1,619,845
168,246,244
5,583,484
713,746,705 173,829,728
184,818
4,365,975
22,027,941
740,325,439
268,765,035
471,560,404
16,886,691
190,716,419
46,741,851
143,974,568
21,600,847
268,765,035 46,741,851
FERC FORM NO.1 (ED. 12-89)Page 201
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/1512011
ELECTRI PLANT IN SERVICE (Account 101,102,103 and 106)
1.Report below the original cost of electric plant in service accrding to the prescribed accunts.
2. In addition to Accunt 101, Electric Plant in Service (Classifed), this page and the next include Accunt 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Accunt 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 accunt, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accunts to indicate the negative effct of such accunts.
6. Classify Account 106 according to prescribed accunts, 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 accunts 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 accunt for accumulated depreciation provision. Include also in column (d)
ine Account ~No.Beginning of Year
(a)(b) (c)
1 1. INTANGIBLE PLANT
2 (301) Organization
3 (302) Franchises and Consents 44,478,295 152,088
4 (303) Miscellaneous Intangible Plant 3,968,847 174,780
5 TOTAL Intangible Plant (Enter Total of lines 2,3, and 4)48,447,142 326,868
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights 2,230,746
9 ! (311) Structures and Improvements 124,903,704 344,352
10 (312) Boiler Plant Equipment 166,294,776 2,460,691
11 (313) Engines and Engine-Driven Generators
12 (314) Turbogenerator Units 48,239,041 42,045
13 (315) Accessory Electric Equipment 26,930,014 3,545
14 (316) Misc. Power Plant Equipment 15,650,932 23,630
15 (317) Asset Retirement Costs for Steam Production 585,276
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)384,834,489 2,874,263
17 B. Nuclear Production Plant
18 (320) Land and Land Rights
19 (321) Structures and Improvements
20 (322) Reactor Plant Equipment
21 (323) Turbenerator 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 56,519,003 845
28 (331) Structures and Improvements 40,656,073 1,839,019
29 (332) Reservoirs, Dams, and Waterways 117,796,318 5,443,778
30 (333) Water Wheels, Turbines, and Generators 141,170,373 8,413,432
31 (334) Accssory Electric Equipment 34,096,337 108,176
32 (335) Misc. Power PLant Equipment 7,318,628 17,928
33 (336) Roads, Railroads, and Bridges 1,999,562
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)399,556,294 15,823,178
36 D. Other Production Plant
37 (340) Land and Land Riahts 903,118 5,988
38 (341) Structures and Improvements 15,743,240 400,035
39 (342) Fuel Holders, Products, and Accessories 21,06,681 105,457
40 I (343) Prime Movers 21,876,780
41 (344) Generators 198,781,330 790,153
42 (345) Accssory Electric Equipment 15,994,108 1,101,775
43 (346) Misc. Power Plant Equipment 1,389,422 198,568
44 (347) Asset Retirement Costs for Other Production 351,682
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)276,104,361 2,601,976
46 TOTAL Prod. Plant (Enter Total of lines 16,25,35, and 45)1,060,495,144 21,299,417
FERC FORM NO.1 (REV. 12-05)Page 204
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
distributions of these tentative classifcations in columns (c) and (d), including the reversals of the prior years tentative accunt distributions of these
amounts. Careful observance of the above instructions and the text of Accunts 101 and 106 wil 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 utilty plant accounts. Include also in column (f) the additions or reductions of primary accunt
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
accunt 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
subaccunt classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Accunt 102, state the propert 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 dateRetirements Adjustments Transfers Balance at LineEnd lg)Year No.
YearlPeriod of Report
End of 2010/04
350
107,595
7,694,060
2,230,396
125,140,461
161,061,407
19,580
48,281,086
26,933,559
15,654,982
585,276
379,887,1677,821,585-~ - --~- - ------- --- ~ - -- - - --- - --- -- ---
56,519,848
193,647 42,301,445
3,263,452 119,976,644
7,744 149,576,061
395,703 33,808,810
7,336,556
1,999,562
3,860,54 411,518,926
3,938 905,168
6,880 16,136,395
17,815 21,152,323
21,876,780
2,837,690 196,733,793
319,179 16,776,704
9,099 1,578,891
351,682
3,194,601 275,511,736
14,876,732 1,066,917,829
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. 12-05)205Page
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) EiA Resubmission 04/15/2011
ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106) (Continued)
Line Accunt ~No.Beginning of Year
(a)(b) (c)
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights 16,092,056 3,623,034
49 (352) Structures and Improvements 16,040,755 752,665
50 (353) Station Equipment 177,678,840 17,804,118
51 (354) Towers and Fixtures 17,113,029 7,792
52 (355) Poles and Fixtures 131,611,436 3,628,228
53 (356) Overhead Conductors and Devices 106,341,896 1,893,064
54 (357) Underground Conduit 2,605,488
55 (358) Underground Conductors and Devices 2,330,071
56 (359) 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)471,685,817 27,708,901
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights 4,336,127 1,086,034
61 (361) Structures and Improvements 14,029,847 495,999
62 (362) Station Equipment 93,198,468 4,866,342
63 (363) Storage Battery Equipment
64 (364) Poles, Towers, and Fixtures 214,302,534 15,321,278
65 (365) Overhead Conductors and Devices 139,008,612 13,271,577
66 (366) Underground Conduit 74,816,416 2,986,849
67 (367) UnderQround Conductors and Devices 123,155,633 7,118.187
68 (368) Line Transformers 169,574,920 10,887,227
69 (369) Services 115,182,247 5,077,737
70 (370) Meters 45,007,149 1,348,471
71 (371) Installations on Customer Premises
72 (372) Leased Propert on Customer Premises
73 (373) Street Lighting and Signal Systems 29,342,489 2,503,071
74 I (374) Asset Retirement Costs for Distribution Plant 129,707
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)1,022,084,149 64,962,772
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 Softare
81 (384) Communication Equipment
82 (385) Miscellaneous Regional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Regional Transmission and Market Oper
84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Rights 124,681
87 (390) Structures and Improvements 3,432,419 188,676
88 (391) Offce Furniture and Equipment 1,163,669 834,808
89 (392) Transportation Equipment 11,406,205 5,023,432
90 (393) Stores Equipment 383,459 6,918
91 (394) Tools, Shop and Garage Equipment 3,455,055 38,717
92 (395) Laboratory Equipment 1,467,560 29,070
93 (396) Power Operated Equipment 25,194,583 12,328,274
94 (397) Communication Equipment 39,099,709 2,662,744
95 (398) Miscellaneous Equipment 8,849
96 SUBTOTAL (Enter Total of lines 86 thru 95)85,736,189 21,112,639
97 (399) Other Tangible Propert
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96,97 and 98)85,736,189 21,112,639
100 TOTAL (Accounts 101 and 106)2,688,448,441 135,410,597
101 (102) Electric Plant Purchased (See Instr. 8)
102 (Less) (102) Electric Plant Sold (See Instr. 8)
103 (103) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)2,688,448,441 135,410,597
.,
FERC FORM NO.1 (REV. 12-05)Page 206
Name of Respondent
Avista Corporation
Retirements
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1512011
ELECTRIC PLANT IN SERVICE (Accunt 101,102,103 and 106) (Continued)Adjustments Transfers Balance at
End 9f Year
\g)
YearlPeriod of Report
End of 2010/04
207,863
2,683,011
19,715,090
16,585,557
192,799,947
17,120,821
135,112,530
108,159,787
2,605,488
2,330,071
1,872,246
127,134
75,173
3,093,181 496,301,537
497
4,197
969,057
5,421,664
14,521,649
97,095,753
312,503
563,810
39,206
509,604
1,944,378
83,212
300,610
229,311,309
151,716,379
77,764,059
129,764,216
178,517,769
120,176,772
46,055,010
78,012 31,767,548
129,707
1,082,241,8354,805,086-- -~ -- -~--~ --- -- ---- --- --~ ,- ------ -~---
32,336
7,620
846,401
124,681
3,588,759
1,990,857
15,583,236
390,377
3,257,564
1,127,661
34,906,065
41,361,517
8,468
102,339,185
236,208
368,969
2,616,792
400,936
381
4,509,643
4,509,643
27,840,145
102,339,185
2,796,018,893
27,840,145 2,796,018,893
FERC FORM NO.1 (REV. 12-05)Page 207
Line
No.
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/1512011
ELECTRIC PLANT HELD FOR FUTURE USE (Accunt 105)
1. Report separately each propert held for future use at end of the year having an original cost of $250,000 or more. Group other items of propert held
for future use.
2. For propert having an original cost of $250,000 or more previously used in utilty operations, now held for fuure use, give in column (a), in addition to
other required information, the date that utilty use of such propert was discontinued, and the date the original cost was transferred to Accunt 105.
Line Description and Location ~No.Of protert in is Accunt in Utilty Service End of Year
(a (b) (c) (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 193,588
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Other Propert:
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 2,033,223
FERC FORM NO.1 (ED. 12-96)Page 214
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) FïA Resubmission 04/15/2011
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Accunt 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 Description of Project Construction work in progress -
No.Electric (Accunt 107)
(a)(b)
1 State of Washington
2 NE Sub-Increase Capacity 1,216,991
3 SGDP Pullman Smart Grid Demonstration Project 1,474,917
4 Minor Projects (232) Under $1,000,000 3,164,510
5
6 State of Idaho
7 Appleway Sub-Rebuild 1,639,907
8 Minor Projects (132) under $1,000,000 1,501,439
9
10 Common -WA & ID
11 Appleway Sub-Rebuild 1,168,858
12 Idaho Road Sub 1,199,560
13 Colstrip Capital Additions 1,397,988
14 Noxon Rapids Unit 2 Runner Upgrade 5,109,642
15 Noxon Rapids Unit 4 Runner Upgrade 1,522,833
16 Nine Mile Redevelopment 1,761,235
17 Microwave Replacement With Fiber 2,764,603
18 Clark Fork Implement PME Agreement 5,623,561
19 Spokane River Implementation (PM&E)1,840,951
20 Transportation Equipment 956,888
21 Minor Projects (206) Under $1,000,000 7,169,604
22
23 Common -WAID/OR
24 Minor Projects (0) Under $1 ,000,000
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43 TOTAL 39,513,487
FERC FORM NO.1 (ED. 12-87)Page 216
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1512011
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1. Explain in a footnote any important adjustments dunng 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 propert.
3. The provisions of Accunt 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 vanous 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.
me
No.
em
(a)
1 Balance Beginning of Year
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense
4 (403.1) Depreciation Expense for Asset
Retirement Costs
5 (413) Exp. of Elec. PIt. Leas. to Others
6 Transportation Expenses-Clearing
7 Other Clearing Accounts
8 Other Accunts (Specify, details in footnote):
9
10 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired
13 Cost of Removal
14 Salvage (Credit)
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
16 Other Debit or Cr. Items (Describe, details in
footnote):
69,766,052 69,766,052~~~
17,368,623
2,651,566
1,268,366
18,751,823
17,368,623
2,651,566
1,268,366
18,751,823
17
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1,
10,15,16, and 18)
960,938,591 960,938,591
Section B. Balances at End of Year According to Functional Classification
20 Steam Production 256,610,251 256,610,251
21 Nuclear Production
22 Hydraulic Production-Conventional 102,530,485 102,530,485
23 Hydraulic Production-Pumped Storage
24 Other Production 62,516,258 62,516,258
2 Transmission 165,976,498 165,976,498
26 Distribution 327,916,454 327,916,454
27 Regional Transmission and Market Operation
28 General 45,388,645 45,388,645
29 TOTAL (Enter Total of lines 20 thru 28)960,938,591 960,938,591
FERC FORM NO.1 (REV. 12-05)Page 219
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
FOOTNOTE DATA
¡Schedule Page: 219 Line No.: 8 Column: c
Includes: Accumulated provision of non-recoverable plant of $290,798.
Also includes FAS 143 depreciation of $22,019.
¡Schedule Page: 219 Line No.: 16 Column: c
Change in Removal Work in Process of ~$136, 612~
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corpration (1) An Oriinal (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/1512011
I NVESTM NTS IN SUBSIDIARY COMPANIES Accunt 123.1)
1.Report below investments in Accunts 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, maturit 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 accunt. List each note giving date of issuance, maturity
date, and specifying whether note is a renewaL.
3. Report separately the equit in undistributed subsidiary eamings since acquisition. The TOTAL in column (e) should equal the amount entered for
Accunt 418.1.
Line Descnption ófnvestment Date Acquired Date Of Amount. otinvestment at
No.(a)
Mal~rity Beginning of Year
(b)(d)
1
2 Avista Capital - Common Stock 1997 187,935,344
3 Avista Capital - Equity in Earnings -107,001,757
4 OCI Investment in Subs
5 Avista Capital - Other Changes in Net Investment
6 Avista Capital - Other Changes in Net Investment
7 Avista Capital - Other Changes in Net Investment 309,652
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 Total Cost of Accunt 123.1 $01 TOTAL 81,243,239
FERC FORM NO.1 (ED. 12-89)Page 224
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04(2) DA Resubmission 04/15/2011
INVESTMENTS IN SUBSIDIARY COMPANIES (Accunt 123.1) (Continued)
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accunts 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 sellng price thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Accunt 123.1
Equity in Subsidiary Revenues for Year Amount Of Investment at üain or LOSS from investment LineEamin~~)of Year
(f)
End lifYear DiSPY~fd of No.g)
1
-10,915,535 177,019,809 2
6,092,992 -100,908,756 3
4
5
6
1,312,864 1,622,516 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
6,092,992 -9,602,671 77,733,569 42
FERC FORM NO.1 (ED. 12-89)Page 225
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2010/04
(2) D A Resubmission 04/151011 End of
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 accptable. 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 accunts (operating expenses, clearing accunts, plant, etc.) affcted debited or creited. Show separately debit or credits to stores expense
clearing, if applicable.
Line Accunt Balance Balance Department or
No.Beginning of Year End of Year Departments which
Use Material
(a)(b)(c)(d)
1 Fuel Stock (Account 151)4,294,013 6,288,853 ~.'.......'. ....
2 Fuel Stock Expenses Undistributed (Accunt 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Accunt 154)
5 Assigned to - Construction (Estimated)12,289,004 15,715,351 1m ...
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)2,161,593 2,314,543 . (1 ................... ....".
8 Transmission Plant (Estimated)55,859 91,697 (1) ........
..... ...
9 Distribution Plant (Estimated)280,550 320,705 . (1).....
10 Regional Transmission and Market Operation Plant (1),(2)
..
(Estimated)I
11 Assigned to - Other (provide details in footnote)3,599,503 4,892,847 I (1m?) ........... ................. ..........
12 TOTAL Accunt 154 (Enter Total of lines 5 thru 11)18,386,509 23,335,143
13 Merchandise (Accunt 155)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Uti)
16 Stores Expense Undistributed (Account 163)12,832
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)22,693,354 29,623,996
FERC FORM NO.1 (REV. 12-05)Page 227
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
FOOTNOTE DATA
'¡chedule Page: 227(1) Electric
(2) Gas
¡Schedule Page: 227Footnote Linked.
Line No.: 1 Column: d
Line No.: 5 Column: d
See note on 227, Row: 11 col/item:
¡Schedule Page: 227 Line No.: 7 Column: d
Footnote Linked. See note on 227, Row: 1, col/item:
¡Schedule Page: 227 Line No.: 8 Column: d
Footnote Linked. See note on 227, Row: 1, col/item:
ISchedule Page: 227 Line No.: 9 Column: d
Footnote Linked. See note on 227, Row: 1, col/item:
flhi¡¡ePiiie:Ii7 Line No.: 10 Column:d
Footnote Linked. See note on 227, Row: 1, col/item:
-----~
~ule Page:-1_?Z__ Li~J'o.: 11 Column: d
Footnote Linked. See note on 227, Row: 1, col/item:
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/1512011
Transmission Service and Generation Interconnection Study Costs
1. Report the particulars (details) called for conceming 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.
ine
No.Description
(a)
1 Transmission Studies
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
Costs Incurred During
Period
(b)
eim ursements
Received During
the Period
(d)
Accunt Credited
With Reimbursement
(e)
Accunt Charged
(c)- - ------ -----~-~--~--~-----~~-
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07)Page 231
Generation Studies
Horizon Wind Interconnect
Avista - Pomeroy Area Interconnect
BP Wind Interconnect
PPM Energy Wind Interconnect
Martinsdale Wind Interconnect
Palouse Wind Interconnect
Avista - Nine Mile Upgrade
Avista - Noxon Upgrade
United Renew Interconnect
Exergy Dev Inter 50MW
Exergy Dev Inter 2 100MW
186210
186210
186210
186210
186210
186210
186210
186210
186210
186210
186210
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Dar Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
FOOTNOTE DATA
!Schedule Paije:2- Line No.: 22 Column: b
Total Charges Incurred Life to Date.
ISchedule Page: 231 Line No.: 22 Column: d
Total Reimbursements Received Life to Date.
¡Schedule Page: 231 Line No.: 23 Column: b
Total Charges Incurred Life to Date.
!Schedule Page: 231 Line No.: 23 Column: d
Total Reimbursements Received Life to Date.
!Schedule Page: 231 Line No.: 24 Column: b
Total Charges Incurred Life to Date.
ISchedule Page: 231 Line No.: 24 Column: dTotal Reimbursements Received Life to Date.
¡Schedule Page: 231 Line No.: 25 Column: b
Total Charges Incurred Life to Date.
!Schedule Page: 231 Line No.: 26 Column: b
Total Charges Incurred Life to Date.
ISchedule Page: 231 Line No.: 26 Column: d
Total Reimbursements Received Life to Date.
ISchedule Page: 231 - Line No.: 27 Column: b
Total Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 28 Column: b
Total Charges incurred Life to Date.
¡sule Page: 23T-LTne No.: 29 Column: b
Total Charges Incurred Life to Date.
!Schedule Page: 231 Line No.: 30 Column: b
Total Charges Incurred Life to Date.
ISchedule Page: 231 Line No.: 31 Column: b
Total Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 32 Column: b
Total Charges Incurred Life to Date.
I
I
I
I
I
I
I
I--------~
I
I
I
I
I
I
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Ei A Resubmission 0415/2011
OTHER REGULA TORY ASSETS (Accunt 182.3)
1. Report below the particulars (details) called for con~ming other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Accunt 182.3 at end of penod, or amounts less than $100,00 which ever is less), may be
grouped by classes.
3. For Regulatory Assets being amortized, show penod of amortization.
Line Description and Purpose of Balanc at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beinning of wnnen ott uunng wnnen ófnng Currnt QuarterlY ear
Currnt the QuarterlY ear the Period
QuarterlYear Accunt Charged Amount
(a)(b)(c)(d)(e)(1)
1 Regulatory Asst FAS 106 1,418,256 926 472,752 945,504
2 Guarantee Residual Value-Airplane
3 Reg Asset Pos Ret Liab 141,08,84 37,899,90 178,984,752
4 Regulatory Aset FAS109 Utility Plant 82,355,23 283 6,778,073 75,577,163
5 Regulatory Asst Lancaster Generation 6,68,667 6,686,667
6 Regulatory Asset FAS109 OSIT Non Plant 2,387,826 283 232,356 2,155,470
7 Regulatory Asst FAS109 OFIT Slate Tax Cr 6,248,158 283 196,871 6,051,287
8 Regulatory Asset FAS109 WNP3 7,128,805 283 737,483 6,391,322
9 Regulatory Asst- Spokane River Relicense 802,034 407 22,20 77,834
10 Regulatory Asst- Spokane River PM&E 443,350 279,160 72,510
11 Regulatory Asst- Lake COA Fund 10,062,735 407 203,00 9,859,729
12 Regulatory Asset- Lake COA IPA Fund 2,00,00 2,000,000
13 Reg Assts Oecuplings Surcharge 378,929 92,730 471,659
14 Regulator Asset 10 OSIT Amort 29.60 299,605
15 Regulatory Asset AMR
16 Regulatory Asst RTO Oepoit- 10 141,611 560 70,80 70,805
17 Regulatory Asset BPA Residential Exchange 663,953 663,953
18 Regulatory Asst ERM Approved for Recvery 6,233,99 557 6,233,995
19 10 Wind Gen AFUOC 120,476 119,124 239,600
20 Regulatory Asset Wartila Unit 1.765,181 407 337,788 1,427,393
21 MTM St Regulatory Asset 8.331.750 40,559.323 48,891,073
22 MTM Lt Regulatory Aset 15,723,77 15,723,775
23 Regulatory Aset FAS143 Asset Retirement Obligation 3,130,245 111 65,214 3,065,031
24 Reg Asset AN- COA Lake SetUement 37,202.198 3,183,778 40,385,976
25 Reg Asset WA-COA Lake SetUement 1,55,54 407 45,042 1,508,506
26 Regulatory Asst Worers Comp 2,921,17 9,58 2,930,760
27 CS2 Lev Ret 1.50,659 407 60,30 1,444,359
28 Regulatory Asset 10 PCA Deferrl 1 10.457,471 4,280.973 14,738,444
29 Regulatory Asset 10 PCA Deferrl 2 3,56.30 3,566,306
30 Regulatory Asset 10 PCA Deferrl 3 11,049,788 557 11,049,788
31 Reg Asset-Futre Payments Lake COA 4,00,00 182 4,00,00
32 OSMAsset 11,894,248 4,251,311 11,894.248 4,251,311
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 352,616,516 119,616,200 42,399,922 429.832,794
FERC FORM NO. 113-Q (REV. 02-04)Page 232
This Page Intentionally Left Blank
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) FiA Resubmission 04/1512011
M SCELLANEOUS DEFFERED DEBITS (Accunt 186)
1.Report below the particulars (details) called for conceming miscellaneous deferred debits.
2.For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1 % of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~r:ount.Amount End of Year Char~ed
(a)(b)(c)(d (e)(f)
1
2 Colstrip Common Fac.1,110,999 406 1,110,999
3 ReQulatorv Asset-DecouplinQdef 254,614 407 299,390 -4,776
4 WA Deferred Power Costs 29,449 29,449
5 WA ERM YTD Company Band -3,037,637 3,037,637
6 WA ERM YTD Contra Account 3,037,637 3,037,637
7 Regulatory Asset RTO Deposit 237,321 560 158,214 79,107
8 Regulatory Asset-Mt lease pymt 2,434,617 540 360,684 2,073,933
9 Regulatory Asset-Mt lease pymt 4,736,376 540 676,632 4,059,744
10 Colstrip Common Fac.2,355,642 406 2,355,642
11 Regulatory Asset- COLS 584,330 506 584,330
12 Guaranteed Residual Value-Plane 2,916,673 2,916,673
13 Prepaid airplane Lease L T 28,743 584,448 613,191
14 Misc DD- airplane lease cap 48,316 48,316
15 Payroll Accrual VAR
16 ,
17 Plant Allocation of clearing jr 2,837,265 VAR 1,551,959 1,285,306
18 Misc DD- IR Swaps 52,705 VAR 52,705
19 Misc Error Suspense -15,154 455,407 440,253
20
21 Renewable Energy-Cert Fees 174,000 557 174,000
22 Misc susp acc-non wlo 47,415 47,415
23 Unamortized AIR sale 35,445 .35,445
24
25 IntanQible Pension Asset
26
27 Nez Perce Settlement 176,385 557 5,212 171,173
28 Misc Deferred Debit Centralia 678,434 678,434
29
30 Long Term Note Rec acct 277,158 282,270 143 559,428
31 Reg Asset ID-Lake Cdal 315,120 506 13,115 302,005
32 ID Panhandle Forest Use Permit 226,097 45,080 181,017
33 Credit Union Labor and Exp 20,275 40,836 61,111
34
35 Horizon Wind Interco 47,020 14,323 61,343
36
37
38 Reclass IPA acct deposit 2,000,000 2,000,000
39 Reclass Idaho Clk Fork Relic 976,731 260,633 716,098
40 Noxon Living Facilty Exp 67,001 67,001
41 Dry Creek Transport
42
43 PG & E Canada to N Cal trans 867,043 19,130 886,173
44 Misc Work Orders .:$50,000 -71,696 98,013 VAR 26,317
45 Subsidiary Bilings 87,699 VAR 54,323 33,376
46 "Null" Projects directly to 186 12,645 8,188 4,457
47 Misc. Work in Progress
48 Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
49 TOTAL 26,105,547 17,414,947
FERC FORM NO.1 (ED. 12-94)Page 233
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) FiA Resubmission 04/15/2011
MISCELLANEOUS DEFFERED DEBITS (Accunt 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 % ofthe Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year lSccum:Amount End of Year
(a)(b)(c)
chëæed
(e)(f)
1
2 Regulatorv Assets Consv 229,213 229,213
3 Regulatory Assets Consv 63,569 2,049,197 2,112,766
4 Regulatory Assets Consv 2,072,766 2,072,766
5 Regulatory Assets Consv 152,407 101,144 51,263
6 Regulatory Assets Consv 139,945 139,945
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
47 Misc. Work in Progress
48 ueerred Reguiatory Comm.
Expenses (See pages 350 - 351)
49 TOTAL 26,105,547 17,414,947
FERC FORM NO.1 (ED. 12-94)Page 233.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/1512011
ACCUMULATED DEFERRED INCOME TAXE S (Accunt 190)
1. Report the information called for below concerning the respondent's accunting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
I Line Descnption and Location ~No.of Year of Year
(a)(b) (c)
1 Electric
2 5,391,537 11,937,146
3
4
5
6
7 Other
8 TOTAL Electric (Enter Total of lines 2 thru 7)5,391,537 11,937,146
9 Gas
10 -267,754 777,990
11
12
13
14
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15 -267,754 777,990
17 Other 86,851,764 107,272,905
18 TOTAL (Acc 190) (Total of lines 8, 16 and 17)91,975,547 119,988,041
Notes
FERC FORM NO.1 (ED. 12-88)Page 234
This Page Intentionally Left Blank
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo. Da, Yr)End of 2010/04
(2) nA Resubmission 041512011
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
senes 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 1 Q-K Report Form filing, a specific reference to report form (Le., 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 authonzed by the articles of incorporation as amended to end of year.
Line Class and Series of Stock and Number of shares Par or Stated Call Price at
No.Name of Stock Series Authorized by Charter Value per share End of Year
(a)(b)(c)(d)
1 Accunt 201 - Common Stock Issued
2 No Par Value 200,000,000
3 Restricted shares
4 Total Common 200,000,000
5
6
7 Accunt 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.1 (ED. 12-91)Page 250
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/15/2011
CAPITAL STOCKS (Accunt 201 and 2 4) (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 HELD BY RESPONDENT Line(Total amount outstanding without reduction AS REACOUIRED STOCK (Accunt 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
Sh.ares Amount ~n.ares
1~)t ~n8)es Amount
(e)(f)(g)ul
1
57,119,723 805,656,943 ....... .................9..,1,)1,665,853 2
3
57,119,723 805,656,943 ..84,134 1,665,853 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO.1 (ED. 12-88)Page 251
This Page Intentionally Left Blank
Name of Respondent This i!0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) n A Resubmission 04/1512011
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 accunts. Provide a
subheading for each accunt and show a total for the account, as well as total of all accounts for reconcilation with balance sheet, Page 112. Add more
columns for any accunt if deemed necessary. Explain changes made in any accunt during the year and give the accunting 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.
IL~e
'(~f A"(unto.
1 Equity transactions of subsidiaries 15,798,128
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 15,798,128
FERC FORM NO.1 (ED. 12-87)Page 253
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/15/2011
CAPITAL STOCK EXPENSE (Accunt 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 dunng the year in the balance in respect to any class or senes 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 accunt charged.
Line ciass and senes of Stock Balance at End of Year
No.(a)(b)
1 Common Stock - Public issue
.....-6,131,359.. .
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22 TOTAL -6,137,359
FERC FORM NO.1 (ED. 12-87)Page 254b
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
FOOTNOTE DATA
!Schedule Page: 254 Line No.: 1 Column: b
Capital stock expense activity, 2010
Beginning balance
Issuance of common stock
Repurchase of common stock
Excess tax benefits on stock compensation
Stock compensation accrual
Ending balance
$(2,090,960)558,660
209,498
(404,293)
(4,410,265)
$(6,137,359)
¡Schedule Page: 254 Line No.: 1 Column: b
Footnote Linked. See note on 254, Row: 1, col/item:
IFERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This 7!0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/1512011
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 authonzation 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 accunts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authonzation of treatment other than as
specified by the Uniform System of Accunts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 FMBS - SERIES A - 7.53% DUE 05/05/2023 5,500,000 42,712
2 FMBS - SERIES A - 7.54% DUE 5/0512023 1,000,000 7,766
3 FMBS - SERIES A - 7.37% DUE 5/10/2012 7,000,000 49,114
4 FMBS - SERIES A -7.39% DUE 5111/2018 7,000,000 54,364
5 FMBS - SERIES A - 7.45% DUE 6/11/2018 15,500,000 170,597
6 FMBS - SERIES A - 7.18% DUE 8/11/2023 7,000,000 54,364
7 KETTLE FALLS P C REV BONDS DUE 14 4,100,000 135,855
8 ADVANCE ASSOCIATED-AVISTA CAPITAL II (ToPRS)51,547,000 1,296,086
9 FMBS - 6.37% SERIES C 25,000,000 158,304
10 FMBS - 5.45% SERIES 90,000,000 1,432,081
11 FMBS - 6.25% SERIES 150,000,000 2,713,435
12 FMBS - 5.70% SERIES 150,000,000 4,924,304
13 FMBS - 5.95% SERIES 250,000,000 3,081,419
14 FMBS - 5.125% SERIES 250,000,000 2,859,788
15 FMBS - 1.68% SERIES 50,000,000 296,372
16 FMBS - 3.89% SERIES 52,000,000 375,867
17 FMBS - 5.55% SERIES 35,000,000 252,988
18 COLSTRIP 2010A PCRBs DUE 2032 66,700,000
19 COLSTRIP 2010B PCRBs DUE 2034 17,000,000
20 INTEREST RATE SWAPS
21 SERIES C SET UP 66,169
22
23
24
25
26
27
28
29
30
31
32
33 TOTAL 1,234,347,000 18,571,585
FERC FORM NO.1 (ED. 12-96)Page 256
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/Q4
(2) Fi A Resubmission 04/15/2011
LONG-TERM DEBT (Account 221, 222, 22 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 Accunt 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accunts 223 and 224 of net changes dunng 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 authonzation 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 Accunt 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.
AMORTIZATION PERIOD -QUstanøíng LineNominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)reSP?~dent)
(i)
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
05-10-1993 5-10-2012 05-10-1993 5-10-2012 7,000,000 515,900 3
05-11-1993 05-11-2018 05-11-1993 05-11-2018 7,000,000 517,300 4
06-09-1993 06-11-2018 06-09-1993 06-11-2018 15,500,000 1,154,750 5
08-12-1993 08-11-2023 08-12-1993 08-11-2023 7,000,000 502,600 6
07-29-1993 12-01-2023 07-29-1993 12-01-2023 4,100,000 246,000 7
06-03-1997 06-01-2037 06-03-1997 06-01-2037 51,547,000 685,019 8
06-19-1998 0619-2028 06-19-1998 06-19-2028 25,000,000 1,592,500 9
11-18-2004 12-01-2019 11-18-2004 12-01-2019 90,000,000 4,905,000 10
11-17-2005 12-01-2035 11-17-2005 12-01-2035 150,000,000 9,375,000 11
12-15-2006 07-01-2037 12-15-2006 07-01-2037 150,000,000 8,550,000 12
04-02-2008 06-01-2018 04-02-2008 06-01-2018 250,000,000 14,875,000 13
09-22-2009 04-01-2022 09-22-2009 04-01-2022 250,000,000 12,812,500 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 17
12-15-2010 10-1-2034 ........ ....10-1-2034 .66,700,000 18
12-15-2010 3-1-2034 14"t5~201Ö ..3-1-2034 17,000,000 19
Various Various Various Various -951,364 20
6-15-1998 6-15-2013 6-15-1998 6-15-2013 21
22
23
24
25
26
27
28
29
30
31
32
1,233,395,636 59,083,919 33
FERC FORM NO.1 (ED. 12-96)Page 257
Name of Respondent This Report is:Date of Report Year/Period of Report
( 1 ) 2Ç An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
FOOTNOTE DATA
I
at page 122. These bonds do not appear in the!Schedule Page: 256 Line No.: 18 Column: f
Please see footnotes to financial statements
balance sheet total of long term debt
¡Schedule Page: 256 Line No.: 19 Column: f
Please see footnotes to financial statements
balance sheet total of long term debt
I
at page 122. These bonds do not appear in the
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/15/2011
RECONCILIATION OF REPORTED NET INCOME WITH TAXBLE INCOME FOR FEDERAL INCOME TAXES
1. Report the reconcilation 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 reconcilation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconcilation even though there is no taxable income for the year. Indicate clearly the nature of each reconcilng amount.
2. If the utilty 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.
I Line particuiars. (Details)AmountNo.(a)(b)
1 Net Income for the Year (Page 117)JI2
3
4 Taxable Income Not Reported on Books
5 4,217,908
6
7
8
9 Deductions Recorded on Books Not Deducted for Return
10 98,555,448
11 Federal Income Tax 11,848,337
12 Deferred Income Tax 34,098,960
13 Investment Tax Credit 291,967
14 Income Recorded on Books Not Included in Return
15 4,872,900
16 Equity in Sub Earnings -6,092,992
17 Corporated Overhead Unallocated Subs 537,773
18
19 Deductions on Return Not Charged Against Book Income
20 -201,378,590
21
22
23
24
25
26
27 Federal Tax Net Income 39,376,401
28 Show Computation of Tax:
29 State Tax l§2% Less Idaho ITC 469,639
30 Federal Tax Net income less state tax 39,846,040
31
32 Federal Tax l§35%13,946,114
33 Prior years tax return, misc true ups -1,967,645
34 Cabinet Gorge Tax Credit -130,132
35 1T0tai Federal Expense 11,848,337
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (ED. 12-96)Page 261
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) EiA Resubmission 04/15/2011
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accred tax accunts and show the total taxes charged to operations and other accunts during
the year. Do not include gasoline and other sales taxes which have been charged to the accunts 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 accunts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affcted 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 accunts.
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.
..ine Kind of Tax BALANCE AT BEGINNING OF YEAR C~xesd '~~Fc Adjust-argeNo.(See instruction 5)Taxes Accrued ~repata i axes ~ring ~ring ments
(Account 236)(Include in Accunt 165)ear ear
(a)(b)(c)(d)(e)(f)
1 FEDERAL:
2 Income Tax Prior 25,778,732
3 Income Tax 2006 -23,788,097 -2,700,913
4 Income Tax 2007 -454,486 -728,828
5 Income Tax 2008 10,768,896 -1,293,655
6 Income Tax 2009 -18,895,541 13,198,286
7 Income Tax (Current)12,116,921 23,841,641
8 Retained Earnings
9 Prior Retained Earnings -5,015,936 -4,773,830
10 Prior Retained Eamings -2,127,838 2,127,838
11 Prior Retained Earnings -1,435,621 1,435,621
12 Prior Retained Earnings -1,210,371 1,210,371
13 Current Retained Earnings -386,409
14 Total Federal -16,380,262 20,205,402 23,841,641
15
16 STATE OF WASHINGTON:
17 Propert Tax (2009)7,086,606 -736,257 6,342,069
18 Property Tax (2010)8,027,008
19 Excise Tax (2005)91,452 -91,452
20 Excise Tax (2006)-464
21 Excise Tax (2007)400,000 121,563 400,000
22 Excise Tax (2009)2,265,543 -20,970 2,244,573
23 Excise Tax (2010)22,135,679 19,553,738
24 Natural Gas Use Tax 15,109 34,014 41,293
25 Municipal Occupation Tax 2,435,373 20,011,536 19,792,188
26 Sales & Use Tax (2006)-8,173
27 Sales & Use Tax (2009)84,190 84,190
28 Sales & Use Tax (2010)855,271 805,723
29 Motor Vehicle Tax (2010)26,109 26,109
30 Total Washington 12,369,636 50,362,501 49,289,883
31
32 STATE OF IDAHO:
33 Income Tax (2006)346,389
34 Income Tax (2007)-104,516
35 Income Tax (2008)-101,560 -202,872
36 Income Tax (2009)-290,110 -5,421
37 Income Tax (2010)293,319 600,000
38 Property Tax (2009)1,958,891 -2,930 1,954,314
39 Propert Tax (2010)4,636,980 2,324,276
40 Motor Vehicle Tax (2010)4,722 4,722
41 TOTAL 2,222,627 94,953,802 97,573,879
FERC FORM NO.1 (ED. 12-96)Page 262
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) FiA Resubmission 04/15/2011
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 otherwse 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 Accunts 408.1 and 109.1 pertaining to other utilty departments and
amounts charged to Accunts 408.2 and 409.2. Also shown in column (i) the taxes charged to utilty plant or other balance sheet accunts.
9. For any tax apportioned to more than one utilty department or accunt, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items . Adjustments to Ret.Other No.ACCO~m236)(Inc!. in Accunt 165)(Accunt 408.1, 409.1)(Accunt 409.3)Earnings (Account 439)
(h)(i)(j)(k)(I)
1
25,778,732 2
-26,489,010 -2,700,913 3
-1,183,314 -524,756 -204,072 4
9,475,241 -904,526 -389,129 5
-5,697,255 -714,210 13,912,496 6
-11,724,719 22,794,744 -10,677,823 7
8
-9,789,766 9
10
11
12
-386,409 -386,409 13
-20,016,500 20,651,252 -445,850 14
15
16
8,281 -530,742 -205,515 17
8,027,008 6,148,008 1,879,000 18
102,921 -194,373 19
-464 20
121,563 121,563 21
-18,691 -2,279 22
2,581,941 16,730,929 5,404,751 23
7,830 6,417 27,596 24
2,654,720 14,849,283 5,162,252 25
-8,173 26
27
49,548 855,271 28
26,109 29
13,442,254 37,288,125 13,074,375 30
31
32
346,389 33
-104,516 34
101,312 35
-295,531 -4,337 -1,084 36
-306,681 494,532 -201,213 37
1,647 -2,930 38
2,312,704 3,829,944 807,037 39
4,722 40
-397,450 75,375,276 19,578,526 41
FERC FORM NO.1 (ED. 12-96)Page 263
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) EiA Resubmission 04/15/2011
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combilled prepaid and accrued tax accunts and show the total taxes charged to operations and other accunts during
the year. Do not include gasoline and other sales taxes which have ben charged to the accunts to which the taed 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 accunts, (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 taes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accunts 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 accunts 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.
..ine Kind ofTax BALANCE AT BEGINNING OF YEAR C1~xesd '~~Fc Adjust-
No.(See instruction 5)Taxes Accrued arge~repata i axes ~ring ~ring ments
(Accunt 236)(Include in Accunt 165)ear ear
(a)(b)(c)(d)(e)(f)
1 Sales & Use Tax (2005)436
2 Sales & Use Tax (2008)4,348 1 -4,349
3 Sales & Use Tax (2009)4,150 8,497 4,349
4 Sales & Use Tax (2010)83,354 75,412
5 Irrigation Credits (2009)444 -44
6 KWH Tax (2009)16,185 817 17,002
7 KWH Tax (2010)313,304 285,450
8 Franchise Tax (2009)1,703,625 1,703,625
9 Franchise Tax (2010)4,148,926 2,651,701
10 Total Idaho 3,538,282 9,472,628 9,422,127
11
12 STATE OF MONTANA:
13 Income Tax (2006)520,245
14 Income Tax (2008)-180,574 -180,574
15 Income Tax (2009)-209,972 4,524 -205,273
16 Income Tax (2010)196,651 370,000
17 Propert Tax (2009)3,084,410 -9,620 3,075,220
18 Propert Tax (2010)6,614,757 3,314,570
19 Colstrip Generation Tax 3,129 3,129
20 KWH Tax (2009)220,298 -481 219,818
21 KWH Tax (2010)1,114,299 864,778
22 Motor Vehicle Tax (2010)4,675 4,675
23 Consumer Council Tax 3 7,070 1,737
24 Public Commission Tax 808 1,293 2,091
25 Total Montana 3,435,218 7,936,297 7,470,171
26
27 STATE OF OREGON:
28 Income Tax (2006)266,087 -34,444
29 Income Tax (2007)-5 -241,886
30 Income Tax (2008)109,583 241,886
31 Income Tax (2009)-368,312 -249,611 -280,000
32 Income Tax (2010)228,576 215,00
33 Propert Tax (2009)-1,317,390 1,747,230 3,182
34 Propert Tax (2010)1,751,024 3,931,888
35 Motor Vehicle Tax (2010)2,475 2,475
36 BETC Credit (2006 & Prior)-420,805
37 BETC Credit (2007)243,353
38 BETC Credit (2008)-40,383
39 BETC Credit (2009)-91,881 -297
40 BETC Credit (2010)-68,844
41 TOTAL 2,222,627 94,953,802 97,573,879
FERC FORM NO.1 (ED. 12-96)Page 262.1
Name of Respondent This ~ort Is:Date of Report Yea~Penod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/15/2011
TAXES ACCF UED, 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 Accunts 408.1 and 109.1 pertaining to other utilty departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (i) the taxes charged to utilty plant or other balance sheet accounts.
9. For any tax apportioned to more than one utilty 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 Prepaid Taxes Electric Extraordinary Items Adustments to Ket.Other No.Acco~nt 236)(Inc!. in Account 165)(Account 408.1, 409.1)(Account 409.3)Earnings (Accunt 439)
g)(h)(i)u)(k)(I)
436 1
2
2 3
7,942 83,354 4
-444 5
817 6
27,854 313,304 7
8
1,497,225 3,011,831 1,137,095 9
3,588,783 7,646,091 1,826,537 10
11
12
520,245 13
14
-175 4,524 15
-173,349 196,651 16
-430 -183,863 174,243 17
3,300,187 6,789,000 -174,243 18
3,129 19
-481 20
249,521 1,113,819 481 21
4,675 22
5,336 8,340 -1,270 23
9 22 1,271 24
3,901,34 7,931,622 4,676 25
26
27
300,531 28
-241,891 29
351,469 30
-337,923 -62,403 -187,208 31
13,576 57,143 171,433 32
426,658 922,031 825,199 33
-2,180,864 926,276 824,748 34
2,475 35
-420,805 36
243,353 37
-40,383 38
-92,178 -297 39
-68,844 -68,844 40
-397,450 75,375,276 19,578,526 41
FERC FORM NO.1 (ED. 12-96)Page 263.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo;Da, Yr)End of 2010/04
(2) nA Resubmission 04/1512011
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accunts and show the total taxes charged to operations and other accunts during
the year. Do not include gasoline and other sales taxes which have been charged to the accunts 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 accunts, (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 accunts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to currnt 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 Kind of Tax BALANCE AT BEGINNING OF YEAR cmxesd le~Fc Adjust-argeNo.(See instruction 5)i: axes Accrye¡F'repald Taxes ~ring ~~~g ments
(Accunt 236)(Include in Accunt 165)ear
(a)(b)(c)(d)(e)(f)
1 Glendale Regulatory Cr. 2008 -210,889
2 Glendate Regulatory Cr. 2009 70,289
3 Franchise Tax (2006)755 -755
4 Franchise Tax (2008)30,327 -30,327
5 Franchise Tax (2009)996,981 998,078 1,097
6 Franchise Tax (2010)3,598,576 2,724,573 29,986
7 Total Oregon -732,290 7,009,129 7,560,752 1
8
9 STATE OF CALIFORNIA:
10 Income Tax (2005)-1,869 3,342
11 Income Tax (2006)-314
12 Income Tax (2009)-2,400 1,600
13 Income Tax (2010)2,400
14 Total California -4,583 1,600 5,742
15
16 MISCELLANEOUS STATES:
17 Income Tax (2008)-1
18 Income Tax (2010)-17,884
19 Total Misc States -17,884 -1
20
21 COUNTY & MUNICIPAL
22 WA Renewable Energy -39,290 -39,290
23 Misc.-3,374 23,419 22,853
24 Total County -3,374 -15,871 -16,437
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 2,222,627 94,953,802 97,573,879
FERC FORM NO.1 (ED. 12-96)Page 262.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/15/2011
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 Accunts 408.1 and 109.1 pertaining to other utilit departments and
amounts charged to Accunts 408.2 and 409.2. Also shown in column (I) the taxes charged to utilty plant or other balance sheet accunts.
9. For any tax apportioned to more than one utilty 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 Prepaid Taxes Electric Extraordinary Items AClJustments to Ket.Other No.Acc~nt 236)(Inc!. in Account 165)(Account 408.1, 409.1)(Accunt 409.3)Earnings (Account 439)
g)(h)(i)Ol (k)(I)
-210,889 1
70,289 2
3
4
5
903,988 3,598,576 6
-1,283,913 1,843,047 5,166,082 7
8
9
-5,211 10
-314 11
-800 1,600 12
-2,400 13
-8,725 1,600 14
15
16
-1 17
-17,884 -17,884 18
-17,885 -17,884 19
20
21
-39,290 22
-2,808 15,139 8,280 23
-2,808 15,139 -31,010 24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
-397,450 75,375,276 19,578,526 41
FERC FORM NO.1 (ED. 12-96)Page 263.2
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/1512011
ACCUMULA ED DEFERRED INVESTMENT TAX RED ITS (Accunt 255)
Report below information applicable to Accunt 255. Where appropnate, segregate the balances and transactions by utilty and
non utilty operations. Explain by footnote any correction adjustments to the accunt balance shown in column (g).Include in column (i)
the average penod over which the tax credits are amortized.
..ine Account
No.SUbdl~lsions of Year Deferred for Year Current Year's Income Adjustments(b) -Accoul)t NO. AmOUnt ACCOUnt No. Amount ( )(c) (d) (e) (f) g
1 Electric Utilty
23%
34%
47%
510%
6 5,308,088 190 2,256,090
7
8 TOTAL 5,308,088 2,256,090
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10 Gas Propertry (100%324,420 411 46,23€
11
12 TOTAL PROPERTY 324,420 46,23€
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) n A Resubmission 04115/2011
ACCUMULATED Di:FERRED INVESTMENT TAX CRED TS (Account 255) (continued)
Balance at End Avera~e ~eriod ADJUSTMENT EXPLANATION Line
of Year of A ocation No.to Incomehi -
1
2
3
4
5
7,564,178 6
7
7,564,178 8
9
278,184 10
11
278,184 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
.41
42
43
44
45
46
47
48
FERC FORM NO.1 (ED. 12-89)Page 267
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/1512011
OTHER DEFFERED CREDITS (Accunt 253)
1. Report below the particulars (details) called for conceming C?ther 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 Accunt 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
Line Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
(b)
Accunt
(f)(a)(c)(d)(e)
1 Defer Gas Exchange (253028)2,119,525 130,435 2,249,960
2
3 Centralia Environmental (253110)966,323 421 966,323
4 Rathdrum Refund (253120)341,042 550 33,822 307,220
5 NE Tank Spil (253130)87,105 1 87,106
6 Bils Pole Rentals (253140)215,203 7,938 223,141
7 CR-CS2 GE LTSA (253150)2,412,558 232 2,412,558
8 DOC EECE Grant 900,017 900,017
9 DOC EECE Admin Fee 100,000 100,000
10 IR Swaps (254170)126,864 126,864
11
12 SalelLeaseback on Bldg (253850)522,912 931 261,456 261,456
13
14 Defer Comp Retired Execs (253900)119,174 431,232 25,218 93,956
15 Defer Comp Active Execs (253910)9,436,629 128 151,516 9,285,113
16 Executive Incent Plan (253920)140,000 140,000
17 Unbiled Revenue (253990)5,970,328 908 2,694,428 3,275,900
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 22,330,799 6,545,321 1,265,255 17,050,733
FERC FORM NO.1 (ED. 12-94)Page 269
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2010/Q4
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ACCUMULATED DEFFERED INCOME TAXES. OTHER PROPERTY (Account 282)
1. Report the information called for below concerning the respondent's accunting for deferred income taxes rating to propert 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
to Account 410.1
(c)
Amounts Credited
to Accunt 411.1
(d)(a)(b)
1 Accunt 282
2 Electric
3 Gas
4 Other
5 TOTAL (Enter Total of lines 2 thru 4)
6
7
8
9 TOTAL Account 282 (Enter Total of lines 5 thru
10 Classification of TOTAL
11 Federal Income Tax
12 State Income Tax
13 Local Income Tax
255,283,307
76,033,192
16,758,482
348,074,981
15,267,229
12,627,052
4,248,441
32,142,722
348,074,981 32,142,722
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Accunt 410.2 to Accunt 411.2
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.
Debits
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 275
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1512011
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Accunt 283)
1. Report the information called for below concerning the respondent's accunting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
Year/Period of Report
End of 2010/Q4
Name of Respondent
Avista Corporation
1 Accunt 283
2 Electric
3 Electric
4
5
6
7
8
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
11 Gas
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18 Other
19 TOTAL (Acc 283) (Enter Total of lines 9, 17 and 18)
20 Classification of TOTAL
21 Federal Income Tax
22 State Income Tax
23 Local Income Tax
Accunt
(a)
Balance at
Beginning of Year
(b)
Line
No.
45.107,264
-1,259,488
402,332
1,785,900 415,630
44,250,108 1,785,900 415,630
-12,851,902
-21,363
-69,458
5,061,282 -226,664
-12,942,723 5,061,282 -226,664
194,272,444 -63,966 4,016,875
225,579,829 6,783,216 4,205,841
221,346,023 6,783,216 4,205,841
4,233,806
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ACCUMULATED DEFERRED INCOME TAXES - OTHE (Accunt 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.
ADJUSTMENTS
Balance at Line
End of Year No.
(k)
167,220 -1,494,390 45,150,364
-1,259,488
402,332
4
167,220 -1,494,390 44,293,208
-2,642 -189,419 -7,377,179
-21,363
-69,458
-2,642 -189,419 -7,468,000
-13,275,982 203,467,585
164,578 -13,465,401 -1,494,390 240,292,793
164,578 -13,465,401 -1,494,390 236,058,987
4,233,806
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 277
Name of Respondent This ~ort Is:Date of Report YeadPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/15/2011
OTHER REGULATORY LIABILITIES (Accunt 254)
1. Report below the particulars (details) called for concerning other regulatory liabilties, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Accunt 254 at end of penod, or amounts less than $100,000 which ever is less),may be grouped
by classes.
3. For Regulatory Liabilties being amortized, show period of amortization.
Balance at Begining DEBITS Balance at End
Line Description and Purpose of of Currnt of Current
No.Other Regulatory Liabilties OuarterlYear Account Amount Credits OuarterlYearCredited
(a)(b)(c)(d)(e)(f)
1 Idaho Invesent Tax Credit (254005)11,603,n3 190 470,351 11,133,372
2 Oreon BETC Credit (254010)104,733 104,733
3 Noxon, ITC (254025)1,441,110 595.399 2,036,509
4 Defer Gas Exchange (254028)
5 Oreon Commercal Fee (254120)116,233 116,233
6 F AS 109 Invest Credit (254180)174,68 190 24,90 149,784
7 Nez Perc (254220)748,38 557 22,00 726,380
8 Oreon Senate Bil (254250)1,789,652 755,285 2,544,937
9 Reg liabilit CCX CR ID (254300)34,512 407 34,512
10 Acce Lake CDA IPA int (254325)64,410 407 64,410
11 Idaho DSIT Amort 14,713,202 14,713,202
12 BPA Res Exch Regulatory Liab (254345)2,900,393 407 2,90,393
13 Unrelized Currncy Exchange (254399)35,54 143 9,259 26,289
14 Reg Liabilty Oter (254700)
15 Mark to Market ST (254740)245 5,878 -5,878
16 Mark to Market FAS133 (254750)42,611,493 244,175 42,611,493
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 61,709,913 46,449,204 16,284,852 31.545,561
FERC FORM NO. 1/3-Q (REV 02-04)Page 278
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2010/04
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1512011
E ECTRIC OPERATING REVENUES (Accunt 400)
1. The followng instrctions generally apply to the annual version of th pages. Do not report quartrly data in coumns (c), (e), (f), and (g). Unbiled revenues and MWH
related to unbiled revenues nee not be report separately as reuire in the annual version of thes pages.
2. Report below operating revenues for each prescrbed accunt, and manufctured gas revenues in total.
3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accunts; except that where separate meter readings are added
for billng purposes, one customer should be counted for each group of meters added. The -average number of customers means th average of twlve fiures at the close of
each month.
4. If increases or decreases frm previous period (columns (c),(e), and (g)), are not derive frm previously reported figures, explain any inconsistencies in a fotnote.
5. Disclose amounts of $250,000 or greater in a footnote for accunts 451, 456, and 457.2.
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no Quarterly)
(c)
Line
No.
Title of Accunt
Sales of Electricity
2 (440) Residential Sales
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)
5 Large (or Ind.) (See Instr. 4)
6 (444) Public Street and Highway lighting
7 (445) Other Sales to Public Authoriies
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers
11 (447) Sales for Resale
12 TOTAL Sales of Electricity
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provo for Refunds
15 Other Operating Revenues
16 (450) Forfited Discounts
17 (451) Miscellaneous Service Revenues
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Propert
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues
22 (456.1) Revenues from Transmission of Electricity of Others
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues
27 TOTAL Electric Operating Revenues
265,219,243
114,792,344
6,702,211
273,953,602
107,741,463
6,607,434
999,779
684,340,236
256,319,131
940,659,367
1,075,772
705,026,815
198,516,063
903,542,878
940,659,367 903,542,878~- ~ ----~ --~~- ~--
567,270
281,752
2,797,559
651,836
381,238
2,742,428
113,233,443
12,414,756
34,534,405
9,176,474
129,294,780
1,069,954,147
47,486,381
951,029,259
FERC FORM NO.1/3-Q (REV. 12-05)Page 300
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ELECTRIC OPERATING REVENUES (Account 400)
6. Commercial and industrial Sales, Accunt 442, may be classified accrding to the basis of classification (Small or Commercal, and Large or Industrial) regularl use by the
respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Accunt 442 of the Uniform System of Accunts. Explain basis of classification
in a footnote.)
7. See pages 106-109, Importnt Changes During Period, for importnt new terrtory added and importnt rate incrase or decreses.
8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accunts.
9. Include unmetered sales. Provide details of such sales in a footnote.
MEGAWATI HOURS SOLD
Year to Date Quarterly/Annual Amount Previous year (no Quarterl)(d) (e)
AVG.NO. CUSTOMERS PER MONTH Line
Current Year (no Ouarterly) Previous Year (no Quarterly) No.(f) (g)
3,100,156 3,176,670 39,489 39,276 4
2,099,333 1,947,553 1,376 1,394 5
26,114 26,021 449 444 6
7
8
12,458 13,371 86 81 9
8,856,389 8,954,984 356,682 355,079 10
6,251,508 4,737,063 11
15,107,897 13,692,047 356,682 355,079 12
13
15,107,897 13,692,047 356,682 355,079 14
Line 12, column (b) includes $
Line 12, column (d) includes
-2,124,891
-40,411
of unbiled revenues.
MWH relating to unbiled revenues
FERC FORM NO. 1/3-0 (REV. 12-05)Page 301
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/1512011
SALES OF ELECTRICITY BY RATE S( HEDULES
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 accunt in the sequence followe in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue accunt, 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 accunt 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 bils rendered during the year divided by the number of billng periods dunng the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
Line Numoer ana ime 01 Kate scneaUie Mvvn ;:oia Kevenue Average Numoer !Söf saies KfWR~olderNo.(a)(b)(c)of C~~\omers Per r~stomer
(f)
1 RESIDENTIAL SALES (440)
2 1 Residential Service 3,517,184 276,489,736 300,814 11,692 0.0786
3 2 Residential Service
4 3 Residential Service
5 12 Res. & Farm Gen. Service 65,742 7,484,692 12,638 5,202 0.1138
6 15 MOPS II Residential
7 22 Res. & Farm Lg. Gen. Service 50,727 3,902,949 111 457,000 0.0769
8 30 Pumping-Special
932 Res. & Farm Pumping Service 12,761 1,065,213 1,719 7,424 0.0835
10 48 Res. & Farm Area Lighting 4,583 1,041,194 0.2272
11 49 Area Lighting-High-Press.272 74,519 0.2740
12 56 Centralia Refund
13 95 Wind Power 174,658
14 72 Residential Service
15 73 Residential Service
16 74 Residential Service
17 76 Residential Service
18 77 Residential Service
19 58A Tax Adjustment -43,206
20 58 Tax Adjustment 7,853,937
21 SubTotal 3,651,269 298,043,692 315,282 11,581 0.0816
22 Residential-Unbiled -32,941 -1,417,033 0.0430
23 Total Residential Sales 3,618,328 296,626,659 315,282 11,476 0.0820
24
25 COMMERCIAL SALES (442)
26 2 General Service
27 3 General Service
28 11 General Service 650,954 67,512,245 34,025 19,132 0.1037
29 12 Res. & Farm Gen. Service
30 16 MOPS II Commercial
31 19 Contract-General Service
32 21 Large General Service 2,018,544 162,022,602 4,406 458,135 0.0803
33 25 Extra Lg. Gen. Service 349,655 19,451,763 13 26,896,538 0.0556
34 28 Contract-Extra Large Serv
35 31 Pumping Service 85,336 6,323,302 1,045 81,661 0.0741
36 47 Area Lighting-Sod. Vap 6,524 1,310,852 0.2009
37 49 Area Lighting-High-Press.2,417 524,548 0.2170
38 56 Centralia Refune
39 95 Wind Power 61,793
40 74 Large General Service
41 TOTAL Biled 15,148,301 942,784,258 356,68.42,47C 0.062
42 Total Unbiled Rev.(See Instr. 6)-40,411 -2,124,891 C C 0.052E
43 TOTAL 15,107,89 940,659,367 356,68.42,351 0.062
FERC FORM NO.1 (ED. 12-95)Page 304
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04115/2011
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricit 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 bils rendered during the year divided by the number of billng periods during the year (12
if all bilings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
ine Numoer analitie Of t(ate scneauie Mvvn ;:oia ~evenue lwerage Numoer ~vvn_ or ~aies ~~~olderNo.(a)(b)(c)of C~~\omers Per r~stomer
(f)
1 75 Large General Service
2 76 Large General Service
3 77 General Service
4 58A Tax Adjustment -43,632
5 58 Tax Adjustment 9,229,653
6 SubTotal 3,113,430 266,393,126 39,489 78,843 0.0856
7 Commercial-Unbiled -13,274 -1,173,883 0.0884
8 Total Commercial 3,100,156 265,219,243 39,489 78,507 0.0856
9
10 INDUSTRIAL SALES (442)
11 2 General Service
12 3 General Service
13 8 Lg Gen Time of Use
14 11 General Service 6,45~690,349 233 27,695 0.1070
15 12 Res. & Farm Gen. Service
16 21 Large General Service 163,672 12,941,031 185 884,714 0.0791
17 25 Exra Lg. Gen. Service 1,844,277 94,156,743 18 102,459,833 0.0511
18 28 Contract - Extra Large Service 1,409 336,574 1 1,409,000 0.2389
15 29 Contract Lg. Gen. Service
20 30 Pumping Service - Special 20,983 1,292,810 34 617,147 0.0616
21 31 Pumping Service 52,604 4,069,893 755 69,674 0.0774
22 32 Pumping Svc Res & Firm 3,912 295,851 150 26,080 0.0756
23 47 Area Lighting-Sod. Vap.227 41,377 0.1823
24 49 Area Lighting - High-Press 50 10,069 0.2014
25 95 Wind Power 1,728
26 72 General Service
27 73 General Service
28 74 Large General Service
29 75 Large General Service
30 76 Pumping Service
31 77 General Service
32 58A Tax Adjustment -1,200
33 58 Tax Adjustment 598,734
34 SubTotal 2,093,587 114,433,959 1,376 1,521,502 0.0547
35 Industrial-Unbiled 5,746 358,385 0.0624
36 Total Industrial 2,099,333 114,792,344 1,376 1,525,678 0.0547
37
38 STREET AND HWY LIGHTING (444)
39 6 Mercury Vapor St. Ltg.
40 7 HP Sodium Vap. St. Ltg
41 TOTAL Biled 15,148,30~942,784,258 356,68.42,47C 0.062.
42 Total Unbiled Rev.(See Instr. 6)-40,411 -2,124,891 (C 0.052E
43 TOTAL 15,107,897 940,659,367 356,682 42,35 0.062~
FERC FORM NO.1 (ED. 12-95)Page 304.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) FiA Resubmission 04/1512011
SALES OF ELECTRICITY BY RATE S( HEDULES
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 accunt in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classifed in more than one revenue accunt, List the rate schedule and sales data under each
applicable revenue accunt 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 billng periods during the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
ILlne l'umoer ano ime Of ~aie scneaUie Mvvn ~OIO ~evenue Average"Numoer îS~Of Sales ~RigolderNo.(a)(b)(c)of C~~\omers Per ?~stomer
(f)
1 11 General Service
2 41 Co-Owned St. Lt. Service 222 39,659 16 13,875 0.1786
3 42 Co-Owned St. Lt. Service 20,332 5,837,670 368 55,250 0.2871
4 High-Press. Sod. Vap.
5 43 Cust-Owned St. Lt. Energy 9 875 1 9,000 0.0972
6 and Maint. Service
7 44 Cust-Owned St. Lt. Energy 856 123,696 28 30,571 0.1445.
8 and Maint. Svce - High-Pres
9 Sodium Vapor
10 45 Cust. Owned St. Lt. Energy Svc 1,301 85,586 6 216,833 0.0658
11 46 Cust. Owned St. Lt. Energy Svc 3,336 294,670 30 111,200 0.0883
12 58A Tax Adjustment -622
13 58 Tax Adjustment 213,037
14 SubTotal 26,056 6,594,571 449 58,031 0.2531
15 Street & Hwy Lighting-Unbiled 58 107,640 1.8559
16 Total Street & Hwy Lighting 26,114 6,702,211 449 58,160 0.2567
17
18 OTHER SALES TO PUBLIC
19 (445)
20 None
21
22 INTERDEPARTMENTAL SALES 12,458 999,779 86 144,860 0.0803
23 58 Tax Adjustment
24 Total Interdepartmental 12,458 999,779 86 144,860 0.0803
25
26 SALES FOR RESALE (447)
27 61 Sales to Other Utilties (NDA)6,251,508 256,319,131 0.0410
28
29
30 Total Sales for Resale 6,251,508 256,319,131 0.0410
31
32
33
34
35
36
37
38
39
40
41 TOTAL Biled 15,148,30f 942,784,258 356,68~42,47C 0.062
42 Total Unbiled Rev.(See Instr. 6)-40,411 -2,124,891 C C 0.052E
43 TOTAL 15,107,891 940,659,367 356,68~42,351 0.062
FERC FORM NO.1 (ED. 12-95)Page 304.2
This Page Intentionally Left Blank
~
Name of Respondent ThiS~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2)A Resubmission 04/1512011
SALES FOR RESALE (Accunt 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 dunng the year. Do not report exchanges of electncit ( 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 schèdule (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 affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the onginal 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 reliabilty of requirements service must
be the same as, or second only to, the suppliets 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 delivenes 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 ofthe 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 reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty 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 Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing -Avera~e Aver~
cation Tariff Number Demand (MW Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 BC Transmission Corp.SF Tariff 9
2 BNP Paribas Energy Trading GP SF Tarif 9
3 BP Corporation North America, Inc.SF ISDA
4 BP Energy Company SF Tariff 9
5 Barclays Bank PLC SF Tariff 9
6 Barclays Bank PLC SF ISDA
7 Black Hils Power, Inc.SF Tarif 9
8 Bonnevile Power Administration LF Tarif 8
9 Bonnevile Power Administration LF ACS-06
10 Bonnevile Power Administration IF ACS-06
11 Bonnevile Power Administration IF ACS-06
12 Bonnevile Power Administration SF Tariff 9
13 Bonnevile Power Administration LF Tariff 12
14 Burbank, City of SF Tariff 9
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2)D A Resubmission 04/1512011
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-penod 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 billng 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (6o-minute
integration) in which the suppliets 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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column (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 ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.($)($)($)
(g)(h)(i)(j)(k)
24 821 821 1
3,800 119,350 119,350 2
3,190,831 3,190,831 3
729,793 31,366,477 31,366,477 4
90,975 3,364,934 3,364,934 5
90,224 90,224 6
1,600 54,200 54,200 7
30,419 1,028,648 1,028,648 8
6,478 203,909 203,909 9
5,835 191,439 191,439 10
1,909 26,233 26,233 11
284,083 10,873,211 10,873,211 12
4 168 168 13
200 7,700 7,700 14
0 0 0 0 0
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
FERC FORM NO.1 (ED. 12-90)Page 311
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges dunng the year. Do not report exchanges of electncity ( 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 affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classifcation 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 (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty 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 Avera~e Actual Demand (MW
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing Avera~e Averjl
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Cargil Power Markets, LLC SF Tariff 9
2 Chelan County PUD NO.1 SF Tariff 9
3 Citigroup Energy, Inc.SF Tariff 9
4 Clatskanie Peoples PUD SF Tariff 9
5 Conoco Philips SF Tariff 9
6 Conoco Philips SF Tariff 9
7 DB Energy Trading, LLC SF Tariff 9
8 Douglas County PUD NO.1 SF Tariff 9
9 EDF Trading North America SF Tarif 9
10 Endure Energy, LLC SF Tariff 9
11 Eugene Water & Electric Board SF Tariff 9
12 Grant County PUD No. 2 SF Tariff 9
13 Grant County PUD No. 2 LF Tariff 12
14 Grant County PUD No. 2 SF Tariff 10
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.1
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) 0 A Resubmission 04/15/2011
SALES FOR RESALE (Accunt 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. Descnbe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accunting adjustments or "true-ups" for service provided in pnor reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" 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.
S. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (SD-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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-ROgrouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" 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 ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
140,852 5,140,867 5,140,867 1
10,625 377,290 377,290 2
234,625 7,907,682 7,907,682 3
1,448 48,620 48,620 4
70,606 2,830,042 2,830,042 5
122,640 122,640 6
24,600 727,878 727,878 7
8,100 275,940 275,940 8
400 19,300 19,300 9
2,768 99,458 99,458 10
9,762 328,783 328,783 11
26,530 887,004 887,004 12
2 78 78 13
2,103 2,103 14
0 0 0 0 0
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
FERC FORM NO.1 (ED. 12-90)Page 311.1
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) ri A Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electncity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedùle. 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 affliation 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 (Le., 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 Loiig-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty 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 Averaße Actual Demand (MW)
No.(Footnote Affliations)Classif Schedule or Monthly iIling Avera~e Aver~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Iberdrola Renewables, Inc.SF Tariff 9
2 Idaho Power Company SF Tariff 9
3 Idaho Power Company LF .Tariff 12
4 J. Aron & Company SF Tariff 9
5 J. Aron & Company SF .ISDA
6 JP Morgan Ventures Energy SF Tariff 9
7 JP Morgan Ventures Energy SF ISDA
8 Macquarie Energy, LLC SF Tariff 9
9 Modesto Irrigation District SF Tariff 9
10 Morgan Stanley SF ISDA
11 Morgan Stanley SF ...ISDA~è ...
12 NaturEner Power Watch, LLC SF Tariff 9
13 NaturEner Power Watch, LLC LF Tariff 12
14 NaturEner Power Watch, LLC SF ...Tariff 9
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.2
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/15/2011
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. Descnbe 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 pnor 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 biling 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 suppliets 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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled onthe 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 ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.($)($)($)
(g)(h)(i)ü)(k)
607,789 23,914,898 23,914,898 1
14,836 522,560 522,560 2
130 4,392 4,392 3
10,000 512,500 512,500 4
715,697 715,697 5
153,758 6,001,526 6,001,526 6
431,777 431,777 7
187,391 6,572,910 6,572,910 8
6,372 213,857 213,857 9
362,854 15,478,962 15,478,962 10
119,007 119,007 11
22,876 754,489 754,489 12
1 41 41 13
5,002 5,002 14
0 0 0 0 0
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
FERC FORM NO.1 (ED. 12-90)Page 311.2
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) 0 A Resubmission 04/1512011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (Le.. sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electncity ( Le., 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 affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the onginal 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 (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the suppliets 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 delivenes 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 reliabilty of
service, aside from transmission constraints, must match the availabilit and reliabilty 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 Averaie Actual Demand (MW
No.(Footnote Affliations)Classifi-Schedule or Monthly iIling Avera~e Aver~
cation Tariff Number Demand(MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 NaturEner Power Watch, LLC SF Tarif 9
2 NaturEner Power Watch, LLC SF Tarif 9
3 NaturEner Power Watch, LLC SF Tariff 9
4 NorthWestern Energy LLC IF Tariff 10
5 NorthWestern Energy LLC If ..Tariff 10
6 NorthWestern Energy LLC IF"..Tariff 9
7 NorthWestern Energy LLC SF Tariff 9
8 NorthWestern Energy LLC ILF Tariff 12
9 NorthWestern Energy LLC ILF Tariff 9
10 NorthWestern Energy LLC SF Tariff 9
11 Okanogan County PUD SF Tariff 9
12 Pacific NW Generating Coop SF Tariff 9
13 PacifiCorp SF Tariff 9
14 PacifiCorp LF Tariff 12
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.3
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) nA Resubmission 04/15/2011
SALES FOR RESALE (Accunt 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 tanffs 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 biling 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 suppliets 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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of.period adjustments, in column 0). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bils 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 ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.($)($)($)
(g)(h)(i)(j)(k)
140,400 140,400 1
551,282 551,282 2
70,000 70,OOC 3
3,256,935 3,256,935 4
984,000 984,000 5
29,368 986,685 986,685 6
121,607 5,030,599 5,030,599 7
94 3,256 3,256 8
8,131 248,341 248,341 9
230 230 10
7,595 262,856 262,856 11
1,852 42,316 42,316 12
128,378 4,219,541 4,219,541 13
472 15,946 15,946 14
0 0 0 0 0
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
FERC FORM NO.1 (ED. 12-90)Page 311.3
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/15/2011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges dunng the year. Do not report exchanges of electncity ( Le., 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 affliation the respondent has with the purchaser.
3. In coh,Jmn (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 (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the suppliets 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 delivenes 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 penod 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 reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty 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 Avera~e Actual Demand (MW)
No.(Footnote Affliations)Classif-Schedule or Monthly iIling -Avera~e Aver~
cation Tarif Number Demand (MW Monthly NC Deman Monthly C em and
(a)(b)(c)(d)(e)(f)
1 PacifiCorp . .i:'.,,",. ,:',Tariff 9
2 Peaker LLC ltFf ?".Tarif 9
3 Pend Oreile Public Utilty District LF Tariff 10
4 Pend Oreile Public Utilty District LF Tarif 9
5 Pend Oreile Public Utilty District SF Tarif 9
6 Pend Oreile Public Utiity District SF Tariff10
7 Portland General Electric Company SF Tariff 9
8 Portland General Electric Company LF Tanff 12
9 Portland General Electric Company SF Tariff 9
10 Powerex SF Tariff 9
11 Powerex SF Tariff 9
12 Powerex I sF' Tariff 9
13 PPL EnergyPlus, LLC SF Tariff 10
14 PPL EnergyPlus, LLC SF Tariff 9
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.4
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) n A Resubmission 04/15/2011
SALES FOR RESALE (Accunt 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 pnor 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 tanffs 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 billng 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 bils 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 bils 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 ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)u)(k)
5,174 158,035 158,035 1
1,748,695 1,748,695 2
419,372 419,372 3
8,317 283,256 283,256 4
42,950 1,329,497 1,329,497 5
35,972 35,972 6
40,050 1,289,090 1,289,090 7
64 2,216 2,216 8
850 850 9
327,442 11,413,514 11,413,514 10
53,970 53,970 11
21,169 21,169 12
286,521 286,521 13
129,240 4,638,272 4,638,272 14
0 0 0 0 0
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
FERC FORM NO.1 (ED. 12-90)Page 311.4
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/1512011
SALES FOR RESALE (Accunt 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges dunng the year. Do not report exchanges of electncity ( Le., 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 affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the onginal 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 (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty 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 delivenes 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 Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly illng Avera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 PPL EnergyPlus, LLC LF ..Tarif 9
2 Public Service of Colorado SF Tarif 9
3 Puget Sound Energy LF Tariff 9
4 Puget Sound Energy SF Tariff 9
5 Puget Sound Energy LE;..............Tariff 12
6 Rainbow Energy Marketing SF Tariff 9
7 Redding, City of SF Tariff 9
8 Sacramento Municipal Utilty District SF Tariff 9
9 Sacramento Municipal Utilty District Iqf ...Tariff 12
10 Sacramento Municipal Utilit District ILF Tariff 9..
11 San Diego Gas & Electric Company SF Tariff 9
12 Seattle City Light SF Tariff 9
13 Sempra Energy Trading SF Tariff 9
14 Sempra Energy Trading SF ISDA
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.5
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/15/2011
SALES FOR RESALE (Account 447) (Continued)
as - 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-penod 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.
5. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the suppliets 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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column (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 ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.($)($)($)
(g)(h)(i)(j)(k)
18,480 564,412 564,412 1
3,600 124,720 124,720 2
23,654 722,447 722,447 3
142,045 6,031,398 6,031,398 4
69 2,500 2,500 5
47,393 1,292,140 1,292,140 6
1,376 53,552 53,552 7
85,284 3,095,708 3,095,708 8
2 45 45 9
642,458 27,761,301 27,761,301 10
8,798 157,228 157,228 11
17,361 604,728 604,728 12
46,848 2,142,123 2,142,123 13
50,769 50,769 14
0 0 0 0 0
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
FERC FORM NO.1 (ED. 12-90)Page 311.5
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) D A Resubmission 04/15/2011
SALES FOR RESALE (Accunt 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 exchangesimust 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 affliation 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 penod 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 reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty 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 Authorit Statistical FERC Rate Avera~e Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing Avera~e Avera~
cation Tarif Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Shell Energy N.A.SF Tariff 9
2 Shell Energy N.A.SF ISDA
3 Shell Energy N.A.SF Tarif 9
4 Sierra Pacifc Power Company SF Tariff 9
5 Sierra Pacific Power Company LF Tariff 12
6 Snohomish County PUD SF Tariff 9
7 Sovereign Power LF ..Tarif 10
8 Sovereign Power LF ........Tarif 9
9 Tacoma Power SF Tariff 9
10 Tacoma Power U=. ...............Tariff 12
11 Tacoma Power SF Tariff 10
12 Tenaska Power Services Co.SF Tariff 9
13 The Energy Authority SF Tariff 9
14 TransAlta Energy Marketing SF Tariff 9
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.6
Name of Respondent This '(0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) n A Resubmission 04/15/2011
SALES FOR RESALE (Accunt 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 RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" 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 RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 bils 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 ü). Explain in a footnote all components of the amount shown in column ü). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-ROn 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 ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.($)($)($)
(g)(h)(i)0)(k)
1,050,124 41,910,567 41,910,567 1
218,140 218,140 2
2,200 2,200 3
40,726 736,431 736,431 4
27 1,061 1,061 5
5,55 186,680 186,680 6
80,368 80,368 7
15,902 504,545 504,545 8
3,117 77,658 77,658 9
3 59 59 10
1,070 1,070 11
400 14,000 14,000 12
6,667 235,258 235,258 13
189,141 7,070,961 7,070,961 14
0 0 0 0 0
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
FERC FORM NO.1 (ED. 12-90)Page 311.6
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2)A Resubmission 04/151011
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., 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 (Le., transactions involvng 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 affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the onginal 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 (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty 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 availabilty and reliabilty 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 Averaße Actual Demand (MW)
Classifi-Schedule or Monthly iIing -Avera~e AverisNo.(Footnote Affliations)cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Turlock Irrigation District SF Tariff 9
2 IntraCompany Wheeling ......F
3 IntraCompanyGenerafion ... ...... ...LF ...... ........... ......
4 Revenue Adjustment AD
5
6
7
8
9
10
11
12
13
14
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.7
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) n A Resubmission 04/15/2011
SALES FOR RESALE (Accunt 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-penod 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 RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" 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 RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" 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 ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.($)($)($)
(g)(h)(i)ü)(k)
400 14,200 14,200 1
-22,469,603 22,469,603 2
631,350 631,35C 3
-1 5,248 5,248 4
5
6
7
8
9
10
11
12
13
14
0 0 0 0 0
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
6,251,508 6,702,608 220,613,706 29,002,817 256,319,131
FERC FORM NO.1 (ED. 12-90)Page 311.7
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) 2Ç An Original (Mo, Oa, Yr)
Avista Corpration (2) A Resubmission 04/15/2011 2010104
FOOTNOTE DATA
!Schedule Page: 310 Line No.: 3 Column: b
SWAP
\Schedule Page: 310 Line No.: 6 Column: b
SWAP
\Schedule Page: 310 Line No.: 8 Column: bBPA Contract Terminates Septemer 30, 2011.
I§chedule Page: 310 Line No.: 9 Column: b
BPA Contract Terminates January 1,2036.
I§chedule Page: 310 Line No.: 13 Column: b
NWPP Reserve Sharing Sales
I§chedule Page: 310.1 Line No.: 13 Column: b
NWPP Reserve Sharing Sales
I§chedule Page: 310.2 Line No.: 3 Column: b
NWPP Reserve Sharing Sales
\Schedule Page: 310.2 Line No.: 5 Column: b
SWAP
\Schedule Page: 310.2 Line No.: 7 Column: b
SWAP
I§chedule Page: 310.2 Line No.: 11 Column: b
SWAP
I§chedule Page: 310.2 Line No.: 13 Column: b
NWPP Reserve Sharing Sales
\Schedule Page: 310.2 Line No.: 14 Column: b
Loss Return
\Schedule Page: 310.3 Line No.: 2 Column: bCapacity
\Schedule Page: 310.3 Line No.: 3 Column: bBundled Transmission
!Schedule Page: 310.3 Line No.: 4 Column: b
Capacity Sale expires January 6, 2011
!Schedule Page: 310.3 Line No.: 5 Column: b
Bundled Transmission - Capacity Sale expires January 6, 2011.
¡Schedule Page: 310.3 Line No.: 6 Column: b
Contract terminates January 6, 2011.
¡Schedule Page: 310.3 Line No.: 8 Column: b
NWPP Reserve Sharing Sales
¡Schedule Page: 310.3 Line No.: 9 Column: bNorthWestern Energy LLC sale expires October 31, 2013.
¡Schedule Page: 310.3 Line No.: 14 Column: bNWPP Reserve Sharing Sales
¡Schedule Page: 310.4 Line No.: 1 Column: b
PacifiCorp sale terminates October 31, 2013.
¡Schedule Page: 310.4 Line No.: 2 Column: bPeaker, LLC capacity contract terminates Decemer 31, 2016.
!Schedule Page: 310.4 Line No.: 3 Column: bContract expires 09/30/2014
!Schedule Page: 310.4 Line No.: 4 Column: b
Contract expires 9/30/2014.
¡Schedule Page: 310.4 Line No.: 8 Column: b
NWPP Reserve Sharing Sales
¡Schedule Page: 310.4 Line No.: 12 Column: bBundled Transmission
~dule Page: 310.5 Line No.: 1 Column: b
PPL sale terminates October 31, 2013.
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)Avista Corpration (2)A Resubmission 04/15/2011 2010/Q4
FOOTNOTE DATA
¡Schedule Page: 310.5 Line No.: 3 Column: bPuget Sound Energy sale terminates October 31, 2013.
¡Schedule Page: 310.5 Line No.: 5 Column: b
NWPP Reserve Sharing Sales
¡Schedule Page: 310.5 Line No.: 9 Column: b
NWPP Reserve Sharing Sales
¡Schedule Page: 310.5 Line No.: 10 Column: b
Contract expires 2014.
¡Schedule Page: 310.5 Line No.: 14 Column: b
SWAP
¡Schedule Page: 310.6 Line No.: 2 Column: b
SWAP
¡Schedule Page: 310.6 Line No.: 5 Column: b
NWPP Reserve Sharing Sales
¡Schedule Page: 310.6 Line No.: 7 Column: b
Sovereign Power contract terminates 1-3.1-2015
¡Schedule Page: 310.6 Line No.: 8 Column: b
Sovereign Power Contract terminates 1-31-2015
¡Schedule Page: 310.6 Line No.: 10 Column: b
NWPP Reserve Sharing Sales
¡Schedule Page: 310.7 Line No.: 2 Column: a
Intracompany Wheeling
¡Schedule Page: 310.7 Line No.: 2 Column: bIntraCompany Wheeling terminates 09/30/2023.
¡Schedule Page: 310.7 Line No.: 3 Column: a
Intracompany Generation - Sale of Ancillary Services
!Schedule Page: 310.7 Line No.: 3 Column: b
IntraCompany Generation - Sale of Ancillary Services.
¡Schedule Page: 310.7 Line No.: 4 Column: b
Estimated revenues - true up in later periods.
IFERC FORM NO.1 (ED. 12-87) Page 450.2
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 0411512011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Accunt AmouptforN ~~~~~ W ~
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineerin
5 (501) Fuel
6 (502) Steam Expenses
7 (503) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr.
9 (505) Electric Expenses
10 (506) Miscellaneous Steam Power Expenses
11 (507) Rents
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12)
14 Maintenance
15 (510) Maintenance Supervision and En ineerin
16 (511) Maintenance of Structures
17 (512) Maintenance of Boiler Plant
18 (513) Maintenance of Electric Plant
19 514) Maintenance of Miscellaneous Steam Plant
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering
25 518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transferred-er.
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 Engineerin
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 Ex enses-Nuc. Power (Entr tot lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering
45 (536) Water for Power
46 (537) Hydraulic Expenses
47 (538) Electric Expenses
48 (539 Miscellaneous Hydraulic Power Generation Expenses
49 (540) Rents
50 TOTAL Operation (Enter Total of Lines 44 thru 49)
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering
54 (542) Maintenance of Structures
55 (543) Maintenance of Reservoirs, Dams, and Waterwa s
56 (544) Maintenance of Electric Plant
57 (545) Maintenance of Miscellaneous Hydraulic Plant
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)
59 TOTAL Power Production Expenses-H draulic Power (tot of lines 50 & 58)
Am.ounUørPrevious Year
(c)
536,766 514,450
28,352,582 22,358,344
4,265,708 2,614,109
838,347 699,318
2,468,855 2,783,706
15,498 29,773
36,477,756 28,999,700
501,359 500,139
610,113 546,526
4,899,998 5,457,086
645,697 2,565,316
661,490 937,372
7,318,657 10,006,439
43,796,413 39,006,139
2,349,973
900,793
5,932,977
5,726,408
733,429
6,529,629
22,173,209
2,278,227
815,150
4,390,300
5,604,151
630,038
6,068,605
19,786,471
376,904
522,921
1,290,854
1,789,839
177,024
4,157,542
26,330,751
249,607
343,445
646,541
1,937,827
1,835,745
5,013,165
24,799,636
FERC FORM NO.1 (ED. 12-93)Page 320
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/15/2011
ELECTRIC OPERATION AND MAINTENANCE EIIPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account ..No.urrent ear Previous ear
(a)(b) (c)
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering 873,063 846,899
63 (547) Fuel 115,449,329 68,656,659
64 (548) Generation Expenses 2,463,056 2,215,456
65 (549) Miscellaneous Other Power Generation Expenses 505,589 456,697
66 (550) Rents 33,433 -33,811
67 TOTAL Operation (Enter Total of lines 62 thru 66)119,324,470 72,141,900
68 Maintenance
69 (551) Maintenance Supervision and Encineering 798,646 775,889
70 (552) Maintenance of Structures 8,426 1,850
71 (553) Maintenance of Generating and Electric Plant 1,691,146 1,893,421
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 116,403 100,412
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)2,614,621 2,771,572
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)121,939,091 74,913,472
75 E. Other Power Supply Expenses
76 (555) Purchased Power 277,079,128 303,784,778
77 (556) System Control and Load Dispatching 555,351 528,673
78 (557) Other Expenses 126,323,056 69,198,479
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)403,957,535 373,511,930
80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79)596,023,790 512,231,177
81 2. TRANSMISSION EXPENSES
.82 Operation
83 (560) Operation Supervision and Engineering 2,210,636 2,436,974
84 (561) Load Dispatching 2,192,996 2,224,918
85 (561.1) Load Dispatch-Reliabilty
86 (561.2) Load Dispatch-Monitor and Operate Transmission System
87 (561.3) Load Dispatch-Transmission Service and Scheduling
88 (561.4) Scheduling, System Control and Dispatch Services
89 (561.5) Reliabiltv, Planning and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation Interconnection Studies
92 (561.8) Reliabilty, Plannina and Standards Development Services
93 (562) Station Expenses 272,063 190,291
94 (563) Overhead Lines Expenses 447,185 543,042
95 (564) Underground Lines Expenses
96 (565) Transmission of Electricitv bv Others 17,742,126 13,350,741
97 (566) Miscellaneous Transmission Expenses 1,617,125 1,387,100
98 (567) Rents 120,946 152,055
99 TOTAL Operation (Enter Total of lines 83 thru 98)24,603,077 20,285,121
100 Maintenance
101 (568) Maintenance Supervision and Engineering 665,430 566,082
102 (569) Maintenance of Structures 275,169 330,766
103 (569.1) Maintenance of Computer Hardware
104 (569.2) Maintenance of Computer Softare
105 (569.3) Maintenance of Communication Equipment
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment 1,157,114 1,127,999
108 (571) Maintenance of Overhead Lines 1,751,805 1,528,641
109 (572) Maintenance of Underground Lines 11,590 17,566
110 (573) Maintenance of Miscellaneous Transmission Plant -2,754 38,785
111 TOTAL Maintenance (Total of lines 101 thru 110)3,858,354 3,609,839
112 TOTAL Transmission Expenses (Total of lines 99 and 111)28,461,431 23,894,960
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04115/2011
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Accunt ~No.urren ear Previous ear
(a)(b) (c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Day-Ahead and Real-Time Market Facilittion
117 (575.3) Transmission Rights Market Faciltation
118 (575.4) Capacity Market Faciltation
119 (575.5) Ancilary Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Faciltation, 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 Softare
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)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering 1,495,137 1,367,048
135 (581) Load Dispatching
136 (582) Station Expenses 715,019 546,953
137 (583) Overhead Line Expenses 1,402,987 1,577,717
138 (584) Underground Line Expenses 581,320 710,346
139 (585) Street Lighting and Signal System Expenses 226,745 218,441
140 (586) Meter Expenses 1,773,001 1,619,021
141 (587) Customer Installations Exp~nses 790,470 861,022
142 (588) Miscellaneous Expenses 6,426,792 5,871,255
143 (589) Rents 294,788 375,764
144 TOTAL Operation (Enter Total of lines 134 thru 143)13,706,259 13,147,567
145 Maintenance
146 (590) Maintenance Supervision and Enoineerino 1,261,570 1,326,210
147 (591) Maintenance of Structures 396,786 280,729
148 (592) Maintenance of Station Equipment 785,071 1,030,655
149 (593) Maintenance of Overhead Lines 7,948,732 6,823,635
150 (594) Maintenance of Underground Lines 845,853 1,067,148
151 (595) Maintenance of Line Transformers 1,094,896 1,040,344
152 (596) Maintenance of Street Lighting and Signal Systems 652,322 638,654
153 (597) Maintenance of Meters 138,937 160,883
154 (598) Maintenance of Miscellaneous Distribution Plant 270,915 315,281
155 TOTAL Maintenance (Total of lines 146 thru 154)13,395,082 12,683,539
156 TOTAL Distribution Expenses (Total of lines 144 and 155)27,101,341 25,831,106
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 592,956 567,832
160 (902) Meter Reading Expenses 2,739,310 2,624,185
161 (903) Customer Records and Collection Expenses 7,798,575 8,243,568
162 (904) Uncollectible Accunts 1,674,638 2,735,983
163 (905) Miscellaneous Customer Accounts Expenses 131,019 244,871
164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163)12,936,498 14,416,439
FERC FORM NO.1 (ED. 12-93)Page 322
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount forNo ~~. 00 ~
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision
168 (908) Customer Assistance Expenses
169 (909) Informational and Instructional Expenses
170 (910 Miscellaneous Customer Service and Informational Expenses
171 TOTAL Customer Service and Information Expenses (Total 167 thru 170)
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision
175 (912) Demonstrating and Sellng Expenses
176 913) Advertising Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries
182 (921) Offce Supplies and Expenses
183 (Less) (922) Administrative Expenses Transferred-Credit
184 (923) Outside Services Employed
185 (924) Propert Insurance
186 (925) Injuries and Damages
187 (926) Employee Pensions and Benefits
188 (927) Franchise Requirements
189 (928 Regulatory Commission Expenses
190 (929) (Less) Duplicate Charges-Cr.
191 (930.1) General Advertising Expenses
192 (930.2) Miscellaneous General Expenses
193 (931) Rents
194 TOTAL Operation (Enter Total of lines 181 thru 193)
195 Maintenance
196 (935) Maintenance of General Plant
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196)
198 TOTAL Elec Op and Maint Expns (Total 80, 112,131,156,164,171,178,197)
Am.ount forPrevious Year
(c)
27,971,131
874,830
168,978
29,014,939
25,449,316
67,743
146,608
25,663,667
4,734 506,252
452 114,294
192,237 307,957
197,423 928,503
25,316,910 22,474,374
4,127,587 3,928,835
50,151 49,301
15,053,420 11,313,636
1,300,926 1,283,269
5,380,816 3,543,277
1,098,670 1,053,264
6,027 6,704
5,550,292 4,999,707
204,098 264,628
3,269,466 3,129,106
872,289 393,144
62,130,350 52,340,643
7,655,998 7,960,364
69,786,348 60,301,007
763,521,770 663,266,859
FERC FORM NO.1 (ED. 12-93)Page 323
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 041512011
PU~C~&iED POWER hAccu~t 555)
( nc U 109 power exc anges
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 part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain ina footnote any ownership interest or affliation 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 suppliets 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categones, 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)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 BP ''I,!i i. ,.........SF ISDA"
2 BP Energy Comp IF WSPP
3 BP Energy Comp SF WSPP
4 Barclays Bank PLC SF WSPP
5 Black Creek Hydro LU FERC#1
6 BNP Paribas Energy SF WSPP
7 Bonnevile Power Administration LF WNP#3Agr.
8 Bonnevile Power Administration SF WSPP
9 BonneviiePower Adminístratiòn EX PNCA
10 Bonnevile Power Administration SF Tariff #8
11 l30nneviUe POwër Adrninlstratiòn OS BPAOATI
12 13*l'neyillee9~~r Mniinistration .....SF BPAOATI
13 Calpine Energy Services SF WSPP
14 California Independent System Operator SF WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) n A Resubmission 04/15/2011
v ."'. ccu~ti~g~l: (Continued)'(1ncludlng pówer exc ange )
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 junsdictional 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the suppliets 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.
6. Report in column (g) the megawatthours shown on bils 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 bils 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 O+k+l)No.Received Delivered
~l ($~~fl
of Settlement ($)
(g)(h)(i)(k (m)
7,357,836 7,357,836 1
219,00C 7,555,50C 7,555,500 2
353,92~13,794,67€13,794,676 3
16,45.721,30C 721,300 4
10,43f 233,90~233,903 5
3,OOC 35,95c 35,950 6
406,71C 13,920,03E 13,920,036 7
66,1(!1,739,34'1,739,345 8
700 700 2,33f 2,338 9
37,161 1,166,69;1,166,693 10
244,70(824,256 1,068,956 11
14,79€317,73c -79,214 238,516 12
5C 13
3,21~14
8,441,791 650,299 649,168 9,510,548 256,938,753 10,629,829 277,079,13C
FERC FORM NO.1 (ED. 12-90)Page 327
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original .(Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/1512011
PU~C~AÆiED POWER ~Accu~t 5 5)( nc u ing power exc anges
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 part 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the onginal 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 reliabilty of requirement service must
be the same as, or second only to, the suppliets 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 reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Descnbe 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)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Cargil Power Markets SF WSPP
2 City of Spokane LU PURPA
3 Chelan County PUD LU Rocky Reach
4 Chelan County PUD SF WSPP
5 Citigroup Energy SF WSPP
6 Clatskanie PUD SF WSPP
7 Conoco Phillps SF WSPP
8 Douglas County PUD No. 1 LU Wells
9 Douglas County PUD NO.1 LU Wells Settlement
10 Douglas County PUD No. 1 IF Wells
11 Douglas County PUD No. 1 SF WSPP
12 Dougias County pub No. 1 EX 305
13 DB Energy Trading LLC SF WSPP
14 Eagle Energy Partners SF WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326.1
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/15/2011
CCU~\~8gl~ (l'ontinued)'llncluding pówe'r exc ange )
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 billng 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 suppliets 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.
6. Report in column (g) the megawatthours shown on bils 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 0), 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 bils 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 LinePurchasedMegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
~l ($~\fl
of Settlement ($)(g)(h)(i)(k (m)57,77!1,847,46!i 1,847,465 1
52,519 2,O54,621l 2,054,628 2
144,501l 2;171,979 2,171,979 3
6,60!i 186,37-186,374 4
118,77~3,954,1 () 3,954,104 5
2,28 86,57~86,575 6
4.7
211,59!1,399,72(1,399,720 8
17,61.334,02!334,029 9
23,29E 9,496,248 9,496,248 10
22,17C 827,51:i 827,513 11
114,405 114,285 1,553,36:i 3,458 1,556,821 12
7,20C 189,20(189,200 13
40(13,90(13,900 14
8,441,791 650,299 649,168 9,510,548 256,938,753 10,629,829 277,079,13(
FERC FORM NO.1 (ED. 12-90)Page 327.1
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) r"A Resubmission 04/1512011
PU~C~~ED POWER ~Accust 555)
(n u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electncit (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 part 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the onginal 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 (Le., 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 suppliets 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electncity. 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)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Endure Energy SF WSPP
2 Eugene Water & Electric Board SF WSPP
3 Ford Hydro Limited Partnership LU PURPA
4 Grant County PUD NO.2 LU Wanapum
5 Grant County PUD NO.2 LU Priest Rapids
6 Grant County PUD NO.2 SF WSPP
7 Grant County PUD NO.2 EX FERC#104
8 Grant County PUD NO.2 LU Displacement
9 Hydro Technology Systems LU PURPA
10 Idaho Power Company SF WSPP
11 Inland Power & Light Company RO 208
12 Iberdrola Renewables SF WSPP
13 Jim White LU PURPA
14 John Day Hydro LU PURPA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.2
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2)o A Resubmission 04/15/2011
CCUR\~g~l) (Continued)"71iicludlng pöwer exc ange )
AD - for out-of-period adjustment. Use this code for any accunting 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 billng 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 suppliets 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.
6. Report in column (g) the megawatthours shown on bils 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 0), 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 bils 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 O+k+l)No.Received Delivered
~l ($~($)of Settlement ($)
(g)(h)(i)(k (I)(m)
2,26i 89,32E 89,326 1
7,40C 257,38C 257,380 2
2,93~186,06S 186,068 3
136,44C -1,227,58E -1,227,586 4
151 ,94~5,608,844 5,608,844 5
12,61~392,112 392,112 6
3,415 3,415 7
192,99E 5,653,02~5,653,029 8
7,86~405,m 405,179 9
2,20'83,12!83,125 10
10~6,23~6,239 11
336,69C 13,358,96E 13,358,966 12
96i 90,80 90,807 13
2,01~90,814 90,814 14
8,441,791 650,299 649,168 9,510,548 256,938,753 10,629,829 277,079,13C
FERC FORM NO.1 (ED. 12-90)Page 327.2
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/15/2011
PU~C~drED POWER ~Accu~t 555)( nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the onginal 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 (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets servce 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electncity. 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 Authorit Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tarif Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 J P Morgan Ventures Energy LLC SF WSPP
2 J P Morgan Ventures Energy LLC LU PPM Energy
3 Mirant Energy Trading LU WSPP
4 Morgan Stanley Capital Group IF WSPP
5 Morgan Stanley Capital Group SF WSPP
6 Macquarie Energy LLC SF ISDA
7 NaturEner Power Watch SF WSPP
8 Northpoint Energy Solutions SF WSPP
9 NorthWestern Energy LLC SF WSPP
10 Okanogan County PUD No. 1 SF WSPP
11 PPL Energy Plus SF WSPP
12 PacifiCorp SF WSPP
13 Pacifc NW Gen Corp SF WSPP
14 Pend Oreile County PUD No. 1 SF Pend 0'
Total
FERC FORM NO.1 (ED. 12-90)Page 326.3
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) n A Resubmission 04/15/2011
ccu~ti~gg¿i (Continued)micluding power exc ange )
AD - for out-of-period adjustment. Use this code for any accunting 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 billng 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 suppliets 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.
6. Report in column (g) the megawatthours shown on bils 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 0), 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 O+k+l)No.Received Delivered
~l ($~
~'l
of Settlement ($)
(g)(h)(i)(k (m)
15,60'452,801 452,806 1
73,276 3,016,4~3,016,499 2
3
656,99.20,191,5~20,191,554 4
100,71 3,458,9~3,458,919 5
66,331 2,141,80C 2,141,800 6
1 ;7
30 7,571 7,571 8
39,95-1,403,58~1,403,589 9
57,24.1,535,9Ej 1,535,964 10
1,724,32.54,745,62.54,745,622 11
51,78.1,653,58~1,653,589 12
8,43c 183,00C 183,000 13
26,335 861,34f 861,345 14
8,441,791 650,299 649,168 9,510,548 256,938,753 10,629,829 277,079,13C
FERC FORM NO.1 (ED. 12-90)Page 327.3
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/1512011
PU~C!rcHED POWER ~Accou~t 555)
n u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electncity (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 part 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 affliation the respondent has with the seller.
3.In column (b), enter a Statistical Classification Code based on the onginal 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 (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets 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 interrpted 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 delivenes 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 availabilty and reliability of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 PØiid. Ôtøiiec.olJrtYpOoNø.)"SF Pend 0'
2 Phillps Ranch LU PURPA
3 Portland General Electric Company EX 304
4 portland :GeneraIEleêtriccon1päriy..EX 178
5 Portland General Electric Company SF WSPP
6 Potlatch Corporation LU PURPA
7 Powerex Corp SF WSPP
8 Powerex Corp SF WSPP
9 Public Service Co of Colorado SF WSPP
10 Puget Sound Energy SF WSPP
11 Rainbow Energy Marketing Corp SF WSPP
12 Sacramento Municipal Utility District SF WSPP
13 Seattle City Light EX WSPP
14 Seattle City Light SF WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326.4
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) 0 A Resubmission 04/15/2011
ccu~ti~ggl~ (Continued)"" , ,r.ì1iiC1uding power exc ange )
AD - for out-of-period adjustment. Use this code for any accunting adjustments or "true-ups" for service provided in pnor reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tanff, or, for non-FERC jurisdictional sellers, include an appropnate
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 billng 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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.
6. Report in column (g) the megawatthours shown on bils 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 0), 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 bils 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. Ifthe settlement amount (i) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or chargesçovered 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 O+k+l)No.Received Delivered
~l ($~($)of Settlement ($)
(g)(h)(i)(k (I)(m)
77,301 9,354 7,851 2,014,63E -359 2,014,277 1
6E 4,169 4,169 2
10,379 10,347 3
430,075 430,785 46,035 46,035 4
6,88~228,15f 228,158 5
436,15~18,719,68 18,719,687 6
14,300 14,300 7
73, 14~3,54,97f 3,544,975 8
80C 35,30(35,300 9
27,01'926,051 926,051 10
116,021 3,569,68-3,569,684 11
1,20(33,00C 33,000 12
85,200 85,200 1,074,04C 1,074,040 13
56,21~1,666,08€1,666,086 14
8,441,791 650,299 649,168 9,510,548 256,938,753 10,629,829 277,079,13C
FERC FORM NO.1 (ED. 12-90)Page 327.4
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) i1A Resubmission 04/1512011
PU~C~&iED POWER hAccu~t 555)
( nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of elecncity (Le., 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 part 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classifcation Code based on the onginal 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 (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categones, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Descnbe 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)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(1)
1 Sempra Energy Trading SF WSPP
2 Sheep Creek Hydro LU PURPA
3 Sh~IIEil~rgy ..SF ISDA
4 Shell Energy SF WSPP
5 Southem California Edison Co.SF WSPP
6 Snohomish County PUD No. 1 SF WSPP
7 Sovereign Power IF Sovereign
8 Stimson Lumber IU PURPA
9 Tacoma Power SF WSPP
10 Tacoma Power SF WSPP
11 The Energy Authority SF WSPP
12 TransAlta Energy Marketing SF WSPP
13 IntraCompany Generation Services OS OATT
14 Avista Turbine Power LF Lancaster
Total
FERC FORM NO.1 (ED. 12-90)Page 326.5
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2)DA Resubmission 04/15/2011
ccuRt~ontlnUed)(Including power exc ange )
AD - for out-of-penod 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 biling 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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.
6. Report in column (g) the megawatthours shown on bils 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 0), 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 bils 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/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
~l ($~($)of Settlement ($)
(g)(h)(i)(k (i)(m)
99, 15~5,424,66~5,424,668 1
7,09 301,525 301,525 2
2,357,890 2,357,890 3
473,14~18,266,09 18,266,097 4
61C 20,38C 20,380 5
23, 10~689,82C 689,820 6
7,40¿232,201 232,201 7
35,84E 1,964,16C 1,964,160 8
30,60E 939,91~939,913 9
10
10,52~296,901 296,901 11
76,07.3,194,22E 3,194,228 12
631,35C 631,350 13
1,304,09C 22,201,691 22,201,691 14
8,441,791 650,299 649,168 9,510,548 256,938,753 10,629,829 277,079,13C
FERC FORM NO.1 (ED. 12-90)Page 327.5
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) n A Resubmission 04115/2011
PU~C~~ED POWER hAccou~t 5 5)( nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electncity (Le., 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 part 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 affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the onginal 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 (Le., 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 suppliets 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 interrpted 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 availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categones, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Descnbe 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)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Averagè Average
cation Tarif Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Rathdrum Power LLC LF Lancaster
2 Other - Inadvertent Interchange EX
3
4
5
6
7
8
9
10
11
12
13
14
Total
FERC FORM NO.1 (ED. 12-90)Page 326.6
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) riA Resubmission 04/15/2011
cc~~~8gs~ \I.ontinueo)(Including pôwer ex ange)
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, tanffs 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 billng 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 suppliets 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.
6. Report in column (g) the megawatthours shown on bils 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 bils 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 LinePurchasedMegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
~?~~~~f?
of Settlement ($)(g)(h)(i)(m)105,3(1,962,451 1,962,451 1
186 116,512 116,512 2
3
4
5
6
7
8
9
10
11
12
13
14
8,441,791 650,299 649,168 9,510,548 256,938,753 10,629,829 277,079,13(
FERC FORM NO.1 (ED. 12-90)Page 327.6
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
FOOTNOTE DATA
¡Schedule Page: 326 Line No.: 1 Column: a
Fianncial Swap
¡Schedule Page: 326 Line No.: 9 Column: a
Non Monetary
¡Schedule Page: 326 Line No.: 11 Column: a
Ancillary Services - Spinning & Supplemental
!schedule Page: 326 Line No.: 12 Column: aNon Monetary
¡Schedule Page: 326.1 Line No.: 12 Column: a
Non Monetary
¡Schedule Page: 326.2 Line No.: 7 Column: a
Non Monetary
!schedule Page: 326.4 Line No.: 1 Column: aNon Monetary
~ule Page: 326.4 Line No.: 4 Column: a
Non Monetary
¡Schedule Page: 326.5 Line No.: 3 Column: a
Financial Swap
I FERCFORM NO.1 (ED. 12-87)Page 450.1
This Page Intentionally Left Blank
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/1512011
'. "'" "'.' '.'~ '~;Jccunt 456.1 )-(Includino" transactions referred to as 'weelin ')
1. Report all transmission of electricity, i.e., wheeling, provided for other electnc utilties, cooperatives, other public authorities,
qualifying facilities, non-traditional utilty 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 authonty 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 affliation 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-Penod Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in pnor reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 PacifiCorp PacifiCorp PacifiCorp LFP
2 Seattle City Light Seattle City Light Bonnevile Power Administration LFP
3 Tacoma City Light Tacoma City Light Bonnevile Power Administration LFP
4 Grant County Public Utilty District Grant County Public Utilit Distr Grant County Public Utilit Distr LFP
5 Spokane Indian Tribes Bonneville Power Administration Spokane Indian Tribes LFP
6 USBR Bonnevile Power Administration East Greenacres LFP
7 Consolidated Irrigation District Bonnevile Power Administration Consolidated Irrigation District LFP
8 Bonnevile Power Administration Bonnevile Power Administration Bonnevile Power Administration FNO
9 City of Spokane Cit of Spokane Puget Sound Energy LFP
10 Grant County Public Utilit District Bonnevile Power Administration NorthWestern Montana LFP
11 Bonnevile Power Administration Bonnevile Power Administration Idaho Power Company NF
12 Bonnevile Power Administration Bonnevile Power Administration Avista Corporation NF
13 Bonneville Power Administration Bonnevile Power Administration Avista Corporation SFP
14 Bonnevile Power Administration Bonnevile Power Administration Idaho Power Company SFP
15 Idaho Power Company Grant County Public Utilit Distr Idaho Power Company NF
16 Idaho Power Company PacifiCorp Idaho Power Company NF
17 Idaho Power Company Avista Corporation Idaho Power Company NF
18 Idaho Power Company Idaho Power Company Bonnevile Power Administration NF
19 Idaho Power Company Bonnevile Power Administration Idaho Power Company NF
20 Idaho Power Company NorthWestern Montana Idaho Power Company NF
21 Idaho Power Company Chelan Public Utilit District Idaho Power Company NF
22 Idaho Power Company Bonnevile Power Administration Idaho Power Company SFP
23 Idaho Power Company Avista Corporation Bonneville Power Administration SFP
24 Idaho Power Company Idaho Power Company Bonneville Power Administration SFP
25 Idaho Power Company Portland General Electric Idaho Power Company SFP
26 Idaho Power Company NorthWestern Montana Idaho Power Company SFP
27 Idaho Power Company PacifiCorp Idaho Power Company SFP
28 NorthWestern Energy NorthWestern Montana Bonnevile Power Administration NF
29 PacifiCorp PacifiCorp Bonnevile Power Administration NF
30 PacifiCorp PacifiCorp NorthWestern Montana NF
31 PacifiCorp PacifiCorp Idaho Power Company NF
32 PacifiCorp PacifiCorp Bonnevile Power Administration NF
33 Powerex NorthWestern Montana Bonnevile Power Administration NF
34
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) n A Resubmission 04/15/2011
.l.f EL.EC.1 KIÇ;ITY '... ,(Account 4tit:)(l,ontlnUeO)(Including transactions reffered to as 'wlieeling')
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 billng 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 ü) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWattffours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)(g)(h)(i)(j)
FERC No. 182 Dry Creek Walla Wall Dry Gulch 20 50,244 50,244 1
FERC Trf No.8 Chelan-Stratford 115 Stratford 115kV SS 173,230 173,23C 2
FERC TrfNo. 8 Chelan-Stratford 115 Stratford 115kV SS 173,230 173,23C 3
FERC No. 104 Stratford Substation Coulee CylWilson Crk 25 68,582 68,58~4
FERC Trf NO.8 Westside Little Falls 2 2,409 2,405 5
FERC Trf NO.8 Bell Substation Post Falls 3 3,014 3,01.i 6
FERC Trf NO.8 Bell Substation BKRlOPT/EFM/LlB 4 5,599 5,595 7
FERC Trf NO.8 1,760,718 1,760,7H 8
FERC No. 155 Sunset-Westside 115k Westside 23 141,498 141,49f 9
FERC Trf NO.8 BPATPUD Burke 40,299 40,295 10
FERC Trf NO.8 7,848 7,841 11
FERC Trf No.8 12
FERC Trf NO.8 13
FERC Trf NO.8 56,829 56,2!14
FERC Trf NO.8 1,930 1,93(15
FERC Trf NO.8 3,071 3,071 16
FERC Trf NO.8 480 48(17
FERC Trf No.8 13,749 13,745 18
FERC Trf No.8 19,942 19,94~19
FERC Trf NO.8 325 32~20
FERC Trf NO.8 400 40C 21
FERC Trf NO.8 122,163 122,16~22
FERC Trf No.8 6,168 6,16f 23
FERC Trf NO.8 62,115 62,11~24
FERC Trf NO.8 280 28C 25
FERC Trf NO.8 406 40e 26
FERC Trf No. 8 10,837 10,831 27
FERC Trf NO.8 290 29(28
FERC Trf NO.8 2,620 2,62(29
FERC Trf NO.8 30
FERC Trf NO.8 1,519 1,511 31
FERC Trf No.8 21 21 32
FERC Trf No.8 4,455 4,45!33
34
77 2,918,232 2,918,23
FERC FORM NO.1 (ED. 12-90)Page 329
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/15/2011
l u.i: ELEc;TI'I_~."1 T , . (Accu0f56J(Continued)(Including trnsactions reffered to as 'wfeeliñiiÒ)
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling 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 bils 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 bils 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 ü) 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 Energy Charges (Other Charges)Total Revenues ($)¡Line
($)($)($)(k+l+m)No.
(k)(I)(m).(n)
217,930 217,930 1
182,990 182,990 2
182,990 182,990 3
23,750 23,750 4
21,346 21,346 5
16,517 16,517 6
46,982 46,982 7
8,435,924 8,435,924 8
127,506 32,088 159,594 9
240,000 240,000 10
45,473 45,473 11
5,343 5,343 12
1,292 1,292 13
339,572 339,572 14
10,561 10,561 15
22,973 22,973 16
2,770 2,770 17
65,128 65,128 18
109,850 109,850 19
1,908 1,908 20
2,308 2,308 21
569,078 569,078 22
27,133 27,133 23
354,398 354,398 24
1,601 1,601 25
2,322 2,322 26
59,072 59,072 27
1,673 .1,673 28
36,349 36,349 29
12 12 30
37,103 37,103 31
577 577 32
33,432 33,432 33
34
11,450,739 931,928 32,088 12,414,755
FERC FORM NO.1 (ED. 12-90)Page 330
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) ri A Resubmission 04/15/2011
t:YK U i ni; ~u. ~ ccount 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 faciliies, 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 authonty 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 affliation 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 onginal 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 accunting 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 Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authorit)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Powerex Idaho Power Company Bonnevile Power Administration NF
2 Powerex Bonnevile Power Administration Idaho Power Company NF
3 Powerex Bonnevile Power Administration Idaho Power Company SFP
4 Puget Sound Energy Idaho Power Company Bonnevile Power Administration NF
5 Puget Sound Energy NorthWestern Montana Puget Sound Energy NF
6 Puget Sound Energy NorthWestern Montana Bonnevile Power Administration NF
7 Puget Sound Energy Bonnevile Power Administration Idaho Power Company NF
8 Puget Sound Energy NorthWestern Montana Bonnevile Power Administration SFP
9 Portland General Electric NorthWestern Montana Portland General Electric NF
10 Portland General Electric NorthWestern Montana Bonnevile Power Administration NF
11 Portland General Electric NorthWestern Montana Portland General Electric SFP
12 Morgan Stanley Capital Group Avista Corporation Bonnevile Powr Administration NF
13 Morgan Stanley Capital Group Bonnevile Power Administration Idaho Power Company NF
14 Morgan Stanley Capital Group NorthWestern Montana Chelan Public Utilty District NF
15 Morgan Stanley Capital Group NorthWestern Montana Portland General Electric NF
16 Morgan Stanley Capital Group NorthWestern Montana Idaho Power Company NF
17 Morgan Stanley Capital Group NorthWestern Montana Grant County Public Utilty Distr NF
18 Morgan Stanley Capital Group Idaho Power Company Bonnevile Power Administration NF
19 Morgan Stanley Capital Group NorthWestern Montana Bonnevile Power Administration NF
20 Morgan Stanley Capital Group Idaho Power Company Chelan Public Utilty District NF
21 Sierra Pacific Power Company Bonnevile Power Administration Idaho Power Company NF
22 Cargil Power Markets NorthWestern Montana Bonneville Powr Administration NF
23 Cargil Power Markets Idaho Power Company Bonneville Power Administration NF
24 Cargil Power Markets Bonnevile Power Administration Idaho Power Company NF
25 Cargil Power Markets Bonnevile Power Administration Idaho Power Company SFP
26 Cargil Power Markets NorthWestern Montana Bonnevile Power Administration SFP
27 Cargil Power Markets NorthWestem Montana PaciCorp SFP
28 Rainbow Energy Marketing Corp Bonnevile Powr Administration Idaho Power Company NF
29 Rainbow Energy Marketing Corp NorthWestern Montana Idaho Power Company NF
30 Coral Power NorthWestern Montana Chelan Public Utilty District NF
31 Coral Power Chelan Public Utilty District Idaho Power Company NF
32 Coral Power Chelan Public Utilty District NorthWestern Montana NF
33 Coral Power Bonnevile Power Administration Idaho Power Company NF
34
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.1
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) D A Resubmission 04/151011~ FI i "OR .,(Jl ccunt 4(5)(Contlnued-
(Includina transactions reffred to as 'wlieeliñaòf
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 appropnate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropnate 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 u) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand Megawatt Hours MegaWatt Hours No.
Tariff Number Designation)Designation)(MW)Recc;ved Delivered
(e)(f)(g)(h)ü)
FERC Trf NO.8 277 271 1
FERC Trf NO.8 2,632 2,63"2
FERC Trf NO.8 1,600 1,60C 3
FERC Trf NO.8 5 f 4
FERC Trf No. 8 22 2"5
FERC Trf NO.8 21,798 21,79f 6
FERC Trf NO.8 148 14f 7
FERC Trf NO.8 15,779 15,775 8
FERC Trf NO.8 4,760 4,76C 9
FERC Trf NO.8 1,544 1,54 10
FERC Trf No. 8 11
FERC Trf NO.8 25 2f 12
FERC Trf No. 8 993 99 13
FERC Trf No. 8 10,323 10,323 14
FERC Trf NO.8 20 20 15
FERC Trf NO.8 196 196 16
FERC Trf NO.8 383 38 17
FERC Trf No. 8 1,560 1,56C 18
FERC Trf NO.8 7,458 7,45€19
FERC Trf NO.8 1,371 1,371 20
FERC Trf No. 8 1,165 1,16f 21
FERC Trf NO.8 1,998 1,99€22
FERC Trf NO.8 2,980 2,98C 23
FERC Trf NO.8 6,530 6,53C 24
FERC Trf NO.8 18,025 18,02f 25
FERC Trf NO.8 2,368 2,36€26
FERC Trf NO.8 400 400 27
FERC Trf NO.8 80 80 28
FERC Trf No. 8 263 26 29
FERC Trf NO.8 3,126 3,12E 30
FERC Trf NO.8 50 50 31
FERC Trf NO.8 1,704 1,704 32
FERC Trf No. 8 89 89 33
34
77 2,918,232 2,918,232
,
FERC FORM NO.1 (ED. 12-90)Page 329.1
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) 0 A Resubmission 04/15/2011
i . u.1; t:Lt:~ I KI.~II Y i-YK '-! ,_,. ccount 40ö) (~ontinuea)
(Including transactions reffered to as ':W~eeling')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the billng 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 bils or vouchers rendered, including
out of penod adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils 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 entnes and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
1,906 1,906 1
19,610 19,610 2
9,230 9,230 3
29 29 4
133 133 5
133,484 133,484 6
869 869 7
70,000 70,000 8
30,588 30,588 9
9,548 9,548 10
4,639 4,639 11
331 331 12
6,849 6,849 13
69,460 69,460 14
133 133 15
1,282 1,282 16
2,594 2,594 17
10,660 10,660 18
50,123 50,123 19
9,363 9,363 20
6,866 6,866 21
12,115 12,115 22
20,337 20,337 23
31,362 31,362 24
96,638 96,638 25
13,660 13,660 26
2,308 2,308 27
462 462 28
1,517 1,517 29
21,583 21,583 30
288 288 31
9,913 9,913 32
528 528 33
34
11,450,739 931,928 32,088 12,414,755
FERC FORM NO.1 (ED. 12-90)Page 330.1
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/151011
I.Ui- T '. ~l~ccunt456.1)
(Includinc transactions referred to as 'weeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilties, 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 authonty that the energy was delivered to.
Provide the full name of each company or public authonty. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation 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 Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authorit)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Coral Power Idaho Power Company Chelan Public Utility District NF
2 PPL Energy Plus, LLC NorthWestern Montana Bonnevile Power Administration NF
3 PPL Energy Plus, LLC NorthWestern Montana Idaho Power Company NF
4 PPL Energy Plus, LLC NorthWestern Montana Grant County Public Utilty Distr NF
5 TransAlta Energy Marketing (U.S.) Inc.Idaho Power Company Bonnevile Power Administration NF
6 TransAlta Energy Marketing (U.S.) Inc.Bonnevile Powr Administration Idaho Power Company NF
7 NaturEner USA NorthWestem Montana Bonnevile Power Administration NF
8 NaturEner USA NorthWestern Montana Portland General Electric NF
9 NaturEner USA Bonnevile Power Administration NorthWestern Montana SFP
10 NaturEner USA NorthWestem Montana Bonnevile Power Administration SFP
11 NaturEner USA NorthWestem Montana Portland General Electric SFP
12 Grant County Public Utility District Avista Corporation Grant County Public Utilty Distr NF
13 Grant County Public Utilty District NorthWestern Montana Bonnevile Power Administration SFP
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.2
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/15/2011
u.r _~1'I'_,\' ccun'''''Ul\vontlnueo)(Including transactions reffered to'ãs "wlìeeling')
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 billng demand that is specified in the firm transmission service contract.Demandreported 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 Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand Megawatt HOUrs MegaWatt HOUrs No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)(g)(h)(i)Ol
FERC Trf NO.8 70 7C 1
FERC Trf NO.8 520 52C 2
FERC Trf NO.8 1,931 1,931 3
FERC Trf No.8 465 46f 4
FERC Trf NO.8 73 7~5
FERC Trf No. 8 1,553 1,55 6
FERC Trf NO.8 2,833 2,83 7
FERC Trf No.8 3,277 3,27,8
FERC Trf No.8 17,366 17,36€9
FERC Trf NO.8 1,453 1,45 10
FERC Trf NO.8 1,456 1,45€11
FERC Trf-No. 8 12
FERC Trf NO.8 43,292 43,29.13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
77 2,918,232 2,918,23
FERC FORM NO.1 (ED. 12-90)Page 329.2
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/151011
i I OF t:Lt:l, 11'1.':11 T ryl' \. ccunt 456) (Continued)
(Including transactions reffered to as'Weelinai)
9. In column (k) through (n), report the revenue amounts as shown on bils 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 bils or vouchers rendered, including
out of penod adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils 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 0) 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 Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(i)(m)(n)
473 473 1
3,00 3,000 2
11,142 11,142 3
2,683 2,683 4
474 474 5
10,996 10,996 6
22,551 22,551 7
37,350 37,350 8
206,718 206,718 9
16,673 16,673 10
33,149 33,149 11
15,866 15,866 12
147,321 147,321 13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
11,450,739 931,928 32,088 12,414,755
FERC FORM NO.1 (ED. 12-90)Page 330.2
This Page Intentionally Left Blank
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) FiA Resubmission 04/1512011
TRANSMISSION OF ELECTRICITY BY OTHE RS (Accunt 565)
(Including transactions referred to as "weeling,
1. Report all transmission, i.e. wheeling or electricity pròvided by other electric utilties, cooperatives, municipalities, other public
authorities, qualifying facilties, and others for the quarter.
2. In column (a) report each company or public authonty 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 affliation 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 onginal 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 bils 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 bils 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 bils 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 ENERG'EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-. Magawatt-l;tlmano ~nergy .LJtner Total Cost of
lìouTS lìours Charres Char¡ies Charres Trans~ssionAuthority (Footnote Affliations)Classification Received Delivered ($($($
(a)(b)(c)(d)(e)(f)(g)
1 Bonnevile Power Admin LFP 1,172,536 1,17,536
2 Bonneville Powr Admin LFP 11,183,568 1,786,922 12,970,490
3 Bonnevile Power Admin LFP 788,565 788,565...'" .,."..".
4 Bönneí¡iilØPøWØt Admin .....FNS 1,065,965 162,596 1,228,561
5 Bohnevile PoWer Admin ....os 24,360 24,360
6 BonnévilleP()YlêrAd!fin ..:NF 64,578 64,578 280,267 -1,954 278,313
7 ",,,"'01 in ............................................:.......LFP 9,285 9,285
8 Kootenai Elect Coop LFP 45,222 45,222
9 Nortern Lights LFP 138,670 138,670
10 N()rtWestemEnergy ... ...........NF 49,063 49,063 193,321 16,411 209,732
11 Nortwestern Energy SFP 127,589 127,589
12 Portand General Elec LFP 642,989 642,989
13 Portand General Elec NF 510 510 713 713
14 Puget Sound Energy NF 38,234 38,234 87,187 87,187
15 Rainbow Energy Mkt NF
16 Seatte City Light NF 6,905 6,905 9,241 9,241
TOTAL 163,761 163,769 15,165,104 579,405 1,997,620 17,742,129
FERC FORM NO. 1/3-0 (REV. 02-04)Page 332
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) FiA Resubmission 04/15/2011
TRANSri ISS ION OF ELECTRICITY BY OTHERS (Accunt 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electncity provided by other electric utilties, cooperatives, municipalities. other public
authonties, qualifying facilties, 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 affliation 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 bils 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 bils 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 ENERG'I EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawatt-uemano t:nergy J.Jtner Total Cost oflìoUfSlìoursChartesChartesChawesTrans~ssionAuthority (Footnote Affliations)Classification Received Delivered ($($($(a)(b)(c)(d)(e)(f)(g)
1 Snohomish PUD NF
2 Tacoma Power NF 4,479 4,479 8,676 8,676
3
4
5
6
7
8
9
10
11
12
13
14
15
16
TOTAL 163,76c 163,769 15,165,104 579,405 1,997,620 17,742,129
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
FOOTNOTE DATA
¡Schedule Page: 332 Line No.: 2 Column: a
Ancillary Services
¡Schedule Page: 332 Line No.: 4 Column: a
Ancillary Services
'$chedule Page: 332 Line No.: 5 Column: a
Use of Facilities
'$chedule Page: 332 Line No.: 6 Column: a
Ancillary Services
fSchedulé Page: 332 Line No.: 7 Column: a
Use of Facilities
¡Schedule Page: 332 Line No.: 10 Column: a
Ancillary Services
I FERC FORM NO.1 (ED. 12-87) Page 450.1
Name of Respondent This ~ort Is:Date of Rep'ort YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/15/2011
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line Descriltion AmountNo.(a (b)
1 Industry Association Dues 511,266
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 113,998
5 Oth Expn =-=5,000 show purpose, recipient, amount. Group if oc $5,000 1,$6Q,~1
6 Community Relations 615,508
7 Education and Informational 37,192
8 Other Miscellaneous General Expenses 37,208
9 Directors fees and expenses I....593,343
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 3,269,466
FERC FORM NO.1 (ED. 12-94)Page 335
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
FOOTNOTE DATA
!Schedule Page: 335 Line No.: 5 Column: b
ISChedule Page: 335 LineNo.: 5
Purpose AmountVendor
VENDORS LESS THAN $5,000
ADVENTI IN ADVERTISING
AMRICAN GAS ASSOCIATION
AMRICAN STOCK TRSFER & TRUST CO
AZR'S FOOD SERVICES
BANK OF NY - PERSHIG
BNYMELON
BOARDV ANTAGE INC
BROADRIDGE ICS
CHIMAN MOVING & STORAGE (SPOKA) INC
CITANKNA
CORP CREDIT CARD
CORPRATE EXECUTIVE BOAR
CUTAWAY MEDIA
DAVID D HOLME
DAVIS HIBITS & MIDGHAL INC
DESAU1L HEGE COMMICATIONS
DEZDA FI PROPERTI LLC
ENTRPRISE RENT A CAR
ENTRPRISE SEA TIE FOUNDATION
GARD COMMUNICATIONS
HANNA & ASSOCIATES INC
J D POWER AND ASSOCIATES
KLUNT HOSMER
DESIGN
MARKET DECISIONS
CORPRATION
MELON INESTOR SERVICES LLC
MICHAL G ANDREA
MICHAL J FAULKENBERRY
MOODYS INTORS SERVICE
NYSE MA INC
OLS'fN
PATRCIA A NEMA
RH ENERGY SOLUTIONS
ROGER D WOODWORTH
STANARD & POORS
S'fVE L VINCENT
STR 'fOLC RESEARCH ASSOCIATE
SYSTRNDS USA
TH BANK OF NE YORK MELLON
THE BANK OF NEW YORK MELLON TRUST CO
TH DAVENPORT HO'fL
TH LAURL HilL ADVISORY GROUP LLC
I FERC FORM NO.1 (ED. 12-87) Page 450.1
Miscellaneous
Miscellaneous
General Services
Miscellaneous
Miscellaneous
Postage
Subscriptions
General Services
Employee Relocation
Miscellaneous
Telecommunication Use
Subscriptions
Miscellaneous
Employee Misc Expenses
Professional Services
Professional Services
Employee Relocation
Printing
Miscellaneous
Professional Services
Advertising Expenses
Professional services
Professional Services
97,601
13729
o
4692.55
6226
5411
4013.18
22476.08
56609.82
5719.99
46978.62
93610.91
9087.29
17374.97
5157.61
19131.5
43867
5631
6063
5000
53689
6189.04
17326.32
23690.86
Professional Services 1791 I
Miscellaneous
Employee Misc Expenses
Employee Mise Expenses
Miscellaneous
General Service
Workforce - Contract
Professional Services
Professional Services
Offce Supplies
Miscellaneous
Offce Supplies
Professional Services
General Services
Miscellaneous
Miscellaneous
Miscellaneous
General Services
124151.67
13867
o
71471.07
36816.99
390.8
8604.54
o
4840.31
72895
260.94
4548
9350
14212.74
5054
17885
5432.87
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 04/15/2011 2010104
FOOTNOTE DATA
TIDKIG CAP
WASIDGTON ROUNTABLE
WASIDGTON STATE UNERSIT
WILMINGTON TRUST COMPAN
Miscellaneous
Misællaneous
Miscellaneous
Miscellaneous
5963
3725.88
24365.13
3609.65
¡Schedule Page: 335 Line No.: 9 Column: b
ISchedule Page: 335 Line No.: 9
Directors 2010 Expenses
Vendor Name
HEIDI B STANLEY
BRIAN W DUNHAM
MARC F RACICOT
ERIK J ANDERSON
KRISTIANNE BLAKE
REBECCA A KLEIN
JOHN F KELLY
MICHAEL L NOEL
R JOHN TAYLOR
ROYEIGUREN
SCOTT L MORRIS
$73,765
$32,068
$36,307
$74,672
$62,858
$32,711
$71,066
$50,929
$76,745
$74,057
$8,165
IFERC FORM NO.1 (ED. 12-87)Page 450.2
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/1512011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Accunt 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 (Accunt 403.1; (d) Amortization of Limited-Term Electric Plant (Accunt 404); and (e) Amortization of Other Electnc
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accunts 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 accunting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
accunt or functional classification, as appropnate, 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 subaccunt, 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 appropnate for the accunt 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 D~reciation Expense for Asset Limited Term Amortization of
No.Functional Classification xpense Retirement Costs Electric Plant Other Electric Total
(Accunt 403)(Accunt 403.1)(Account 404)Plant (Acc 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 4,383,334 4,383,334
2 Steam Production Plant 10,491,685 10,491,685
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 8,447,346 8,447,346
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 8,974,310 2,450,031 11,424,341
7 Transmission Plant 9,750,937 9,750,937
8 Distribution Plant 28,359,278 28,359,278
9 Regional Transmission and Market Operation
10 General Plant 2,979,759 2,979,759
11 Common Plant-Electric 6,859,386 1,277,131 8,136,517
12 TOTAL 75.862,701 5,660,465 2,450,031 83,973,197
B. Basis for Amortization Charges
FERC FORM NO.1 (REV. 12-03)Page 336
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) FiA Resubmission 04/15/2011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciabie t:stimatea Net Apprea MOrtaliy .
AVerage
No.Accunt No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
fa)(In Th~~~andS)7~r (pergrnt)(per;rnt)Trte 7~l
12 STEAM PLANT
13 Colstrip No. 3
14 311 50,517 65.00 -5.00 2.28 S1.5 17.88
15 312 76,878 60.00 -10.00 2.70 R1 18.57
16 314 18,669 50.00 -10.00 3.39 01 28.07
17 315 9,389 55.00 -5.00 2.49 S1.5 20.78
18 316 8,839 50.00 2.26 R2 15.88
19 Subtotal 164,292
20
21 Colstrip NO.4
22 311 49,668 65.00 -5.00 2.35 S1.5 21.32
23 312 50,137 60.00 -10.00 2.83 R1 23.84
24 314 16,304 50.00 -10.00 3.50 01 28.31
25 315 6,706 55.00 -5.00 2.59 S1.5 25.11
26 316 4,213 50.00 2.46 R3 19.98
27 Subtotal 127,028
28
29 Kettle Falls
30 310 148 35.00 2.19 SO
31 311 24,955 65.00 -5.00 2.34 S1.5 20.59
32 312 41,358 60.00 -10.00 3.31 R1 22.43
33 314 13,308 50.00 -10.00 3.18 01 16.35
34 315 10,838 55.00 -5.00 2.74 S1.5 17.61
35 316 2,604 50.00 2.68 R2 21.44
36 Subtotal 93,211
37
38 HYDRO PLANT
39 Cabinet Gorge
40 330 7,725 75.00 2.75 R3 67.57
41 331 10,670 110.00 -5.00 1.62 RO.5 56.19
42 332 31,134 100.00 1.79 R1.5 77.96
43 333 37,441 60.00 -5.00 2.59 R1.5 52.14
44 334 5,457 45.00 1.43 R2.5 16.54
45 335 2,625 65.00 0.13 R1 1.20
46 336 1,099 60.00 2.05 S2.5 17.49
47 Subtotal 96,151
48
49 Noxon Rapids
50 330 29,974 75.00 2.83 R3 69.37
FERC FORM NO.1 (REV. 12-03)Page 337
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) n A Resubmission 04/1512011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line Depreciaoie i:stimatea Net -Appiiea Mortality l\verage
No.Accunt No.Plant Base Avg. Service Salvage DeFlr. rates Curve Remaining
(a)(In Th~~~ands)~~l (pergrnt)( er:nt)Tyie ~~r
12 331 13,935 110.00 -5.00 1.77 RO.5 81.53
13 332 32,298 100.00 1.79 R1.5 75.35
14 333 75,263 60.00 -5.00 2.89 R1.5 56.01
15 334 14,201 45.00 2.53 R2.5 43.88
16 335 3,378 65.00 0.97 R1 19.90
17 336 225 60.00 2.12 R2.5 39.60
18 Subtotal 169,274
19
20 Post Falls
21 330 2,732 75.00 3.79 R3 56.46
22 331 1,345 110.00 -5.00 0.36 RO.5 56.29
23 332 6,317 100.00 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 R1 53.83
27 Subtotal 13,567
28
29 Long Lake
30 330 418 75.00 5.68 R3 45.63
31 331 2,195 110.00 -5.00 0.12 RO.5 15.32
32 332 16,638 100.00 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 R1 30.46
36 Subtotal 31,427
37
38 Little Falls
39 330 4,217 75.00 7.03 R3 56.31
40 331 1,185 110.00 -5.00 0.12 RO.5 2.00
41 332 5,066 100.00 1.51 R1.5 51.95
42 333 3,971 60.00 -5.00 0.51 R1.5
43 334 2,027 45.00 0.93 R2.5 12.81
44 335 144 65.00 1.18 R1 19.46
45 Subtotal 16,610
46
47 Upper Falls
48 330 64 75.00 2.48 R4 37.64
49 331 584 110.00 -5.00 0.12 RO.5 9.42
50 332 7,126 100.00 1.20 R1.5 76.61
FERC FORM NO.1 (REV. 12-Q3)Page 337.1
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/15/2011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciabie i:srimarea Net Applied Mortality Average
No.Accunt No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)(In Th~~)sands)~~l (pergrnt)(Per:nt)TYKe
~~~
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 R1 51.46
15 Subtotal 13,335
16
17 Nine Mile
18 330 11 75.00 4.59 R3 34.35
19 331 3,943 110.00 -5.00 2.35 RO.5 80.39
20 332 13,350 100.00 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 R1 45.87
24 336 625 60.00 2.64 S2.5 56.50
25 Subtotal 30,490
26
27 Monroe Street
28 331 8,44 110.00 -5.00 1.82 RO.5 109.02
29 332 8,047 100.00 1.72 R1.5 99.22
30 333 11,031 60.00 -5.00 2.28 R1.5 60.23
31 334 1,679 45.00 2.97 R2.5 45.13
32 335 34 65.00 2.04 R1 64.37
33 336 50 60.00 2.17 S2.5 59.42
34 Subtotal 29,285
35
36 OTHER PRODUCTION
37 Northeast Turbine
38 341 365 0.98 SO
39 342 32 55.00 1.31 R3
40 343 9,090 50.00 7.83 S2.5 8.42
41 344 2,605 45.00 0.72 R3
42 345 1,158 40.00 8.54 S1.5 11.83
43 346 300 1.24 SO
44 Subtotal 13,550
45
46 Rathdrum Turbine
47 341 3,259 3.95 SO
48 342 1,696 55.00 4.10 R2.5 44.14
49 343 3,658 50.00 3.61 S2.5 33.50
50 34 48,858 45.00 3.37 R3 35.49
FERC FORM NO.1 (REV. 12-03)Page 337.2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) FiA Resubmission 04/15/2011
DEPRECIA nON AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie i=stimatea Net Appiiea ~onauty Average
No.Accunt No. Plant Base Avg. Service Salvage D~r. rates Curve Remaining
(a)(In Th~~fands)~:(pe(~nt)( er;rnt)TYKe ~gl
12 345 2,567 40.00 3.56 S1.5
13 Subtotal 60,038
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 34 4 45.00 4.98 R3 36.77
19 345 5 40.00 4.48 S1.5 28.83
20 Subtotal 9,169
21
22 Boulder Park
23 341 1,164 2.63 SO
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
27 345 345 40.00 2.97 S1.5 31.24
28 346 7 2.69 SO
29 Subtotal 32,300
30
31 Coyote Springs 2
32 341 11,349 2.76 SO
33 342 19,128 55.00 2.85 R3 44.23
34 34 116,984 45.00 2.92 R3 41.58
35 345 12,701 40.00 3.10 S1.5 32.07
36 346 1,271 2.76 SO
37 Subtotal 161,433
38
39 Solar Power 64
40 Subtotal 64
41 TRANSMISSION PLANT
42 350 15,286 75.00 1.28 R4 53.27
43 352 16,586 60.00 -5.00 1.61 R4 44.73
44 353 192,800 47.00 -15.00 2,39 R3 31.13
45 354 17,121 70.00 -20.00 1.87 S3 43.89
46 355 135,113 60.00 -30.00 1.84 R3 37.27
47 356 108,160 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.1 (REV. 12-03)Page 337.3
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/1512011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie t:stimatea Net Applied MOrtalitY Average
No.Accunt No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)(In Thousands)~~r (pergrnt)(Percent)Tree
7gl(b)(e)
12 Subtotal 491,873
13 DISTRIBUTION PLANT
14 360 1,026
15 361 14,522 55.00 -10.00 1.80 R3 35.51
16 362 97,096 42.00 -10.00 2.60 R1.5 28.26
17 364 229,311 50.00 -25.00 2.66 R2.5 34.66
18 365 151,71€50.00 -15.00 2.46 R2.5 35.35
19 366 77,764 45.00 -1000 2.71 R3 36.09
20 367 129,764 28.00 -15.00 6.38 L4 23.05
21 368 178,518 44.00 -5.00 2.00 R2 27.21
22 369 120,177 60.00 -15.00 1.63 R3 38.01
23 370 46,055 38.00 2.39 S1 33.72
24 373 15,406 32.00 -15.00 1.08 R2.5 8.68
25 373.4 16,361 32.00 -5.00 2.82 R2.5 18.79
26 Subtotal 1,077,716
27
28 GENERAL PLANT
29 390.1 3,589 55.00 -5.00 1.85 S2 20.91
30 391.1 1,991 5.00 17.67 SO 3.80
31 393 390 25.00 2.25 SO 22.97
32 394 3,258 20.00 4.22 SO 10.35
33 395 1,128 15.00 7.72 SO 7.82
34 397 41,361 15.00 5.40 SO 5.17
35 398 8 10.00 2.37 SO 7.80
36 Subtotal 51,725
37
38 MISCPOWER
39 392 2,739 11.00 10.00 3.70 S3
40 396 2,266 15.00 10.00 5.40 L2
41 Subtotal 5,005
42
43
44
45
46
47
48
49
50
FERC FORM NO.1 (REV. 12.03)Page 337.4
Name of Respondent This mort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/151011
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie ~stimatea Net Appiiea MOnall:Y Average
No.Accunt No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)(In Thousands)~~(pergrnt)(per~nt)TYKe ~~l(b)
12 Lancaster
13 342 92 52.43
14 344 209 42.90
15 SUBTOTAL 301
16
17 TOTAL COMPANY 2,687,844
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
48
49
50
FERC FORM NO.1 (REV. 12-03)Page 337.5
This Page Intentionally Left Blank
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) FiA Resubmission 04/1512011
REGULATORY COMMISSION EXPEN ES
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 part.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Line Description Assessed by Expenses Total . Deferred
No.(Furnish name of regulatory commission or body the Regulatory of Expense for in Accunt
Commission Current Year .18i.3 a¡docket or case number and a description of the case)Utilty (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
1 Federal Energy Regulatory Commission
2 Charges include annual fee and license fees
3 for the Spokane River Project. the Cabinet
4 Gorge Project and the Noxon Rapids Project.2,247,187 345,541 2,592,728
5 ,
6
7
8
9 Washington Utilties and Transportation
10 Commission: includes annual fee and various
11 other electric dockets 907,189 285,206 1,192,395
12
13 Includes annual fee and various other natural
14 gas dockets 421,053 127,029 548,082
15
16 Idaho Public Utilties Commission
17 Includes annual fee and various other electric
18 dockets 505,813 190,597 696,410
19
20 Includes annual fee and various other natural
21 gas dockets 170,468 96,189 266,657
22
23 Public Utilty Commission of Oregon
24 Includes annual fees and various other natural
25 gas dockets 566,667 61,737 628,404
26
27 Not directly assigned electric 1,068,709 1,068,709
28 Not directly assigned natural gas 411,641 411,641
29
30 .
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 4,818,377 2,586,649 7,405,026
FERC FORM NO.1 (ED. 12-96)Page 350
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/15/2011
REGULA TORY 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 dunng year which were charged currently to income, plant, or other accunts.
5.Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to Contra Amount Deferred in LineDepartmentAmOUntAccount 182.3 Accunt Accunt 182.3 No.No.End of Year (fl (g)lh)(i)0)(k)(I)
1
2
3
Electric 928 2,592,728 4
5
6
7
8
9
10
Electric 928 1,192,395 11
12
13
Gas 928 548,082 14
15
16
17
Electric 928 696,410 18
19
20
Gas 928 266,657 21
22
23
24
Gas 928 628,404 25
26
Electric 928 1,068,709 27
Gas 928 411,641 28
29
30
31
32
33
.34
35
36
37
38
39
40
41
42
43
44
45
7,405,026 46
FERC FORM NO.1 (ED. 12-96)Page 351
This ~ort Is: Date of Report
(1) ~An Original (Mo. Da, Yr)
(2) A Resubmission 0411512011
DISTRIBUTION OF SALARIES AND WAGES
Report below the distnbution of total salaries and wages for the year. Segregate amounts onginally charged to cleanng accunts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropnate lines and columns
provided. In determining this segregation of salaries and wages onginally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Name of Respondent
Avista Corporation
Year/Penod of Report
End of 2010/04
(a)
TotalLine
No.
Classification
1 Electric
2 Operation
3 Production
4 Transmission
5 Regional Market
6 Distribution
7 Customer Accounts
8 Customer Service and Informational
9 Sales
10 Administrative and General
11 TOTAL Operation (Enter Total of lines 3 thru 10)
12 Maintenance
13 Production
14 Transmission
15 Regional Market
16 Distribution
17 Administrative and General
18 TOTAL Maintenance (Total of lines 13 thru 17)
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)
21 Transmission (Enter Total of lines 4 and 14)
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)
24 Customer Accunts (Transcribe from line 7)
25 Customer Service and Informational (Transcribe from line 8)
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17)
28 TOTAL Oper. and Maint. (Total of lines 20 thru 27)
29 Gas
30 Operation
31 Production-Manufactured Gas
32 Production-Nat. Gas (Including Expl. and Dev.)
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42 Maintenance
43 Production-Manufactured Gas
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
4,154,967
6,114,360
634,361
129,785
13,792,391
37,120,168
8,233,356
6,114,360
634,361
129,785
13,792,391
44,530,986
3,563,152
2,641,759
330,534
49,990
4,840,841
12,270,604
FERC FORM NO.1 (ED. 12-88)Page 354
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
DISTRIBUTION OF SALARIES AND WAGES (Continued)
YearlPeriod of Report
End of 2010/04
(a)
Direct PayrollDistribution
(b)
Totalline
No.
Classification
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru
56 Transmission (Lines 35 and 47)
57 Distribution (Lines 36 and 48)
58 Customer Accounts (line 37)
59 Customer Service and Informational (Line 38)
60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)
63 Other Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64)
66 Utilty Plant
67 Construction (By Utility Departments)
68 Electric Plant
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70)
72 Plant Removal (By Utilty Departments)
73 Electric Plant
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)
77 Other Accunts (Specify, provide details in footnote):
78 Stores Expense (163)
79 Preliminary Survey and Investigation (183)
80 Small Tool Expense (184)
81 Miscellaneous Deferred Debits (186)
82 Merchandising Expenses (416)
83
84 Expenditures of Certain Civic, Political and Related Activiti
85 Employee Incentive Plan (232380)
86 DSM Tarrif Rider and Payroll Equalization Liab. (242600, 2427
87 Incentivel Stock Compensation (238000)
88
89
90
91
92
93
94
95 TOTAL Other Accounts
96 TOTAL SALARIES AND WAGES
598,383
6,080,136
2,641,759
330,534
49,990
4,840,841
15,385,971 7,515,613 22,901,584
~----- -~---- - ~-- ~---- - ---- - ---- -
i
59,916,957 17,218,097 77,135,054
29,478,679
5,935,086
6,478,172
1,304,281
35,956,851
7,239,367
1- ~- -~--- -------~----- ---- ---- -~35,413,765 7,782,453 43,196,218
1,309,103 280,493 1,589,596
96,345 20,643 116,988
1,405,448 301,136 1,706,584
1,698,876 -1,698,876
36,969 36,969
4,157,526 -4,157,526
772,896 772,896
288,382 288,382
532,655 532,655
5,917,714 -5,917,714
16,506,045 -14,809,334 1,696,711
76,010 76,010
29,987,073
126,723,243
-26,583,450
-1,281,764
3,403,623
125,441,479
FERC FORM NO.1 (ED. 12-88)Page 355
Year/Period of ReportDate of Report
(Mo, Da, Yr)
04/1512011
Name of Respondent
Avista Corporation
This Report Is:
(1) IX An Original
(2) 0 A Resubmission 2010/04End of
COMMON UTILITY PLANT AND EXPENSES
1. Describe the property carried in the utiltys accunts as common utilit plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utilty Plant, of the Uniform System of Accunts. Also show the allocation of such plant costs to
the respective departments using the common utilty 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 utilty departments using the Common utilit 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 utilit plant classified by accounts as
provided by the Uniform System of Accunts. Show the allocation of such expenses to the departments using the common utilit 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 utiit 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.
303
389
390
391
392
393
394
395
396
397
398
399
Description
Intangible
Land and Land Rights
Structures and Improvements
Office Furniture and Equipment
Transportation Equipment
Stores Equipment
Tools, Shop & Garage Equipment
Laboratory Equipment
Power Operated Equipment
Communications Equipment
Miscellaneous Equipment
Asset Retirement Cost
Total Common Plant
Const. Work in Progress
Total Utility Plant
Acc. Prov. for Dep. & Amort.
Net Utility Plant
3. Common Expenses allocated to Electric and Gas
Acct. No.TotalDescription
901 Cust acct/collect 1,118,953
supervision
902 Meter reading expenses 4,207,359
903 Cust rec & collection 13,160,557
expenses
903.90-99 A/R misc fees 426,347
904 Uncollectible accounts 3,160,171
905 Misc cust acct expenses 247,244
907 Cust srvc & Info exp 0
supervision
908 Cust assistance exp 980,345
909 Info & instruct advert 1,508,278
33,088,760
5,288,514
59,082,583
35,855,609
9,005,542
1,480,701
4,664,596
573,784
2,384,859
21,621,565
412,287
370,928
173,829,729
16,886,691
190,716,420
46,741,851
143,974,569
departments:
Allocation to
Electric Dept
Allocated to
Gas Dept
Basis of
Allocation
592,956 525,998 #of cust Cé yr end
2,598,717 1,608,642 #of cust Cé yr end
7,176,227 5,984,329 #of cust Cé yr end
340,822 85,525 net direct plant
1,674,638 1,485,533 #of cust Cé yr end
131,019 116,225 #of cust Cé yr end
0 0 #of cust Cé yr end
605,497 374,847 #of cust Cé yr end
842,202 666,076 #of cust Cé yr end
FERC FORM NO.1 (ED. 12-87)Page 356
Name of Respondent
Avista Corporation
This Report Is:
(1) IX An Original
(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2011
Year/Period of Report
End of 2010104
COMMON UTILITY PLANT AND EXPENSES
1. Describe the propert carried in the utiltys accounts as common utilty plant and show the book cost of such plant at end of year classifed by
accunts as provided by Plant Instruction 13, Common Utilty Plant, of the Uniform System of Accunts. Also show the alloction of such plant costs to
the respective departments using the common utilty 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, showng the amounts and classifications of such accumulated
provisions, and amounts allocated to utilty 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 utilty plant classified by accounts as
provided by the Uniform System of Accunts. Show the allocation of such expenses to the departments using the common utilty 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 utilty plant classification and reference to order of the Commission or other
authorization.
exenses
910 Misc cust srvc & info 318,612 168,978 149,634 #of cust cg yr end
expenses
911 Sales expense sprvsn 0 0 0 #of cust cg yr end
912 Demo and selling expenses 10,622 4,734 5,927 #of cust cg yr end
913 Advertising expenses 732 452 280 #of cust cg yr end
916 Misc sales expenses 311,235 192,237 118,998 #of cust cg yr end
920 Admin & gen salaries 32,531,389 23,603,594 8,927,794 four factor
921 Office supplies &5,489,199 3,964,539 1,524,660 four factor
expenses
922 Admin exenses tranf-3,438 2,556 883 four factor
cred
923 OUtside srvcs employed 20,319,181 14,669,258 5,649,923 four factor
924 Property insurance 1,507,926 1,088,617 419,309 four factor
925 Injuries and damages 6,302,224 4,698,609 1,603,615 four factor
926 Employee pensions &47,334,327 34,290,934 13,043,392 four factorbenefits
927 Franchise requirement 0 0 0 four factor
928 Regulatory commission 1,491,104 1,077,199 413,905 four factor
expenses
929 Duplicate charges-credit 0 0 0 four factor
930.1 General advertising 281,990 203,858 78,131 four factor
expenses
930.2 Misc general expenses 3,858,816 2,818,869 1,039,948 four factor
931 Rents 1,072,579 777,341 295,238 four factor
935 Maint of general plant 8,171,994 5,961,093 2,210,901 four factor
403 Depreciation 9,392,046 6,859,385 2,532,661 four factor
404 Amort of LTD term plant 6,070,782 4,383,336 1,687,446 four factor
Note 1: The four factor allocator is made up of 25 percent each of customer counts, direct labor, direct
O&M & Net direct plant
4. Letters of approval received from staffs of State Regulatory Commissions in 1993
FERC FORM NO.1 (ED. 12-87)Page 356.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 0411512011
PURCHASES AND SALES OF ANCILLAR SERVICES
Report the amounts for each type of ancilary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Accss Transmission Tanff.
In columns for usage, report usage-related billng determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancilary 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 dunng 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), (è), (f), and (g) report the total amount of all other types ancilary 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 Biling Determinant Usage - Related Billng Determinant
Unit of Unit of
Line Type of Ancilary Service Number of Units Measure Dollars Number of Units Measure Dollars
No.(a)(b)(c)(d)(e)(f)(g)
1 Scheduling, System Contrl and Dispatch 622 MW 126,180
2 Reacte Supply and Voltge
3 Regulation and Freuency Resnse 219,874 MWh 32,981 70,621 MW 631,350
4 Energy Imbalance 966 MW 4,159,507
5 Operating Reserve - Spinning 54,117 MWh 529,652 57,448 MWh 528,859
6 Operating Reserve - Supplement 49,243 MWh 406,544 21,667 MWh 226,622
7 Other
. c 1,317,84 MW ...11,780,987 1,317,784 MW :.11,i8Mäi
8 Total (Lines 1 thru 7)1,641,640 12,876,344 1,468,486 17,327,325
FERC FORM NO.1 (New 2-04)Page 398
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
FOOTNOTE DATA
¡Schedule Page: 398 Line No.: 7 Column: bInterdepartmentalspinning reserve service for Native Load.
¡Schedule Page: 398 Line No.: 7 Column: dIn terdepartmen tal spinning reserve service for Native Load.
¡Schedule Page: 398 Line No.: 7 Column: eInterdepartmentalspinning reserve service for Native Load.
¡Schedule Page: 398 Line No.: 7 Column: gIn terdepartmen tal spinning reserve service for Native Load.
I FERC FORM NO.1 (ED. 12-87)Page 450.1
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/15/2011
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 ul by month the system' monthly maximum megawatt load by statistical classifcations. See General Instruction for
the definition of each statistical classification.
NAME OF SYSTEM:
Monthly Peak
MW-Total
Line
No.Month
Day of
Monthly
Peak
(c)
Hour of Firm Network
Monthly Servce for Self
Peak
(a)(b)
1 Januar
2 February
3 March
4 Total for Quartr 1
5 April
6 May
7 June
8 Total to Quarer 2
9 July
10 August
11 September
12 Total to Quartr 3
13 Ocbe
14 November
15 Dember
16 Total for Quarter 4
17 Total Year to
Datear
2,38
2,2
2,00
6,69
2,16
1,95
2,25
6,38
2,31
2,30
1,88
6,50
2,16
2,461
2,29
6,92
"
1700
1700
1800
i'i
(e)
1,487
1,257
1,293
4,037
1,268
1,193
1,292
3,753
1,492
1,490
1,173
4,155
1,124
1,619
1,44
4,187
16,132
Firm Network Long-Term Firm Oter Long- Short-Term Firm Oter
Service for Point-toint Term Firm Point-topoint Servic
Oters Reservations Service Reservation
(f)(g)(h)(i)ul
306 190 38 405 57
248 190 36 601 59
26 201 33 248 225
820 581 107 1,254 341
232 209 22 460 171
244 210 44 312 299
229 203 44 528 118
705 622 110 1,300 588
260 212 40 355 120
253 207 25 355 238
189 200 37 320 188
702 619 102 1,030 546
207 197 21 637 198
350 190 31 302 282
288 190 25 377 42
845 577 77 1,316 522
3,072 2,399 396 4,900 1,997
FERC FORM NO. 1/3-0 (NEW. 07-04)Page 400
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) EiA Resubmission 04/15/2011
ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line Item MegaWatt Hours Line Item MegaWatt Hours
No.No.
(a)(b)(a)(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to Ultimate Consumers (Including 8,856,389
3 Steam 2,061,17~Interdepartmental Sales)
4 Nuclear 23 Requirements Sales for Resale (See
5 Hydro-Conventional 3,493,58f instruction 4, page 311.)
6 Hydro-Pumped Storage 24 Non-Requirements Sales for Resale (See 6,251,508
7 Other 1,686,988 instruction 4, page 311.)
8 Less Energy for Pumping 25 Energy Furnished Without Charge
9 Net Generation (Enter Total of lines 3 7,241,750 26 Energy Used by the Company (Electric 10,733
through 8)Dept Only, Excluding Station Use)
10 Purchases 8,441,791 27 Total Energy Losses 566,042
11 Power Exchanges:28 TOTAL (Enter Total of Lines 22 Through 15,684,672
12 Received 650,29~27) (MUST EOUAL LINE 20)
13 Delivered 649,16f
14 Net Exchanges (Line 12 minus line 13)1,131
15 Transmission For Other (Wheeling)
16 Received 2,918,232
17 Delivered 2,918,23¿
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses
20 TOTAL(EnterTotaloflines9,10, 14,18 15,684,67~
and 19)
FERC FORM NO.1 (ED. 12-90)Page 401a
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) 0 A Resubmission 04/15/2011
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 system's monthly maximum megawatt load (60 minute integration) associated with the system.
5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
NAME OF SYSTEM:
Line Monthly Non-Requirments MONTHLY PEAK
No.Sales for Resale &Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(f)29 January 1,327,445 448,076 1,526 7 1800
30 February 1,199,451 436,865 1,383 23 0800
31 March 1,313,274 535,803 1,348 10 0800
32 April 1,318,158 579,345 1,286 6 0900
33 May 1,167,464 443,620 1,245 6 0900
34 June 1,261,626 566,083 1,34 28 1700
35 July 1,444,136 650,286 1,552 26 1700
36 August 1,282,393 487,071 1,556 5 1700
37 September 1,262,155 561,087 1,210 3 1700
38 October 1,277,014 517,792 1,301 25 1900
39 November 1,406,544 548,097 1,704 23 1900
40 December 1,425,012 477,383 1,597 16 1800
41 TOTAL 15,684,672 6,251,508
FERC FORM NO.1 (ED. 12-90)Page 401b
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2010/04
(2) DA Resubmission 0415/2011 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in service only.2. Large plants are steam plants with installed capaci (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 facilty.4. If net peak demand for 60 minutes is not available, give data which is available, speciing period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Ouantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expnse accunts 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 bumed.
Line Item Plant Plant
No.Name: COyote Springs 2
,Name: Spokane N.E.
(a)(b)(c)
,..'i",,.., ..
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine Gas Turbine
2 Type 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)307 51
7 Plant Hours Connected to Load 6416 19
8 Net Continuous Plant Capabilty (Megawatts)278 61
9 When Not Limited by Condenser Water 278 0
10 When Limited by Condenser Water 278 0
11 Average Number of Employees 22 1
12 Net Generation, Exclusive of Plant Use - KWh 1661182000 687000
13 Cost of Plant: Land and Land Rights 0 157277
14 Structures and Improvements 11348799 365280
15 Equipment Costs 1500841 13193240
16 Asset Retirement Costs 351682 0
17 Total Cost 161784922 13715797
18 Cost per KW of Installed Capacity (line 17/5) Including 563.7105 221.9385
19 Production Expenses: Oper, Supv, & Engr 786563 29139
20 Fuel 61382688 62238
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 2064950 21774
26 Misc Steam (or Nuclear) Power Expenses 49443 3668
27 Rents 67255 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 614377 5468
30 Maintenance of Structures 0 462
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 1148793 86863
33 Maintenance of Misc Steam (or Nuclear) Plant 3485 34034
34 Total Production Expenses 66117554 243646
35 Expenses per Net KWh 0.0398 0.3547
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas Gas
37 Unit (Coal-tonslOil-barreI/Gas-mcf/Nuclear-indicate)MCF MCF
38 Ouantit (Units) of Fuel Burned 11356459 0 0 12130 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)1020000 0 0 1020000 0 0
40 Avg Cost of Fuellunit, as Delvd f.o.b. during year 5.405 0.000 0.000 5.131 0.000 0.000
41 Average Cost of Fuel per Unit Burned 5.405 0.000 0.00 5.131 0.000 0.000
42 Average Cost of Fuel Burned per Milion BTU 5.299 0.000 0.000 5.030 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.037 0.000 0.000 0.091 0.000 0.000
44 Average BTU per KWh Net Generation 6973.000 0.000 0.00 18010.000 0.000 0.000
FERC FORM NO.1 (REV. 12-03)Page 402
Name of Respondent This (!0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2010/04(2)DA Resubmission 04/15/2011 End of
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, Accunt 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 Plant Plant Line
Name: Kette Falls Name:Colstrip Name:Rathdrum No.
(d)(e)(f)
......... ... -. .
,c. ..
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
50 227 --147 6
7402 8759 144 7
50 222 149 8
50 222 0 9
50 222 0 10
31 210 2 11
312276000 1748898000 10719000 12
941300 1289095 621682 13
24955417 100185043 3258386 14
68107702 191134566 56779395 15
450687 134589 0 16
94455106 292743293 60659463 17
1863.0198 1254.2558 364.3211 18
355493 180662 24385 19
11953801 16398780 545160 20
0 0 0 21
587712 3677996 0 22
0 0 0 23
0 0 0 24
801210 37137 150490 25
318820 2060904 181761 26
0 15498 0 27
0 0 0 28
123849 323810 407 29
13384 476268 4566 30
1757762 3142265 108557 31
253104 392594 0 32
321102 340421 30670 33
16606697 2704335 1045996 34
0.0532 0.0155 0.0976 35
Wood Gas Coal Oil Gas 36
Tons MCF Tons Bbls MCF 37
434622 5506 0 1075160 1627 0 120297 0 0 38
8500000 1020000 0 16855667 140000 0 1020000 0 0 39
27.431 5.384 0.00 15.123 85.581 0.00 4.532 0.00 0.00 40
27.431 5.384 0.000 15.123 85.581 0.000 4.532 0.000 0.000 41
3.230 5.278 0.000 0.900 14.420 0.000 4.443 0.000 0.000 42
0.038 0.063 0.000 0.009 0.000 0.000 0.051 0.000 0.000 43
11848.000 0.000 0.000 10368.000 0.000 0.00 11447.000 0.00 0.000 44
FERC FORM NO.1 (REV. 12-03)Page 403
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2010104
(2) DA Resubmission 04/1512011 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only.2. Large plants are steam plants wih installe 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 facilit.4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities offuel burned (Line 38) and average cost
per unit offuel bumed (Line 41) must be consistent with charges to expense accunts 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 Item Plant Plant
No.Name: Boulder Park Name:
(a)(b)(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Internal Comb
2 Type 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 514 0
8 Net Continuous Plant Capabilty (Megawatts)24 0
9 When Not Limited by Condenser Water 0 0
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 1 0
12 Net Generation, Exclusive of Plant Use - KWh 10938000 0
13 Cost of Plant: Land and Land Rights 144733 0
14 Structures and Improvements 1163930 0
15 Equipment Costs 31136453 0
16 Asset Retirement Costs 0 0
17 Total Cost 32445116 0
18 Cost per KW of Installed Capacity (line 17/5) Including 1318.9072 0.0000
19 Production Expenses: Oper, Supv, & Engr 24057 0
20 Fuel 527656 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 76531 0
26 Misc Steam (or Nuclear) Power Expenses 20097 0
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 3876 0
30 Maintenance of Structures 3346 0
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 333801 0
33 Maintenance of Misc Steam (or Nuclear) Plant 39498 0
34 Total Production Expenses 1028862 0
35 Expenses per Net KWh 0.0941 0.0000
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas
37 Unit (Coal-tons/Oil-barreVGas-mcf/Nuclear-indicate)MCF
38 Ouantity (Units) of Fuel Burned 107278 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 FueVunit, as Delvd f.o.b. during year 4.919 0.000 0.000 0.000 0.000 0.00
41 Average Cost of Fuel per Unit Burned 4.919 0.000 0.00 0.000 0.000 0.000
42 Average Cost of Fuel Burned per Milion BTU 4.822 0.000 0.000 0.000 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.048 0.00 0.000 0.000 0.000 0.00
44 Average BTU per KWh Net Generation 10004.000 0.000 0.000 0.000 0.000 0.000
FERC FORM NO.1 (REV. 12-03)Page 402.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2010/04(2) D A Resubmission 04115/2011 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accunts. 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, Accunt 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) accunting 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 conceming plant type fuel used, fuel enrichment tye and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant LineName:Name:Name:No.
(d)(e)(f)
1
2
3
4
0.00 0.00 0.00 5
0 0 0 6
0 0 0 7
0 0 0 8
0 0 0 9
0 0 0 10
0 0 0 11
0 0 0 12
0 0 0 13
0 0 0 14
0 0 0 15
0 0 \0 16
0 0 0 17
0.0000 0.0000 0.000 18
0 0 0 19
0 0 0 20
0 0 0 21
0 0 0 22
0 0 0 23
0 0 0 24
0 0 0 25
0 0 0 26
0 0 0 27
0 0 0 28
0 0 0 29
0 0 0 30
0 0 0 31
0 0 0 32
0 0 0 33
0 0 0 34
0.0000 0.0000 0.0000 35
36
37
0 0 0 0 0 0 0 0 0 38
0 0 0 0 0 0 0 0 0 390.000 0.000 0.00 0.00 0.000 0.000 0.000 0.000 0.000 400.000 0.00 0.000 0.00 0.000 0.000 0.000 0.000 0.000 410.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 420.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 430.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44
FERC FORM NO.1 (REV. 12-03)Page 403.1
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
FOOTNOTE DATA
¡Schedule Page: 402 Line No.: -1 Column: b
Operated by Portland General Electric.
!Schedule Page: 402 Line No.: -1 Column: e
Joint project operated by PPL Montana LLC.
I FERC FORM NO.1 (ED. 12-87)Page 450.1
This Page Intentionally Left Blank
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2010/04
(2) DA Resubmission 04/1512011 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacit (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilty, 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 specfying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.2545 FERC Licensed Project No.2545
No.Plant Name: Monroe Street Plant Name: Upper Falls
(a)(b)(c)
... .........Tú ................................................,.......,.";J.... .
.'..:. :.
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 Total installed cap (Gen name plate Rating in MW)14.80 10.20
6 Net Peak Demand on Plant-Megawatts (60 minutes)16 15
7 Plant Hours Connect to Load 8,626 8,435
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions 15 10
10 (b) Under the Most Adverse Oper Conditions 14 10
11 Average Number of Employees 1 1
12 Net Generation, Exclusive of Plant Use - Kwh 105,901,000 71,163,000
13 Cost of Plant
14 Land and Land Rights 0 1,081,854
15 Structures and Improvements 8,443,779 584,216
16 Reservoirs, Dams, and Waterways 8,047,296 7,126,169
17 Equipment Costs 12,743,784 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)29,285,307 14,353,474
21 Cost per KW of Installed Capacity (line 20 I 5)1,978.7370 1,407.2033
22 Production Expenses
23 Operation Supervision and Engineering 31 7
24 Water for Power 0 0
25 Hydraulic Expenses 391 0
26 Electric Expenses 492,429 502,096
27 Misc Hydraulic Power Generation Expenses 17,848 37,301
28 Rents 0 0
29 Maintenance Supervision and Engineering 1,573 11,672
30 Maintenance of Structures 2,150 11,935
31 Maintenance of Reservoirs, Dams, and Waterways 99,293 50,642
32 Maintenance of Electric Plant 76,018 50,104
33 Maintenance of Misc Hydraulic Plant 13,608 4,061
34 Total Production Expenses (total 23 thru 33)703,341 667,818
35 Expenses per net KWh 0.0066 0.0094
FERC FORM NO.1 (REV. 12-03)Page 406
Name of Respondent
Avista Corporation
Year/Penod of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/1512011
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 classifed 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.
Plant Name: Cabinet Gorge
FERC Licensed Project No. .2058
Plant Name: Noxon Rapids
(e)
FERC Licensed Project No. 2545
Plant Name: Long Lake
Line
No.
Storage
Outdoor
1952
1953
265.00
261
8,758
Storage
Outdoor
1959
1977
480.60
545
6,686
Storage
Conventional
1915
1924
70.00
90
7,028
10,573,152
10,670,126
31,133,950
45,523,191
1,098,564
o
98,998,983
373.5811
35,831,527
13,934,921
32,298,217
92,841,623
225,369
o
175,131,657
364.4021
1,597,959
2,194,764
16,637,951
12,176,179
o
o
32,606,853
465.8122-- ~-~-~- - ~ -~-~-- --- - --- -
102,869 115,030 11,187 23
0 0 0 24
1,164 6,210 9,270 25
1,044,638 1,192,827 626,390 26
128,782 280,202 75,344 27
111 0 0 28
26,904 55,878 13,852 29
127,897 232,209 39,984 30
95,711 451,694 48,350 31
424,579 411,518 182,349 32
11,474 -50,770 13,265 33
1,964,129 2,694,798 1,019,991 34
0.0021 0.0018 0.0021 35
FERC FORM NO.1 (REV. 12-03)Page 407
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2010/04
(2) DA Resubmission 04/1512011 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installe capacit (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilty, 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 specifing peñod.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.~040 ....FERC Licensed Project No.2545
No.Plant Name: Nine Mile Falls Plant Name: Post Falls
(a)(b)(c)
1....0--.......,:...,.....................:-¡'.::.:.
1 Kind of Plant (Run-of-River or Storage)Run-of-River Storage
2 Plant Construction type (Conventional or Outdoor)Conventional Conventional
3 Year Originally Constructed 1908 1906
4 Year Last Unit was Installed 1994 1980
5 Total installed cap (Gen name plate Rating in MW)26.40 14.80
6 Net Peak Demand on Plant-Megawatts (60 minutes)23 18
7 Plant Hours Connect to Load 8,696 8,760
8 Net Plant Capabilit (in megawatts)
9 (a) Under Most Favorable Oper Conditions 18 18
10 (b) Under the Most Adverse Oper Conditions 18 14
11 Average Number of Employees 2 2
12 Net Generation, Exclusive of Plant Use - Kwh 101,430,000 90,272,000
13 Cost of Plant
14 Land and Land Rights 33,429 3,076,554
15 Structures and Improvements 3,943,110 1,345,554
16 Reservoirs, Dams, and Waterways 13,350,064 6,317,496
17 Equipment Costs 12,560,784 3,171,979
18 Roads, Railroads, and Bridges 625,181 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)30,512,568 13,911,583
21 Cost per KW of Installed Capacity (line 20 I 5)1,155.7791 939.9718
22 Production Expenses
23 Operation Supervision and Engineering 350 20,124
24 Water for Power 0 0
25 Hydraulic Expenses 9,635 0
26 Electric Expenses 616,984 598,189
27 Misc Hydraulic Power Generation Expenses 33,207 37,566
28 Rents 0 0
29 Maintenance Supervision and Engineering 17,070 15,647
30 Maintenance of Structures 38,766 15,202
31 Maintenance of Reservoirs, Dams, and Waterways 68,735 395,688
32 Maintenance of Electric Plant 102,820 76,479
33 Maintenance of Misc Hydraulic Plant 4,710 10,023
34 Total Production Expenses (total 23 thru 33)892,277 1,168,918
35 Expenses per net KWh 0.0088 0.0129
FERC FORM NO.1 (REV. 12-03)Page 406.1
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/15/2011
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accunts prescribed by the Uniform System of Accunts. 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.
Plant Name: Little Falls
(d)
o FERC Licensed Project No.
Plant Name:
o FERC Licensed Project No.
Plant Name:
o Line
No.
(e)
- - ~ ~ -- -- - ~---- ~- ~ - - - - - -
Run-of-River
Conventional
1910
1911
32.00
37
7,015
0.00
o
o
0.00
o
o
1
2
3
4
5
6
7
35 0 0 9
26 0 0 10
5 0 0 11
200,463,000 0 0 12
13
4,325,371 0 0 14
1,184,974 0 0 15
5,065,501 0 0 16
6,142,651 0 0 17
0 0 0 18
0 0 0 19
16,718,497 0 0 20
522.4530 0.0000 0.000 21-- --~- - - --- - -- - - - - - - --
241 0 0 23
0 0 0 24
8,977 0 0 25
598,139 0 0 26
47,518 0 0 27
721,398 0 0 28
18,331 0 0 29
54,553 0 0 30
24,029 0 0 31
246,604 0 0 32
4,827 0 0 33
1,724,617 0 0 34
0.0086 0.0000 0.0000 35
FERC FORM NO.1 (REV. 12-03)Page 407.1
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2010/04
(2) D A Resubmission 04/1512011 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacit (name plate raings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilty, 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 specifing period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.0 FERC Licensed Project No.0
No.Plant Name:Plant Name:
(a)(b)(c)
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)0.00 0.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)0 0
7 Plant Hours Connect to Load 0 0
8 Net Plant Capabilit (in megawatts)
9 (a) Under Most Favorable Oper Conditions 0 0
10 (b) Under the Most Adverse Oper Conditions 0 0
11 Average Number of Employees 0 0
12 Net Generation, Exclusive of Plant Use - Kwh 0 0
13 Cost of Plant
14 Land and Land Rights 0 0
15 Structures and Improvements 0 0
16 Reservoirs, Dams, and Waterways 0 0
17 Equipment Costs 0 0
18 Roads, Railroads, and Bridges 0 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)0 0
21 Cost per KW of Installed Capacity (line 20 I 5)0.0000 0.0000
22 Production Expenses
23 Operation Supervision and Engineering 0 0
24 Water for Power 0 0
25 Hydraulic Expenses 0 0
26 Electric Expenses 0 0
27 Misc Hydraulic Power Generation Expenses 0 0
28 Rents 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 0 0
31 Maintenance of Reservoirs, Dams, and Waterways 0 0
32 Maintenance of Electric Plant 0 0
33 Maintenance of Misc Hydraulic Plant 0 0
34 Total Production Expenses (total 23 thru 33)0 0
35 Expenses per net KWh 0.0000 0.000
FERC FORM NO.1 (REV. 12-Q3)Page 406.2
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2010/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/15/2011
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 Accunts. 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.
Plant Name:
o FERC Licensed Project No.
Plant Name:
o FERC Licensed Project No.
Plant Name:
o Line
No.
(d)(e)
0.00
o
o
0.00
o
o
0.00
o
o
- --~ - -- - - ~- - - - ~ - - --- - - - -
o
o
o
o
o
o
o
0.0000
o
o
o
o
o
o
o
0.000
o
o
o
o
o
o
o
0.0000
0 0 0 23
0 0 0 24
0 0 0 25
0 0 0 26
0 0 0 27
0 0 0 28
0 0 0 29
0 0 0 30
0 0 0 31
0 0 0 32
0 0 0 33
0 0 0 34
0.0000 0.0000 0.000 35
FERC FORM NO.1 (REV. 12-03)Page 407.2
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/15/2011 2010104
FOOTNOTE DATA
!Schedule Page: 406 Line No.: -2License period from June 1,
¡Schedule Page: 406 Line No.: -2License period from June 1,
¡Schedule Page: 406 Line No.: -2
License period from March 1,
Column: b
2009 to May 31, 2059.
Column: c
2009 to May 31, 2059.
Column: d
2001 to February 28, 2046
\Schedule Page: 406 Line No.: -2 Column: eLicense period from March 1,2001 to February 28,2046.
I=:
=i
-----------=i
¡Schedule Page: 406 Line No.: -2 Column: f
License period from June 1, 2009 to May 31, 2059.
¡Schedule Page: 406.1 Line No.: -2 Column: b
License period from June 1, 2009 to May 31, 2059.
¡Schedule Page: 406.1 Line No.: -2 Column: c
Licensed period from June 1, 2009 to May 31, 2059.
¡Sche~ule Page: 406.1 Line No.: -2 Column: dNot a licensed project.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
This Page Intentionally Left Blank
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) riA Resubmission 04/1512011
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 facilit, and give a concise statement of the fact in a footnote. If licensed project,
give project number in footnote.
Line Year ¡Installed ca~acit N"et Peak Net Generation
Name of Plant Orig.Name Plate atin Demand Excluding Cost of Plant
No.Const.(In MW)(6~n.)Plant Use
(a)(b)(c)(e)(f)
1 Kettle Falls CT 2002 7.20 9.0 3,462,000 9,169,338
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO.1 (REV. 12-03)Page 410
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) ri A Resubmission 04115/2011
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 withcombinations 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 utilzed in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset Operation Production expenses Fuel Costs (in cents LineRetire. Costs) Per MW Exc'l. Fuel Fuel Maintenance Kind of Fuel (per Milion Btu)
(g)(h)(i)(j)(k)(i)
No.
1,273,519 165,454 193,539 31,859 Nat Gas 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 This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/15/2011
TRANSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of Iines, 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 Accunts.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 Accunt 121, Nonutilty Propert.
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 nee not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely; show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line (Indicate wliere Type of LE~G~H ~oie wiles)Numberot e scl0
No.other than u aergroun lines Of60 cvcle 30hase)Supporting report circuit miles)
From Operating
un srueture un.::tr~i~res CircuitsToDesignedStructureof Lin~Of~l)ot er
Desir;a ed ine
(a)(b)(c)(d)(e)(g)(h)
1 Group Sum 60.õC 60.00 1.00
2
3 Group Sum 115.0(115.00 1,54.00
4
5 Beacon Sub #4 BPABell Sub 230.0(230.00 Stel Tower 1.00 1
6 Beacon Sub BPABeIl Sub 230.01 230.00 HType 5.00 1
7 Beacon Sub #5 BPA Bell Sub 230.01 230.00 Stl Pole 4.00 1
8 Beacon Sub #5 BPABeIl Sub 230.0(230.00 HType 2.00 1
9 Beacon Cabinet Gorge Plant 230.0(230.00 Stel Tower 1.00 1
10 Beacon Cabinet Gorge Plant 230.0(230.00 Steel Pole 26.00 2
11 Beacon Cabinet Gorge Plant 230.01 230.00 HType 53.00 1
12 Beacon Sub Lolo Sub 230.0(230.00 Steel Tower 1.00 1
13 Beacon Sub Lolo Sub 230.01 230.00 HType 104.00 1
14 Benewah Shawnee 23Q.l 230.00 Steel Pol 60.00 1
15 Noxon Plant Pine Creek Sub 230.0(230.00 Stel Pole 29.00 2
16 Noxon Plant Pine Creek Sub 230.0(230.00 HType 14.00 1
17 Cabinet Gorge Plant Noxon 230.0(230.00 HType 19.00 1
18 Benewah Sw. Station Pine Creek Sub 230.0l 230.00 Steel Tower 1
19 Benewah Sw. Station Pine Creek Sub 230.0(230.00 HType 43.00 1
20 Divide Creek Lolo Sub 230.0(230.00 Steel Tower 1
21 Divide Creek Lolo Sub 230.õl 230.00 HType 43.00 1
22 N. Lewiston Walla Walla 230.01 230.00 HType 43.00 1
23 N. Lewiston Walla Walla 230.õl 230.00 Steel Pole 4.00 1
24 N. Lewiston Shawnee 230.0l 230.00 Steel Pole 7.00 1
25 N. Lewiston Shawnee 230.õl 230.00 HType 27.00 1
26 Walla Walla Wanapum 230:0l 230.00 Alum 1
27 Walla Walla Wanapum 230-:230.00 HType 78.00 1
28 BPA (Libby)Noxon Plant 23Q.l 230.00 Steel Tower 1.00 1
29 BPAlHot Springs #1 Noxon Plant 230.õl 230.00 Stel Tower 1.00 1
30 BPAlHot Springs #2 Noxon Plant (dead)23Q.l 230.00 Steel Tower 2.00 1
31 BPAlHot Springs #2 Noxon Plant 230.01 230.00 HType 68.00 1
32 BPA Line West Side Sub 230.01 230.00 Stel Pole 2.00 2
33 Hatwai N. Lewiston Sub 230.01 230.00 HType 7.00 1
34 Divide Creek Imnaha 230.01 230.00 HType 20.00 1
35 Colstrip Plant Broadview 500.Ol 500.00
36 TOTAL 2,207.00 3.00 33
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This i!0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/15/2011
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 propert 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, coowner, or
other part 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) to (I) on the book cost at end of year.
.
i.v:: i vi- LINE (InerOOe in Column ü) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXESSize of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses Expenses(i)(j)(k)(i)(m)(n)(0)(p)No.
136,031 70,092 206,130 1
2
9,590,91'96,902,738 106,93,653 372,527 471,803 844,33C 3
4
1272 ACSS 17,91 1,316,679 1,334,592 5
1272 ACSS 6
1272 ACSS 7
1272 ACSS 30,32;3,273,923 3,304,246 8
1272 ACSS 9
1590 ACSS 10
1590 ACSR 798,60!36,029,040 36,827,649 290,623 290,62~11
1272 ACSS 12
1272 McL 456,16,7,m,307 7,733,469 80,720 23,853 104,5T=13
1590 ACSS 570,20 47,543,332 48,113,539 193 263 45E 14
1272 ACSR 15
954McML 671,04 17,987,859 18,658,906 6,480 96,311 102,791 16
~54 McML 125,7!1,091,601 1,217,477 443 4,884 5,32i 17
i54 McMAL 18
54 McMAL 162,05.1 2,604,949 2,767,001 4,727 341,862 34,585 19
1272 McML 20
1272 McMAL 86,22f 3,698,377 3,784,605 312 18,466 18,77f 21
1272 McL 22
1272 McMAL 623,98 6,923,51 7,547,435 2,412 301,328 303,74C 23
1272 McMAL 24
1272 McML 872,15(8,067,903 8,940,053 240 895 1,13f 25
1272 McMAL 26
1272 McMAL 70,781 2,572,506 2,643,287 21,415 21,4H 27
1272 McML 28
1272 McML 19,521 19,521 29
1272 McML 30
1272 McML 231,33'3,308,08 3,539,742 1,780 74,884 76,66 31
1272 McML 120.m 510,225 631,004 3,556 3,556 32
1590 ACSR 106,581 2,546,756 2,653,337 1,420 8,677 10,09 33
1272 McMAL 155.59C 1,297,751 1,453,341 251 1,065 1,31E 34
595,78~29,323,495 29,919,284 54,948 301,903 86,240 443,091 35
15,422,358 272,365,913 287,788,271 526,453 1,961,788 86,240 2,574,481 36
FERC FORM NO.1 (ED. 12-87)Page 423
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/151011
RANSMISSION LINES ADDED DURING YEAR
1. Report below the information called.for concerning T.ransmission lines added or altered dunng 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 (0), it is permissible to report in these columns the
Line LI Lint!IINI.J-t K rUR
No.From To
Le!"gth Type l\V~rage Present UltimateinNumber perMilesMiles
(a)(b)(c)(d)(e)(f)(g)
1 No additions during 2010
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17 -c
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 This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2010/04
(2) Fi A Resubmission 04/15/2011
TRAN MISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are r~ported. 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.
J~;:Voltage LINE COST LineSizeSpecificationConf~uration KV Land and Poles, Towers Conductors Asset Total No.
(h)
and pacing (Operating)Land Rights and Fixtures and D~)Vices Retire. Costs
(i)ü)(k)(I)(m)(n (0)(p)
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
FERC FORM NO.1 (REV. 12-03)Page 425
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) DA Resubmission 04/1512011
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 industnal or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those servng customers with energy for resale, may be grouped accrding
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, summanze accrding to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 STATE OF WASHINGTON
2
3 Airway Heights Distr. Unattended 115.00 13.80
4 Barker Road Distr. Unattended 110.00 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 Colvile 115Kv Distr. Unattended 115.00 13.80
12 Critchfield Distr. Unattended 115.00 13.80
13 Deer Park Dist. Unattnded 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 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 Libert 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 Milwood Dist. Unattended 115.00 13.80
35 Ninth & Central Distr. Unattended 115.00 13.80
36 Northeast Distr. Unattended 115.00 13.80
37 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.1 (ED. 12-96)Page 426
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) Õ A Resubmission 04/15/2011
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary 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 accunting 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 part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(n
(In MVa)(f)(g)(h)ü)(k)
1
2
24 2 Fred Oil&Air Fan&Cap 39 40 3
12 1 Two Stage Fan 1 20 4
536 4 Fred Oil & Air Fan 4 560 5
300 2 Two Stage Fan 2 500 6
24 2 Fred Oil & Air Fan 2 40 7
12 1 Two Stage Fan 1 20 8
12 1 Fred Oil & Air Fan 16 20 9
36 2 Two Stage Fan 2 60 10
31 3 Fred 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 FrOil/Air Fan 1 20 16
12 1 Two Stage Fan 1 20 17
24 2 Fr OillAirl2StgFan 2 40 18
36 2 Two Stage Fan 2 60 19
12 1 20
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
28 3 Two Stg/PVFred Oil 15 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 29
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 1 FrcAir/FrcOil/AirFan 2 36 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 2 40 39
36 2 Fred Oil & Wt Fan 2 60 40
FERC FORM NO.1 (ED. 12-96)Page 427
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) nA Resubmission 04/1512011
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 accrding
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 accrding to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Pound Lane Distr. Unattended 115.00 13.80
2 Pullman Dist Unattended 115.00 13.80
3 Ross Park Distr. Unattended 115.00 13.80
4 Roxboro Distr. Unattended 115.00 24.00
5 Shawnee Trans. Unattended 230.00 115.00 13.80
6 Silver Lake Distr. Unattended 115.00 13.80
7 Southeast Distr. Unattended 115.00 13.80
8 South Othello Distr. Unattended 115.00 13.80
9 South Pullman Distr. Unattended 115.00 13.80
10 Sunset Distr. Unattended 115.00 13.80
11 Terre View Dist. Unattended 115.00 13.80
12 Third & Hatch Distr. Unattended 115.00 13.80
13 Waikiki Distr. Unattended 115.00 13.80
14 WestSide Trans. Unattended 230.00 115.00 13.80
15 Other: 72substa less than 10MVA 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 Hil 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 Grangevile 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 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. 12-96)Page 426.1
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/Q4
(2) i: A Resubmission 04/15/2011
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary 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 sale ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accunting 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 part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In ~~a)
(f)(a)(h)(i)ü)(k
24 2 Two Stage Fan 2 40 1
24 2 Fred Oil & Air Fan 2 40 2
30 2 Two Stage Fan 2 60 3
24 2 Two Stage Fan 2 40 4
150 1 Two Stage Fan 250 5
12 1 Fred Oil & Air Fan 1 20 6
30 2 Two Stage Fan 2 50 7
12 1 Two Stage Fan 1 20 8
30 2 Two Stage Fan 2 50 9
33 2 Two Stage Fan & Caps 50 55 10
12 1 Two Stage Fan 1 20 11
54 3 Two Stg Fan & Cap 103 90 12
24 2 Two Stage Fan 2 40 13
250 2 14
189 136 3 15
16
17
30 2 Two Stage Fan 2 50 18
12 1 Two Stage Fan 1 20 19
75 1 Two Stage Fan & Caps 223 125 20
17 2 Portable Fan 2 22 21
20 3 1 22
12 1 Fred Air Fan 1 26 23
75 1 Two Stage Fan 1 125 24
10 1 Fred Air Fan .
1 13 25
36 2 Two Stage Fan 2 60 26
12 1 Two Stage Fan 1 20 27
24 2 FrcOiVAir2StgFan 2 40 28
25 4 FredOiVAir/Pt Fan&C 17 34 29
12 1 Two Stage Fan 1 20 30
12 1 Two Stage Fan 1 20 31
12 1 Two Stage Fan 1 2C 32
12 1 Fred Oil & Air Fan 1 20 33
12 1 Two Stage Fan 1 20 34
15 3 Fred Air Fan 2 20 35
262 3 Fred Oil/AirlTwo Stg 1 270 36
24 2 FrOilIAir/2Stg Fan 2 40 37
137 2 1 Capacitors 48 38
12 1 Two Stage Fan 1 20 39
250 1 1 Capacitors 48 40
FERC FORM NO.1 (ED. 12-96)Page 427.1
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) Õ A Resubmission 04/15/2011
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 VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(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 Oistr. 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 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. Maries Oistr. Unattended 115.00 23.90
19 Tenth & Stewart Distr. Unattended 115.00 13.80
20 Wallace Distr. Unattended 115.00 13.80
21 Other: 28 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 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 35.00
35
36 STATE OF IDAHO
37 Cabinet Gorge (HEO)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.1 (ED. 12-96)Page 426.2
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) n A Resubmission 04/15/2011
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary 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 accunting 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 part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)(f)(a)(h)(i)(j)(k)
10 3 1
10 1 Fred Air Fan 13 2
18 2 Fred Air Fan 2 22 3
20 2 Fred Oil & Air Fan 1 28 4
12 1 Portable Fan 1 15 5
262 3 Capacitors 48 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 Fred Oil & Air Fan 1 20 11
10 1 1 Fred Air Fan 1 13 12
474 4 Fred Oil & Air Fan 50 490 13
12 1 Two Stage Fan 1 20 14
30 3 Fred Air Fan 3 38 15
27 4 Port FanlFredOillAi 4 39 16
12 1 Fred Oil & Air Fan 1 20 17
24 2 Two Stage Fan 2 40 18
30 2 Fred OillAirlTwo Stg 2 50 19
10 3 20
77 45 21
22
23
5 1 24
25
26
27
36 1 Two Stage Fan 1 60 28
34 1 1 Two Stage Fan 1 62 29
80 4 1 30
24 2 Fred Oil & Air Fan 1 40 31
24 2 Fred Oil & Air Fan 2 40 32
36 1 Two Stage Fan 1 60 33
2 34
35
36
300 6 1 Fred Oil and Air Fan 2 30 37
16 2 Fred AirlOillAir Fan 2 21 38
114 2 3 Two Stage Fan 2 190 39
40
FERC FORM NO.1 (ED. 12-96)Page 427.2
Name of Respondent This oo0rt Is:Date of Report Year/Penod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) D A Resubmission 04/1512011
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 accrding
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 distnbution and whether
attended or unattended. At the end of the page, summarize accrding to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Noxon Trans. Attended 230.00 13.80
2
3 STATE OF OREGON .
4 Coyote Springs II Trans. Attended 500.00 13.80 18.00
5
6 SUMMARY:
7 Washington:
8 4 subs Trans. Unattended
9 119subs Distr. Unattended
10 1 subs Tran & Dist Unattnd
11 7 subs Trans. Attended
12 Idaho:
13 3 subs Trans. Unattended
14 63 subs Distr. Unattended
15 4 subs Tran & Dist Unattnd
16 3 subs Trans. Attended
17 Montana:1 sub Trans. Attended
18 1 sub Distr. Unattended
19 Oregon:1 sub Trans. Unattended
20 System: 207 subs
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO.1 (ED. 12-96)Page 426.3
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2010/04
(2) ÕA Resubmission 04/15/2011
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary 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 accunting between the parties, and state amounts and accunts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)(f)(g)(h)(i)ü)(k)495 9 2 Two Stage Fan 1 595 1
2
3
213 1 1 Two Stage fan 1 355 4
5
6
7
850 8
1200 9
536 10
269 11
12
400 13
669 14
1135 15
430 16
555 17
5 18
213 19
6201 20
21
22
23
24..
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO.1 (ED. 12-96)Page 427.3
This Page Intentionally Left Blank
Avu-E
RECEIVED
lOll APR is
AN /0: 04
A vista Corp.
IDAHO
Annual Electric Report
2010
This Page Intentionally Left Blank
Name of Respondent This Report Is:Date of Report Yea of Report
(l)IlAn Original (Mo, Da, Yr)
A vista Corpration (2)DA Resubmission April 15, 2011 Dember 31, 201 0
SUMMRY OF UTILIT PLAN AN ACCUMULATED PROVISIONS
FOR DEPRECIATION, AMORTIZTION AN DEPLETION
Line Item Total Electric
No.
(a)(b)(c)
1 UTILITY PLANT
2 In Service
3 Plant in Service (Classified)1,098,60 1,839 940,368,099
4 Prooert Under Capital Leases
.499,951 0
5 Plant Purchased or Sold
6 Completed Constrction not Classified
7 Investment in Kettle Fans
8 TOTAL (Enter Total of lines 3 th 7)1,099,101,790 940,368,099
9 Leased to Others
10 Held for Futue Use 347,171 162,353
11 Constrction Work in Progress 3,427,363 3,322,305
12 ACQuisition Adjustments 0 0
13 TOTAL Utilty Plant (Enter Total of lines 8 th 12)1,102,876,324 943,852,757
14 Accum. Prov. for Depr., Amort., & DePI.0 0
15 Net Utilty Plant (Enter total of line 13 less 14)1,102,876,324 943,852,757
DETAIL OF ACCUMUATED PROVISIONS FOR ~\d'J ....".........y:d.,d
16 DEPRECIATION, AMORTIZATION AND DEPLETION
. ..u/. ..' '.','" " " 'd .. ". ... dU/!
17 In Service:
18 Depreciation ~.,u..19 Amort. and Depl. of Producing Nat. Gas Land and Land Rights
"d.,.
20 Accumulated Depreciation - Kette Fans
21 Amort. of Other Utilty Plant
22 TOTAL in Service (Enter Total of lines 18 th 21)
23 Lesed to Others
24 Depreciation
25 Amortization and Depletion
26 TOTAL Leased to Others (Enter Total of lines 24 and 25)
27 Held for Future Use d(dC...........:).........\......d...... ......d,.
28 Depreciation
29 Amortization
30 TOTAL Held for Future Use (Ent. Tot. of lines 28 and 29)..31 Abandonment of Leases (Natual Gas)
32 Amort. of Plant ACQuisition Adjustment 0 0
TOTAL Accumulated Provisions (Should agree with line 14 above)
33 (Enter Total of lines 22, 26, 30, 31, and 32)0 0
State of Idaho
FERC FORM NO.1 (ED. 12.89)Page 200
Name of Respondent This R~ort Is:
(l) il An Original
Date of Report
State of Idaho
Year of Report
A vista Corpration (2) 0 A Resubmission April 15,2011 December 31,2010
SUMMAY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION (Continued)
Gas Other (Specify)Other (Specify)Other (Specify)Common Line
No.
148,107,751 10,625,940
184,818
91,253 13,805
148,383,822 10,639,745
0
148,383,822 10,639,745
o o 33
FERC FORM NO.1 (ED. 12-89)Page 201
State ofIdaho
Name of Respondent This R~rt Is:Date of Report Yea of Report
2 (l) X An Orginal (Mo, Da, fr)
A vista Corp.(2)D A Resbmission April 15,201 i Decbe 31, 20 i 0
ELECTRIC PLAN IN SERVICE (Accounts 101, 102, 103, 106)
i. Reprt below the original cost of electrc plant in serce ac-estimated bas if necsar, and include the entres in column
cording to the prescribe accounts.(c). Also to be included in column (c) are entres for reverals
2. In addition to Account i 0 i, Electrc Plant in Serce (Clas-of tentative distrbutions of pror yea rert in column (b).
sified), this page and the next include Accounts 102, Electrc Plant Likewise, if the respondent has a significant amount of plant
Purchased or Sold; Account i 03, Expemental Electrc Plant Un-retireents which have not been classified to primary accounts
Classified; and Account 106, Completed Constrction Not Clas-at the end of the year, include in column (d) a tentati ve distrb-
sified - Electrc.ution of such retirements on an estimated basis, with approp-
3. Include in column (c) or (d), as appropriate, corrtions of add-riate contr entry to the account for accumulated depeciation
itions and retireents for the curnt or preceding year.prvision. Include also in column (d) reverls oftentative dis-
4. Enclose in parentheses creit adjustments of plant accounts to trbutions of pror year of unclassified retireents. Attch sup-
indicate the negative effect of such accounts.plemental stateent showing the account distrbutions of these
5. Classify Accountl06 accordinl! to Drescribed accounts, on an tentative classifications in columns (c) and (d), including the
Balance at
Line Account Beginning of Yea Additions
No.(a)(b)(c)
1 1. !N ANGIDLE PLAN
2 301 Organization --
3 302 Franchises and Consents 10,609,425 -
4 303 Miscel1aneous Intagible Plant --
5 TOTAL Intagible Plant (Enter Total oflines 2, 3, and 4)10,609,425 -
6 2. PRODUCTION PLAN
7 A. Steam Production Plant
8 310 Land and Land Rights --
9 31 i Strctures and Imoroyements --
10 312 Boiler Plant Eauioment --
11 313 Engines and Engine Dryen Generators --
12 314 Turbogenertor Units --
13 315 Accessory Electrc Ecuioment --
14 316 Misc. Power Plant EQuipment --
15 317 Asset Retrement Costs for Steam Production --
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)--
17 B. Nuclear Production Plant
18 320 Land and Land Rights --
19 321 Strctures and Imoroyements --
20 322 Reactor Plant Eauipment --
21 323 Turbogenerator Units --
22 324 Accessory Electrc Eauipment --
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 Lad and Lad Ril!hts 6,612,042 845
28 331 Strctures and Imoroyements 10,935,190 583,860
29 332 Reseroirs, Dams, and Waterays 35,805,181 359,633
30 333 Water Wheels, Turbines, and Generators 39,674,285 -
31 334 Accessory Electrc EQuipment 6,135,145 38,174
32 335 Misc. Power Plant EQuipment 2,816,522 10,330
33 336 Roads, Railroads, and Bridges 1098,564 -
34 337 Asset Retirement Costs for Hydrulic Production --
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)103,076,929 992,842
36 D. Other Production Plant
37 340 Lad and Lad Rights 621,682 -
38 341 Strctures and Imoroyements 3,255,691 9,576
39 342 Fuel Holders, Products and Accessories 1,700,144 105,457
40 343 Prime Moyers 3,658,328 -
41 344 Genertors 48,858,107 208,506
42 345 Accessorv Electrc EQuipment 2,552284 40149
FERC FORM NO.1 (ED. 12-91)Page 204
State ofIdahoName of Respondent This (g0rt Is:Date of Report Yea of Report
(1) X An Orginal (Mo, Da, fr)
A vista Corp.(2)0 A Resubmission April 15,2011 Decber 31, 2010
ELECTRIC PLAN IN SERVICE (Accounts 101, 102, 103, and 106) (Continued)
reverals of the prior year tentative account distrbutions of umn (f) only the offset to the debits or credits distrbute in
these amounts. Careful obserance of the above instrctions column (f) to primaiy account classifications.
and the texts of Accounts 10 i and 106 will avoid serous omis-7. For Account 399, state the natu and use of plant included
sions of the rerted amount of respndent's plant actually in the account and if substatial in amount submit a supple-
in servce at end of year. mentaiy statement showing subaccount classification of such
6.Show in column (f) relassifications or trnsfer within plant confonning to the reuireents of these pages.
utility plant accunts. Include also in column (f) the additions 8. For each amount comprising the rerted balance and
or reductions of primaiy account classifications arising from changes in Account 102, state the prope purhased or sold,
distrbution of amounts initially reorded in Account 102. In name of vendor or purchaser, and date of trnsaction. Ifpmshowing the clearace of Account 102, include in column (e)posed jourl entres have been filed with the Commissionthe amounts with respect to accumulate provision for as reuire by the Unifonn Syste of Accounts,give alsodepreiation, acauistion adjustments, etc., and show in col.date of such filing.
. Balance at
Retirements Adjustments Trasfers End of Yea Line
(d)(e)(f 6â No.
1
---301 2--10,609,425 302 3---303 4---10,609,425 5
6
7---310 8---311 9
---312 10---313 11---314 12
---315 13---316 14---317 15
----16
17----320 18----321 19----322 20----323 21----324 22----325 23----326 24----25
26---6,612,887 330 27
40649 --11,478,401 331 28
33,755 --36,131,059 332 29---39,674,285 333 30
397 --6172,922 334 31---2,826852 335 32---1,098,564 336 33----337 34
74,801 --103,994970 35
36---621,682 340 37
6,880 --3,258,387 341 38
17,815 --1.87,786 342 39---3,658,328 343 40
---49,066,613 344 41
25,282 --2,567,151 345 42FERC FORM NO.1 (ED. 12-87)Page 205
Name of Respondent This Ri~t Is:Date of Report Yea of Reprt
( I ) X An Orginal (Mo. Da. Yr)
Avista Corp.(2)0 A Resubmission April 15.201 i December 3 1,2010
ELECTRIC PLA IN SERVICE (Accounts 101,102,103,106)
Balance at
Line Account Beginning of Yea Additions
No.(a)(b)(c)
43 (46)Misc. Power Plant Eauipment --
44 347)Asset Retreent Costs for Oter Production --
45 TOTAL Oter Production Plant (Enter Total of lines 37 th 45)60,646,236 363,688
46 TOTAL Producton Plant (Enter Tota oflines 16, 25, 35, and 45)163,723,165 1,356,530
47 3. TRASMISSION PLAN
48 350 Land and Lad Rights 5,102,164 3,224,148
49 352 Strctures and Imorovements 8,168,941 639,977
50 353 Station Eauioment 73,254,097 7,181,239
51 354 Towers and Fixtures 556,655 -
52 355 Poles and Fixtures 46,998,860 1,159,731
53 356 Overhead Conductors and Devices 28,717,494 577,790
54 357 Underiround Conduit
--
55 358 Underiround Conductors and Device --
56 359 Roads and Trails 1,374,002 -
57 359.1)Asset Retireent Costs for Transmission Plant
--
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)164,172,213 12,782,885
59 4. DISTRIUTION PLAN
60 360 Land and Land Rights 964,029 1,058,943
61 361 Strctures and Improvements 4,459,230 47,749
62 362 Station Eauioment 32,441,214 923,563
63 363 Storage Batter-Eauioment --
64 364 Poles, Tower, and Fixtures 84,265,495 5,973,191
65 365 Overhead Conductors and Devices 56,557,145 3,440,951
66 366 Underiround Conduit 28,604,017 1,083,790
67 367 Underground Conductors and Devices 44,433,568 1,909,537
68 368 Line Transformers 59,369,276 1,950,082
69 369 Serices 43,861,626 1,409,005
70 370 Meters 28,502,816 277,626
71 371 Instalations on Customer Premises --
72 372 Leased Proper on Customer Preises
--
73 373 Stree Lighting and Signal Systems 12,901,950 495,553
74 374 Asset Retirement Costs for Distrbution Plant
--
75 TOTAL Distrbution Plant (Enter Tota oflines 60 thru 74)396,360,366 18,569,990
76 5. GENERA PLAN
77 389 Land and Lad Riirts 101,907 -
78 390 Strctures and Imorovements 1,351,622 120,820
79 391 Offce Furniture and Eauioment --
80 392 Transortation Eauioment 2,094,468 888,227
81 393 Stores Eauipment 14,745 -
82 394 Tools, Shoo and Garge EauiDlent 432,865 -
83 395 Laboratory Eauioment 144,113 -
84 396 Power Ooerated Eauipment 6,763,612 2,045,775
85 397 Communication EQuipment 4,219,718 97,503
86 398 Miscellaneous Eauioment 2,299 -
87 SUBTOTAL (Enter Total of lines 77 thru 86)15,125,349 3,152,325
88 399 Other Tanl!ible Prooer 1 --
89 399.1)Asset Retirement Costs for General Plant --
90 TOTAL General Plant (Enter Total of lines 87 and 90)15,125,349 3,152,325
91 TOTAL (Accounts 101 and 106)749,990,518 35,861,730
92 102)Electrc Plant Purchased --
93 Less)(l02) Electrc Plant Sold
-
94 103)Exoermental Plant Unclassified --
95 TOTAL Electrc Plant in Serice 749,990,518 35,861.730
FERC FORM NO.1 (ED. 12-87)Page 206
State ofldaho State ofldaho
Name of Respondent This ~ort Is:Date of Report Year of Report
(I) X An Orginal (Mo, Da, Yr)
Avista Corp.(2)D A Resbmission April 15,2011 December 31, 20 I 0
ELECTRIC PLAN IN SERVICE (Accounts 101, 102, 103, and 106) (Continued)
Balance at
Retirements Adjustments Trasfers End of Yea Line
(d)(e)(f (rzJ No.
----346)43
----347)44
49,977 --60,959,947 45
124,778 --164,954,917 46
47
---8,326,312 350 48
207,863 --8,601,055 352 49
1,368,084 --79,067,252 353 50
---556,655 354 51
43,616 --48,114,975 355 52
56,869 --29,238,415 356 53
,. ..,----357 54
-- -.--358 55
---1,374002 359 56
----359.1)57
1,676,432 --175,278,666 58
59
497 --2,022,475 360 60
---4,506,979 361 61
49,131 --33,315,646 362 62
----363 63
110,803 --90,127,883 364 64
155,274 --59842,822 365 65
14,849 -(4,432 29,668,526 366 66
86,890 --46,256,215 367 67
57,688 --61,261,670 368 68
31,748 --45,238,883 369 69
---28,780,442 370 70
----371 71
----372 72
36,248 --13.361,255 373 73
----374 74
543,128 -(4,432 414,382,796 75
76
---101,907 389 77
18,418 --1,454,024 390 78
----391 79
232,727 --2749,968 392 80
---14,745 393 81
35,180 --397,685 394 82
39,986 --104,127 395 83
235,378 --8,574,009 396 84
---4,317,221 397 85
---2,299 398 86
561,689 --17,715,985 87
---- 1(399)88
---- 1(399.1 89
561,689 --17,715,985 90
2,906,027 -(4,432)782,941,789 91
---- IQ02)92
-93
----103)94
2,906,027 -(4,432)782,941,789 95
State ofIdaho
FERC FORM NO.1 (ED. 12-87)Page 207
Name of Respondent This R~rt Is:Date of Report Year of Report
(1) An Original (Mo, Do, Yr)
A vista Corporation (2)0 A Resubmission April 15,2011 Dec. 31,2010
ELECTRIC OPERATING REVENUES (Account 400)
1. Report below operating revenues for each prescribed for each group of meters added. The average number of
account, and manufactued gas revenues in total.customers means the average of twelve figues at the close
2. Report number of customers, colums (f) and (g), on of each month.
the basis of meters, in addition to the number of flat rate 3. If previous year (columns (c), (e), and (g), are not
accounts; except that where separate meter readings are derived from previously reported figures, explain any incon-
added for billng purposes, one customer should be counted sistencies in a footnote.
OPERATING REVENUES
Line Title of Account Amount for Amount for
No.Year Previous Year
(a)(b)(c)
i Sales of Electrcít-
2 440) Residential Sales 100,732,420 101,397,475
3 442) Commercial and Industrial Sales (3)
4 Small (or Commercial)82,538,298 81,073,948
5 Lariie (or Industral)64,194,131 62,109,598
6 (444) Public Street and Highwav Lighting 2,250,093 2,126,115
7 445) Oter Sales to Public Authorities
8 (446) Sales to Railroads and Railwavs
9 448) Interdeparental Sales 187,603 178,951
10 TOTAL Sales to Ultimate Consumers 249,902,545 (1)246,886,087
11 447) Sales for Resale 89,301,585 69,738,693
12 TOTAL Sales of Electrcity 339,204,130 316,624,780
13 Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provision for Refuds 339,204,130 316,624,780
15 Oter Operatig Revenues
16 (450 Fodeited Discounts
17 (451 Miscellaneous Service Revenues 219,901 242,635
18 (453 Sales of Water and Water Power 98,162 133,929
19 (454) Rent from Electrc Propert 892,796 897,391
20 (455) Interdeparmenta Rents
21 (456) Other Electrc Revenues 39,445,502 12,080,448
22 (456.1) Revenues from Transmission of Electrictv of Others 4,325,301 3,223,695
23
24
25
26 TOTAL Other Operating Revenues 44,981,662 16,578,098
27 TOTAL Electrc Operating Revenues $384,185,792 $333,202,878
State ofIdaho
FERC FORM NO. i (ED. 12-90)Page 300
Name of Respondent This R~rt Is:Date of Report Year of Report
(1) X An Original (Mo, Da, Yr)
A vista Corporation (2)0 A Resubmission April 15,2011 Dec. 31, 2010
ELECTRC OPERATING REVENUS (Account 400) (Continued)
4. Commercial and Industrial Sales, Account 442, may 5. See page 108, Importt Changes Durng Yea, for
be classified according to the basis of classification (Small important new territory added and importnt rate increases
or Commercial, and Large or Industrial) regularly used by or decreaes.
the respondent if such basis of classifcation is not generally 6. For lines 2, 4, 5, and 6, see page 304 for amounts
greater than 1000 K w of demand.(See Account 442 of the relating to unbiled revenue by accounts.
Uniform System of Accounts. Explain basis of classification 7. Include unetered sales. Provide details of such sales
in a footnote.)in a foonote.
MEGAWATI HOURS SOLD AVG. NO. OF CUSTOMERS PER MONT
Amount for Number for
Amount for Year Previous Year Number for Year Previous Year Line
(d)(e)(f ( í!)No.
1
1,179,482 1,224,836 105,286 104,609 2
3
987,327 1,010,376 16,573 16,484 4
1,210,786 1,198,407 476 486 5
8,888 8,847 124 123 6
7
8
2,250 2,226 28 25 9
3,388,733 (2)3,44,692 122,487 121,727 10
2,178,025 1,664,130 11
5,566,758 5,108,822 122,487 121,727 12
13
5,566,758 5,108,822 122,487 121,727 14
(1) Includes $264,324 ofunbiled revenues.
(2) Includes ~6,915 MW relating to unbiled revenues.
(3) Segregation of Commerical and Industrial made on basis of utilzation of energy and not on size of account.
State of Idao
FERC FORM NO.1 (ED. 12-89)Page 301
Name of Respondent This Reprt Is:
~An Orginal
Date of Report Year of Report
(Mo, Da, Yr)
DA Resubmission Aprl 15, 2011 Dec. 31, 2010State of Idao
SALES OF ELECTRCITY BY RATE SCHEDULES
1. Report below for each rat schedule in effect durg the
yea the m Wh of electricity sold, revenue, average number of
customers, average kWh per customer, and average revenue
per kWh, excluding data for Sales for Resale which is report
on pages 310-31 1.
2. Provide a subheading and total for each prscribed
operating revenue account in the sequence followed in "Elec-
trc Operating Revenues," page 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
A vista Corporation
Lim
No.
Number and Title of Rate Schedule MWSoid
(a)
1 RESIDENTIAL SALES (440)
2 1 Residential Service
3 2 Residential Service
4 3 Residential Service
5 12 Res. & Far Gen. Service
6 22 Res. & Farm Lg. Gen. Service
7 30 Pumping-Special
8 32 Res. & Far Pumping Service
9 48 Res. & Far Area Lighting
10 49 Area Lighting-High-Press.
11 56 Centralia Credit
12 95 Wind Power
13 73 Residential
14 74 Residential Service
15 76 Residential Service
16 77 Residential Service
17 79 Residential Service
18 58 Tax Adjustment19 Total
20 Residential-Unbiled
21 COMMRCIAL SALES (442)
22 2 General Service
23 3 General Service
24 1 1 General Service
25 19 Contract-General Service
26 21 Lage General Service
27 25 Extra Lg. Gen. Service
28 28 Contract-Extra Lage Service
29 31 Pumping Service
30 47 Area Lighting-Sod. Yap.
31 49 Area Lighting-High-Press.
32 56 Centralia Credit
33 95 Wind Power
34 73 General Service
35 74 Large General Service
36 75 Large General Service
37 76 Large General Service
38 77 General Service
39 79 Area Light-High Press.
40 58 Tax Adjustment41 Tota
42 Commercial-Unbiled
43 Total Biled
44 Total Unbiled Rev. (See Intr. 6)
45 TOTAL
FERC FORM NO.1 (ED 12.90)
(bl
1,147,627
20,313
12,906
3,343
1,203
272
1,185,664
(6,182)
(such as a genera residential schedule and an off pea water
heatg schedule), the entres in colum (d) for the special
schedule should denote the duplication in number of reported
cutomers.
4. The average number of customers should be the number
of bils rendere durg the year divided by the number of
biling periods durg the year (12 if all bilings ar made
monthy).
5. For any rate schedule having a fuel adjustment clause
state in a footnote the estimated additional revenue biled pur-
suant thereto.
6. Report amount of unbiled revenue as of end of year for
each aDDlicab1e revenue account subheadinl!.Average KW of
Number of Sales per
Customers Customer(d) (e)
Revenue
Revenue
(cents) per
KWH Sold
(f(e)
95,391,528 100,132 11,461 8.31
2,234,808 4,524 4,490 11.00
937,332 29 445,034 7.26
309,449 601 5,562 9.26
257,723 21.42
74,519 27.40
50,423
1,339,351
100,595,133
137,287
105,286 11,261 8.54
288,916 28,273,712 14,774 19,556 9.79
608,442 46,632,753 1,330 457,475 7.66
64,519 3,527,048 3 21,506,333 5.47
25,302 2,027,443 466 54,296 8.01
938 139,309 14.85
2,417 524,548 21.70
9,008
1,572,523
990,534 82,706,344 16,573 59,768 8.36
0,207)068,046)
2,176,198 183,301,477 121,859 8.42
-9,389 -30,759 0 0.33
2,166,809 183,270,718 121,859 8.46
Page 304 .._-- --
Name of Respondent This Report Is:
!!An Orginal
A vista Corpration DA Resubmission
Date of Report Year of Report
(Mo. Va, Yr)
i\pril 15,2011 Dec. 31, 2010
State of Idaho
SALES OF ELECTRCITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect durg the
(such as a general residential schedule and an off peak wateryear the m Wh of electrcity sold, revenue, average number of heating schedule), the entres in colum (d) for the specialcustomers, average kWh per customer, and average revenue schedule should denote the duplication in number of reported
per kWh, excluding data for Sales for Resale which is reported customers.on pages 310-311.4. The average number of customers should be the number2. Provide a subheading and tota for. each prescribed of bils rendere durg the year divided by the number ofoperating revenue account in the sequence followed in "Elec-biling periods during the year (12 if all bilings ar madetrc Operating Revenues," page 301. If the sales under any rate monthy).
schedule are classified in more than one revenue accunt, list 5. For any rate schedule having a fuel adjustment clausethe rate schedule and sales data under each applicable revenue state in a footnote the estimate additional revenue biled pur-
account subheading.suant thereto.
3. Where the same customers ar served under more than 6. Report amount of unbiled revenue as of end of yea for
one rate schedule in the same revenue account classifcation each applicable revenue account subheadin,g.
Average KWH of RevenueLineNumber and Title of Rate Schedule MWSoid Revenue Number of Sales per (cents) perNo.Customers Customer KWH Sold (a)(b)(c)(d)(e)(f1INDUSTRIAL SALES (442)
2 2 General Service
3 3 General Service
4 8 Lg Gen Time of Use
5 11 Genera Service 3,640 376,434 132 27,576 10.34621 Large General Service 78,120 5,969,925 79 988,861 7.64725 Extr Lg. Gen. Service 1,101,060 55,526,233 6 183,510,00 5.04828 Contrt-Extra Large Service
9 29 Contract Lg. Gen. Service
10 30 Pumping Service -Special
11 31 Pumping Service 22,985 1,825,711 217 105,922 7.941232 Pumping Svc Res & Fnn 2,433 183,884 42 57,929 7.561347 Mea Lighting-Sod. Yap.53 7,371 13.911449 Mea Lighting-High-Press.50 10,069 20.141556 Centralia Credit
16 72 General Service
17 73 General Service
18 74 Lage Gen~al Servæe
19 75 Large General Service
20 76 Pumping Service
21 17 General Service
22 78 Lg Gen Tim of Use.
23 58 Tax Adjustment 70,32124Total1,208,341 63,969,948 476 2,538,532 5.3025Industral-Unbiled 2,445 224,183 026
27 STREET AN HW LIGHTING (444)
28 1 1 General Service
29 41 Co.-Owned S1. L1. Service 115 18,095 5 23,000 15.733042 Co.-Owned S1. L1. Service 6844 1,962,290 89 76,899 28.6731High-Press. Sod. Yap.
32 43 Cus1.-Owned S1. L1. Energy 9 875 1 9,000 9.7233and Main1. Service
34 44 Cus1.-Owned S1. L1. Energy 588 89,180 15 39,200 15.1735and Main1. Svce.-High-
36 Press. Sod. Yap.
37 45 Cus1.Owned S1. Lt. Energy Service 281 18,383 3 93,667 6.543846 Cus1.Owned S1. L1. Energy Service 1,022 88,174 11 92,909 8.6939High-Press. Sod. Yap.
40 56 Centralia Credit
41 58 Tax Adjustment 35,75642Total8,859 2,213,353 124 71.44 7.4043Strt and Hwy Lighting-Unbiled 29 36,74044Total Biled 3,393,398 249,484,778 122,459 7.3545Tota Unbiled Rev. (See Instr. 6)-6,915 230,164 0 (3.33)46 TOTAL 3,386,483 249,714,942 122,459 7.37FERC FORM NO.1 (ED 12-90)Page 304.1
Name of Respondent This Report Is:
~An Orginal
A vista Corporation DA Resubmission April 15,2011 Dec. 31, 2010
State of Idaho
SALES OF ELECTRICITY BY RATE SCHEDUL
Date of Report Year of Report
(Mo, Da, Yr)
1. Report below for each rate schedule in effec durg the
year the m Wh of electricity sold, revenue, averge number of
customers, average kWh per customer, and average revenue
per kWh, excluding data for Sales for Resale which is reportd
on pages 310-31 1.
2. Provide a subheading and tota for eah prescribed
operating revenue account in the sequence followed in "Elec-
trc Operating Revenues," page 301. If the sales under any rate
schedule ar 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 classifcation
Lim
No.
Number and Title of Rate Schedule MWSold
(a)
OTHR SALES TO PUBLIC
AUTHORITIS (445)
None
(b)
1
2
3
4
5
6
7
8
9
10 SALES FOR REALE (447) (1)
11 61 Sales to Other Utilties - ID
12
13
14
14
15
16
17 Note: Sch. 61 is a state assigned rate schedule for Saleslesale
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39 Total Biled
40 Tota Unbiled Rev.
41 TOTAL
INTERDEPARTMNTAL
SALES (448)
58 Tax Adjustment
Total 2,250
2,178,025
(such as a gener residential schedule and an off pea water
heati schedule), the entres in colum (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 bils rendere during the year divided by the number of
biling periods durng the yea (12 if all bilings are made
monthly).
5. For any rate schedule having a fuel adjustment clause
state in a footnote the estimated additional revenue biled pur-
suat thereto.
6. Report amount of unbiled revenue as of end of year for
each applicable revenue account subheading.
Average KW of
Number of Sales per
Customers Customer(d) (e)
Revenue
(c)
2,250 187,603
187,603
28 80,357
80,357
Revenue
(cents) per
KWH Sold
(f
8.34
8.34
Total 2,178,0251
5,573,673
(6,915)
5,566,758
FERC FORM NO.1 (ED 12.90)
28
89,301,585
89,301,585
338,973,966
230,164
339,204,130
122,487
o
122,487
45,504
45,448
Page 304.2
6.08
(3.33)
6.09
Idaho
Name of Respondnt This Report Is:Date or Report Year of Reprt(1) iKAnOrigil
Ayista Corp.(2)c=A Resubmlsslon Ap15. 2011 December 31, 2010
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not deried frm preiously reprted fiures, explain In fotnotes.
Line
No.Accunt Amout for Curnt Year Amount for PriQr Year
fa!bl ( c1(1) POWER PRODUCTION EXPENSES
2 A. Steam Pow Generation
3 Ooeration
4 50 Operation Suoervlsion and Enaineerlng 213 -5 501 Fuel 3,311,212 -6 502 Steam Exoenses --7 503 Steam frm Other Sourc --8 Lass) 150 Steam Transferred-Cr.--
9 505 Electri Exoenses -5891050Miscellaneus Steam Pow Expenses 31,054 26,65311507Rents--12 509 Allownce -.13 TOTAL Ooeratin CEntr Total or Lines 4 thru 11 3,342,478 27,24214Maintenance
15 510 Maintenance Suoervlslon and Engineering 18,70 68016511Maintenance or Strctres --17 512 Maintenance of Boller Plant 10 .18 513 Maintenance of Elect Plant --
19 514 Maintenance of Miscellaneous Steam Plant 11 -20 TOTAL Maintenance (Enter Total of Lines 14 th 181 18.688 68021TOTAL Power ProduClon Exoenses-Steam Plant (Ent Total or lines 12 an 19)3361,166 27,92222B. Nuclear Power Generation
23 Ooeration
24 517 Operation Suoervlslon and Engineer --25 518 Fuel --26 519 Coolants and Water --27 520 Steam Exoenses --
28 521 Steam from Oter Sources --29 Less) 1522 Steam Transferred-Cr.--30 523 EIe Exoenses --
31 524 MiScellaneous Nuclear Power Exoenses --32 525 Rants ..
33 TOTAL Ooeratlon Enter Total or liens 23 thru 31 --
34 Maintenance
35 528 Maintenance Suoervislon and Enolneerlng --36 529 Maintenance or Strctres --37 530 Maintenance or Reactor Plant Eouloment -.38 531 Maintenance or Electc Plant .-39 532 Maintenance or Miscellaneou Nuclear Plant --40 TOTAL Maintenance Enter Total of lines 34 thru 38 ..
41 TOTAL Power ProduClon Exoenses-Nucear Power Enter total or lines 32 and 39 --
42 C. Hydraulic Power Generon
43 Ooeration
44 535 Operation Suoervlsion and Encineerlno 819,028 798,3045536Water for Power 313.838 286.36246537Hvaraulic Exoenses 2,078,409 1,867.70847538Elect Exoenses 1,661,890 1,645,37748539Miscellaneous HYdraulic Powr Generation Exoenses 192,708 167,11649540Rents2.035361 2,145.97550TOTAL Ooeration Enter T ola of lines 43 thru 48 7.101.233 6.910.838
FERC FORM NO.1 (12-96)Page 320
3151011 Form 1 P9 320-323 by state 2010.xls.
Idaho
Date of Repo Year of ReportName of Respondent
Avlsta Corp.
This Report Is:(1) L:An Original
(2) c:A Resubmlsslon
ELECTRIC OPERATION AND MAINTENNCE EXPENSES
Aprl 15, 2011 Dember 31, 2010
Line
No.Accont
(e I
C. HYdraulic Powr Generation IContinue50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
109
110
Maintenance
541 Maintnance Supervision and Enalneerina
542 Maintenan of Strres
543 Maintenance pf Reservoirs. Dams. and Waterwa""
54 Maintenance pf Electc Plant
545 Maintenance of Miscellaneous HYdraulic Plant
TOTAL Maintenance Enter Totl of lines 52 thru 56\
TOTAL Power Production Expenses-Hvdreullc Power (Enter total of lines 49 end 57\
D. Other Powr Genration
Operation
546 Operation SUDervislon and EnolneerinD
547 Fuel
548 Generation Exoenses
549 Miscellaneous Other Power Generation Expenses
550 Renls
TOTAL Operation Enter Total of lis 61 thru 65
Maintenance
5511 Maintenance SUDervslon and EnDlneerlna
552) Maintenance of Structures
553\ Maintenance of Generatina and Electrc Plant
55 Maintenance of Miscellaneous Other Powr Generation Plant
TOTAL Maintenance Enter Totl of lines 68 thru 71
TOTAL Power Production Exoenses-other Pow Enter Tptal of lines 66 and 72
E. Other Power Supplv Expenses
555 Purchased Powr
556 SYStem Contrl and Load Dlspatchlna
557 Other Exoenses
TOTAL Other Power SUDDIv Expeses (Enter Totel of lines 75 thru 77\
TOTAL Power Producton Exoenses En Total of lines 20, 40, 58, 73 and 78
2. TRANSMISSION EXPENSES
Operation
560 Ooeration Suoervlslon and Enalneerino
561 Load Dispalchlng
561.1 Load Dis atchl Rellabllllv
561.2 Load Dis atehin Monitor and Ooerate Transmision S""lem
561,3 Load Dis aternn Transmlsslpn Service and Sched
561.4 Schedulin S""emt Control and Dlsoateh Servic
561.5 Reliabllit . Planning and Standards Development
561.6 Transmission Service Studies
561.7 Generation Interconnection Studies
561.8 Reliablillv. Planning and Standards Develomenl Servics
562 Station Exoenses
563 Overhead Line Exoenses
564 Underaround Line Expenses
565 Transmission of Electcilv bv Oter
566 Miscellaneous Transmission Expenses
567 Renls
TOTAL Operation Ente Total of lines 82 thru 89
Maintenance
568 Maintenance SUDervlslon and Enolneerino
569 Maintenance of Strctures
570 Maintenance of Station EDuiomenl
571 Mainlenance 01 Overhead Lines
572 Maintenance of Underoround Lines
573 Maintenance of Miscellaneous Transmission Plant
TOTAL Maintenance Enter Totl of lines 92 thru 97
TOTAL Transmission Expenses (Enter Total of lines 90 and 98
3. DISTRIBUTION EXPENSES
Operation
5801 Ooeratln SUDervision and EnoineerinD
FERC FORM NO.1 (12-96)Page 321
3151011
Amoynt fo CYrr Year Amount fo Previous Year(bTcl
117.797 87,034
143,177 103,726
511,137 267,952
577 529 848.660
78,868 75,55
1.428,50 1.382.925
8.529.740 8,293.763
25.065 38.150
14.903,439 2.827,749
150,490 110,412
265880 267,663
111,784 11.914
15,333,09 3,032,060
54,912 41,886
4,566 1,169
108,55 118,078
33,497 42,205
201,533 203,33
15.53,823 3,235.398
96,53,388 106,719,593
193,48 185,723
47,48,397 12.54,494
144,208,249 119,448,809
171,633,778 131,005,893
772,139 852.402
752,070 769,280
--
--
--
--
--
--
--
--
116,54 69,316
327,794 79.442
--
6.181.357 4,690,115
571167 484,611
12,092 26,811
8,733,166 6.971.978
197276 166,195
112.182 120,137
38,083 416,494
1.007,373 1.005,28
134 3,892
3,149 16,288
1,704,197 1,728,38
10,437.363 8,700,413
54,983 484,527
Fonn 1 P9 320-323 by state 2010.xlsx
Idaho
Name of Respodent
Avlsta Corp.
Th Report Is:(1) ~An Original
(2) i:A Resubmlsslon Decembe 31. 2010
Date of Report Year of Repo
April 15, 2011
Line
No.
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Account
(8)
3. DISTRIBUTION EXPENSES (Continued)
581 Load Dioatlno
582 StaUon Expenses
58 Overhead Une Exoenses
584 Underoround Une Expenses
585 Str Llohtna and Sional SYStem Expenses
586 Meter Expenses
587 Customr Installations Exoenses
588 Miscellaneous Distrbution Expenses
589 Rents
TOTAL OoeraUon Enter Totl of lines 102lhru 112
Maintenace
59 Maintenance Suoervlslon and Enolneerio .
591 Maintenance of Strctres
592 Maintnance of Statn Eouloment
593 Maintenance of Overhead Lines
594 Maintenance of Underoround Lines
595 Malntenence of Une Transformers
596 Maintenance of Street Llohting and Signal SyStems.
597 Maintenance of Meters
598 Maintenance of Miscellaneous Distrbution Plant
TOTAL Maintenance Enter Totl of lies 115lhru 123
TOTAL Distrbuion Exoenses renter Total of lines 113 and 1241
4. CUSTOMER ACCOUNTS EXPENSES
Amount fo Currnt Year
(b)Amount for Prior Year
(c)103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
152
.-
255.53 218,337
43,850 54,93
221.579 252,091
182,248 172,955
223,83 139228
399,146 401,8501,705,99 1.780.72487,09 89,562
4,051,263 4,08,203
429,05 461,079
152,578 103,495
203,06 3859332,85,672 2,618,661277358286,540
43.393 261,020
21290 190,439
24,206 38,33
41.510 79.238
4,625,739 4.40.741
8,677002 8.492.94
203,657 194.693
437,260 362.283
2,651,726 2,709,234
575,171 936,06745,00 83,959
3,912,813 4,288,255
-.
7,760,232 5.867.133
297,416 17,264
58,037 50,267
8,115,686 5,93,66
..
1,626 173,500
155 39,188
15,864 38,600
17,64 251,288
8,513,036 8.148,288
1,386,720 1379,591
(16,287 17,312
Operation
901 Suoervision
902 Meter Readlno Exoenses
903 Customer Records and Collection Expenses
90 Uncollectibl Accounts
905 Miscellaneous Customer Accounts Expenses
TOTAL Customer Accounts Exoenses (Ente Total of lines 128lhru 132)
5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
Operation
907 Suoervislon
908 Customer Assistance Exoenses
909 Informational and Instrctional Exoenses
910 Miscellaneous Customer Service and Infrmational Exoenes
TOTAL CusL Service and Infrmational Exoenses (Enter Total of Unes 136lhru 1391
6. SALES EXPENSES
Operation
911 Supervision
912 Demonstratino and Sellino Exoenses
913 Advertsing Expenses
916 Miscellaneous Sales Exoenses
TOTAL Sales Exoenses Enter Total of lies 143lhru 146
7. ADMINISTRATIVE AND GENERAL EXPENSES
.
Operation
920 Administrtie and Genera Salaries
921) Ofce Suoolies and Exoenses
Lessl1922 Administratie expenses Transferred-Credll
FERC FORM NO.1 (12-96)Page 322
3151011 Form 1 P9 320-323 by state 2010.xlsx
Idaho
Name of Respondent This Report Is:Date of Report Vea of Repor
(1) irAn Original
Avista Corp.(2)i:A Resubmission April 15. 2011 December 31. 2010
ELECTRIC OPERATION AND MAINTENACE EXPENSES
Line
No,Accunt Amount for Currnt Vear Amount for Prior Vear'a)bJ ( c
153 7. ADMINISTRATIVE AND GENERAL EXPENSES fContinued
154 923 Outside Services Emoloved 5.043,643 3.972.670155924Pronert Insurance 437,241 450.607156925In ures and Damaoes 1,808,492 1.243.326
157 926 Emnlo""e Pensions and Benets 343,886 33,615
158 927 Franchise Reoulrements 6,027 6,704
159 928 Renulatorv Commission Exnenses 1,927,019 1,698.820
160 Less\ 19291 Duolicate Charaes-Cr...
161 930.1 General Advertslna Exoenses 67.411 84,243
162 930.2 Miscellaneous General Exoenses 1,04,972 1,019,3531639311 Rents 252,531 100,527
164 TOTAL Oneration Enter Total 01 lines 150 thru 1631 20.814.691 18,425,432
165 Maintennce
166 935\ Maintenance 01 General Plant 1,929,813 2102,635
167 TOTAL Administrative and General Exoenses IEnter Total of lis 164 and 1661 22,744,50 20.528.067
168 TOTAL Elèctric Ooeration and Maintenance Expenses Entr Totl of lines 225,53,791 179.201.524
79.99,125,133,140.147,and 167
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES I
1. The data on number of employees should be repored constrtion employees in a fotnot.for the payroll perio endln9 nearest to October 31. or any 3. The number of employees assignable to the electc
payroll period ending 60 days before or aIer October 31.departent fr joint functons of cobinati utlts mav
2. If the respondent's payroll for the reportn9 period in.be determined by estimate. on th bais of employee eouiva.
cludes any special construction personnel, include such lents. Show the esmated number of equivalent emoloves
employees on line 3. and show the number of such special altbutd to th elect departnt frm Joint fuctons.
1 Pavroll Period Ended fDatel December 31. 2010
2 Total Reoular Full. nme Emplovees 85 83
3 Total Part. Time and T emoorarv Emplovees 1 2
4 Allocation of General Emolovees 126 128
5 Total Emnlovees ISee Note 1 212 213
FERC FORM NO.1 (12-96)Page 323
3151011 Form 1 pg 320-323 by state 2010.xlsx