2006Annual Report.pdf

THIS FILING IS
Item 1: 00 An Initial (Original)
Submission
OR D 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, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Form 1 Approved
OMB No. 1902-0021
(Expires 7/31/2008)
Form 1-F Approved
OMB No. 1902-0029
(Expires 6/30/2007)
Form 3-0 Approved
OMB No. 1902-0205
(Expires 6/30/2007)
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Exact Legal Name of Respondent (Company)
Avista Corporation End of
Year/Period of Report
2006/04
FERC FORM No.1I3-Q (REV. 02-04)
IDENTIFICATION
01 Exact Legal Name of Respondent 02 Year/Period of Report
Avista Corporation End of 2006/04
03 Previous Name and Date of Change (if name changed during year)
/ /
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
1411 East Mission Avenue, Spokane, W A, 99202
05 Name of Contact Person 06 Title of Contact Person
M. K. Malquist Executive VP and CFO
07 Address of Contact Person (Street, City, State, Zip Code)
1411 East Mission Avenue, Spokane, WA, 99202
08 Telephone of Contact Person lncluding 09 This Report Is 10 Date of Report
Area Code (1) 00 An Original (2) D A Resubmission (Mo, Da, Yr)
[phone] 04/18/2007
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accounts.
01 Name 03 Signature
j/ttft:/d/
04 Date Signed
M. K. Malquist CZf (Mo, Da, Yr)
02 Title
Executive VP and CFO M. K. Malquist 04/18/2007
Title 18, U.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM NO. 1/3-
REPORT OF MAJOR ELECTRIC UTILITIES LICENSEES AND OTHER
FERC FORM No.2/3-Q (REV. 02-04)Page 1
Name of Respondent This report is:Date of RepoI1 Year Ending
Avista Corp.( XJ An Original (Mo, Da, Yr)
J A Resubrnission Apri118, 2007 Dec. 31,2006
List of Schedules (Natural Gas Company)
Enter in column (d) the teans "none,
" "
not applicable " or "NA" as appropriate, where no infoanation or amounts have been reported for
certain pages. Omit pages where the responses are "none,
" "
not applicable," or "NA"
Line Title of Schedule Reference Page No.Date Revised Remarks
No.(a)(b)(c)(d)
GENERAL CORPORATE lNFORMA TION AND FINANCIAL STATEMENTS
I General Information 101
2 Control Over Respondent 102 N/A
3 Corporations Controlled by Respondent 103
4 Secwitv Holders and Votin.e; Powers 107
5 lmportant Chan.e;es Durin.e; the Year 108-109
6 Comparative Balance Sheet 110-113
7 Statement of Income for the Year 114-116
8 Statement of Accumulated Comprehensive Income and Hed.e;in.e; Activities 117 shown as 122a1b
9 Statement of Retained Eamin.e:s for the Year 118-119
Statements of Cash Flows 120-121
Notes to Financial Statements 122-123
BALANCE SHEET SUPPORTING SCHEDULES (Assets and Other Debits)
Summary of UtilitY Plant and Accumulated Provisions for Depreciation, Amortization, and Deoletion 200-201
Gas Plant in Service 204-209
Gas Prooertv and Caoacitv Leased from Others 212 N/A
Gas Prooertv and Caoacitv Leased to Others 213 N/A
Gas Plant Held for Future Use 214 N/A
Construction Work in Proe:ress-Gas 216
General Descriotion of Construction Overhead Procedure 218 N/A
Accumulated Provision for Deoreciation of Gas UtilitY Plant 219
Gas Stored 220
Investments 222-223 N/A
Investments in Subsidiary Comoanies 224-225
Prepayments 230
Extraordinary Property Losses 230 N/A
Unrecovered Plant and Re!!ulatorv Studv Costs 230 N/A
Other Re.e;ulatory Assets 232
Miscellaneous Deferred Debits 233
Accumulated Deferred Income Taxes 234-235
BALANCE SHEET SUPPORTING SCHEDULES (Liabilities and Other Credits)
Caoital Stock 250-251
Capital Stock Subscribed, Capital Stock Liability for Conversion
, ,
Premium on Capital Stock, and
Installments Received on Capital Stock 252 N/A
Other Paid-in Caoital 253 N/A
Discount on Caoital Stock 254 N/A
Caoital Stock Expense 254(b)
Securities issued or Assumed and Securities Refunded or Retired Durin.e; the Year 255 N/A
Lon.e;-Term Debt 256-257
Unamortized Debt Expense, Premium, and Discount on Lon.e;-Term Debt 258-259 N/A
Unamortized Loss and Gain on ReacQuired Debt 260 N/A
FERC FORM NO.2 (12-96)Page 2
Name of Respondent This (!)ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none
" "
not applicable " or "" 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)
Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273
Accumulated Deferred Income Taxes-Other Property 274-275
Accumulated Deferred Income Taxes-Other 276-277
Other Regulatory Liabilities 278
Electric Operating Revenues 300-301
Sales of Electricity by Rate Schedules 304
Sales for Resale 310-311
Electric Operation and Maintenance Expenses 320-323
Purchased Power 326-327
Transmission of Electricity for Others 328-330
Transmission of Electricity by ISO/RTOs 331
Transmission of Electricity by Others 332
Miscellaneous General Expenses-Electric 335
Depreciation and Amortization of Electric Plant 336-337
Regulatory Commission Expenses 350-351
Research, Development and Demonstration Activities 352-353
Distribution of Salaries and Wages 354-355
Common Utility Plant and Expenses 356
Amounts included in ISO/RTO Settlement Statements 397
Purchase and Sale of Ancillary Services 398
Monthly Transmission System Peak Load 400
Monthly ISO/RTO Transmission System Peak Load 400a
Electric Energy Account 401
Monthly Peaks and Output 401
Steam Electric Generating Plant Statistics 402-403
Hydroelectric Generating Plant Statistics 406-407
Pumped Storage Generating Plant Statistics 408-409
Generating Plant Statistics Pages 410-411
Transmission Line Statistics Pages 422-423
Transmission Lines Added During the Year 424-425
FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
Avista Corporation
Year/Period of ReportEnd m 2006104
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) nA Resubmission 04/18/2007
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none
" "
not applicable," or "" as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none
" "
not applicable " or "NA"
(a)
Reference
Page No.
(b)
426-427
450
RemarksLine
No.
Title of Schedule
(c)
67 Substations
68 Footnote Data
Stockholders' Reports Check appropriate box:
(!) Four copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO.1 (ED. 12-96)Page 4
Name of Respondent
Avista Corporation
This Report Is:
(1) 00 An Original(2) D A Resubmission
Date of Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/04
GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
M. K. Malquist, Executive vice President and Chief Financial Officer
1411 E. Mission Avenue
Spokane, WA 99202
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
State of Washington, Incorporated March 15, 1889
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not Applicable
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
Electric service in the states of Washington, Idaho and Montana
Natural gas service in the states of 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) D Yes...Enter the date when such independent accountant was initially engaged:
(2) !XI No
FERC FORM No.1 (ED. 12-87)PAGE 101
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation
(1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
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 prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
Avista Capital, Inc.Parent company to the 100
Company s subsidiaries.
4 Advantage la, Inc. (formerly Avista Advantage)Provider of utility bill 99.Subsidiary of
processing, payment and Avista Capital
information services to multi
site customers in North Amer.
Avista Communications, Inc.Telecommunications 100 Inactive
Subsidiary of
Avista Capital
Avista Development, Inc.Nonoperating company which 100 Subsidiary of
maintains an investment Avista Ventures
portfolio of real estate and
other investments.
Avista Energy, Inc.Wholesale electricity and 99.Subsidiary of
natural gas trading,marketing Avista Capital
and resource management.
Avista Laboratories, Inc.Holds a cost based investment 100
in a fuel cell technology Inactive subsidiary
company.of Avista Capital.
FERC FORM NO.1 (ED. 12-96)Page 103
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
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 prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
Avista Power, LLC Owns non-regulated generation 100 Subsidiary of
assets.Avista Capital
Avista Turbine Power, Inc.Receives assignments of 100 Subsidiary of
purchase power agreements.Avista Power
Avista Rathdrum, LLC Owned 49 percent of Rathdrum 100 Subsidiary of
Power, LLC (sold 10/2006)Avista Power
Avista Ventures, Inc.Invests in emerging business.100 Subsidiary of
Parent of Avista Development Avista Capital
and Pentzer Corporation
Pentzer Corporation Parent company of Advanced 100 Subsidiary of
Manufacturing and Avista Ventures
Development.
Advanced Manufacturing and Development, Inc.Performs custom sheet metal Subsidiary of
manufacturing of electronic Pentzer Corporation
enclosures, parts and systems
for the computer, telecom and
medical industries. AM&D
also has a wood products
division.
Avista Receivables Corporation Acquires and sells accounts 100
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 2006/04(2) nA Resubmission 04/18/2007
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 prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
receivable of Avista Corp.
Avista Energy Canada, Ltd.A wholly owned subsidiary of 100 Subsidiary of
Avista Energy, Inc. that Avista Energy
provides natural gas service
to approximately 250
individual customers in
British Columbia, Canada
Rathdrum Power, LLC Developed and owns an 49 (sold 10/2006)Sold in October 2006
electric generation asset.
Coyote Springs 2, LLC 100
" ,
Spokane Energy, LLC Marketing of energy.100
Avista Capital II An affiliated business trust 100
formed by the Company.
Issued Pref. Trust Securities
AVA Capital Trust III An affiliated business trust 100
formed by the Company.
Issued Pref. Trust Securities
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 2006/04
(2)D A Resubmission 04/18/2007
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 prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
Steam Plant Square, LLC Commercial office and retail Subsidiary of
leasing.Avista Development
Courtyard Office Center Commercial office and retail 100 Subsidiary of
leasing.Avista Development
AVA Formation Corp.Holding Company 100 Formed in 2006 for th
purpose of completing
proposed statutory
share exchange and
holding company
structure. Currently
a subsidiary of
Avista Corp.
FERC FORM NO.1 (ED. 12-96)Page 103.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
OFFICERS
1. Report below the name, title and salary for each executive officer whose salary is $50 000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
'Line Title Name of Officer S~,-ary
No.for Year(a)(b)(c)
Chairman of the Board and Chief Executive Officer G. Ely
(title change effective 05/15/06)
Executive Vice President and Chief Financial Officer M. K. Malquist
(title change effective 05/15/06)
" ": "';' ",. , '.,
President and Chief Operating Officer S. L. Morris
(title change effective 05/15/06)
Vice President and Chief Counsel for Regulatory and D. J. Meyer
Governmental Affairs
Vice President, with responsibility for R. R. Peterson
Energy Resources
Vice President, with responsibility for R. D. Woodworth
Business Development
Senior Vice President and Corporate Secretary K. S. Feltes
with responsibility for Human Resources
Vice President and Treasurer C. M. Burmeister - Smith
(title change effective 0 103/06)
Vice President with responsibility for Transmission D. F. Kopczynski
and Distribution Operations
Vice President, with responsibility for State and K. O. Norwood
Federal Regulation
Senior Vice President, General Counsel and Chief M. M. Durkin
Compliance Officer
Vice President and Controller A. M. Wilson
(hired from Energy 01/03/06)
FERC FORM NO.1 (ED. 12-96)Page 104
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
DIRECTORS
1. Report below the information called for concerning each director of the respondent who held office at any time during the year.Include in column (a), abbreviated
titles of the directors who are officers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
Name (an!=! .lltle) of IJirector PrinCipal Business Address
(a)(b)
David A. Clack'" (retired 05/11/06)325 E. Sprague Avenue, Spokane WA 99202
Lura J. Powell 2400 Stevens Dr., Suite B, Richland, WA 99352
R. John Taylor 111 Main Street, Lewiston ID 83501
John F. Kelly 4915 E. Doubletree Ranch Rd., Paradise Valley, AZ 85253
Jack W. Gustavel ...P. O. Box J, Coeur d' Alene, ID 83816
Jessie J. Knight, Jr. (resigned 06/22/06)Emerald Plaza, 402 W. Broadway, Suite 1000,
San Diego, CA 92101
Erik J. Anderson 3720 Carillon Point, Kirkland, WA 98033
Kristianne Blake O. Box 28338, Spokane, WA 99228
Gary G. Ely 1411 E. Mission Ave, Spokane, WA 99202
(Chairman & CEO)
Roy Lewis Eiguren O. Box 2720, Boise, ID 83701
Michael L. Noel 11960 W. Six Shooter Rd. , Prescott, AZ 86305
Heidi B. Stanley 111 N. Wall St., Spokane, WA 99201
FERC FORM NO.1 (ED. 12-95)Page 105
Name of Respondent
Avista Corporation
This Report Is:(1) (29 An Original(2) D A Resubmission
IMI ORTANT CHANGES DURING THE QUARTER/YEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or uNA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions , name of the Commission authorizing the transaction , and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto
and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given , assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization , if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate , and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer
director, security holder reported on Page 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 officers, directors, major security holders and voting powers of the respondent that may have
occurred during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
Date of Report
04/18/2007
Year/Period of Report
End of 2006/Q4
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) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
IMPORTANT CHANGES DURING THE OUARTER/YEAR (Continued)1. None.2. None.3. None.4. None.5. None.6. A vista Receivables Corporation (ARC) is a wholly owned, bankruptcy-remote subsidiary of A vista Corp.
fonned for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the
Company. On March 20, 2006, Avista Corp., ARC and a third-party financial institution amended a Receivables
Purchase Agreement. The most significant amendment was to extend the tennination date from March 21 , 2006 to March
20,2007. Under the Receivables Purchase Agreement, ARC can sell without recourse, on a revolving basis, up to $85.
million of those receivables. ARC is obligated to pay fees that approximate the purchaser s cost of issuing commercial
paper equal in value to the interests in receivables sold. On a consolidated basis, the amount of such fees is included in
other operating expenses of Avista Corp. At each of December 31 2006 and 2005, $85.0 million in accounts receivables
were sold under this revolving agreement.
On April 6, 2006, the Company amended its committed line of credit agreement with various banks. The
committed line of credit was originally entered into on December 17, 2004. Amendments to the committed line of credit
include a reduction in the total amount of the facility to $320.0 million from $350.0 million and an extension of the
expiration date to April 5, 2011 from December 16, 2009. The Company chose to reduce the facility based on forecasted
liquidity needs. Under the amended credit agreement, the Company can request the issuance of up to $320.0 million in
letters of credit, an increase from $150.0 million prior to the amendment. As of December 31 , 2006 and December 31,
2005, the Company had $4.0 million and $63.0 million, respectively, of borrowings outstanding. Total letters of credit
outstanding were $77.1 million as of December 31, 2006 and $44.1 million as of December 31 , 2005. The amended
committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds of the Company issued to
the agent bank that would only become due and payable in the event, and then only to the extent, that the Company
defaults on its obligations under the committed line of credit.
During December 2006, the Company issued $150.0 million of 5.70 percent First Mortgage Bonds due in
2037. The proceeds from the issuance were used to legally defease $150.0 million of First Mortgage Bonds that were
scheduled to mature on January 1 , 2007. This debt issuance was approved by the respective regulatory commissions as
follows: WUTC (Docket No. UE-061688 Order No.1); IPUC (Case No. A VU-06-02 Order No. 30150); and OPUC
(Docket UP 4230 Order No. 06-583).
In December 2006, the Company issued 3,162 500 shares of common stock through an underwriter and
received net proceeds of $77.7 million. This issuance was approved by the respective regulatory commissions as follows:
WUTC (Docket UE-060537 Order 01); OPUC (Docket UP 4225 Order No. 06-358); and IPUC (Case No. A VU-06-
Order No. 30036).
Also, in December 2006, the Company entered into a sales agency agreement with a sales agent, to issue up
to 2 million shares of its common stock from time to time.7. No changes in articles of incorporation or amendments to charter. On August 16,2006, the Bylaws of Avista
Corporation were amended. Specifically, section 2 of Article ill of the Bylaws of A vista Corporation has been changed
with respect to the number of directors of the Corporation. Section 2 of Article ill, which previously stated that "the
number of directors of the Corporation shall be eleven " has been amended to state "the number of directors of the
Corporation shall be no more than eleven.
On November 9,2006, the Bylaws of Avista Corporation were amended. Specifically, section 2 of Article
ill of the Bylaws of A vista Corporation has been changed with respect to the number of directors of the Corporation.
Section 2 of Article ill, which previously stated that "the number of directors of the Corporation shall be no more than
eleven," has been amended to state "the number of Directors of the Corporation shall be as fixed from time to time by
resolution of the Board of Directors, but shall not be more than eleven.8. Average annual wage increases were 2.4% during 2006 for non-exempt personnel. Average annual wage
increases were 3.1 % for exempt employees during 2006. Average annual wage increases were 4.0% for officers during
IFERC FORM NO.1 (ED. 12-96) Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
IMPORTANT CHANGES DURING THE OUARTER/YEAR (Continued)
2006. Bargaining unit employees increases were 3.0%.9. Reference is made to Note 23 of Notes to Financial Statements, page 123 of this Report.10. None.11. Reserved12. See page 123 of this Report.13. On January 6, 2006, Avista Corp. announced the appointment of Christy Burmeister-Smith as vice president
and treasurer and Ann Wilson as vice president and controller. Christy Burmeister-Smith previously was vice president
and controller of the Company since June 1999. Ann Wilson previously was vice president and controller of A vista
Energy, Inc., a subsidiary of the Company, since January 2000.
On May 12, 2006, the Board of Directors of A vista Corp. named Scott L. Morris as president and chief
operating officer of A vista Corp. Mr. Morris previously was A vista Corp. senior vice president and president of A vista
Utilities. Gary G. Ely previously president of Avista Corp., will remain as chairman of the board and chief executive
officer. In addition, the board named senior vice president and chief financial officer Malyn K. Malquist to the position
of executive vice president and chief financial officer for the Company.
David A. Clack did not stand for re-election and retired at the annual meeting of shareholders on May 11,
2006. Mr. Clack served on the Company s Board of Directors for 18 years and retired because he reached the mandatory
retirement age for directors as provided for in the Company s bylaws.
Heidi B. Stanley was elected as a director at the annual meeting of shareholders on May 11, 2006 for a
three-year term to expire at the annual meeting of shareholders in 2009. Ms. Stanley has served as Director, Vice Chair
and Chief Operating Officer of Sterling Savings Bank since October 2003. In her 20-year career in banking, she has held
progressively responsible positions of leadership.
On June 22, 2006, Jessie J. Knight, J r. provided written notification to A vista Corp. of his resignation from
A vista Corp.' s board of directors due to the fact that Mr. Knight has accepted a position as an executive officer of another
public utility company.
James M. Kensok was named Vice President and ChiefInformation Officer effective January 1,2007. Mr.
Kensokjoined Avista in 1996 as an internal information systems auditor. He has held positions as manager and director
of information systems and chief security officer, and he has been the Chief Information Officer since February 2001.
On February 9, 2007, Gary G. Ely, Chairman of the Board and Chief Executive Officer of Avista Corp.,
announced to the Company s board of directors, that he will retire from the Company and the board effective December
2007. Following Mr. Ely s announcement, the Company s board of directors appointed Scott L. Morris, President
and Chief Operating Officer of Avista Corp., to serve as a director on the board. The Company s board of directors also
elected Mr. Morris to the positions of Chairman of the Board and Chief Executive Officer of A vista Corp. effective
January 1, 2008.14. Proprietary capital is not less than 30 percent.
IFERC FORM NO.(ED. 12-96) Page 109.
This Page Intentionally Left Blank
This Report Is: Date of Report
(1) !ZI An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2007
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2006/Q4
Line
No.Title of Account
(a)
UTILITY PLANT
Ref.
Page No.
(b)
Current Year Prior Year
End of QuarterlY ear End Balance
Balance 12/31
(c)(d)
938,456,395 847 042,774
177 799 55,887,059
027 634 194 902 929 833
024 356,307 971 551 338
003,277 887 931 378,495
003 277 887 931 378,495
670 391 142,727
878 680 858 924
903 000 903 000
247 190 561 237 737 798
~Lj.jG,lXi20 L Gig. !.ijii f0:L.. 0i Lb,-.
166,335
360 954
574 531
334 987 092
701 281
049 946
731 530
349,407 358
021 873
042 325
684 345
667 445
89,325 500
714 601
730 352
198 865
465,217
121 931
019,070
602 512
5,408,468
726 275
513,042
39,569
101,478,486
041,055
227 916
321 130
773 050
006,429
Utility Plant (101-106 114)
Construction Work in Progress (107)
TOTAL Utility Plant (Enter Total of lines 2 and 3)
(Less) Accum. Provo for Depr. Amort. Depl. (108, 110, 111 , 115)
Net Utility Plant (Enter Total of line 4 less 5)
Nuclear Fuel in Process of Ref., Conv.Enrich., and Fab. (120.
Nuclear Fuel Materials and Assemblies-Stock Account (120.
Nuclear Fuel Assemblies in Reactor (120.
Spent Nuclear Fuel (120.4)
Nuclear Fuel Under Capital Leases (120.
(Less) Accum. Provo for Amort. of Nucl. Fuel Assemblies (120.
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
Net Utility Plant (Enter Total of lines 6 and 13)
Utility Plant Adjustments (116)
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutility Property (121)
(Less) Accum. Provo for Depr. and Amort. (122)
Investments in Associated Companies (123)
Investment in Subsidiary Companies (123.
(For Cost of Account 123., 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 Property 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 Accounts Receivable (142)
Other Accounts Receivable (143)
(Less) Accum. Provo for Uncollectible Acct.-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.
200-201
200-201
200-201
202-203
202-203
122
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 This Report Is:Date of Report Year/Period of Report
A vista Corporation (1)IZI An Original (Mo, Da, Yr)
(2)A Resubmission 04/18/2007 End of 2006/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)Continued)
Line Current Year Prior Year
No.Ref.End of OuarterNear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
(Less) Noncurrent Portion of Allowances
Stores Expense Undistributed (163)227
Gas Stored Underground - Current (164.905,320 12,469 887
Liquefied Natural Gas Stored and Held for Processing (164.164.006,819 006 819
Prepayments (165)467 948 745,002
Advances for Gas (166-167)
Interest and Dividends Receivable (171)259
Rents Receivable (172)327 042 361 071
Accrued Utility Revenues (173)
Miscellaneous Current and Accrued Assets (174)162 032 449 358
Derivative Instrument Assets (175)36,402 843 116,224 963
(Less) Long-Term Portion of Derivative Instrument Assets (175)25,574 531 731 530
Derivative Instrument Assets - Hedges (176)
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176
Total Current and Accrued Assets (Lines 34 through 66)154 188 806 254 002 646
DEFERRED DEBITS
Unamortized Debt Expenses (181)931 388 15,692 385
Extraordinary Property Losses (182.230
Unrecovered Plant and Regulatory Study Costs (182.230
Other Regulatory Assets (182.232 323,816 436 225,248,761
Prelim. Survey and Investigation Charges (Electric) (183)645,616 988,821
Preliminary Natural Gas Survey and Investigation Charges 183.
Other Preliminary Survey and Investigation Charges (183.
Clearing Accounts (184)046
Temporary Facilities (185)
Miscellaneous Deferred Debits (186)233 297 127 40,675,589
Def. Losses from Disposition of Utility PIt. (187)
Research, Devel. and Demonstration Expend. (188)352-353
Unamortized Loss on Reaquired Debt (189)28,622 766 829,288
Accumulated Deferred Income Taxes (190)234 55,602 315 647,400
Unrecovered Purchased Gas Costs (191)18,275,674 43,444,010
Total Deferred Debits (lines 69 through 83)484 199,368 403 526,254
TOTAL ASSETS (lines 14-, 32, 67, and 84)976,653 153 938 314 753
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)IX)An Original (mo, da, yr)
(2)A Rresubmission 04/18/2007 end of 2006/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prior Year
No.Ref.End of QuarterlY ear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
PROPRIETARY CAPITAL
Common Stock Issued (201)250-251 722,039,406 631,083,752
Preferred Stock Issued (204)250-251
Capital Stock Subscribed (202, 205)252
Stock Liability for Conversion (203, 206)252
Premium on Capital Stock (207)252
Other Paid-In Capital (208-211)253
Installments Received on Capital Stock (212)252
(Less) Discount on Capital Stock (213)254
(Less) Capital Stock Expense (214)254 419,099 10,485,244
Retained Earnings (215, 215.1, 216)118-119 168 082,338 132 024 036
Unappropriated Undistributed Subsidiary Earnings (216.118-119 51,109 032 804 777
(Less) Reaquired Capital Stock (217)250-251
Noncorporate Proprietorship (Non-major only) (218)
Accumulated Other Comprehensive Income (219)122(a)(b)965,585 23,299,148
Total Proprietary Capital (lines 2 through 15)916,846 092 771 128 173
LONG-TERM DEBT
Bonds (221)256-257 685 196 931 719,082 687
(Less) Reaquired Bonds (222)256-257
Advances from Associated Companies (223)256-257 115 203,000 115,203,000
Other Long-Term Debt (224)256-257 315 600,402 391 538,636
Unamortized Premium on Long-Term Debt (225)257 617 266,500
(Less) Unamortized Discount on Long-Term Debt-Debit (226)709,479 879,744
Total Long-Term Debt (lines 18 through 23)114 548,471 224 211 079
OTHER NONCURRENT LIABILITIES
Obligations Under Capital Leases - Noncurrent (227)394 921 983,184
Accumulated Provision for Property Insurance (228.
Accumulated Provision for Injuries and Damages (228.954,409 790,259
Accumulated Provision for Pensions and Benefits (228.419 511 353,587
Accumulated Miscellaneous Operating Provisions (228.4)
Accumulated Provision for Rate Refunds (229)
Long-Term Portion of Derivative Instrument Liabilities 10,174,378 272
Long-Term Portion of Derivative Instrument Liabilities - Hedges 144,457 956,479
Asset Retirement Obligations (230)809,738 528,823
Total Other Noncurrent Liabilities (lines 26 through 34)104,897,414 700,604
CURRENT AND ACCRUED LIABILITIES
Notes Payable (231)
Accounts Payable (232)112 367 144 139,804,777
Notes Payable to Associated Companies (233)
Accounts Payable to Associated Companies (234)980,544 769 180
Customer Deposits (235)463,634 264 115
Taxes Accrued (236)262-263 887,161 112 798
Interest Accrued (237)594 861 643 064
Dividends Declared (238)
Matured Long-Term Debt (239)
FERC FORM NO.1 (rev. 12-03)Page 112
Name of Respondent This Report is:Date of Report Year/Period of Report
A vista Corporation (1)IX)An Original (mo, da, yr)
(2)A Rresubmission 04/18/2007 end of 2006/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIT~ntinued)
Line Current Year Prior Year
Ref.End of Quarter/Year End BalanceNo.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
Matured Interest (240)
Tax Collections Payable (241)651 893
Miscellaneous Current and Accrued Liabilities (242)63,245,923 35,225,169
Obligations Under Capital Leases-Current (243)281,894 050,181
Derivative Instrument Liabilities (244)83,652,834 534,971
(Less) Long-Term Portion of Derivative Instrument Liabilities 10,174,378 272
Derivative Instrument Liabilities - Hedges (245)144,457 956,479
(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 144 457 956,479
Total Current and Accrued Liabilities (lines 37 through 53)263 527,946 203 093 280
DEFERRED CREDITS
Customer Advances for Construction (252)087 069 820,898
Accumulated Deferred Investment Tax Credits (255)266-267 472 344 521 652
Deferred Gains from Disposition of Utility Plant (256)
Other Deferred Credits (253)269 36,280,631 36,304,164
Other Regulatory Liabilities (254)278 18,246,960 116,251,545
Unamortized Gain on Reaquired Debt (257)282 969 754,170
Accum. Deferred Income Taxes-Accel. Amort.(281)272-277
Accum. Deferred Income Taxes-Other Property (282)305,474 214 289,242,025
Accum. Deferred Income Taxes-Other (283)211 989,043 228,287,163
Total Deferred Credits (lines 56 through 64)576 833,230 675,181 617
TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)976 653,153 938,314,753
FERC FORM NO.(rev. 12-03)Page 113
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation
(1) An Original (Mo, Da, Yr)End of 2006/Q4(2) DA Resubmission 04/18/2007
STATEMENT OF INCOME
Quarterly
1. Enter in column (d) the balance for the reporting quarter and in column (e) the balance for the same three month period for the prior year.
2. Report in column (f) the quarter to date amounts for electric utility function; in column (h) the quarter to date amounts for gas utility, and in OJ the
quarter to date amounts for other utility function for the current year quarter.
3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in (k) the
quarter to date amounts for other utility function for the prior year quarter.
4. If additional columns are needed place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
8. Report data for lines 8, 10 and 11 for Natural Gas companies using accounts 404.404.404.407.1 and 407.
Line Total Total Current 3 Months Prior 3 Months
No.Current Year to Prior Year to Ended Ended
(Ref.Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Account Page No.Quarter/Year Quarter/Year No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)
1 UTILITY OPERATING INCOME
Operating Revenues (400)300-301 319 860,703 237 767,426
Operating Expenses
Operation Expenses (401)320-323 957 162,716 905 198,240
5 Maintenance Expenses (402)320-323 805,328 37,138,187
Depreciation Expense (403)336-337 637 110 73,085,675
Depreciation Expense for Asset Retirement Costs (403.336-337
8 Amort. & Depl. of Utility Plant (404-405)336-337 717,177 502 043
9 Amort. of Utility Plant Acq. Adj. (406)336-337 047 047
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
Amort. of Conversion Expenses (407)
Regulatory Debits (407.637 368 184 236
(Less) Regulatory Cred~s (407.4)989,452 16,785 763
Taxes Other Than Income Taxes (408,262-263 881 930 044 198
Income Taxes - Federal (409.262-263 535 123 778,732
- Other (409.262-263 155,970 017,492
Provision for Deferred Income Taxes (410.234 272-277 330,636 077 269
(Less) Provision for Deferred Income Taxes-Cr. (411.234 272-277 112,169 425,562
Investment Tax Credit Adj. - Net (411.4)266 -49,308 308
(Less) Gains from Disp. of Utility Plant (411.6)
Losses from Disp. of Utility Plant (411.
(Less) Gains from Disposition of Allowances (411.
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)170 811,476 101 864,486
Net Uti! Oper Inc (Enter Tot line 2 less 25) Carry to Pg117 line 27 149 049 227 135 902 940
FERC FORM NO. 1/3-(REV. 02-04)Page 114
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmisslon 04/18/2007
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for important notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accounts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous years/quarter s figures are different from that reported in prior reports.
15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY
Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Line
(in dollars)(in dollars)(in dollars)(in dollars)(in dollars)(in dollars)No.
(g)
(h) (i) OJ (k) (I)
514 013 824 535,268 030 443 148,892 369,930 210
34,489 049 159 167 316 279 979 020
61,477 791 591 752 159,319 15,493 923
912 961 285 954 804 216 216 089
047 047
337 368 184 236 300 000
989,452 16,785 763
176 981 46,205 269 704 949 838 929
758,428 28,567 999 776,695 789 267
847 436 101 948 308,534 915,544
067 991 917 531 737 355 994 800
689,311 566 602 422 858 141 040
308 49,308
672 502 113 683,193,506 498 309 363 418 670 980
125,052 970 111 357,723 996,257 545 217
FERC FORM NO.1 (ED. 12-96)Page 115
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
STA EMENT OF INCOME FOR THE YEAR (continued)
TOTAL
Year/Period of Report
End of 2006/04
Prior 3 Mont s
Ended
Quarterly Only
No 4th Quarter
Line
No.
(Ref.)
Page No.
(b)
Title of Account
(a)
Current Year
(c)
Previous Year
(d)
27 Net Utility Operating Income (Carried forward from page 114)
28 Other Income and Deductions
29 Other Income
30 Nonutilty Operating Income
31 Revenues From Merchandising, Jobbing and Contract Work (415)
32 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
33 Revenues From Nonutility Operations (417)
34 (Less) Expenses of Nonutility Operations (417.
35 Nonoperating Rental Income (418)
36 Equity in Eamings of Subsidiary Companies (418.
37 Interest and Dividend Income (419)
38 Allowance for Other Funds Used During Construction (419.
39 Miscellaneous Nonoperating Income (421)
40 Gain on Disposition of Property (421.
41 TOTAL Other Income (Enter Total of lines 31 thru40)
42 Other Income Deductions
43 Loss on Disposition of Property (421.
44 Miscellaneous Amortization (425)
45 Donations (426.1)
46 Life Insurance (426.
47 Penalties (426.
48 Exp. for Certain Civic, Political & Related Activities (426.4)
49 Other Deductions (426.
50 TOTAL Other Income Deductions (Total of lines 43 thru 49)
51 Taxes Applic. to Other Income and Deductions
52 Taxes Other Than Income Taxes (408.
53 Income Taxes-Federal (409.
54 Income Taxes-Other (409.
55 Provision for Deferred Inc. Taxes (410.
56 (Less) Provision for Deferred Income Taxes-Cr. (411.
57 Investment Tax Credit Adj.Net (411.
58 (Less) Investment Tax Creqits (420)
59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)
60 Net Other Income and Deductions (Total of lines 41 59)
61 Interest Charges
62 Interest on Long-Term Debt (427)
63 Amort. of Debt Disc. and Expense (428)
64 Amortization of Loss on Reaquired Debt (428.
65 (Less) Amort. of Premium on Debt-Credit (429)
66 (Less) Amortization of Gain on Reaquired Debt-Credit (429.
67 Interest on Debt to Assoc. Companies (430)
68 Other Interest Expense (431)
69 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)
70 Net Interest Charges (Total of lines 62 thru 69)
71 Income Before Extraordinary Items (Total of lines 27,60 and 70)
72 Extraordinary Items
73 Extraordinary Income (434)
74 (Less) Extraordinary Deductions (435)
75 Net Extraordinary Items (Total of line 73 less line 74)
76 Income Taxes-Federal and Other (409.
77 Extraordinary Items After Taxes (line 75 less line 76)
78 Net Income (Total of line 71 and 77)
149,049,227 135,902 940
20,984
052,579
625
611 524
041 049
388 777
756,573
127
16,839,461
267,952
2,429 542
119
237 712
998 967
398 103
179 185~I0"18C'~
...,
Jiii:; 01 '1&f ;f,~:2EI f J..:L. "-LIe ,;.i.' ;.:L1,i!.22
138,153
120,288
368,086
972,456
500
052 120
059 980
716 583
160
182 975
874 169
686 972
530
893 627
537 552
159 925
340
340
~;.. '
::.'1!~,' ~c. .,,L~2d;.iJi;~V.2;!
.;.'
E:.L;C:jJ/'.t:c fit';,. .'
262,263
262,263
262-263
234 272-277
234, 272-277
153,385
584,900
912,325
874 146
087 684
878
853 876
376,668
853,172
761 854
387 578
669 962
641,404
622 144
~ :..;
"Lilinili:,D2.8c"':Zw2.2i;;I:.!. L.: .2:.1.:c0:,:,U",i..I03. ~I
938 550
020,316
729,883
884
268 237
509 307
252 219
340
340
116,429
724 805
934 769
586 330
132 859
202 703
569,331
689,303
112,494
45,168 302~c~l... c L;2Bi .;;:iG.: J . + d: .ii" :L:L i,i;LL
262-263
132 859 168,302
FERC FORM NO. 1/3-Q (REV. 02-04)Page 117
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
STATEMENT OF RETAINED EARNINGS
1 . Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439 , Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Year/Period of Report
End of 2006/04
Line
No.
Item
(a)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Account 439)
5 ESOP and Other Adjustment
6 Tax Benefit Received from 401 (k) Dividend Reinvestment Plan
7 Dividends Received from Subsidiaries
Contra Primary
ccount Affected
Current
OuarterNear
Year to Date
Balance
Previous
OuarterNear
Year to Date
Balance
9 TOTAL Credits to Retained Earnings (Acct. 439)
12 Stock Options Exercised
15 TOTAL Debits to Retained Earnings (Acct. 439)
16 Balance Transferred from Income (Account 433 less Account 418.
17 Appropriations of Retained Earnings (Acct. 436)
22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
36 TOTAL Dividends Declared-Common Stock (Acct. 438)
37 Transfers from Acct 216., Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1 ,15,36,37)
790
415,237
989 256 095,863
404,493 15,133,653
160 637 788,018)
160,637 788 018)
293 398 51,779 826~ilitil810BRTJ::~8TI02~Zz;~C, ~I8;;:' ; :;:XG;
;;;j
:-',::j" I,
0; ,icE' ~)fi;;!lli.0dE j,iIill12001iITG08828;~;8L8.:L;L2 2 j;,L2, ..:.L
27,924.168 ( 26,443,242)
924 168
445 216
166,534 217
( 26 443,242)
699 526
130,475,915
FERC FORM NO. 1/3-0 (REV. 02-04)Page 118
Name of Respondent
A vista Corporation
Year/Period of Report
End of 2006/Q4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
APPROPRIATED RETAINED EARNINGS (Account 215)
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Ace!. 215.
47 TOTAL Approp. Retained Earnings (Acc!. 215, 215.1) (Total 45,46)
48 TOTAL Retained Earnings (Acct. 215, 215.216) (Total 38, 47) (216.
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.
51 (Less) Dividends Received (Debit)
52 Subsidiary Expense & Misc Subs Equity Comp
53 Balance-End of Year (Total lines 49 thru 52)
Current Previous
QuarterNear QuarterNear
Contra Primary Year to Date Year to Date
Account Affected Balance Balance
(b)(c)(d)
lii.Jif5ill2,ll~; 1Kli (, ~bt&;ill:ld~:,LL12c,bl;i." ,3.; ""
; . ,
, c". '
- ," .
548,121 548,121
548 121 548 121
!Z ;L;c:;I;;2.:Lilii2lli: ~\:l;Ujjh\.CL~ C.:;Uii:B:'J2d.ZellilIlJii
;'::..
l;,.'l; JG\:,.J Gc:..L.;.
548 121
168 082 338
548,121
132 024 036~L",:;E2L..
..,.'..,......-,....,
l...",L~JL2.BL0,,LL,
,_,'."".
804 777
839 461
989 256
545,950
109,032
211,690
611 524)
15,095,863
699,526)
804,777
FERC FORM NO. 1/3-0 (REV. 02-04)Page 119
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2) riA Resubmission 04/18/2007
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles. etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash
Equivaients at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line Description (See Instruction No.1 for Explanation of Codes)Current Year to Date Previous Year to Date
No.OuarterNear OuarterNear
(a)(b)(c)
Net Cash Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117)132 859 168 302
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion 84,354,287 79,158,362
5 Amortization of deferred power and natural gas costs 56,326 822 629,580
6 Amortization of debt expense 741 314 761,526
7 Amortizaton of investment in exchange power 450,031 450,031
8 Deferred Income Taxes (Net)16,465,046 594 223
9 Investment Tax Credit Adjustment (Net)49,308 49,308
Net (Increase) Decrease in Receivables 519 009 54,565 111
Net (Increase) Decrease in Inventory 203,045 674 661
Net (Increase) Decrease in Allowances Inventory
Net Increase (Decrease) in Payables and Accrued Expenses 118,183 447,322
Net (Increase) Decrease in Other Regulatory Assets 061 549 8,426,825
Net Increase (Decrease) in Other Regulatory Liabilities 175,736 618,782
(Less) Allowance for Other Funds Used During Construction 429,542 078,080
(Less) Undistributed Eamings from Subsidiary Companies 839,461 611 523
Other (provide details in footnote):376 700 816 795
Gain on sale of property 559 398,103
Net change in receivables allowance 497 564 504 630
Change in other noncurrent assets and liabilities 672 181 269 258
Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)172 942 538 154 967 092
Cash Flows from Investment Activities:
Construction and Acquisition of Plant (including land):
Gross Additions to Utility Plant (less nuclear fuel)156 952 633 259,675,718
Gross Additions to Nuclear Fuel
Gross Additions to Common Utility Plant
Gross Additions to Nonutility Plant
(Less) Allowance for Other Funds Used During Construction
Other (provide details in footnote):
Cash Outflows for Plant (Total of lines 26 thru 33)156,952 633 259 675 718
Acquisition of Other Noncurrent Assets (d)
Proceeds from Disposal of Noncurrent Assets (d)657 770 014 769
Investments in and Advances to Assoc. and Subsidiary Companies
Contributions and Advances from Assoc. and Subsidiary Companies 646,304 785 415
Disposition of Investments in (and Advances to)
Associated and Subsidiary Companies
Purchase of Investment Securities (a)
Proceeds from Sales of Investment Securities (a)
FERC FORM NO.1 (ED. 12-96)Page 120
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc,
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements, Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line Description (See Instruction No.1 for Explanation of Codes)Current Year to Date Previous Year to Date
No.OuarterNear OuarterNear
(a)(b)(c)
Loans Made or Purchased
Collections on Loans 15,263 678
Net (Increase) Decrease in Receivables
Net (Increase) Decrease in Inventory
Net (Increase) Decrease in Allowances Held for Speculation
Net Increase (Decrease) in Payables and Accrued Expenses
Other (provide details in footnote):
Changes in other property and investments 763,324 540,127
Proceeds from sale of utility property claim 483,780
Net Cash Provided by (Used in) Investing Activities
Total of lines 34 thru 55)114,912 840 222 320,729
Cash Flows from Financing Activities:
Proceeds from Issuance of:
Long-Term Debt (b)149 778 000 149,632 500
Preferred Stock
Common Stock 393 784 570,795
Other (provide details in footnote):
Net Increase in Short-Term Debt (c)
Other (provide details in footnote):
Cash received in interest rate swap agreement 445,000
Cash Provided by Outside Sources (Total 61 thru 69)238,171 784 155 648 295
Payments for Retirement of:
Long-term Debt (b)197,231 550 440,903
Preferred Stock 750,000 750,000
Common Stock
Premiums paid for the redemption of long-term debt 425,996 826,430
Long-term debt and short-term borrowing issuance costs 5,435 618 152 802
Net Decrease in Short-Term Debt (c)000 000 000 000
Cash paid in interest rate swap agreement 738 000
Dividends on Preferred Stock
Dividends on Common Stock 927 206 443 249
Net Cash Provided by (Used in) Financing Activities
(Total of lines 70 thru 81)
Net Increase (Decrease) in Cash and Cash Equivalents
(Total of lines 22,57 and 83)693 112 318,726
Cash and Cash Equivalents at Beginning of Period 363,195 955,531
Cash and Cash Equivalents at End of period 670 083 363 195
FERC FORM NO.1 (ED. 12-96)Page 121
Name of Respondent
Avista Corporation
Date of Report
04/18/2007
Year/Period of Report
End of 2006/04
This Report Is:(1) ~ An Original
(2) 0 A Resubmisslon
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
S. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121 , such notes may be included herein.
7. For the SO disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 30 disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REOUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 122
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
Avista Corporation (Avista Corp. or the Company) is an energy company engaged in the generation, transmission and distribution of
energy as well as other energy-related businesses. A vista Corp. generates, transmits and distributes electricity in parts of eastern
Washington and northern Idaho. In addition, Avista Corp. has electric generating facilities in western Montana and northern Oregon.
A vista Corp. also provides natural gas distribution service in parts of eastern Washington and northern Idaho, as well as parts of
northeast and southwest Oregon. Avista Capital, Inc. (A vista Capital), a wholly owned subsidiary of Avista Corp., is the parent
company of all of the subsidiary companies in the non-utility business segments.
The Company s operations are exposed to risks including, but not limited to:
price and supply of purchased power, fuel and natural gas
regulatory recovery of power and natural gas costs and capital investments
streamflow and weather conditions,
effects of changes in legislative and governmental regulations
changes in regulatory requirements,
availability of generation facilities
. competition
technology, and
availability of funding.
Also, like other utilities, the Company s facilities and operations are exposed to terrorism risks or other malicious acts. In addition, the
energy business exposes the Company to the financial, liquidity, credit and price risks associated with wholesale purchases and sales of
energy commodities.
Basis of Reporting
The financial statements include the assets, liabilities, revenues and expenses of the Company. As required by the Federal Energy
Regulatory Commission (FERC), the Company accounts for its investment in majority-owned subsidiaries on the equity method rather
than consolidating the assets, liabilities;' revenues, and expenses of these subsidiaries, as required by accounting principles generally
accepted in the United States of America. The accompanying financial statements include the Company s proportionate share of utility
plant and related operations resulting from its interests in jointly owned plants. In addition, under the requirements of the FERC, there
are differences from accounting principles generally accepted in the United States of America in the presentation of (1) current
portions of long-term debt, short-term borrowings, and preferred stock, (2) assets and liabilities for cost of removal of assets, (3) assets
held for sale, (4) regulatory assets and liabilities, and (5) comprehensive income.
Use of Estimates
The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of
America 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 assets and liabilities,
pension and other postretirement benefit plan obligations,
contingent liabilities
recoverability of regulatory assets
stock-based compensation, and
unbilled revenues.
Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the financial
statements and thus actual results could differ from the amounts reported and disclosed herein.
System of Accounts
The accounting records of the Company s utility operations are maintained in accordance with the uniform system of accounts
prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the appropriate state regulatory commissions.
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Regulation
The Company is subject to state regulation in Washington, Idaho, Montana and Oregon. The Company is also subject to federal
regulation by the FERC.
Operating Revenues
Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. The
determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis
throughout the month. At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter
reading is estimated and the corresponding unbilled revenue is estimated and recorded. Accounts receivable includes unbilled energy
revenues of $21.7 million (net of $51.6 million of unbilled receivables sold) as of December 31 , 2006 and $13.1 million (net of $57.
million of unbilled receivables sold) as of December 31 , 2005. See Note 3 for information related to the sale of accounts receivable.
Advertising Expenses
The Company expenses advertising costs as incurred. Advertising expenses were not a material portion of the Company s operating
expenses in 2006, 2005 and 2004.
Taxes Other Than Income Taxes
Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and
certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes
collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled
$48.3 million in 2006, $43.1 million in 2005 and $35.0 million in 2004.
Income Taxes
The Company and its eligible subsidiaries file consolidated federal income tax returns. Subsidiaries are charged or credited with the
tax effects of their operations on a stand-alone basis. The Internal Revenue Service (IRS) has examined the Company s 2001, 2002
and 2003 federal income tax returns. Despite those tax years still remaining open, all issues have been resolved with the exception of
certain indirect overhead costs (see Note 10).
The Company accounts for income taxes under SFAS No. 109, "Accounting for Income Taxes." Under SFAS No. 109, a deferred tax
asset or liability is determined based on the enacted tax rates that will be in effect when the differences between the financial statement
carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company s consolidated income tax
returns. The deferred tax expense for the period is equal to the net change in the deferred tax asset and liability accounts from the
beginning to the end of the period. The effect on deferred taxes of a change in tax rates is recognized in income in the period that
includes the enactment date. Deferred tax liabilities and reguJatory assets have been established for tax benefits flowed through to
customers as prescribed by the respective regulatory commissions.
Stock-Based Compensation
Prior to January 1 2006, the Company followed the disclosure only provisions of SFAS No. 123
, "
Accounting for Stock-Based
Compensation." Accordingly, employee stock options were accounted for under Accounting Principle Board Opinion (APB) No. 25,
Accounting for Stock Issued to Employees." Stock options are granted at exercise prices not less than the fair value of common stock
on the date of grant. Avista Corp. has not granted any stock options since 2003. Under APB No. 25, no compensation expense was
recognized pursuant to the Company s stock option plans. However, the Company recognized compensation expense related to
performance-based share awards. The Company adopted SFAS No. 123R
, "
Share-Based Payment " on January 1 2006, which has
resulted in changes to stock compensation expense recognition. See Note 2 and Note 22 for further information. The Company
adopted SFAS No. 123R using the modified prospective method and, accordingly, financial statement amounts for prior periods
presented have not been restated to reflect the fair value method of recognizing compensation expense relating to share-based
payments.
If compensation expense for the Company s stock-based employee compensation plans were detennined consistent with SFAS No.
123, net income and earnings per common share would have been the following pro forma amounts for the years ended December 31
(prior to the adoption of SF AS No. 123R):
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubm ission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
2005 2004
Net income (doJlars in thousands):
As reported
Add: Total stock-based employee compensation
expense included in net income, net of tax
Deduct: Total stock-based employee compensation
expense determined under the fair value
method for all awards, net of tax
Pro forma
Basic and diluted earnings per common share:
Basic as reported
Diluted as reported
Basic pro forma
Diluted pro forma
$45 168 $35,154
211
Q.2.ill
468
(2,033)
121
$0.
$0.
$0.
$0.
$0.
$0.
$0.
$0.
Earnings Per Common Share
Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of
common shares outstanding for the period. Diluted earnings per common share is calculated by dividing income available for common
stock by diluted weighted average common shares outstanding during the period, including common stock equivalent shares
outstanding using the treasury stock method, urness such shares are anti-dilutive. Common stock equivalent shares include shares
issuable upon exercise of stock options and contingent stock awards. See Note 21 for earnings per common share calculations.
Cash and Cash Equivalents
For the purposes of the Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months or
less when purchased to be cash equivalents. Cash and cash equivalents include cash deposits from counterparties. See Note 6 for
further information related to cash deposits from counterparties.
Allowance for Doubtful Accounts
The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The
Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to
accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual
accounts. The following table presents the activity in the allowance for doubtful accounts during the years ended December 31
(dollars in thousands):
Allowance as of the beginning of the year
Additions expensed during the year
Net deductions
Allowance as of the end of the year
2006
228
888
(3,386)
$2.730
2005
810
752
(2,334)
$3.228
2004
281
195
(2,666)
$2.810
Materials and Supplies, Fuel Stock and Natural Gas Stored
Inventories of materials and supplies, fuel stock and natural gas stored are recorded at the lower of cost or market, primarily using the
average cost method.
Utility Plant in Service
The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of
property and improvements, is capitalized. Costs of depreciable units of property retired plus costs of removal less salvage are charged
to accumulated depreciation.
Allowance for Funds Used During Construction
The Allowance for Funds Used During Construction (AFUDC) represents the cost of both the debt and equity funds used to finance
utility plant additions during the construction period. In accordance with the uniform system of accounts prescribed by regulatory
authorities, AFUDC is capitalized as a part of the cost of utility plant and the debt related portion is credited currently as a non-cash
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubm ission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
item in the Statements of Income. The Company generally is permitted, under established regulatory rate practices, to recover the
capitalized AFUDC, and a fair return thereon, through its inclusion in rate base and the provision for depreciation after the related
utility plant is placed in service. Cash inflow related to AFUDC generally does not occur until the related utility plant is placed in
service and included in rate base. The effective AFUDC rate was 9.11 percent in 2006 and 9.72 percent for 2005 and 2004. The
Company s AFUDC rates do not exceed the maximum allowable rates as determined in accordance with the requirements of regulatory
authorities.
Depreciation
For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing unit rates for generation
plants and composite rates for other utility plant. Such rates are designed to provide for retirements of properties at the expiration of
their service lives. The rates for hydroelectric plants include annuity and interest components, in which the interest component is 9
percent. For utility operations, the ratio of depreciation provisions to average depreciable property was 2.89 percent in 2006, 2.
percent in 2005 and 2.92 percent in 2004.
The average service lives for the following broad categories of utility property are:
electric thermal production - 28 years,
hydroelectric production - 77 years,
electric transmission - 42 years
electric distribution - 47 years, and
natural gas distribution property - 36 years.
The Company recovers certain asset retirement costs through rates charged to customers as a portion of its depreciation expense for
which the Company has not recorded asset retirement obligations (see Note 8). These costs do not represent legal or contractual
obligations.
Regulatory Deferred Charges and Credits
The Company prepares its financial statements in accordance with the provisions of SF AS No. 71
, "
Accounting for the Effects of
Certain Types of Regulation." The Company prepares its financial statements in accordance with SF AS No. 71 because:
rates for regulated services are established by or subject to approval by an independent third-party regulator
the regulated rates are designed to recover the cost of providing the regulated services, and
in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be charged
to and collected from customers at levels that will recover costs.
SF AS No. 71 requires the Company to reflect the impact of regulatory decisions in its financial statements. SF AS No. 71 requires that
certain costs and/or obligations (such as incurred power and natural gas costs not currently recovered through rates, but expected to be
recovered in the future) are reflected as deferred charges or credits on the Balance Sheets. These costs and/or obligations are not
reflected in the statement of income until the period during which matching revenues are recognized.
If at some point in the future the Company determines that it no longer meets the criteria for continued application of SF AS No. 71 for
all or a portion of its regulated operations, the Company could be:
required to write off its regulatory assets, and
precluded from the future deferral of costs not recovered through rates at the time such costs are incurred, even if the
Company expected to recover such costs in the future.
The Company s primary regulatory assets include:
power and natural gas deferrals
investment in exchange power
regulatory asset for deferred income taxes
unamortized debt expense,
demand side management programs,
conservation programs, and
unfunded pensions and other postretirement benefits.
IFERC FORM NO.1 (ED. 12-88)Page 123.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Regulatory liabilities include utility plant retirement costs, liabilities created when the Centralia Power Plant was sold
liabilities offsetting net utility energy commodity derivative assets (see Note 4 for further information), and the gain on the general
office building salelleaseback.
Investment in Exchange Power-Net
The investment in exchange power represents the Company s previous investment in Washington Public Power Supply System Project
3 (WNP-3), a nuclear project that was terminated prior to completion. Under a settlement agreement with the Bonneville Power
Administration in 1985, A vista Corp. began receiving power in 1987, for a 32.5-year period, related to its investment in WNP-
Through a settlement agreement with the Washington Utilities and Transportation Commission (WUTC) in the Washington
jurisdiction, A vista Corp. is amortizing the recoverable portion of its investment in WNP-3 (recorded as investment in exchange
power) over a 32.5 year period beginning in 1987. For the Idaho jurisdiction, Avista Corp. has fully amortized the recoverable portion
of its investment in exchange power.
Unamortized Debt Expense and Unamortized Loss on Reacquired Debt
Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt, as weB as premiums paid to
repurchase debt, which are amortized over the average remaining maturity of outstanding debt in accordance with regulatory
accounting practices under SFAS No. 71. These costs are recovered through retail rates as a component of interest expense.
Power Cost Deferrals and Recovery Meclulnisms
Deferred power supply costs are recorded as a deferred charge on the Balance Sheets for future review and the opportunity for
recovery through retail rates. The power supply costs deferred include certain differences between actual power supply costs incurred
by Avista Corp. and the costs included in base retail rates. This difference in power suppJy costs primarily results from changes in:
. short-term wholesale market prices
the level of hydroelectric generation, and
the level of thermal generation (including changes in fuel prices).
In Washington, the Energy Recovery Mechanism (ERM) allows A vista Corp. to increase or decrease electric rates periodically with
WUTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences
between actual power supply costs and the amount included in base retail rates for Washington customers. 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. A vista Corp. accrues interest on deferred power costs in the Washington jurisdiction at a rate
which is adjusted semi-annually, of 8.25 percent as of December 31, 2006. Total deferred power costs for Washington customers
were $70.2 million as of December 31 , 2006 and $96.2 million as of December 31 , 2005.
In June 2006, the WUTC approved a settlement agreement between the Company, the staff of the WUTC, the Industrial Customers of
Northwest Utilities and the office of Public Counsel Section of the Washington Attorney General's Office , representing all parties in
the Company s ERM proceeding. The settlement agreement provides for the continuation of the ERM with certain agreed-upon
modifications and is effective as of January 2006. The settling parties have agreed to review the ERM after five years.
The settlement agreement modified the ERM such that the Company s annual deadband was reduced from $9.0 million to $4.0 million
and the Company will incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. Annual
power supply cost variances between $4.0 million and $10.0 million are shared equally between the Company and its customers. As
such, 50 percent of the annual power supply cost variance in this range is deferred for future surcharge or rebate to the Company
customers and the remaining 50 percent is an expense of, or benefit to, the Company. Once the annual power supply cost variance
from the amount included in base rates exceeds $10.0 million, 90 percent of the cost variance is deferred for future surcharge or rebate.
The remaining 10 percent of the variance beyond $10.0 million is an expense of, or benefit to, the Company without affecting current
or future customer rates. The following table summarizes the historical (prior to January 2006) and modified ERM (effective
January 2006):
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubm ission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Annual Power Supply
Cost Variabilitv
Historical ERM:
+/- $0 - $9 million
+/- excess over $9 million
Modified ERM:
+/- $0 - $4 million
+/- between $4 million - $10 million
+/- excess over $10 million
Deferred for Future
Surcharge or Rebate
to Customers
Expense or Benefit
to the Com
90%
100%
10%
50%
90%
100%
50%
10%
Under the ERM, Avista Corp. makes an annual filing to provide the opportunity for the WUTC and other interested parties to review
the prudence of and audit the ERM deferred power cost transactions for the prior calendar year. The ERM provides for a 90-day
review period for the filing; however, the period may be extended by agreement of the parties or by WUTC order. In June 2006, the
WUTC issued an order, which approved the recovery of the $4.1 million of deferred power costs incurred for 2005.
Avista Corp. has a power cost adjustment (PCA) mechanism in Idaho that allows it to modify electric rates periodically with Idaho
Public Utilities Commission (IPUC) approval. Under the PCA mechanism, A vista Corp. defers 90 percent of the difference between
certain actual net power supply expenses and the amount included in base retail rates for Idaho customers. Avista Corp. accrues
interest on deferred power costs in the Idaho jurisdiction at a rate, which is adjusted annually, of 3.0 percent on current year deferrals
and 5.0 percent on carryover balances as of December 31 , 2006. Total deferred power costs for Idaho customers were $9.4 million as
of December 31 , 2006 and $8.0 million as of December 31 2005.
Natural Gas Cost Deferrals and Recovery Mechanisms
Natural gas commodity costs in excess of, or which fall below, the amount recovered in current retail rates are deferred and recovered
or refunded as a pass-through to customers in future periods, subject to applicable regulatory review and approval, through adjustments
to rates. Currently, purchased gas adjustments provide for the deferral and future recovery or refund of 100 percent of the difference
between actual commodity costs and the amount recovered in current retail rates in Washington and Idaho. In Oregon, Avista Corp.
receives recovery of 100 percent of the cost of natural gas for which the price is fixed through hedge transactions, and included in retail
rates through the annual purchased gas cost adjustment filing. With respect to the unhedged portion of customer loads in Oregon
A vista Corp. defers 90 percent of the difference between actual prices and the amount recovered in current retail rates. Total deferred
natural gas costs were $18.3 million as of December 31 , 2006 and $43.4 million as of December 31,2005.
Reclassifications
Certain prior period amounts were reclassified to conform to current statement format. These reclassifications were made for
comparative purposes and have not affected previously reported total net income or stockholders' equity.
NOTE 2. NEW ACCOUNTING STANDARDS
In December 2004, the FASB issued SFAS No. 123R
, "
Share-Based Payment " which supersedes APB No. 25 and SF AS No. 123 and
their related implementation guidance. This statement establishes revised standards for the accounting for transactions in which the
Company exchanges its equity instruments for goods or services with a primary focus on transactions in which the Company obtains
employee services in share-based payment transactions. The statement requires that the compensation cost relating to share-based
payment transactions be recognized in financial statements based on the fair value of the equity or liability instruments issued. The
Company implemented the provisions of this statement effective January 1 2006 using the modified prospective method and
accordingly, financial statement amounts for prior periods presented have not been restated to reflect the fair value method of
recognizing compensation expense relating to share-based payments. Under the modified prospective approach, SFAS 123R applies to
all of the Company s unvested stock-based payment awards beginning January 1,2006 and all prospective awards. For 2006, the
Company recorded $4.0 million (pre-tax) of stock-based compensation expense. As a result of implementing SFAS No. 123R, the
Company s income before income taxes increased $1.5 million and net income increased $1.0 million as compared to the amounts that
the Company would have recorded for stock-based compensation expense under prior accounting rules. The impact on basic and
diluted earnings per share was an increase of $0.02 per share. In addition, SFAS No. 123R requires the Company to classify tax
benefits resulting from tax deductions in excess of stock-based compensation expense recognized as a financing activity. This amount
was not significant to cash flows and is included in the line item proceeds from issuance of common stock on the Statement of Cash
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Flows. See Note 22 for further information related to stock compensation plans.
In June 2006, the FASB issued Interpretation No. 48, "Accounting for Uncertainty in Income Taxes-an Interpretation of FASB
Statement No. 109 " (FIN 48) which provides guidance for the recognition and measurement of a tax position taken or expected to be
taken in a tax return. FIN 48 requires the evaluation of a tax position as a two-step process. First, the Company will be required to
determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related
appeals or litigation processes, based on the technical merits of the position. If the tax position meets the "more likely than not"
recognition threshold, it is then measured and recorded at the largest amount of benefit that is greater than 50 percent likely of being
realized upon ultimate settlement. The Company will be required to adopt FIN 48 in the fIrst quarter of 2007. The Company does not
expect the adoption of FIN 48 to have a material effect on its financial condition and results of operations.
In September 2006, the FASB issued SPAS No. 157, "Fair Value Measurements," which provides enhanced guidance for using fair
value to measure assets and liabilities. This statement also expands disclosures about fair value measurements. This statement applies
under other accounting pronouncements that require or permit fair value measurements. However, the statement does not require any
new fair value measurements. This statement emphasizes that fair value is a market-based measurement and not an entity-specific
measurement. Therefore a fair value measurement should be determined based on the assumptions that market participants would use
in pricing an asset or liability. The statement establishes a fair value hierarchy that prioritizes the information used to develop those
assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to
unobservable data. The Company will be required to adopt SF AS No. 157 in 2008. The Company is evaluating the impact SF AS No.
157 will have on its financial condition and results of operations.
In September 2006, the FASB issued SPAS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement
Plans - an amendment ofFASB Statements No. 87, 88, 106, and 132 (R)." SPAS No. 158 required the Company to recognize the
overfunded or underfunded status of defined benefit postretirement plans in the Company s Balance Sheet measured as the difference
between the fair value of plan assets and the benefit obligation as of December 31, 2006. For a pension plan, the benefit obligation is
the projected benefit obligation; for any other postretirement benefit plans, the benefit obligation is the accumulated postretirement
benefit obligation. Previously, the Company only recognized the underfunded status of defined benefit pension plans as the difference
between the fair value of plan assets and the accumulated benefit obligation. As the Company has historically recovered and currently
recovers its pension and other postretirement benefit costs related to its regulated operations in retail rates, the Company has recorded
a regulatory asset for that portion of its pension and other postretirement benefit funding deficiency. As such, the underfunded status
of the Company s pension and other postretirement benefit plans under SPAS No. 158 has resulted in the recognition as of December
2006 of:
a liability of $60.1 million (associated deferred taxes of $21.0 million) for pensions and other postretirement benefits
a regulatory asset of $54.2 million (associated deferred taxes of $19.0 million) for pensions and other postretirement benefits
an increase to accumulated other comprehensive loss of $3.8 million (net of taxes of $2.1 million), and
the removal of the intangible pension asset of $3.7 million (was included in other deferred charges).
As such, the total effect on the deferred income tax liability for the adoption of SPAS No. 158 was a net decrease of $2.1 million. The
adoption of this statement did not have any effect on the Company s net income.
In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin (SAB) No. 108, "Considering
the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements." SAB No. 108
addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year
financial statements. SAB No. 108 requires companies to quantify misstatements using a balance sheet and income statement approach
and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative
factors. The adoption of SAB No. 108 in the fourth quarter of 2006 did not have any effect on the Company s results of operations or
financial condition.
In February 2007, the FASB issued SPAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities." This
statement permits entities to choose to measure many financial assets and financial liabilities at fair value. Umealized gains and losses
on items for which the fair value option has been elected would be reported in net income. The Company will be required to adopt
SPAS No. 159 in 2008. The Company is evaluating the impact SPAS No. 159 will have on its financial condition and results of
operations.
I FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubm Ission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE 3. ACCOUNTS RECEIVABLE SALE
A vista Receivables Corporation (ARC) is a wholly owned, bankruptcy-remote subsidiary of A vista Corp. formed for the purpose of
acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. On March 20, 2006, A vista
Corp., ARC and a third-party financial institution amended a Receivables Purchase Agreement. The most significant amendment was
to extend the tennination date from March 21,2006 to March 20, 2007. Under the Receivables Purchase Agreement, ARC can sell
without recourse, on a revolving basis, up to $85.0 million of those receivables. ARC is obligated to pay fees that approximate the
purchasers cost of issuing commercial paper equal in value to the interests in receivables sold. The amount of such fees is included in
other operating expenses of A vista Corp. The Receivables Purchase Agreement has financial covenants, which are substantially the
same as those of A vista Corp.' s $320.0 million committed line of credit (see Note 12). At each of December 31 , 2006 and 2005
$85.0 million in accounts receivables were sold under this revolving agreement.
NOTE 4. ENERGY COMMODITY DERIVATIVE ASSETS AND LIABILITIES
SF AS No. 133, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. It requires the recording of all derivatives as either assets or
liabilities on the balance sheet measured at estimated fair value and the recognition of the unrealized gains and losses. In certain
defined conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for derivatives
depends on the intended use of the derivatives and the resulting designation.
Avista Corp. enters into forward contracts to purchase or sell electricity and natural gas. Under these forward contracts, Avista Corp.
commits to purchase or sell a specified amount of energy at a specified time, or during a specified period, in the future. Certain of
these forward contracts are considered derivative instruments. Avista Corp. also records derivative commodity assets and liabilities
for over-the-counter and exchange-traded derivative instruments as well as certain long-term contracts. These contracts are entered
into as part of A vista Corp. 's management of its loads and resources as discussed in Note 5. In conjunction with the issuance of SFAS
No. 133, the WUTC and the IPUC issued accounting orders authorizing Avista Corp. to offset any derivative assets or liabilities with
a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on
energy commodity transactions until the period of settlement. The orders provide for Avista Corp. to not recognize the unrealized
gain or loss on utility derivative commodity instruments in the Statements of Income. Realized gains or losses are recognized in the
period of settlement, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval
result in adjustments to retail rates through purchased gas cost adjustments, the ERM and the PCA mechanism.
Substantially all forward contracts to purchase or sell power and natural gas are recorded as assets or liabilities at market value with an
offsetting regulatory asset or liability. Contracts that are not considered derivatives under SFAS No. 133 are generally accounted for
at cost until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other than
temporary .
NOTE 5. ENERGY COMMODITY TRADING
The Company is exposed to risks relating to, but not limited to:
changes in certain commodity prices
interest rates
foreign currency, and
counterparty performance.
Avista Corp. utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating
to these exposures. A vista Corp. uses a variety of techniques to manage risks for their energy resources and wholesale energy market
activities. The Company has risk management policies and procedures to manage these risks, both qualitative and quantitative. The
Company s Risk Management Committee establishes the Company s risk management policies and procedures and monitors
compliance. The Risk Management Committee is comprised of certain Company officers and other individuals and is overseen by the
Audit Committee of the Company s Board of Directors.
A vista Corp. engages in an ongoing process of resource optimization, which involves the economic selection from available resources
to serve Avista Corp.'s load obligations and uses its existing resources to capture available economic value. Avista Corp. sells and
purchases wholesale electric capacity and energy and fuel as part of the process of acquiring resources to serve its load obligations.
These transactions range from terms of one hour up to multiple years. Avista Corp. makes continuing projections of:
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmisslon 04/18/2007 2006/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
loads at various points in time (ranging from one hour to multiple years) based on, among other things, estimates of factors
such as customer usage and weather, as well as historical data and contract terms, and
resource availability at these points in time based on, among other things, estimates of streamflows, availability of generating
units, historic and forward market information and experience.
On the basis of these projections, A vista Corp. makes purchases and sales of energy to match expected resources to expected electric
load requirements. Resource optimization involves generating plant dispatch and scheduling available resources and also includes
transactions such as:
purchasing fuel for generation
when economic, selling fuel and substituting wholesale purchases for the operation of A vista Corp.'s resources, and
other wholesale transactions to capture the value of generation and transmission resources.
Avista Corp.'s optimization process includes entering into hedging transactions to manage risks.
As part of its resource optimization process described above, A vista Corp. manages the impact of fluctuations in electric energy prices
by measuring and controlling the volume of energy imbalance between projected loads and resources and through the use of derivative
commodity instruments for hedging purposes. Load/resource imbalances within a rolling 18-month planning horizon are compared
against established volumetric guidelines and management determines the timing and specific actions to manage the imbalances.
Management also assesses available resource decisions and actions that are appropriate for longer-term planning periods. Prior to
April 1, 2005, A vista Energy was responsible for the daily management of natural gas supplies to meet the requirements of A vista
Corp.'s customers in the states of Washington , Idaho and Oregon. Effective April I, 2005, the management of natural gas procurement
functions was moved from A vista Energy back to A vista Corp. This was required for Washington customers by WUTC orders issued
in February 2004, and Avista Corp.'s resulting transition plan was approved by the WUTC in April 2004. The Company also elected
to move these functions back to A vista Corp. for Idaho and Oregon natural gas customers. The natural gas procurement process
includes entering into financial and physical hedging transactions as a means of managing risks. Avista Corp. always managed natural
gas procurement for its California operations, which the Company sold in April 2005 (see Note 26).
Market Risk
Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by
supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Market
risk is influenced to the extent that the perfonnance or nonperfonnance by market participants of their contractual obligations and
commitments affect the supply of, or demand for, the commodity. Avista Corp. manages the market risks inherent in its activities
according to risk policies established by the Risk Management Committee.
Credit Risk
Credit risk relates to the risk of loss that A vista Corp. would incur as a result of non-performance by counterparties of their contractual
obligations to deliver energy or make financial settlements. Avista Corp. often extends credit to counterparties and customers and is
exposed to the risk that it may not be able to collect amounts owed to them. Changes in market prices may dramatically alter the size
of credit risk with counterparties, even when conservative credit limits have been established. Credit risk includes the risk that a
counterparty may default due to circumstances:
relating directly to it
caused by market price changes, and
relating to other market participants that have a direct or indirect relationship with such counterparty.
Should a counterparty, customer or supplier fail to perform, Avista Corp. may be required to replace existing contracts with contracts
at then-current market prices or to honor the underlying commitment.
A vista Corp. seeks to mitigate credit risk by:
applying specific eligibility criteria to existing and prospective counterparties, and
actively monitoring current credit exposures.
These policies include an evaluation of the financial condition and credit ratings of counterparties, collateral requirements or other
credit enhancements, such as letters of credit or parent company guarantees. Avista Corp. also uses standardized agreements that allow
for the netting or offsetting of positive and negative exposures associated with a single counterparty.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubm ission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The Company has concentrations of suppliers and customers in the electric and natural gas industries including:
electric utilities,
natural gas distribution companies, and
energy marketing and trading companies.
In addition, the Company has concentrations of credit risk related to geographic location as it operates in the western United States and
western Canada. These concentrations of counterparties and concentrations of geographic location may impact the Company s overall
exposure to credit risk, either positively or negatively, because the counterparties may be similarly affected by changes in conditions.
Credit risk also involves the exposure that counterparties perceive related to the ability of Corp. to perform deliveries and settlement
under physical and financial energy contracts. These counterparties may seek assurances of performance in the form of:
letters of credit,
prepayments, and
cash deposits
In periods of price volatility, the level of exposure can change significantly. As a result, sudden and significant demands may be made
against the Company s credit facilities and cash. A vista Corp. actively monitors the exposure to possible collateral calls and take steps
to minimize capital requirements.
Other Operational and Event Risks
In addition to market and credit risk, the Company is subject to operational and event risks including, among others:
increases or decreases in load demand
blackouts or disruptions to transmission or transportation systems,
fuel quality and availability,
forced outages at generating plants,
disruptions to information systems and other administrative tools required for normal operations, and
weather conditions and natural disasters that can cause physical damage to property, requiring repairs to restore utility service.
Terrorism threats, both domestic and foreign, are a risk to the entire utility industry. Potential disruptions to operations or destruction
of facilities from terrorism or other malicious acts are not readily determinable. The Company has taken various steps to mitigate
terrorism risks and prepare contingency plans in the event that its facilities are targeted.
NOTE 6. CASH DEPOSITS FROM COUNTERP ARTIES
Cash deposits from counterparties totaled $39.4 million as of December 31 2006 and $9.0 million as of December 31 , 2005. These
funds are held by A vista Corp. to mitigate the potential impact of counterparty default risk. These amounts are subject to return if
conditions warrant because of continuing portfolio value fluctuations with those parties or substitution of non-cash collateral.
As is common industry practice, Avista Corp. maintains margin agreements with certain counterparties. Margin calls are triggered
when exposures exceed predetermined contractual limits or when there are changes in a counterparty's creditworthiness. Price
movements in electricity and natural gas can generate exposure levels in excess of these contractual limits. From time to time, margin
calls are made and/or received by Avista Corp. Negotiating for collateral in the form of cash or letters of credit is a common industry
practice.
NOTE 7. JOINTLY OWNED ELECTRIC FACILITIES
The Company has a 15 percent ownership interest in a twin-unit coal-rued generating facility, the Colstrip Generating Project
(Colstrip) located in southeastern Montana, and provides financing for its ownership interest in the project. The Company s share of
, related fuel costs as well as operating expenses for plant in service are included in the corresponding accounts in the Statements of
Income. The Company s share of utility plant in service for Colstrip was $329.0 million and accumulated depreciation was $192.5
million as of December 31, 2006.
NOTE 8. ASSET RETIREMENT OBLIGA nONS
The Company follows SF AS No. 143, "Accounting for Asset Retirement Obligations " which requires the recording of the fair value of
IFERC FORM NO.1 (ED. 12-88)Page 123.
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(1) X An Original (Mo, Da, Yr)
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NOTES TO FINANCIAL STATEMENTS (Continued)
a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the associated
costs of the asset retirement obligation are capitalized as part of the carrying amount of the related long-lived asset. The liability is
accreted to its present value each period and the related capitalized costs are depreciated over the useful life of the related asset. Upon
retirement of the asset, the Company either settles the retirement obligation for its recorded amount or incurs a gain or loss. As asset
retirement costs are recovered through rates charged to customers, the Company records regulatory assets and liabilities for the
difference between asset retirement costs currently recovered in rates and asset retirement obligations recorded under SFAS 143. The
regulatory assets do not earn a return.
The Company adopted FIN 47
, "
Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No.
143 " as of December 31 , 2005, which resulted in the recording of additional asset retirement obligations under SFAS No. 143.
Specifically, the Company recorded liabilities for future asset retirement obligations to:
restore ponds at Colstrip,
remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease
remove asbestos at the corporate office building, and
dispose of PCBs in certain transformers.
Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the:
removal and disposal of certain transmission and distribution assets, and
abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities.
The following table documents the changes in the Company s asset retirement obligation during the years ended December 31 (dollars
in thousands):
Asset retirement obligation at beginning of year
New liability recognized
Liability settled
Accretion expense
Asset retirement obligation at end of year
2006
529
2005
191
243
(28)
----In
$4.529
(51)
332
$4.810
The pro forma asset retirement obligation liability balance as if FIN 47 had been adopted on January 1 2005 (rather than December
2005) is as follows (dollars in thousands):
Pro forma asset retirement obligation as of January 1 2005 246
NOTE 9. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a defined benefit pension plan covering substantially all regular full-time employees at A vista Corp. and A vista
Energy. Individual benefits under this plan are based upon the employee s years of service and average compensation as specified in
the plan. The Company s funding policy is to contribute at least the minimum amounts that are required to be funded under the
Employee Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax
purposes. The Company made $15 million in cash contributions to the pension plan in each of 2006,2005 and 2004. The Company
expects to contribute $15 million to the pension plan in 2007.
The Company also has a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to executive
officers of the Company. The SERP is intended to provide benefits to executive officers whose benefits under the pension plan are
reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred
compensation plans.
The Company expects that benefit payments under the pension plan and the SERP will total $14.0 million in 2007, $14.2 million in
2008, $14.5 million in 2009, $15.8 million in 2010 and $16.4 million in 2011. For the ensuing five years (2012 through 2017), the
Company expects that benefit payments under the pension plan and the SERP will total $102.6 million.
The Finance Committee of the Company s Board of Directors:
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(1) ~ An Original (Mo, Da, Yr)
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NOTES TO FINANCIAL STATEMENTS (Continued)
establishes investment policies, objectives and strategies that seek an appropriate return for the pension plan, and
reviews and approves changes to the investment and funding policies.
The Company has contracted with an investment consultant who is responsible for managing/monitoring the individual investment
managers. The investment managers' perfonnance and related individual fund perfonnance is periodically reviewed by the Finance
Committee to ensure compliance with investment policy objectives and strategies. Pension plan assets are invested primarily in
marketable debt and equity securities. Pension plan assets may also be invested in real estate, absolute return, venture capital/private
equity and commodity funds. In seeking to obtain the desired return to fund the pension plan, the Finance Committee has established
investment allocation percentages by asset classes as indicated in the table in this Note.
The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments
held by the plan. The market-related value of pension plan assets invested in debt and equity securities was based primarily on fair
value (market prices).
The market-related value of pension plan assets invested in real estate was determined based on three basic approaches:
current cost of reproducing a property less deterioration and functional economic obsolescence
capitalization of the property's net earnings power, and
value indicated by recent sales of comparable properties in the market.
The market-related value of plan assets was determined as of December 31 , 2006 and 2005.
In 2006, the form of payment election assumption was analyzed based upon historical trends and future projections. The Company
revised the form of payment election to assume that 5 percent of retirees and 50 percent of vested terminated participants will elect a
lump sum payment, based upon the analysis. The form of payment election assumption previously assumed that 50 percent of retirees
and vested tenninated participants would elect a lump sum payment. The change resulted in an increase of $13.2 million to the
pension benefit obligation as of December 31 , 2006. The change will also increase future years' pension costs.
As of December 31 2006 and 2005, the pension and other postretirement benefit plans had assets with a market-related value that was
less than the present value of the benefit obligation under the plans. In 2006, the Company adopted SFAS No. 158, which resulted in
the recording of adjustments to the Balance Sheet as disclosed in Note 2.
The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company
accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. The Company
elected to amortize the transition obligation of $34.5 million over a period of twenty years, beginning in 1993. The Company expects
that benefit payments under the postretirement benefit plan will be $2.9 million in 2007, $2.8 million in 2008, $2.7 million in 2009,
$2.5 million in 2010 and $2.5 million 2011. For the ensuing five years (2012 through 2016), the Company expects that benefit
payments under the postretirement benefit plan will total $10.9 million. The Company expects to contribute $2.9 million to the
postretirement benefit plan in 2007, representing expected benefit payments to be paid during the year.
The Company established a Health Reimbursement Arrangement to provide employees with tax-advantaged funds to pay for allowable
medical expenses upon retirement. The amount earned by the employee is fIXed on the retirement date based on employees' years of
service and the ending salary. The liability and expense of this plan are included as postretirement benefits.
The Company uses a December 31 measurement date for its pension and postretirement plans. The following table sets forth the
pension and other postretirement plan disclosures as of December 31, 2006 and 2005 and the components of net periodic benefit costs
for the years ended December 31 2006,2005 and 2004 (dollars in thousands):
IFERC FORM NO.1 (ED. 12-88)Page 123.
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(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Other
Pension Benefits Postretirement Benefits
2006 2005 2006 2005
Change in benefit obligation:
Benefit obligation as of beginning of year $301 746 $285,738 $28,963 $31,868
Service cost 963 9,480 544 566
Interest cost 17,158 228 755 652
Plan amendment
Actuarial loss (gain)524 352 386 (1,800)
Benefits paid (15,521)(14 932)557)293)
Expenses paid (179)(120)-12Q)
Benefit obligation as of end of year $315.691 $301.746 $30.061 $28.963
Change in plan assets:
Fair value of plan assets as of beginning of year $199,163 $186 579 $18 378 $16,862
Actual return on plan assets 737 11,763 '2,530 236
Employer contributions 000 15,000 183
Benefits paid (14 642)(14 059)(873)
Expenses paid (179)(120)
Fair value of plan assets as of end of year $225.079 $199.163 $20.878 $18.378
Funded status $(90 612)$(102 583)$(9,183)$(10 585)
Unrecognized net actuarial loss 69,679 79,667 318 973
UnrecognIzed prIor service cost 751 4,405
Unrecognized net transition obligation/(asset)031 3,536
Accrued benefit cost (17,182)(18,511)(3,834)076)
Additional liability (73,430)(34.595)(5.349)
Accrued benefit liability $(90.612)$(53.106)$(9.183)$(6.076)
Accumulated pension benefit obligation $264.647 $252.269
Accumulated postretirement benefit obligation:
For retirees $18 548 $14 662
For fully eligible employees $5,401 980
For other participants $6,112 321
Weighted-average asset allocations as of December 31:
Equity securities 53%63%64%62%
Debt securities 28%27%33%36%
Real estate
Other 14%
Target asset allocations as of December 31:
Equity securities 39-61 %54-68%52-72%52-72%
Debt securities 27-33%22-28%28-48%28-48%
Real estate
Other 10-22%13%
Weighted average assumptions as of December 31:
Discount rate for benefit obligation 15%75%15%75%
Discount rate for annual expense 75%75%75%75%
Expected long-term return on plan assets 8.50%50%8.50%50%
Rate of compensation mcrease 84%84%
Medical cost trend pre-age 65 - initial 00%00%
Medical cost trend pre-age 65 - ultimate 00%00%
Ultimate medical cost trend year pre-age 65 2011 2010
Medical cost trend post-age 65 - initial 00%00%
Medical cost trend post-age 65 - ultimate 00%00%
Ultimate medical cost trend year post-age 65 2010 2009
FERC FORM NO.ED. 12-88 Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmlssion 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
2006 2005 2004 2006 2005 2004
Components of net periodic benefit cost:
Service cost $9,963 $ 9,480 $ 8 914 544 566 $ 480
Interest cost 17,158 16,228 16,406 755 652 019
Expected return on plan assets (16,997)(15 917)(13,436)562)(1,368)106)
Transition (asset)/obligation recognition (499)(1,086)505 505 505
Amortization of prior service cost 653 654 654
Net loss recognition 772 442 447 ----2Q 245
Net periodic benefit cost $14.549 $13.388 $14.899 $1.332 $1.355 $2.143
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A
one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement
benefit obligation as of December 31, 2006 by $1.4 million and the service and interest cost by $0.1 million. A one-percentage-point
decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as
of December 31 , 2006 by $1.2 million and the service and interest cost by $0.1 million.
The Company has a salary deferral 40 I (k) plans that is a deemed contribution plan covers substantially all employees. Employees can
make contributions to their respective accounts in the plans on a pre-tax basis up to the maximum amount permitted by law. The
Company matches a portion of the salary deferred by each participant according to the schedule in the plan. Employer matching
contributions were $4.4 million in 2006, $4.1 million in 2005 and $3.9 million in 2004.
The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer
until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of
their incentive payments. Deferred compensation funds are held by the Company in a Rabbi Trust. At December 31 , 2006 and 2005
there were deferred compensation assets of $12.6 million and $11.3 million included in other special funds and corresponding deferred
compensation liabilities of $12.6 million and $11.3 million included in other deferred credits on the Balance Sheets.
NOTE 10. ACCOUNTING FOR INCOME TAXES
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards.
The realization of deferred tax assets is dependent upon the ability to generate taxable income in future periods. The Company
evaluated available evidence supporting the realization of its deferred tax assets and determined it is more likely than not that deferred
tax assets will be realized.
In August 2005, the IRS and Treasury Department issued a revenue ruling, and related regulations that affect the tax treatment by
A vista Corp. of certain indirect overhead expenses. A vista Corp. had previously made a tax election to deduct certain indirect
overhead costs, starting with the 2002 tax return, that were capitalized for financial accounting purposes. This election allowed A vista
Corp. to accelerate tax deductions resulting in a reduction of approximately $40 million in current tax liabilities. The current tax
benefit was deferred on the balance sheet in accordance with provisions of SF AS No. 109 and did not have an effect on net income.
Due to the revenue rulings and related regulations, the IRS has disallowed the accelerated tax deductions during their recent exam.
The Company believes that the tax deductions claimed on tax returns were appropriate based on the applicable statutes and regulations
in effect at the time. Avista Corp. has appealed the proposed IRS adjustment on April 19, 2006. The Company s appeal has been
received, but has not yet been scheduled for review by the IRS Appeals Division. The Company repaid a portion of the accelerated tax
deduction through tax payments in 2005 and 2006. There can be no assurance that the Company s position will prevail. However, it is
not expected to have a significant effect on the Company s net income.
The Company had net regulatory assets of $105.9 million as of December 31 2006 and $114.1 million as of December 31 , 2005
related to the probable recovery of certain deferred tax liabilities from customers through future rates.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE 11. ENERGY PURCHASE CONTRACTS
Avista Corp. has contracts for the purchase of fuel for thermal generation, natural gas and various agreements for the purchase, sale or
exchange of electric energy with other entities. The termination dates of the contracts range from one month to the year 2055. Total
expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs, which are included in operation
expenses in the Statements of Income, were $682.5 million in 2006, $652.2 million in 2005 and $482.2 million in 2004. The
following table details Avista Corp.'s future contractual commitments for power resources (including transmission contracts) and
natural gas resources (including transportation contracts) (dollars in thousands):
Power resources
Natural gas resources
Total
2007
$109,915
215,668
$325.583
2008
$103 526
96,054
$199.580
2009
$102 898
83,625
$186.523
2010
$103 003
57,901
$160.904
2011 Thereafter Total
$ 74 785 $ 463,737 $ 957,864
56,563 719.503 1,229,314
$131.348 $1.1 240 $2.187.J78
All of the energy purchase contracts were entered into as part of A vista Corp.' s obligation to serve its retail natural gas and electric
customers' energy requirements. As a result, these costs are generally recovered either through base retail rates or adjustments to retail
rates as part of the power and natural gas cost deferral and recovery mechanisms.
In addition, Avista Corp. has operational agreements, settlements and other contractual obligations for its generation, transmission and
distribution facilities. The expenses associated with these agreements are reflected as operation expenses and maintenance expenses in
the Statements of Income.
The following table details future contractual commitments for these agreements (dollars in thousands):
Contractual obligations
2007
$15.438
2008
$15.463
2009
611
2010
$15.637
2011
666
Thereafter
$196.863
Total
$274.678
A vista Corp. has fixed contracts with certain Public Utility Districts (POD) to purchase portions of the output of certain generating
facilities. Although Avista Corp. has no investment in the POD generating facilities, the fixed contracts obligate Avista Corp. to pay
certain minimum amounts (based in part on the debt service requirements of the POD) whether or not the facilities are operating. The
cost of power obtained under the contracts, including payments made when a facility is not operating, is included in operation expenses
in the Statements of Income. Expenses under these POD contracts were $13.1 million in 2006, $9.0 million in 2005 and $7.3 million
in 2004.
Information as of December 31 , 2006 pertaining to these POD contracts is summarized in the following table (dollars in thousands):
Company s Current Share of
DebtService Bonds
Costs (1) Outstanding
Kilowatt
abili
Annual
Costs (1)
Expira-
tion
Date
Chelan County POD:
Rocky Reach Project 000 $ 2 031 984 $ 2 179 2011
Douglas County POD:
Wells Project 3.5%30,000 218 809 724 2018
Grant County POD:
Priest Rapids Project 000 898 561 876 2055
Wanapum Project 75,000 932 870 12,938 2055
Totals 197.000 $13.079 $4.224 $27.717
(1) The annual costs will change in proportion to the percentage of output allocated to Avista Corp. in a particular year. Amounts
represent the operating costs for the year 2006. Debt service costs are included in annual costs.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The estimated aggregate amounts of required minimum payments (A vista Corp.' s share of existing debt service costs) under these PUD
contracts are as follows (dollars in thousands):
Minimum payments
2007
$3.519
2008
$3.594
2009
$3.620
2010
$2.738
2011
$2.683
Thereafter
$27.962
Total
$44.116
In addition, A vista Corp. will be required to pay its proportionate share of the variable operating expenses of these projects.
NOTE 12. COMMITTED LINE OF CREDIT
On April 6, 2006, the Company amended its committed line of credit agreement with various banks. The committed line of credit was
originally entered into on December 17, 2004. Amendments to the committed line of credit include a reduction in the total amount of
the facility to $320.0 million from $350.0 million and an extension of the expiration date to April 5, 2011 from December 16 2009.
The Company chose to reduce the facility based on forecasted liquidity needs. Under the amended credit agreement, the Company can
request the issuance of up to $320.0 million in letters of credit, an increase from $150.0 million prior to the amendment. Total letters
of credit outstanding were $77.1 million as of December 31, 2006 and $44.1 million as of December 31, 2005. The amended
committed line of credit is secured by $320.0 million of non-transferable First Mortgage Bonds of the Company issued to the agent
bank that would only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations
under the committed line of credit.
The amended committed line of credit agreement contains customary covenants and default provisions , including a covenant requiring
the ratio of "earnings before interest, taxes, depreciation and amortization" to "interest expense" of A vista Corp. for the preceding
twelve-month period at the end of any fiscal quarter to be greater than 1.6 to 1. As of December 31 , 2006, the Company was in
compliance with this covenant with a ratio of 2.56 to I. The committed line of credit agreement also has a covenant which does not
permit the ratio of "consolidated total debt" to "consolidated total capitalization" of A vista Corp. to be greater than 70 percent at the
end of any fiscal quarter. Under the amendment, this ratio limitation will be increased to 75 percent during the period between the
completion of the proposed change in the Company s corporate organization (see Note 24) and December 31, 2007. As of December
2006, the Company was in compliance with this covenant with a ratio of 53.7 percent. If the proposed change in organization
becomes effective, the committed line of credit agreement will remain at A vista Corp.
Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company s revolving committed lines of
credit were as follows as of and for the years ended December 31 (dollars in thousands):
Balance outstanding at end of period
Maximum balance outstanding during the period
Average balance outstanding during the period
Average interest rate during the period
Average interest rate at end of period
2006
000
77,000
16,740
07%
25%
2005
$63,000
167 000
181
4.45%
5.48%
2004
$68,000
170 000
858
3.14%
3.52%
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE 13. BONDS AND OTHER LONG-TERM DEBT
The following details the interest rate and maturity dates of bonds and other long-term debt outstanding as of December 31 (dollars in
thousands):
MaturityYear Description
2006 Secured Medium- Tenn Notes
2007 First Mortgage Bonds (1)
2007 Secured Medium-Term Notes
2008 Secured Medium-Term Notes
2010 Secured Medium-Term Notes
2012 Secured Medium-Term Notes
2013 First Mortgage Bonds
2018 Secured Medium-Term Notes
2019 First Mortgage Bonds
2023 Secured Medium-Term Notes
2028 Secured Medium-Term Notes
2032 Pollution Control Bonds
2034 Pollution Control Bonds
2035 First Mortgage Bonds
2037 First Mortgage Bonds (1)
Total secured long-term debt
Unsecured Medium-Term Notes
Unsecured Medium-Tenn Notes
Unsecured Senior Notes
Pollution Control Bonds
Total unsecured long-term debt
Interest rate swaps
Committed line of credit
Preferred stock
Total long-term debt
2006
2007
2008
2023
Interest
Rate 2006 2005
89%-90%000
75%150 000
99%13,850 13,850
06%-95%45,000 45,000
67%-02%000 000
7.37%000 000
13%45,000 45,000
7.39%-7.45%22,500 500
45%000 90,000
18%-7.54%13,500 13,500
37%000 000
00%700 700
13%17,000 17,000
25%150,000 150,000
70%150,000
680,550 710,550
14%000
90%-94%000 000
75%272 860 279,735
00%4.100 100
288,960 303,835
1.037 236
000 63,000
26,250 28,000
$1.000,797 $1.110.621
(1) During December 2006, the Company issued $150.0 million of 5.70 percent First Mortgage Bonds due in 2037. The proceeds from
the issuance were used to legally defease $150.0 million of First Mortgage Bonds that were scheduled to mature on January 1 2007.
The following table details future long-term debt maturities, not including interest rate swaps, the committed line of credit or preferred
stock (dollars in thousands):
Year
Debt maturities
2007
$25.850
2008 2009 2010 2011
$35.000 $
Thereafter
$590.800
Total
$969.510
Substantially all utility properties owned by the Company are subject to the lien of the Company s various mortgage Indentures. The
Mortgage and Deed of Trust securing the Company s First Mortgage Bonds (including Secured Medium-Term Notes) contains
limitations on the amount of First Mortgage Bonds, which may be issued based on, among other things, a 70 percent debt-to-collateral
ratio, and/or retired First Mortgage Bonds, and a 2 to I net earnings to First Mortgage Bond interest ratio. As of December 31 , 2006
the Company could issue $429.5 million of additional First Mortgage Bonds under the Mortgage and Deed of Trust. See Note 12 for
information regarding First Mortgage Bonds issued to secure the Company s obligations under its $320.0 million committed line of
credit.
NOTE 14. ADVANCES FROM ASSOCIATED COMPANIES
In 2004, the Company issued Junior Subordinated Debt Securities, with a principal amount of $61.9 million to A V A Capital Trust III
an affiliated business trust formed by the Company. Concurrently, A V A Capital Trust III issued $60.0 million of Preferred Trust
Securities to third parties and $1.9 million of Common Trust Securities to the Company. All of these securities have a fixed interest
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
rate of 6.50 percent for five years (through March 31, 2009). Subsequent to the initial five-year fIXed rate period, the securities will
either have a new fIXed rate or an adjustable rate. These debt securities may be redeemed by the Company on or after March 31 , 2009
and will mature on April I , 2034.
In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B , with a principal amount of
$51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of
Preferred Trust Securities with a floating distribution rate of LffiOR plus 0.875 percent, calculated and reset quarterly. The annual
distribution rate paid during 2006 ranged from 5.285 percent to 6.275 percent. As of December 31, 2006, the annual distribution rate
was 6.244 percent. Concurrent with the issuance of the Preferred Trust Securities, A vista Capital II issued $1.5 million of Common
Trust Securities to the Company. These debt securities may be redeemed at the option of Avista Capital II on or after June 1 2007 and
mature on June 1 2037; however, this is limited by an agreement under the Company s 9.75 percent Senior Notes that mature in 2008.
In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities.
The Company has guaranteed the payment of distributions on, and redemption price and liquidation amount with respect to, the
Preferred Trust Securities to the extent that A V A Capital Trust III and Avista Capital II have funds available for such payments from
the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust Securities will be
mandatorily redeemed.
NOTE 15. INTEREST RATE SWAP AGREEMENTS
In 2004, A vista Corp. entered into three forward-starting interest rate swap agreements, totaling $200.0 million, to manage the risk
associated with changes in interest rates and the impact on future interest payments. These interest rate swap agreements relate to the
interest payments for the anticipated issuances of debt to fund debt that matures in 2007 and 2008. In 2005, the Company cash settled
an interest rate swap and received $4.4 million. In December 2006, A vista Corp. cash settled an interest rate swap agreement (totaling
$75.0 million) and paid $3.7 million. These settlements have been deferred as regulatory items (part of long-term debt) and will be
amortized over the remaining tenns of the interest rate swap agreements (forecasted interest payments) in accordance with regulatory
accounting practices.
Under the tenns of the two remaining agreements (totaling $125.0 million), the value of the interest rate swaps is determined based
upon A vista Corp. paying a fixed rate and receiving a variable rate based on LffiOR for a term of ten years beginning in 2008.
These interest rate swap agreements are considered hedges against fluctuations in future cash flows associated with changes in interest
rates in accordance with SFAS No. 133. As of December 31,2006, A vista Corp. had a long-term derivative liability of $5.1 million
and a net umealized loss of $3.3 million recorded as accumulated other comprehensive loss on the Balance Sheets. The interest rate
swap agreements provide for mandatory cash settlement of these contracts in 2009. The amount included in accwnulated other
comprehensive income or loss at the cash settlement date will be reclassified to a regulatory asset or liability (part of long-term debt) in
accordance with regulatory accounting practices under SFAS No. 71. This regulatory asset or liability will be amortized as a
component of interest expense over the life of the forecasted interest payments.
NOTE 16. LEASES
The Company has multiple lease arrangements involving various assets, with minimum tenns ranging from one to forty-five years.
Rental expense under operating leases was $2.5 million in 2006, $8.0 million in 2005 and $12.0 million in 2004.
Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one
year as of December 31 , 2006 were as follows (dollars in thousands):
Year ending December 31:
Minimum payments required
2007 2008
$1.491 $1.380
2009
$1.237
2010
$286
2011
$201
Thereafter
$2.915
Total
$7.510
NOTE 17. GUARANTEES
The Company has guaranteed the payment of distributions on, and redemption price and liquidation amount with respect to, the
Preferred Trust Securities issued by its affiliates, A V A Capital Trust III and A vista Capital II, to the extent that these entities have
funds available for such payments from the respective debt securities.
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Oa, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
A vista Power LLC (A vista Power), through its equity investment in Rathdrum Power, LLC (RP LLC), was a 49 percent owner of the
Lancaster Project, which commenced commercial operation in September 2001. In October 2006, Avista Power completed the sale of
its investment in RP LLC for close to book value. Commencing with commercial operations, all of the output from the Lancaster
Project is contracted to Avista Energy through 2026 under a power purchase agreement. Avista Corp. has guaranteed the power
purchase agreement for the perfonnance of Avista Energy.
NOTE 18. PREFERRED STOCK-CUMULATIVE (SUBJECT TO MANDATORY REDEMPTION)
In September 2006, 2005 and 2004, the Company made mandatory redemptions of 17 500 shares of preferred stock for $1.75 million.
The 262 500 remaining shares must be redeemed on September 15 2007 for $26.25 million. Upon involuntary liquidation, all
preferred stock will be entitled to $100 per share plus accrued dividends.
NOTE 19. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying values of cash, special deposits, working funds, temporary cash investments, accounts and notes receivable, accounts
payable and the committed line of credit are reasonable estimates of their fair values. Energy commodity derivative assets and
liabilities, as well as derivatives related to interest rate swap agreements, are reported at estimated fair value on the Balance Sheets.
The following table sets forth the estimated fair value and carrying value of the Company s bonds and other long-term debt, long-term
debt to affiliated trusts (included in advances from associated companies and excluding $3.4 million of debt that is considered common
equity by the affiliated trusts) and preferred stock subject to mandatory redemption as of December 31 2006 and 2005 (dollars in
thousands):
Bonds and other long-tenn debt
Long-term debt to affiliated trusts
Preferred stock
2006
Carrying EstimatedValue Fair Value
$969,510 $976 548
110 000 106 744
250 26 622
2005
Carrying EstimatedValue Fair Value
014 385 $1 063 018
110 000 104,595
000 28 636
These estimates of fair value were primarily based on available market information.
NOTE 20. COMMON STOCK
In November 1999, the Company adopted a shareholder rights plan pursuant to which holders of common stock outstanding on
February 15, 1999, or issued thereafter, were granted one preferred share purchase right (Right) on each outstanding share of common
stock. Each Right, initially evidenced by and traded with the shares of common stock, entitles the registered holder to purchase one
one-hundredth of a share of preferred stock of the Company, without par value, at a purchase price of $70, subject to certain
adjustments, regulatory approval and other specified conditions. The Rights will be exercisable only if a person or group acquires 10
percent or more of the outstanding shares of common stock or commences a tender or exchange offer, the consummation of which
would result in the beneficial ownership by a person or group of 10 percent or more of the outstanding shares of common stock. Upon
any such acquisition, each Right will entitle its holder to purchase, at the purchase price, that number of shares of common stock or
preferred stock of the Company (or, in the case of a merger of the Company into another person or group, common stock of the
acquiring person or group) that has a market value at that time equal to twice the purchase price. In no event will the Rights be
exercisable by a person that has acquired 10 percent or more of the Company s common stock. The Rights may be redeemed, at a
redemption price of $0.0 I per Right, by the Board of Directors of the Company at any time until any person or group has acquired 10
percent or more of the common stock. In connection with the proposed statutory share exchange (see Note 24), the shareholder rights
plan was amended to provide that the Rights will expire upon the earlier of the effective time of the statutory share exchange or March
31,2009 (the originally scheduled expiration date).
The Company has a Dividend Reinvestment and Stock Purchase Plan under which the Company s shareholders may automatically
reinvest their dividends and make optional cash payments for the purchase of the Company s common stock at current market value.
The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock and
long-term debt contained in the Company s Articles of Incorporation and various mortgage indentures. Covenants under the
Company s 9.75 percent Senior Notes that mature in 2008 limit the Company s ability to increase its common stock cash dividend to
no more than 5 percent over the previous quarter, unless certain conditions are met related to restricted payments. As of December 31
IFERC FORM NO.1 (ED. 12-88) Page 123.19
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
2006, the Company is meeting the conditions that would allow it to increase the common stock cash dividend in excess of 5 percent
over the previous quarter.
In December 2006, the Company issued 3 162 500 shares of common stock through an underwriter and received net proceeds of $77.
million. Also, in December 2006, the Company entered into a sales agency agreement with a sales agent, to issue up to 2 million
shares of its common stock from time to time.
NOTE 21. EARNINGS PER COMMON SHARE
The following table presents the computation of basic and diluted earnings per common share for the years ended December 31 (in
thousands, except per share amounts):
2006 2005 2004
Numerator:
Net income before cumulative effect of accounting change $73,133 $45 168 $35 614
Cumulative effect of accounting change ---HQQ2
Net income $73.133 168 $35.154
Denominator:
Weighted-average number of common shares
outstanding- basic 49,162 523 48,400
Effect of dilutive securities:
Contingent stock awards 371 198 209
Stock options --.Ill
Weighted-average number of common shares
outstanding-diluted 49.897 48.979 48.886
Earmngs per common share, basic:
Earnings before cumulative effect of accounting change $1.49 $0.$0.
Loss from cumulative effect of accounting change (0.01)
Total earnings per common share, basic $1.49 $0.$0.
Earnings per common share, diluted:
Earnings before cumulative effect of accounting change $1.47 $0.$0.
Loss from cumulative effect of accounting change (0.01)
Total earnings per common share, diluted $1.47 $0.$0.
Total stock options outstanding that were not included in the calculation of diluted earnings per common share were 26,200 for 2006
695 500 for 2005 and 730 100 for 2004. These stock options were excluded from the calculation because they were antidilutive based
on the fact that the exercise price of the stock options was higher than the average market price of Avista Corp. common stock during
the respective period. In addition, contingent stock awards of318 900 were outstanding as of December 31 , 2005, which were not
included in basic or diluted shares because the performance conditions were not satisfied.
NOTE 22. STOCK COMPENSA nON PLANS
1998 Plan
In 1998, the Company adopted, and shareholders approved, the Long-Term Incentive Plan (1998 Plan). Under the 1998 Plan, certain
key employees, officers and non-employee directors of the Company and its subsidiaries may be granted stock options, stock
appreciation rights, stock awards (including restricted stock) and other stock-based awards and dividend equivalent rights. The
Company has available a maximum of 3.5 million shares of its common stock for grant under the 1998 Plan. As of December 31
2006,9 million shares were remaining for grant under this plan.
2000 Plan
In 2000, the Company adopted a Non-Officer Employee Long-Term Incentive Plan (2000 Plan), which was not required to be
approved by shareholders. The provisions of the 2000 Plan are essentially the same as those under the 1998 Plan, except for the
exclusion of non-employee directors and executive officers of the Company. The Company has available a maximum of 2.5 million
shares of its common stock for grant under the 2000 Plan. However, the Company currently does not plan to issue any further options
or securities under the 2000 Plan. As of December 31, 2006, 1.7 million shares were remaining for grant under this plan.
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Stock Compensation
Prior to January 2006 the Company accounted for stock based compensation using APB No. 25 , which required the recognition of
compensation expense on the excess, if any, of the market price of the stock at the date of grant over the exercise price of the option.
As the exercise price for options granted under the 1998 and 2000 Plans was equal to the market price at the date of grant, there was
no compensation expense recorded by the Company. However, the Company recognized compensation expense related to
performance-based share awards. For periods presented prior to January 2006, the Company is required to disclose pro forma net
income and earnings per common share as if the Company had adopted the fair value method of accounting for stock-based
compensation.
On January 1,2006, the Company adopted SFAS No. 123R, which supersedes APB No. 25 and SFAS No. 123 and their related
implementation guidance. The statement requires that the compensation cost relating to share-based payment transactions be
recognized in financial statements based on the fair value of the equity or liability instruments issued. The Company adopted SFAS
No. 123R using the modified prospective method and, accordingly, financial statement amounts for prior periods presented have not
been restated to reflect the fair value method of recognizing compensation expense relating to share-based payments. For 2006, the
Company recorded $4.0 million (pre-tax) of stock-based compensation expense.
Stock Options
The fair value of stock option awards was calculated using the Black Scholes option pricing model. This model requires the use of
subjective assumptions, including stock price volatility, dividend yield, risk-free interest rate and expected time to exercise. See Note
I for disclosure of pro forma net income and earnings per common share for 2005 and 2004. Avista Corp. has not granted any stock
options since 2003. The following summarizes stock options activity under the 1998 Plan and the 2000 Plan for the years ended
December 31
2006 2005 2004
Number of shares under stock options:
Options outstanding at beginning of year 095 211 332 198 481 886
Options granted
Options exercised (504 452)(192 377)(99,138)
Options canceled 714 (44,610)(50.550)
Options outstanding at end of year 045 211 332
Options exercisable at end of year 045 1.968.629 1.896.648
Weighted average exercise price:
Options granted
Options exercised $16.12 $13.50 $13.
Options canceled $20.$20.42 $18.
Options outstanding at end of year $15.41 $15.$15.
Options exercisable at end of year $15.41 $16.$16.
Information for options outstanding and exercisable as of December 31 , 2006 was as follows:
Weighted Weighted
Average Average
Range of Number Exercise Remaining
Exercise Prices of Shares Price Life (in years)
$10.17-$11.68 388,695 $10.
$11.69-$14.398 375 11.82
$14.62-$17.274 900 17.
$17.54-$20.155 625 18.2.1
$20.46-$26.29 297,250 22.56
$26.30-$28.200 27.
Total 045 $15.41 4.3
FERC FORM NO.ED. 12-Page 123.
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NOTES TO FINANCIAL STATEMENTS (Continued)
The aggregate intrinsic value of options outstanding and exercisable was $15.3 million as of December 31 , 2006. The aggregate
intrinsic value represents the difference between Avista Corp.'s closing price on the last trading day of the period and the exercise
price, multiplied by the number of in-the-money options. This is the value that would have been received by the option holders had all
options holders exercised their options on December 31, 2006. The intrinsic value of options exercised during 2006 was $3.5 million
and total cash received from the exercise of stock options was $9.9 million. At December 31, 2005, the Company had approximately
125 000 unvested stock options outstanding with a weighted average grant date fair value of $3.28 per share. As of December 31
2006, the Company s stock options were fully vested and expensed.
Restricted Shares
Restricted shares vest in equal thirds each year over a three-year period and are payable in A vista Corp. common stock at the end of
each year if the service condition is met. In addition to the service condition, the Company must meet a return on equity target in order
for the CEO's restricted shares to vest. During the vesting period, employees are entitled to dividend equivalents which are paid when
dividends on the Company s common stock are declared. Restricted stock is valued at the average of the high and low market of the
Company s common stock on the grant date. As of December 31 , 2006, the restricted shares had unrecognized compensation expense
of $0.4 million and an intrinsic value of $0.9 million. The intrinsic value represents the total market value of restricted shares as of
December 31 , 2006. The following table summarizes restricted stock activity:
Unvested Shares at December 31 , 2005
Shares granted
Shares cancelled
Shares vested
Unvested Shares at December 31 , 2006
36,260
(80)
Weighted average fair value at grant date
36.180
$21.
073 of restricted shares vested on January 3, 2007 that were granted in 2006.
Performance Shares
Performance share grants have vesting periods of three years. Performance awards entitle the recipients to dividend equivalent rights
are subject to forfeiture under certain circumstances, and subject to meeting specific performance conditions. Based on the attainment
of the performance condition, the amount of cash paid or common stock issued will range from 0 to 150 percent of the performance
shares granted depending on the change in the value of the Company s common stock relative to an external benchmark. Dividend
equivalent rights are accumulated and paid out only on shares that eventually vest.
Performance share awards entitle the grantee to shares of common stock or cash payable once the service condition is satisfied. Based
on attainment of the performance condition, grantees may receive 0 to 150 percent of the original shares granted. The performance
condition used benchmarks the Company s Total Shareholder Return (TSR) performance over a three-year period against other
utilities; under SFAS 123R this is considered a market based condition. Perfonnance shares may be settled in common stock or cash
at the discretion of the Company. Historically, the company has settled these awards through issuance of stock and intends to continue
this practice. These awards vest at the end of the three-year period. Under Statement SFAS 123R, performance shares are equity
awards with a market based condition, which results in the compensation cost for these awards being recognized over the requisite
service period, provided that the requisite service period is rendered , regardless of when, if ever, the market condition is satisfied.
The Company measured (at the grant date) the estimated fair value of performance shares granted in 2006, 2005 and 2004 in
accordance with the provisions of SFAS No. 123R. The fair value of each performance share award was estimated on the date of
grant using a Monte Carlo valuation model. Expected volatility was based on the historical volatility of A vista Corp. common stock
over a three-year period. The expected tenn of the performance shares is three years based on the performance cycle. The risk-free
interest rate was based on the u.S. Treasury yield at the time of grant. The compensation expense on these awards will only be
adjusted for changes in forfeitures. The following summarizes the weighted average assumptions used to detennine the fair value of
performance shares and related compensation costs:
Risk-free interest rate
Expected life, in years
Expected volatility
Dividend yield
IFERC FORM NO.1 (ED. 12-88)
2006
21.9%
2005
3.4%
34.
2004
2.4%
38.
3.4%
Page 123.
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NOTES TO FINANCIAL STATEMENTS (Continued)
The fair value of performance shares granted was estimated to be the following in the year ended December 31:
Weighted average grant date fair value (per share)
2006
$18.
2005
$16.
2004
$17.16
The fair value includes both performance shares and dividend equivalent rights.
During 2006, the Company granted 138 340 performance shares of which 138,042 were outstanding and unvested as of December 31
2006, to certain officers and other key employees. In 2005, the Company granted 163 600 performance shares to certain officers and
other key employees, of which 162 364 awards were outstanding and unvested as of December 31 , 2006.
The Company granted 156 800 performance shares in 2004. Based on the Company s TSR as compared to the benchmark during the
year performance cycle, the Company issued 189,382 shares of common stock in January 2007 related to the performance shares
granted in 2004. The Company issued 183,497 shares of common stock in the rust quarter of 2006 related to the performance shares
granted in 2003.
Umecognized compensation expense for perfonnance share awards was $2.4 million as of December 31, 2006, of which $1.6 million
and $0.8 million is expected to be expensed during 2007 and 2008. The aggregate intrinsic value of all performance share awards
outstanding as of December 31 , 2006 was $11.5 million, which represents the total market value of all performance shares outstanding.
This is the value that would have been received by the share recipients had all perfonnance shares been vested and paid out at 100
percent on December 31 , 2006.
A wards outstanding under the performance share grants include a dividend component that is paid in cash. This component of theperformance share grants is accounted for as a liability award under the guidance of SFAS No. 123R. These liability awards are
revalued on a quarterly basis taking into account the number of awards outstanding, historical dividend rate, and the change in the
value of the Company s common stock relative to an external benchmark. Over the life of these awards, the cumulative amount of
compensation expense recognized will match the actual cash paid. As of December 31 2006, the Company had recognized
compensation expense and a liability of $0.7 million related to the dividend component of performance share grants.
NOTE 2~. COMMITMENTS AND CONTINGENCIES
In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters
including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve
litigation or other contested proceedings. With respect to these proceedings, the Company intends to vigorously protect and defend itsinterests and pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because
litigation and other contested proceedings are inherently subject to numerous uncertainties. With respect to matters that affect Avista
Corp.s operations, the Company intends to seek, to the extent appropriate, recovery of incurred costs through the rate making process.
Federal Energy Regulatory Commission Inquiry
On April 19, 2004, the FERC issued an order approving the contested Agreement in Resolution of Section 206 Proceeding (Agreement
in Resolution) reached by A vista Corp., A vista Energy and the FERC's Trial Staff with respect to an investigation into the activities of
Avista Corp. and Avista Energy in western energy markets during 2000 and 2001. In the Agreement in Resolution, the FERC Trial
Staff stated that its investigation found: (1) no evidence that any executives or employees of Avista Corp. or Avista Energy knowingly
engaged in or facilitated any improper trading strategy; (2) no evidence that Avista Corp. or Avista Energy engaged in any efforts to
manipulate the western energy markets during 2000 and 2001; and (3) that Avista Corp. and Avista Energy did not withhold relevant
information from the FERC's inquiry into the western energy markets for 2000 and 2001. In April 2005 and June 2005, the California
Parties and the City of Tacoma, respectively, filed petitions for review of the FERC's decisions approving the Agreement in Resolution
with the United States Court of Appeals for the Ninth Circuit. Based on the FERC's order approving the Agreement in Resolution and
the FERC's denial of rehearing requests, the Company does not expect that this proceeding will have any material adverse effect on its
financial condition, results of operations or cash flows.
Class Action Securities Litigation
On November 10, 2005, an amended class action complaint was filed in the United States District Court for the Eastern District of
Washington against A vista Corp., Thomas M. Matthews, the former Chairman of the Board, President and Chief Executive Officer of
IFERC FORM NO.1 (ED. 12-88) Page 123.
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NOTES TO FINANCIAL STATEMENTS (Continued)
Avista Corp., Gary G. Ely, the current Chairman of the Board and Chief Executive Officer of Avista Corp., and Jon E. Eliassen, the
former Senior Vice President and Chief Financial Officer of A vista Corp. Several class action complaints were originally filed in
September through November 2002 in the same court against the same parties. In February 2003 , the court issued an order, which
consolidated the complaints and in August 2003 , the plaintiffs filed a consolidated amended class action complaint. On June 13,2005,
the Company filed a motion for reconsideration of its earlier motion to dismiss this complaint, based, in part, on a recent United States
Supreme Court decision with respect to the pleading requirements surrounding a sufficient showing of loss causation. On October 19,
2005, the Court granted the Company s motion to dismiss this complaint. The order to dismiss was issued without prejudice, which
allowed the plaintiffs to amend their complaint. The amended complaint filed on November 10, 2005 alleges damages due to the
decrease in the total market value of the Company s common stock during the class period alleged to be approximately $2.6 billion.
These alleged losses stemmed from alleged violations of federal securities laws through alleged misstatements and omissions of
material facts with respect to the Company s energy trading practices in western power markets. The plaintiffs assert that alleged
misstatements and omissions regarding these matters were made in the Company s filings with the Securities and Exchange
Commission and other information made publicly available by the Company, including press releases. The class action complaint
asserts claims on behalf of all persons who purchased, converted, exchanged or otherwise acquired the Company s common stock
during the period between November 23 1999 and August 13 , 2002. On January 6 2006, the Company filed a motion to dismiss the
November 10, 2005 complaint, asserting deficiencies in the amended complaint, including that the plaintiffs failed to adequately allege
loss causation. On June 2, 2006, the u.s. District Court entered an order denying the Company s motion to dismiss the complaint.
The u.S. District Court's order denying the Company s motion to dismiss is not a decision on the merits of the lawsuit. On September
16,2006, the plaintiffs filed a motion for class certification. On February 13,2007, the plaintiffs' motion for class certification was
heard before the court. Also, pending before the court is defendants' motion for summary judgment seeking to dismiss plaintiffs
claims on the ground that they are barred by the applicable statute of limitations. The matter is expected to proceed in the normal
course of litigation and a trial date is currently scheduled for November 13, 2007. Because the resolution of this lawsuit remains
uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company s liability. However, based on information
currently known to the Company s management, the Company does not expect that this lawsuit will have a material adverse effect on
its financial condition, results of operations or cash flows.
California Refund Proceeding
In July 200 I, the FERC ordered an evidentiary hearing to determine the amount of refunds due to California energy buyers for
purchases made in the spot markets operated by the California Independent System Operator (CaUSO) and the California Power
Exchange (CaIPX) during the period from October 2, 2000 to June 20, 2001 (Refund Period) in the California spot power market. The
findings of the FERC administrative law judge were largely adopted in March 2003 by the FERc. The refunds ordered are based on
the development of a mitigated market clearing price methodology. If the refunds required by the formula would cause a seller to
recover less than its actual costs for the refund period, the FERC has held that the seller would be allowed to document these costs and
limit its refund liability commensurately. In September 2005 , Avista Energy submitted its cost filing claim pursuant to the FERC's
August 2005 order and demonstrated an overall revenue shortfall for sales into the California spot markets during the Refund Period
after the mitigated market clearing price methodology is applied to its transactions. That filing was accepted in orders issued by the
FERC in January 2006 and November 2006. In February 2007, the CanSO filed a status report at the FERC stating that it will take
approximately 10 weeks to complete the financial adjustment phase related to transactions in its markets during the Refund Period.
The report also stated that the CanSO intends to process A vista Energy s cost claim. The CanSO states that its efforts related to cost
filing offsets will require five business weeks to complete. In January 2007, Avista Energy joined in a settlement filed at the FERC by
participants in markets operated by the Automated Power Exchange (APX). The settlement, if approved by the FERC, provides for a
comprehensive resolution of all disputes and other matters with respect to the APX related claims.
In 2001 , Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) defaulted on payment obligations to the CalPX and the
CanSO. As a result, the CalPX and the CanSO failed to pay various energy sellers, including Avista Energy. Both PG&E and the
CalPX declared bankruptcy in 200 I. In March 2002, SCE paid its defaulted obligations to the CaIPX. In April 2004, PG&E paid its
defaulted obligations into an escrow fund in accordance with its bankruptcy reorganization. Funds held by the CalPX and in the
PG&E escrow fund are not subject to release until the FERC issues an order directing such release in the California refund proceeding.
As of December 31, 2006, A vista Energy s accounts receivable outstanding related to defaulting parties in California were fully offset
by reserves for uncollected amounts and funds collected from defaulting parties.
In addition, in June 2003, the FERC issued an order to review bids above $250 per MW made by participants in the short-tenn energy
markets operated by the CanSO and the CalPX from May 1 2000 to October 2, 2000. Market participants with bids above $250 per
MW during the period described above have been required to demonstrate why their bidding behavior and practices did not violate
IFERC FORM NO.1 (ED. 12-88) Page 123.
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NOTES TO FINANCIAL STATEMENTS (Continued)
applicable market rules. If violations were found to exist, the FERC would require the refund of any unjust profits and could also
enforce other non-monetary penalties, such as the revocation of market-based rate authority. A vista Energy was subject to this review.
In May 2004, the FERC provided notice that Avista Energy was no longer subject to this investigation. In March and April 2005, the
California Parties and PG&E, respectively, petitioned for review of the FERC's decision by the United States Court of Appeals for the
Ninth Circuit. In addition, many of the other orders that the FERC has issued in the California refund proceedings are now on appeal
before the Ninth Circuit. Some of those issues have been consolidated as a result of a case management conference conducted in
September 2004. In October 2004, the Ninth Circuit ordered that briefing proceed in two rounds. The first round is limited to three
issues: (1) which parties are subject to the FERC's refund jurisdiction in light of the exemption for government-owned utilities in
section 201(f) of the Federal Power Act (FPA); (2) the temporal scope of refunds under section 206 of the FPA; and (3) which
categories of transactions are subject to refunds. In September 2005, the Ninth Circuit held that the FERC did not have the authority to
order refunds for sales made by municipal utilities in the California Refund Case. In August 2006, the Ninth Circuit upheld October 2
2000 as the refund effective date for the FP A section 206 Refund Proceeding, but remanded to the FERC its decision not to consider a
FPA section 309 remedy for tariff violations prior to October 2, 2000. The Ninth Circuit also granted California s petition for review
challenging the FERC's exclusion of the energy exchange transactions as well as the FERC's exclusion of forward market transactions
from the California refund proceedings. The Ninth Circuit has extended until April 29, 2007, the time for filing petitions for rehearing.
It is unclear at this time what impact, if any, the Court's remand might have on Avista Energy. The second round of issues and their
corresponding briefing schedules have not yet been set by the Ninth Circuit Court of Appeals.
Because the resolution of the California refund proceeding remains uncertain, legal counsel cannot express an opinion on the extent, if
any, of the Company s liability. However, based on information currently known to the Company s management, the Company does
not expect that the California refund proceeding will have a material adverse effect on its fmancial condition, results of operations or
cash flows. This is primarily due to the fact that FERC orders have stated that any refunds will be netted against unpaid amounts owed
to the respective parties and the Company does not believe that refunds would exceed unpaid amounts owed to the Company.
Pacific Northwest Refund Proceeding
In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market
sales in the Pacific Northwest between December 25, 2000 and June 20, 200 I were just and reasonable. During the hearing, A vista
Corp. and Avista Energy vigorously opposed claims that rates for spot market sales were unjust and unreasonable and that the
imposition of refunds would be appropriate. In June 2003, the FERC terminated the Pacific Northwest refund proceedings, after
finding that the equities do not justify the imposition of refunds. Seven petitions for review, including one filed by Puget Sound
Energy, Inc. (Puget), are now pending before the United States Court of Appeals for the Ninth Circuit. Opening briefs were filed in
January 2005. Petitioners other than Puget challenged the merits of the FERC's decision not to order refunds. Puget's brief is directed
to the procedural flaws in the underlying docket. Puget argues that because its complaint was withdrawn as a matter of law in July
2001, the FERC erred in relying on it to serve as the basis to initiate the preliminary investigation into whether refunds for individually
negotiated bilateral transactions in the Pacific Northwest were appropriate. In February 2005, intervening parties, including A vista
Energy and Avista Corp., filed in support ofPuget and also filed in opposition to the other six petitioners. Briefing was completed in
May 2005 and oral arguments were heard on January 8, 2007. Because the resolution of the Pacific Northwest refund proceeding
remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company s liability. However, based on
information currently known to the Company s management, the Company does not expect that the Pacific Northwest refund
proceeding will have a material adverse effect on its financial condition, results of operations or cash flows.
California Attorney General Complaint
In May 2002, the FERC conditionally dismissed a complaint filed in March 2002 by the Attorney General of the State of California
(California AG) that alleged violations of the Federal Power Act by the FERC and all sellers (including A vista Corp. and its
subsidiaries) of electric power and energy into California. The complaint alleged that the FERC's adoption and implementation of
market-based rate authority was flawed and, as a result, individual sellers should refund the difference between the rate charged and a
just and reasonable rate. In May 2002, the FERC issued an order dismissing the complaint but directing sellers to re-file certain
transaction summaries. It was not clear that Avista Corp. and its subsidiaries were subject to this directive but the Company took the
conservative approach and re-filed certain transaction summaries in June and July of 2002. In July 2002, the California AG requested
a rehearing on the FERC order, which request was denied in September 2002. Subsequently, the California AG filed a Petition for
Review of the FERC's decision with the United States Court of Appeals for the Ninth Circuit. In September 2004, the United States
Court of Appeals for the Ninth Circuit upheld the FERC's market-based rate authority, but found the requirement that all sales at
market-based rates be contained in quarterly reports filed with the FERC to be integral to a market-based rate tariff. The California
AG has interpreted the decision as providing authority to the FERC to order refunds in the California refund proceeding for an
IFERC FORM NO.1 (ED. 12-88) Page 123.
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NOTES TO FINANCIAL STATEMENTS (Continued)
expanded refund period. The Court's decision leaves to the FERC the determination as to whether refunds are appropriate. In October
2004, Avista Energy joined with others in seeking rehearing of the Court's decision to remand the case back to the FERC for further
proceedings. The Court denied the request without explanation on July 31, 2006. Based on its current schedule, the Ninth Circuit will
issue the mandate on this decision on April 29, 2007, which will return the case to the FERC for further proceedings. On December
28, 2006 certain parties filed a petition for a writ of certiorari at the Supreme Court, which is currently pending. Based on information
currently known to the Company s management, the Company does not expect that this matter will have a material adverse effect on its
financial condition, results of operations or cash flows.
Wah Chang Complaint
In May 2004, Wah Chang, a division ofTDY Industries, Inc. (a subsidiary of Allegheny Technologies, Inc.), filed a complaint in the
United States District Court for the District of Oregon against numerous companies, including A vista Corp., A vista Energy and A vista
Power. This complaint is similar to the Port of Seattle complaint (which has been dismissed by the United States District Court and the
United States Court of Appeals for the Ninth Circuit) and seeks compensatory and treble damages for alleged violations of the
Sherman Act, the Racketeer Influenced and Corrupt Organization Act, as well as violations of Oregon state law. According to the
complaint, from September 1997 to September 2002, the plaintiff purchased electricity from PacifiCorp pursuant to a contract that was
indexed to the spot wholesale market price of electricity. The plaintiff alleges that the defendants, acting in concert among themselves
and/or with Enron Corporation and certain affiliates thereof (collectively, Enron) and others, engaged in a scheme to defraud electricity
customers by transmitting false market information in interstate commerce in order to artificially increase the price of electricity
provided by them, to receive payment for services not provided by them and to otherwise manipulate the market price of electricity,
and by executing wash trades and other forms of market manipulation techniques and sham transactions. The plaintiff also alleges that
the defendants, acting in concert among themselves and/or with Enron and others, engaged in numerous practices involving the
generation, purchase, sale, exchange, scheduling and/or transmission of electricity with the purpose and effect of causing a shortage (or
the appearance of a shortage) in the generation of electricity and congestion (or the appearance of congestion) in the transmission of
electricity, with the ultimate purpose and effect of artificially and illegally fixing and raising the price of electricity in California and
throughout the Pacific Northwest. As a result of the defendants' alleged conduct , the plaintiff allegedly suffered damages of not less
than $30 million through the payment of higher electricity prices. In September 2004, this case was transferred to the United States
District Court for the Southern District of California for consolidation with other pending actions. In February 2005, the Court granted
the defendants' motion to dismiss the complaint because it determined that it was without jurisdiction to hear the plaintiff's complaint
based on, among other things, the exclusive jurisdiction of the FERC and the filed-rate doctrine. In March 2005, Wah Chang filed an
appeal with the United States Court of Appeals for the Ninth Circuit. The appeal ofWah Chang is still pending before the Ninth
Circuit and oral argument is set for April 10, 2007. Because the resolution of this lawsuit remains uncertain, legal counsel cannot
express an opinion on the extent, if any, of the Company s liability. However, based on information currently known to the Company
management, the Company does not expect that this lawsuit will have a material adverse effect on its financial condition, results of
operations or cash flows.
City of Tacoma Complaint
In June 2004, the City of Tacoma, Department of Public Utilities, Light Division, a Washington municipal corporation (Tacoma
Power), filed a complaint in the United States District Court for the Western District of Washington against over fifty companies
including Avista Corp., Avista Energy and Avista Power. According to the complaint, Tacoma Power distributes electricity to
customers in Tacoma, and Pierce County, Washington, generates electricity at several facilities in western Washington and purchases
power under supply contracts and in the Northwest spot market. Tacoma Power s complaint is similar to the Port of Seattle complaint
(which has been dismissed by the United States District Court and the United States Court of Appeals for the Ninth Circuit) and seeks
compensatory and treble damages from alleged violations of the Sherman Act. Tacoma Power alleges that the defendants, acting in
concert, engaged in a pattern of activities that had the purpose and effect of creating the impressions that the demand for power was
higher, the supply of power was lower, or both, than was in fact the case. This allegedly resulted in an artificial increase of the prices
paid for power sold in California and elsewhere in the western United States during the period from May 2000 through the end of
2001. Due to the alleged unJawful conduct of the defendants, Tacoma Power allegedly paid an amount estimated to be $175.0 million
in excess of what it would have paid in the absence of such alleged conduct. In September 2004, this case was transferred to the
United States District Court for the Southern District of California for consolidation with other pending actions. In February 2005, the
Court granted the defendants ' motion to dismiss this complaint for similar reasons to those expressed by the Court in the Wah Chang
complaint described above. In March 2005, Tacoma Power filed an appeal with the United States Court of Appeals for the Ninth
Circuit. The appeal of Tacoma Power is still pending before the Ninth Circuit and oral argument is set for April 10, 2007. Because
the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company
liability. However, based on information currently known to the Company s management, the Company does not expect that this
IFERC FORM NO.1 (ED. 12-88) Page 123.
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NOTES TO FINANCIAL STATEMENTS (Continued)
lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows.
State of Montana Proceedings
In June 2003, the Attorney General of the State of Montana (Montana AG) filed a complaint in the Montana District Court on behalf of
the people of Montana and the Flathead Electric Cooperative, Inc. against numerous companies, including Avista Corp. The complaint
alleges that the companies illegally manipulated western electric and natural gas markets in 2000 and 2001. This case was
subsequently moved to the United States District Court for the District of Montana; however, it has since been remanded back to the
Montana District Court.
The Montana AG also petitioned the Montana Public Service Commission (MPSC) to fine public utilities $1 000 a day for each day it
finds they engaged in alleged "deceptive, fraudulent, anticompetitive or abusive practices" and order refunds when consumers were
forced to pay more than just and reasonable rates. In February 2004, the MPSC issued an order initiating investigation of the Montana
retail electricity market for the purpose of determining whether there is evidence of unJawful manipulation of that market. The
Montana AG has requested specific infonnation from A vista Energy and A vista Corp. regarding their transactions within the State of
Montana during the period from January 1 2000 through December 31 , 2001.
Because the resolution of these proceedings remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the
Company s liability. However, based on information currently known to the Company s management, the Company does not expect
that these proceedings will have a material adverse effect on its financial condition, results of operations or cash flows.
Montana Public School Trust Fund Lawsuit
In October 2003, a lawsuit was originally filed by two residents of the State of Montana in the United States District Court for the
District of Montana against all private owners of hydroelectric darns in Montana, including A vista Corp. The lawsuit alleged that the
hydroelectric facilities are located on state-owned riverbeds and the owners of the dams have never paid compensation to the state
public school trust fund. The lawsuit requests lease payments dating back to the construction of the respective dams and also requests
damages for trespassing and unjust emichment. In February 2004, the Company filed its motion to dismiss this lawsuit; PacifiCorp
and PPL Montana, the other named defendants, also filed a motion to dismiss, or joined therein. In May 2004, the Montana AG filed a
complaint on behalf of the state in the District Court to join in this lawsuit to allegedly protect and preserve state lands/school trust
lands from use without compensation. In July 2004, the defendants (including Avista Corp.) filed a motion to dismiss the Montana
AG's complaint. In September 2004, the motion to dismiss the Montana AG's complaint was denied, rejecting the defendants
argument, among other things, that the FERC has exclusive jurisdiction over this matter. In September 2005, the u.S. District Court
issued an order vacating its prior decision based on lack of jurisdiction.
In November 2004, the defendants (including A vista Corp.) filed a petition for declaratory relief in Montana State Court requesting the
resolution of the controversy that the plaintiffs raised in federal court, as discussed above, and the Montana AG filed an answer
counterclaim and motion for summary judgment. In June 2005, Avista Corp. moved for leave to amend its complaint to, inter alia, add
two causes of action relating to breach of contract and negligent misrepresentation arising out of its Clark Fork Settlement Agreement
that was entered into in 1999 with the State of Montana relating to the relicensing of Avista Corp.'s Noxon Rapids Hydroelectric
Generating Project. On April 14, 2006, the Montana State Court granted the Montana AG's motion for summary judgment and denied
A vista Corp.s motion to amend its complaint to add its breach of contract and negligent misrepresentation claims. However, the
Montana State Court granted A vista Corp.' s motion to amend its complaint to contend that the Clark Fork River is not navigable. The
Company contends that if the Clark Fork River was not navigable at the time of statehood in 1889, the State of Montana never
acquired ownership of the riverbeds under the equal footing doctrine. The Court determined that the Montana AG's claims for
compensation were not preempted by the Federal Power Act because it was not, on its face, in conflict with Montana law, nor were
they preempted by a federal navigational right for purposes of interstate commerce. The Court also rejected defenses based on
estoppel, waiver, and the statute of limitations. The Court did not relieve the Montana AG, however, of its obligation to prove that the
State of Montana actually owns the riverbeds or that the land is part of a school trust under the Montana Constitution. In addition, the
question of whether there is federal preemption under the Federal Power Act, not on its face, but as actually applied in these
circumstances, and the question of compensation, still remain open issues in the case. On May 16, 2006, the State of Montana filed a
motion for summary judgment on the question of liability. On October 6, 2006, the Company filed several motions, which addressed
among other things, the question of navigability of the Clark Fork River arguing that since the Clark Fork River was not navigable at
the time of statehood, the State of Montana never acquired ownership of the riverbeds under the equal footing doctrine. Oral
arguments on the Company s motions were heard in December 2006. The Company expects this matter to proceed in the normal
course of litigation and a trial date is currently scheduled for October 2007. Because the resolution of this lawsuit remains uncertain
IFERC FORM NO.1 (ED. 12-88)Page 123.
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(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
legal counsel cannot express an opinion on the extent, if any, of the Company s liability. However, the Company intends to seek
recovery, through the rate making process, of any amounts paid.
Colstrip Generating Project Complaint
In May 2003, various parties (all of which are residents or businesses of Colstrip, Montana) filed a consolidated complaint against the
owners of the Colstrip Generating Project (Colstrip) in Montana District Court. A vista Corp. owns a 15 percent interest in Units 3 & 4
of Colstrip. The plaintiffs allege damages to buildings as a result of rising ground water, as well as damages from contaminated waters
leaking from the lakes and ponds of Colstrip. The plaintiffs are seeking punitive damages, an order by the court to remove the lakes
and ponds and the forfeiture of all profits earned from the generation of Colstrip. The owners of Colstrip have undertaken certain
groundwater investigation and remediation measures to address groundwater contamination. These measures include improvements to
the lakes and ponds of Colstrip. The Company intends to continue to work with the other owners of Colstrip in defense of this
complaint. Because the resolution of this lawsuit remains uncertain, legal counsel cannot express an opinion on the extent, if any, of
the Company s liability. However, based on information currently known to the Company s management, the Company does not
expect that this lawsuit will have a material adverse effect on its financial condition, results of operations or cash flows.
Environmental Protection Agency Administrative Compliance Order
In December 2003, PPL Montana, LLC, as operator of Colstrip, received an Administrative Compliance Order (ACO) from the
Environmental Protection Agency (BPA) pursuant to the Clean Air Act (CAA). In January 2006, the EPA issued a draft settlement
agreement related to the ACO. The ACO alleges that Colstrip Units 3 & 4 have been in violation of the CAA permit at Colstrip since
the units came on-line in the 1980s. The permit required the Colstrip project operator to submit for review and approval by the EPA
an analysis and proposal for reducing emissions of nitrogen oxides to address visibility concerns if, and when, EP A promulgates Best
Available Retrofit Technology requirements for nitrogen oxide emissions. The EP A is asserting that regulations it promulgated in
1980 triggered this requirement. A vista Corp. and the other owners of Colstrip believe that the ACO is unfounded. The owners of
Colstrip are discussing the proposed settlement agreement with the EP A, the Department of Environmental Quality (Montana DEQ)
and the Northern Cheyenne Tribe. The draft settlement agreement would resolve the potential liability related to this issue and would
result in the installation of additional nitrogen oxide emissions control equipment at Colstrip. Because the resolution of this issue
remains uncertain, legal counsel cannot express an opinion on the extent, if any, of the Company s liability. However, the Company
intends to seek recovery, through the rate making process, of any amounts paid (including capitalized costs).
Colstrip Royalty Claim
Western Energy Company (WECO) supplies coal to the owners of Colstrip Units 3 & 4 under a Coal Supply Agreement and a
Transportation Agreement. Avista Corp. owns a 15 percent interest in Colstrip Units 3 & 4. The Minerals Management Service
(MMS) of the United States Department of the Interior issued an order to WECO to pay additional royalties concerning coal delivered
to Colstrip Units 3 & 4 via the conveyor belt (4.46 miles long). The owners of Colstrip Units 3 & 4 take delivery of the coal at the
western end (beginning) of the conveyor belt. The order asserts that additional royalties are owed MMS as a result of WECO not
paying royalties in connection with revenue received by WECO from the owners of Colstrip Units 3 & 4 under the Transportation
Agreement during the period October I, 1991 through December 31,2001. WECO's appeal to the MMS was substantially denied in
March 2005; WECO has now appealed the order to the Board of Land Appeals of the US. Department of the Interior. The entire
appeal process could take several years to resolve. The owners of Colstrip Units 3 & 4 are monitoring the appeal process between
WECO and MMS. WECO has indicated to the owners of Colstrip Units 3 & 4 that if WECO is unsuccessful in the appeal process
WECO will seek reimbursement of any royalty payments by passing these costs through the Coal Supply Agreement. The owners of
Colstrip Units 3 & 4 advised WECO that their position would be that these claims are not allowable costs per the Coal Supply
Agreement nor the Transportation Agreement in the event the owners of Colstrip Units 3 & 4 were invoiced for these claims.
Presumably, royalty and tax demands for periods oftime after the years in dispute and future years will be determined by the outcome
of the pending proceedings. Because the resolution of this issue remains uncertain, legal counsel cannot express an opinion on the
extent, if any, of the Company s liability. Based on information currently known to the Company s management, the Company does
not expect that this issue will have a material adverse effect on its financial condition, results of operations or cash flows. However
the Company would most likely seek recovery, through the rate making process, of any amounts paid.
Northeast Combustion Turbine Site
In August 2005, a diesel fuel spill occurred at the Company s Northeast Combustion Turbine generating facility (Northeast CT)
located in Spokane, Washington. The Northeast CT site had fuel storage facilities that were leased to Co-op Supply, Inc., an affiliate
of Cenex Cooperative (Co-op). The fuel spill occurred when Co-op made a delivery of diesel to a tank that was already nearly full
causing excess fuel to overflow into a containment area. It is estimated that approximately 26 000 gallons of fuel escaped the
IFERC FORM NO.1 (ED. 12-88) Page 123.
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(1) X An Original (Mo, Da, Yr)
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NOTES TO FINANCIAL STATEMENTS (Continued)
containment area and leaked into the soil below it. An investigation, supervised by the DOE, detennined the fuel was, for the most
part, uniformly present in the soil to a depth of 30-35 feet. Groundwater below the site is at a depth of 170 feet. The Company
immediately commenced remediation efforts, including the removal of contaminated soil and the related fuel storage facilities.
Options to dispose of the contaminated soil are currently being evaluated. The Company accrued the estimated cleanup costs during
2005 , which was not material to the Company s fmancial condition or results of operations. During the fourth quarter of 2005, the
Company filed a complaint against Co-op and an engineering flIm to recover a substantial portion of the cleanup costs. Through
mediation the Company recovered a substantial portion of the cleanup costs from Co-op and the engineering flIm in the fourth quarter
of 2006. Because of uncertainties related to the disposal of the contaminated soil, the Company s estimate of its liability could change
in future periods. Based on information currently known to the Company s management, the Company does not believe that such a
change would be material to 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 transformer oil in the late 1980s and early
1990s. In June 2005, EPA Region 10 provided notification to Avista Corp., as a customer of Harbor Oil, that the EPA had determined
that hazardous substances were released at the Harbor Oil site in Portland, Oregon and that Avista Corp. may be liable for investigation
and cleanup of the site under the Comprehensive Environmental Response, Compensation, and Liability Act, commonJy referred to as
the federal "Superfund" law. Harbor Oil's primary business was the collection and blending of used oil for sale as fuel to ships at sea.
The initial indication from the EPA is that the site may be contaminated with PCBs, petroleum hydrocarbons, chlorinated solvents and
heavy metals. Thirteen other companies received a similar notice, including current and former owners of the site, the Bonneville
Power Administration, Portland General Electric Company, Northwestern Energy and Unocal Oil. Several meetings have been held
with the EPA and certain of the Potentially Responsible Parties (PRPs) to ask questions of the EPA regarding the Harbor Oil site, as
well as drafting an administrative compliance order related to conducting a remedial investigation and feasibility study for the site.
Based on the review of its records related to Harbor Oil, the Company does not believe it is a major contributor to this potential
environmental contamination based on the relative volume of waste oil delivered to the Harbor Oil site. However, there is currently
not enough information to allow the Company to assess the probability or amount of a liability, if any, being incurred. As such, it is
not possible to make an estimate of any liability at this time.
Lake Coeur d'Alene
In July 1998, the United States District Court for the District of Idaho issued its finding that the Coeur d' Alene Tribe of Idaho (Tribe)
owns, among other things, portions of the bed and banks of Lake Coeur d' Alene (Lake) lying within the current boundaries of the
Coeur d' Alene Reservation. This action had been brought by the United States on behalf of the Tribe against the state of Idaho. The
Company was not a party to this action. The United States District Court decision was affirmed by the United States Court of Appeals
for the Ninth Circuit. The United States Supreme Court afflImed this decision in June 2001. This ownership decision will result in,
among other things, the Company being liable to the Tribe for compensation for the use of reservation lands under Section I O( e) of the
Federal Power Act.
The Company s Post Falls Hydroelectric Generating Station (post Falls), a facility constructed in 1906 with annual generation of 10
aMW, utilizes a dam on the Spokane River downstream of the Lake which controls the water level in the Lake for portions of the year
(including portions of the lakebed owned by the Tribe). The Company has other hydroelectric facilities on the Spokane River
downstream of Post Falls, but these facilities do not affect the water level in the Lake. The Company and the Tribe are engaged in
discussions related to past and future compensation (which may include interest) for use of the portions of the bed and banks of the
Lake, which are owned by the Tribe. If the parties cannot agree on the amount of compensation, the matter could result in litigation.
The Company cannot predict the amount of compensation that it will ultimately payor the terms of such payment. The Company
intends to seek recovery, through the rate making process, of any amounts paid.
Spokane River Relicensing
The Company owns and operates six hydroelectric plants on the Spokane River, and five of these (Long Lake, Nine Mile, Upper Falls,
Monroe Street and Post Falls, which have a total present capability of 155.7 MW) are under one FERC license and are referred to as
the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC.
The license for the Spokane River Project expires on August 1 2007; the Company filed a Notice of Intent to Relicense in July 2002.
The fonnal consultation process involving planning and information gathering with stakeholder groups has been underway since that
time. The Company filed its new license applications with the FERC in July 2005. The Company has requested the FERC to consider
a license for Post Falls, which has a present capability of 18 MW, that is separate from the other four hydroelectric plants because Post
Falls presents more complex issues that may take longer to resolve than those dealing with the rest of the Spokane River Project.
IFERC FORM NO.1 (ED. 12-88) Page 123.
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(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
granted, new licenses would have a term of 30 to 50 years. In the license applications, the Company proposed a number of measures
intended to address the impact of the Spokane River Project and enhance resources associated with the Spokane River.
Since the Company s July 2005 filing of applications to relicense the Spokane River Project, the FERC has continued various stages
of processing the applications. In May 2006, the FERC issued a notice calling for terms and conditions regarding the two license
applications. In response to that notice, a number of parties (including the Coeur d' Alene Tribe , the state of Idaho, Washington State
agencies, and the United States Department of Interior (DOl)) filed either recommended terms and conditions, pursuant to Sections
10(a) and lOG) of the Federal Power Act (FP A), or mandatory conditions related to the Post Falls application, pursuant to Section 4(e)
of the FPA. The Company s initial estimate of the potential cost of the conditions proposed for Post Falls total between $400 million
and $500 million over a 50-year period. This assumes all conditions, both mandatory and recommended, as well as the Company
proposed conditions, would be included in a final license issued by the FERC, which the Company believes to be unlikely. For the
rest of the Spokane River Project, which is located in Washington, the Company s initial estimate of the cost of meeting the
recommended conditions, should they be included in a final license, totals between $175 million and $225 million over a 50-year
period. These cost estimates are based on the preliminary conditions and recommendations and will be updated based on the outcome
of the FERC proceedings.
The Company requested a trial-type hearing on facts in front of a (ALJ) related to the DOl's mandatory conditions for Post Falls. In
January 2007, the AU issued his ruling regarding the Company s challenge of the facts. The Company believes that the ALl's factual
findings support, in several key areas, its analysis of the facts at hand. The ALl's factual findings also support the DOl's analysis in
certain areas as well.
The Bureau of Indian Affairs, which is part of the DOl and is charged with protecting project-related resources on the Coeur d' Alene
Indian Reservation and has authority to set conditions for the Company s license, is now expected to use the ALl's findings to
formulate final mandatory conditions for the operation of Post Falls.
The broader relicensing process continues under the jurisdiction of the FERC. The FERC issued a draft environmental impact
statement (DEIS) in December 2006 that is open for public review and comment until March 6,2007. This document includes the
FERC's initial analysis of the applications , along with analysis of proposed recommended and mandatory terms and conditions. While
the FERC's analysis leads the Company to believe the ultimate cost of relicensing may be less than its earlier projections as disclosed
above, the Company is unable to base specific new cost estimates on it.
The relicensing process also triggers review under the Endangered Species Act. The Company prepared a draft Biological Assessment
in 2005. In the DEIS , the FERC analyzed potential project impacts on listed and threatened endangered species, and has determined
that the proposed action and continued operation of the Post Falls and Spokane River projects, is not likely to adversely effect any
threatened or endangered species. The FERC has issued a Biological Assessment and formally requested concurrence from the United
States Department ofFish and Wildlife Service (USFWS). The USFWS may either concur or request fonnal consultation. Should
they request formal consultation, additional evaluation will be required.
Following the comment period, the FERC will request final tenns and conditions from agencies, the Coeur d' Alene Tribe and others.
After that time, the FERC would issue a final environmental impact statement and, ultimately, license orders on Post Falls and the
Spokane River Project. In addition, the Company must receive Clean Water Act Certifications from the states of Idaho and
Washington for the Projects. Applications for such certification were filed last July with each state; the FERC is precluded from
issuing a license order until such certification has been issued, or waived, by the states. The Company cannot predict the schedule for
these final phases of relicensing.
If the FERC is unable to issue new license orders prior to the August I , 2007 expiration of the current license, an annual license will
be issued, in effect extending the current license and its conditions. The Company has no reason to believe that Spokane River Project
operations would be interrupted in any manner relative to the timing of the FERC's actions.
The total annual operating and capitalized costs associated with the relicensing of the Spokane River Project will become better
known and estimable as the process continues. The Company intends to seek recovery, through the rate making process, of all such
operating and capitalized costs.
Clark Fork Settlement Agreement
Dissolved atmospheric gas levels exceed state of Idaho and federal water quality standards downstream of the Cabinet Gorge
IFERC FORM NO.1 (ED. 12-88) Page 123.
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(1) X An Original (Mo, Da, Yr)
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NOTES TO FINANCIAL STATEMENTS (Continued)
Hydroelectric Generating Project (Cabinet Gorge) during periods when excess river flows must be diverted over the spillway. Under
the terms of the Clark Fork Settlement Agreement, the Company developed an abatement and mitigation strategy with the other
signatories to the agreement and completed the Gas Supersaturation Control Program (GSCP). The Idaho Department of
Environmental Quality and the U.S. Fish and Wildlife Service approved the GSCP in February 2004 and the FERC issued an order
approving the GSCP in January 2005.
The GSCP provides for the opening and modification of one and, potentially, both of the two existing diversion tunnels built when
Cabinet Gorge was originally constructed. When river flows exceed the capacity of the powerhouse turbines, the excess flows would
be diverted to the tunnels rather than released over the spillway. The Company has undertaken physical and computer modeling
studies to confirm the feasibility and likely effectiveness of its tunnel solution. The Company has completed its preliminary design
development efforts (which include additional computer model studies, some site investigation, and preliminary engineering design)
and the cost estimates have been updated. An analysis of the predicted total dissolved gas (TDG) perfonnance indicates that it would
not meet the standards anticipated in the GSCP. The costs of modifying the fIrSt tunnel are now estimated to be $58 million (using
2006 dollars with inflation projected at 5 percent) with the majority of these costs to be incurred in 2008 through 2011 , an increase
from prior estimates of $38 million and an extension of the schedule of at least one year. The calculated updated cost estimates to
modify the second tunnel are $39 million, an increase from prior estimates of $26 million. The second tunnel would be modified only
after evaluation of the performance of the fIrst tunnel and such modifications would commence no later than 10 years following the
completion of the first tunnel. The increases in costs are mainly due to inflation and large increases in materials costs, such as concrete
and steel. As a result of the predicted TDG performance, the new cost estimates and extension of the schedule, the Company is
meeting with stakeholders to explore possible alternatives to the construction of the tunnels. The Company intends to seek recovery,
through the rate making process, of the costs to address the dissolved atmospheric gas levels, including the mitigation payments.
The u.S Fish and Wildlife Service has listed bull trout as threatened under the Endangered Species Act. The Clark Fork Settlement
Agreement describes programs intended to restore bull trout populations in the project area. Using the concept of adaptive
management and working closely with the u.S. Fish and Wildlife Service, the Company is evaluating the feasibility of fish passage at
Cabinet Gorge and Noxon Rapids. The results of these studies will help the Company and other parties determine the best use of funds
toward continuing fish passage efforts or other bull trout population enhancement measures.
Air Quality
The Company must be in compliance with requirements under the Clean Air Act and Clean Air Act Amendments for its thermal
generating plants. The Company continues to monitor legislative developments at both the state and national level for the potential of
further restrictions on sulfur dioxide, nitrogen oxide, carbon dioxide (including cap and trade emission reduction programs), as well as
other greenhouse gas and mercury emissions. In particular, the EPA has finalized mercury emission regulations that will affect
coal-fired generation plants, including Colstrip. The new EP A regulations establish an emission trading program to take effect
beginning in January 2010, with a second phase to take effect in 2018. In addition, in 2006, the Montana DEQ adopted final rules for
the control of mercury emissions from coal-fIred plants that are more restrictive than EPA regulations. The new rules set strict
mercury emission limits by 2010, and put in place a recurring 10-year review process to ensure facilities are keeping pace with
advancing technology in mercury emission control. The rules also provide for temporary alternate emission limits provided certain
provisions are met, and they allocate mercury emission credits in a manner that rewards the cleanest facilities. Avista Corp. owns a 15
percent interest in Colstrip Units 3 & 4, located in Montana. Compliance with these new and proposed requirements and possible
additional legislation or regulations will result in increases to capital expenditures and operating expenses for expanded emission
controls at the Company s thermal generating facilities. The Company, along with the other owners of Colstrip, are in the process of
computing estimates for the amount of these costs and the impact the restrictions will have on the operation of the facilities. The
Company will continue to seek recovery, through the rate making process, of the costs to comply with various air quality requirements.
Other Contingencies
In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company
believes that any ultimate liability arising from these actions will not have a material adverse impact on its financial condition, results
of operations or cash flows. It is possible that a change could occur in the Company s estimates of the probability or amount of a
liability being incurred. Such a change, should it occur, could be significant.
The Company routinely assesses, based on in-depth studies, expert analyses and legal reviews, its contingencies, obligations and
commitments for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other
responsible parties who have and have not agreed to a settlement and recoveries from insurance carriers. The Company s policy is to
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates of
investigation, cleanup and monitoring costs to be incurred.
The Company has potential liabilities under the Federal Endangered Species Act for species of fish that have either already been added
to the endangered species list, been listed as "threatened" or been petitioned for listing. Thus far, measures adopted and implemented
have had minimal impact on the Company.
Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights.
The State of Montana is examining the status of all water right claims within state boundaries. Claims within the Clark Fork River
basin could potentially adversely affect the energy production of the Company s Cabinet Gorge and Noxon Rapids hydroelectric
facilities. The Company is participating in this extensive adjudication process, which is unJikely to be concluded in the foreseeable
future.
As of December 31, 2006, the Company s collective bargaining agreement with the International Brotherhood of Electrical Workers
represented approximately 50 percent of all of Avista Corp.'s employees. The agreement with the local union in Washington and
Idaho representing the majority (approximately 90 percent) of the bargaining unit employees expires in March 2009. Two local
agreements in Oregon, which cover approximately 50 employees, expire in April 2010. Another local agreement in Oregon is up for
negotiations in 2007.
NOTE 24: POTENTIAL HOLDING COMPANY FORMATION
At the 2006 Annual Meeting of Shareholders on May 11 , 2006, the shareholders of A vista Corp. approved a proposal to proceed with
a statutory share exchange, which would change the Company s organization to a holding company structure. The holding company,
currently named AVA Formation Corp. (A V A), would become the parent of Avista Corp. After the contemplated dividend to A V A of
the capital stock of A vista Capital now held by A vista Corp. (A vista Capital Dividend), A V A would then also be the parent of A vista
Capital. The Avista Capital Dividend would effect the structural separation of Avista Corp.'s non-utility businesses from its regulated
utility business. Since the company s 9.75 percent Senior Notes due June 1,2008 contain a restriction that would prohibit the Avista
Capital Dividend (but not the holding company structure), the dividend would not be distributed until the Senior Notes are retired.
A vista Corp. received approval from the FERC in April 2006 (conditioned on approval by the state regulatory agencies) and from the
IPUC in June 2006. Avista Corp. also has filed for approval from the utility regulators in Washington, Oregon and Montana. The
statutory share exchange is subject to the receipt of the remaining regulatory approvals and the satisfaction of other conditions. If the
statutory share exchange and the implementation of the holding company structure are approved by regulators on terms acceptable to
the Company, it may be completed sometime after mid-2007.
The IPUC accepted a stipulation entered into between A vista Corp. and the IPUC Staff that sets forth a variety of conditions, which
would serve to segregate the Company s utility operations from the other businesses conducted by the holding company. The
stipulation would require A vista Corp. to maintain certain common equity levels as part of its capital structure. A vista Corp. has
committed to increase its actual utility common equity component to 35 percent by the end of 2007 and 38 percent by the end of 2008,
which is consistent with provisions of the Company s Washington general rate case implemented on January 1 2006. The calculation
of the utility equity component is essentially the ratio of A vista Corp.' s total common equity to total capitalization excluding, in each
case, Avista Corp.'s investment in Avista Capital. In addition, IPUC approval would be required for any dividend from Avista Corp.
to the holding company that would reduce utility common equity below 25 percent of total capitalization which, for this purpose
includes long and short-term debt, capitalized lease obligations and preferred and common equity.
In January 2007, Avista Corp. entered into a similar stipulation with the WUTC staff. As of February 26, 2007, the stipulation is
subject to approval by the WUTC. The stipulation would require A vista Corp. to increase its actual utility common equity component
to 40 percent by June 30, 2008. In addition, WUTC approval would be required for any dividend from A vista Corp. to the holding
company that would reduce utility common equity below 30 percent of total capitalization.
Pursuant to the Plan of Share Exchange, a statutory share exchange would be effected whereby each outstanding share of Avista Corp.
common stock would be exchanged for one share of A V A common stock, no par value, so that holders of A vista Corp. common stock
would become holders of A V A common stock and A vista Corp. would become a subsidiary of A V A. The other outstanding securities
of Avista Corp. would not be affected by the statutory share exchange, with limited exceptions for stock options and other securities
outstanding under equity compensation and employee benefit plans.
IFERC FORM NO.1 (ED. 12-88) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE 25. INFORMATION SERVICES CONTRACTS
The Company has infonnation services contracts that expire between 2007 and 2012. Total payments under these contracts were $12.
million in 2006, $12.8 million in 2005 and $12.8 million in 2004. The majority of these costs are included in operation expenses in the
Statements of Income. Minimum contractual obligations under the Company s information services contracts are $12.2 million in
2007, $12.6 million in 2008, $13.0 million in 2009, $13.4 million in 2010, $13.8 million in 2011 and $14.2 million in 2012. The most
significant of these contracts provides for increases due to changes in the cost of living index and further provides flexibility in the
annual obligation from year-to-year subject to a three-year true-up cycle.
NOTE 26. DISPOSITION OF SOUTH LAKE TAHOE PROPERTIES
In April 2005, A vista Corp. completed the sale of its South Lake Tahoe, California natural gas properties to Southwest Gas
Corporation as part of Avista Corp.'s strategy to focus on its business in the northwestern United States. This was the Company s only
regulated utility operation in California. The cash proceeds received during 2005 were approximately $16.6 million. The total pre-tax
gain for 2005 was $4.1 million related to the Company s disposition of its South Lake Tahoe natural gas properties. Total revenues for
2004 from the South Lake Tahoe region were approximately $20.3 million (or 6 percent of total natural gas revenues) and
approximately 22.1 million therms (or 4 percent of total thenns) were delivered to South Lake Tahoe customers.
NOTE 27. SUPPLEMENTAL CASH FLOW INFORMATION
Other Cash Flows from Operating Activities:
Power and natural gas deferrals
Change in special deposits
Change in other current assets
Non-cash stock compensation
ESOP Dividends
2006 2005
$94 827,987 $81 029,276
$63 361 034 $26,405,411
$( 6,497 199)$(7,451 146)
366,143 $(3 235 855)
$( I ,405 ,850)$(1 167 585)
744 610
$415 596 $37 791
Cash paid for interest
Cash paid for income taxes
IFERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/Q4
(2)D A Resubmisslon 04/18/2007
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AI' D HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges , report the accounts affected and the related amounts in a footnote.
Line Item Unrealized Gains and Minimum Pension Foreign Currency Other
No.Losses on Available-Liability adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a)(b)(c)(d)(e)
1 Balance of Account 219 at Beginning of
Preceding Year 944 388)
2 Preceding QtrlYr to Date Reclassifications
from Acct 219 to Net Income
3 Preceding QuarterlYear to Date Changes in
Fair Value 63,702)681,415)1,407,305
4 Total (lines 2 and 3)702)681,415)1,407 305
5 Balance of Account 219 at End of
Preceding QuarterlYear 63,702)625 803)1,407 305
6 Balance of Account 219 at Beginning of
Current Year 63,702)19,625,803)407 305
7 Current QtrlYr to Date Reclassifications
from Acct 219 to Net Income 309
8 Current QuarterlYear to Date Changes in
Fair Value 16,607)644 702 38,746)
9 Total (lines 7 and 8)63,702 644 702 38,746)
Balance of Account 219 at End of Current
QuarterlY ear 15,981,101)368,559
FERC FORM NO.1 (NEW 06-02)Page 122a
Name of Respondent This ~ort Is: Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr) End of 2006/04Avista Corporation (2) A Resubmission 04/18/2007
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, A D HEDGING ACTIVITIES
Other Cash Flow Other Cash Flow Totals for each Net Income (Carried Total
Line Hedges Hedges category of items Forward from Com prehensive
No.Interest Rate Swaps Energy Commodity Derivatives recorded in Page 117, Line 78)Income
Account 219
(f)
(g)
(h)(i)
213,530)157,918)
889,250)667 900)557,150)
517,227 236,505 2,415 920
372 023)568 605 141,230)
585,553)568,605 299,148)
585,553)568,605 299 148)
429 700 546,000)964 009
809,492 029,287)369,554
239 192 575 287)333,563
346 361)682)965 585)
FERC FORM NO.1 (NEW 06-02)Page 122b
IS ~o s: a e 0 epo(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2007
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 (specify) and in
column (f) common function.
End of
(a)
Total Company for the
Current Year/Quarter Ended
(b)
Electric
(c)
Line
No.
Classification
1 Utility Plant
2 In Service
3 Plant in Service (Classified)
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7)
9 Leased to Others
910,719 671
525,291
282 217 637
916,244,962 282 217 637
10 Held for Future Use
11 Construction Work in Progress
12 Acquisition Adjustments
13 Total Utility Plant (8 thru 12)
14 Accum Prov for Depr, Amort, & Depl
15 Net Utility Plant (13 less 14)
16 Detail of Accum Prov for Depr, Amort & Depl
17 In Service:
177 799
211 433
027 634 194
024 356 307
003 277 887
081 096
358 298 733
778 218 995
580,079 738
18 Depreciation
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility 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 26,30,32)
158,560
024 356 307 778,218,995
FERC FORM NO.1 (ED. 12-89)Page 200
Gas
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Specify) Other (Specify) Other (Specify)
Year/Period of Report
End of 2006/04
Name of Respondent
A vista Corporation
Common
(d)(e)(f)
(g)
(h)
Line
No.
539,273,194
619,845
89,228,840
905,446
540 893 039 134 286
6,476 151
211 433
569 580,623
222 788,960
346 791 663
620,552
754,838
23,348 352
76,406,486
17,158 560
222 788,960 23,348,352
FERC FORM NO.1 (ED. 12-89)Page 201
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
ELECTRI PLANT IN SERVICE (Account 101,102,103 and 106)
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101 , Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount
of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)me ccount a ance ItlonsNo Beginning of Year
1 1. INTANGIBLE PLANT
(301) Organization
(302) Franchises and Consents
4 (303) Miscellaneous Intangible Plant
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights
9 (311) Structures and Improvements
10 (312) Boiler Plant Equipment
11 (313) Engines and Engine-Driven Generators
12 (314) Turbogenerator Units
13 (315) Accessory Electric Equipment
14 (316) Misc. Power Plant Equipment
15 (317) Asset Retirement 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 Ri hts
19 (321) Structures and Improvements
20 (322) Reactor Plant Equipment
21 (323) Turbogenerator Units
22 (324) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights
28 (331) Structures and Improvements
29 (332) Reservoirs, Dams, and Waterwa s
30 (333) Water Wheels, Turbines, and Generators
31 (334) Accessory Electric Equipment
32 (335) Misc. Power Plant Equipment
33 (336) Roads, Railroads, and Bridges
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
36 D. Other Production Plant
37 (340) Land and Land Rights
38 (341) Structures and Improvements
39 (342) Fuel Holders, Products, and Accessories
40 (343) Prime Movers
41 (344) Generators
42 (345) Accessory Electric Equipment
43 (346) Misc. Power Plant Equipment
44 (347) Asset Retirement Costs for Other Production
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)
240,599
124 502,424
160,467,185
127
745 044
li J""2:~:;~;~ c~iL'2J"BLib_;:o;i1;.':C" JL:J t.
: ;;,
2:,
;,,
, L:0 ,
':.;::"
i" ,:E, L- ..-.
45,206,481
686 829
15,081 529
248 795
373 433 842
973 990
574 903
149 791
5,454 855
12:1"2" '.iLi;:~ii~:2;G2lij;G,_i:j. : L:,:2.:":::ij:t:,:U.l0CL.xL:.
547 780 961,084
112 827 921 156
107,711 308 256,762
101,738,539 213,756
27,425 119 049 712
187 084 186,843
999,562
336 722 219 589,313
877 556
15,839,243 376 031
676,364 611,571
876 780
201 148,786 520,307
331 960 358 070
279,851 903
351,682
278 382 222 887 882
988 538,283 156 286
FERC FORM NO.1 (REV. 12-05)Page 204
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 04/18/2007
ELECTRIC PLANT IN SERVICE (Account 101 , 102, 103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within u1i1ity plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
Line(d) (e) (f) End ?~)Year No.
15,259,132
919 882 4,420,269
919,882 19,679,401
388 238,211
608 124 511 943
164 154 162,048,075
446 47,085,025
26,261,732
15,231 320
248 795
263 596 378,625,101
55,508,864
732 023,251
107 968 070
498 101 869 797
737 322 737,509
373,927
999,562
830 552 340 480,980
562 903,118
15,463,212
362 064,431
876,780
819,944 196,808,535
528 962 362
257 948
351 682
806,272 272 688 068
900,420 991 794,149
FERC FORM NO.1 (REV. 12-05)Page 205
Name of Respondent
Avista Corporation
No.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)ccount a anceBeginning of Year
(b)
Year/Period of Report
End of 2006/04
(a)
12,637 995
024,748
151,745,191
069,239
674 962
709,107
561 148
317 910
826,844
358,910
763 409
234,161
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights
49 (352) Structures and Improvements
50 (353) Station Equipment
51 (354) Towers and Fixtures
52 (355) Poles and Fixtures
53 (356) Overhead Conductors and Devices
54 (357) Underground Conduit
55 (358) Under round Conductors and Devices
56 (359) Roads and Trails
57 (359.1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights
61 (361) Structures and Improvements
62 (362) Station Equipment
63 (363) Storage Battery Equipment
64 (364) Poles, Towers, and Fixtures
65 (365) Overhead Conductors and Devices
66 (366) Underground Conduit
67 (367) Under round Conductors and Devices
68 (368) Line Transformers
69 (369) Services
70 (370) Meters
71 (371) Installations on Customer Premises
72 (372) Leased Property on Customer Premises
73 (373) Street Lighting and Signal Systems
74 (374) Asset Retirement Costs for Distribution Plant
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380) Land and Land Rights
78 (381) Structures and Improvements
79 (382) Computer Hardware
80 (383) Computer Software
81 (384) Communication Equipment
82 (385) Miscellaneous Regional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Regional Transmission and Market Oper
84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Rights
87 (390) Structures and Improvements
88 (391) Office Furniture and Equipment
89 (392) Transportation Equipment
90 (393) Stores Equipment
91 (394) Tools, Shop and Garage Equipment
92 (395) Laborato Equipment
93 (396) Power Operated Equipment
94 (397) Communication Equipment
95 (398) Miscellaneous Equipment
96 SUBTOTAL (Enter Total of lines 86 thru 95)
97 (399) Other Tangible Property
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98)
100 TOTAL (Accounts 101 and 106)
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)
3,477,396
229 365
~'id0J',
;:.
iLL~IL;:",i(.' .'':If:'LG'
.''
2~.LLS.
~,,
369,567 144 063 241
733,870
293,760 145,702
75,678 724 112 655
168 158,120 727 798
111,618 142 362 079
575,675 399,604
91 ,482 128 7,491,583
130,800,987 10,084,786
378 905 554 971
563 129 066 724
23,217 022 599 687
129,707
790,630 169 47,545 589
124 681
973,263
144 700
246 105
100,196
763 698
047 737
18,356 584
660,654
702
60,419 320
293
284
149 503
365
363,914
317 763
724 258
299
657 679
60,419,320
236,269 987
657 679
907 007
236 269,987 907 007
FERC FORM NO.1 (REV. 12-05)Page 206
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 04/18/2007
ELECTRIC PLANT IN SERVICE (Account 101 , 102, 103 and 106) (Continued)
Line
End ~f Year No.(d) (e) (f) 971 12 994 934
13,788 157
668,549 160 310 803
069,239
489 775 101 662 583
646,345 74,292,127
561 148
317 910
826 844
806,640 383,823,745
733,825
193 665 10,245,797
647 339 144,040
447,952 175,437,966
312 278 115,667 943
933 887 346
702 047 98,271,664
1,423 953 139,461 820
142,244 791 632
906 944 23,722 909
217 118 599 591
129 707
081,518 832 094 240
124 681
038 042 518
383 136,601
119,856 275 752
120,561
139,247 988 365
064 039,673
674 347
312 16,264 28,330,864
973
355,928 264 737 335
355,928 264 737 335
064 388 16,264 292 128,870 100
101
102
103
18,064 388 264 292 128 870 104
FERC FORM NO.1 (REV. 12-05)Page 207
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 04/18/2007
CONSTRUCTION WORK IN PROGRESS -. ELEC TRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
State of Washington
Spokane Elec NW Inc 155,514
Wood Pole Management 481,165
Boulder-Construction 327,339
Sys Wood Sub reb 351,477
Transportation Equipment 552 186
Rockford 24kv sub-convert to 13 kv sub 114 796
Barker 12F1 Reconductor along Appleway 106 504
Post St Eas NW Upgrade Fdrs 338,401
Spokane Airport-Increase distrib system capacity 239,302
Minor Projects (120) under $100,000 521 754
State of Idaho
Electric Revenue Blanket 177 663
Electric Distribution Minor Blanket 299,116
Wood Pole Management 212 559
Benewah-Shawnee 230kv const 037,465
Sagle 115 Sub 482 564
Pleasant View 241 Recon & Ext 210 930
Avondale 115 Sub 927,494
Huetter 141-extend feeder 1.1 miles on Mullan 169,034
Transportation Equipment 449 359
Minor Projects (88) Under $100 000 275,961
Common-WA&ID
Transmission Minor Rebuild 181 348
West of Hatwai Telecom 360,636
Benewah-Shawnee 230kv const 20,575,135
Boulder Construct 760 888
Sys Wood Sub Reb 156,761
System Rplc HV OCB 149,088
Sagle 115 Sub 223 558
Avondale 115 Sub 310 525
Critchfield 115 Sub -Construct 113 872
Cabinet Gorge Cap 104,527
Noxon Capital Project 082 977
System Battery Rep 155,423
Control Network 206 209
Cabinet Gorge Unit #4 Runner Replacement 600 100
TOTAL 081 096
FERC FORM NO.1 (ED. 12-87)Page 216
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2) CiA Resubmission 04/18/2007
CONSTRUCTION WORK IN PROGRESS - - ELE( TRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100 000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
Noxon Unit #4 Runner Upgrade 684,722
Clark Fork Implement PME Agreement 303 060
Hydro Relicensing 17,403,112
Beacon Bell # 5 Reconcductor 745 399
Lolo 230 rebuild 230kv yard 195 717
Little Falls Capital Project 154,401
Trans/Distr/sub Reimbursable Projects 201 605
Bronx-Cabinet 115 relocate Pack River 186 853
Minor Projects (145)under $100,000 794 597
Common WA/iD/OR
TOTAL 76,081 096
FERC FORM NO.1 (ED. 12-87)Page 216.
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11 , column (c), and that reported for
electric plant in seNice, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from seNice. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reseNe 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.
Ine
No.
-;242M:4
(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 Accounts (Specify, details in footnote):
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
58,718 927 58,718 927
L~;'2frii~li,ITilii,81!;.
~",~j\
ill
13 Cost of Removal
14 Salvage (Credit)
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
10,030,144
562 777
171,040
421 881
030 144
562 777
171 040
10,421 881
16 Other Debit or Cr. Items (Describe, details in
footnote):
. 939,?22
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1
10,15, 16, and 18)
771 231 596 771,231 596
Section B. Balances at End of Year According to Functional Classification
20 Steam Production
21 Nuclear Production
223,287 652 223 287 652
097 867 097 867
36,139 145 36,139 145
136 875,953 136 875,953
256 150 345 256 150 345
39,680,634 39,680 634
22 Hydraulic Production-Conventional
23 Hydraulic Production-Pumped Storage
24 Other Production
25 Transmission
26 Distribution
27 Regional Transmission and Market Operation
28 General
FERC FORM NO.1 (REV. 12-05)Page 219
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11 , column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
No.
lIem
(a)
Section A. Balances and Changes During Year
I ata!\~lecAnc I;"'lam Inc+o+e ~ervlce(b) (c)
~Iecmc t'lam, !1elcfor Future Use
(d)
~lecInc, lA'ilmLeased to uthers
(e)
29 TOTAL (Enter Total of lines 20 thru 28)771 231 596 771 231,596
FERC FORM NO.1 (REV. 12-05)Page 219
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation
(1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 04/18/2007
INVESTM NTS IN SUBSIDIARY COMPANIES Account 123.
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub. TOTAL by company and give a TOTAL
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition.The TOTAL in column (e) should equal the amount entered for
Account 418.1.
Ine DeSCription of Investment Date Acquired Date Of Amount of Investment at
No.(b)Mity
Beginning of Year(a)(d)
2 Avista Capital - Common Stock 1997 184,251 609
3 Avista Capital - Equity in Earnings 827,604
4 OCllnvestment in Subs 658 585
Total Cost of Account 123.1 $TOTAL 237 737 798
FERC FORM NO.1 (ED. 12-89)Page 224
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)
End of 2006/04(2)DA Resubmission 04/18/2007
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible
in column (t).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.
EqUIty In Subsidiary Revenues tor Year Amount of Investment at Gain or Loss from Investment LineEarnin~s of Year End ~f Year DiSp?~)ed of No.(f)
184 251,609
' ,
16,738 728 989 256 61,577 075
1;296 708 1 ,361 ,877
15,442 020 989 256 247 190,561
FERC FORM NO.1 (ED. 12-89)Page 225
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2006/04(2)0 A Resubmission 04/18/2007 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 acceptable. In column (d), designate the department or departments which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
Line Account Balance Balance Department or
No.Beginning of Year End of Year Departments which
Use Material(a)(b)(c)(d)
Fuel Stock (Account 151)773 050 121 931
" ,
(i) "
:' """ ,
Fuel Stock Expenses Undistributed (Account 152)
Residuals and Extracted Products (Account 153)
Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)979,873 606,317 1,11),
':"
,"i
,:,,,
6 Assigned to - Operations and Maintenance
Production Plant (Estimated)781 870 1 ,766 365 (1). "
" '
8 Transmission Plant (Estimated)596 21,529 (1)
Distribution Plant (Estimated)227 971 233,483 (1) "
" "" '
Regional Transmission and Market Operation Plant (1),(2),
(Estimated)
Assigned to - Other (provide details in footnote)004 119 391 376 (1),(2):'
:"'
i',
" ", "
TOTAL Account 154 (Enter Total of lines 5 thru 11)006,429 019,070
Merchandise (Account 155)
Other Materials and Supplies (Account 156)
Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
Stores Expense Undistributed (Account 163)
TOTAL Materials and Supplies (Per Balance Sheet)779,479 141 001
FERC FORM NO.(REV. 12-05)Page 227
Name of Respondent
A vista Corporation
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report
(1) An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2007
Transmission Service and Generation Interconnection Study Costs
1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. In column (a) provide the name of the study.
4. In column (b) report the cost incurred to perform the study at the end of period.
5. In column (c) report the account charged with the cost of the study.
6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
7. In column (e) report the account credited with the reimbursement received for performing the study.
No.Description
(a)
Transmission Studies
2CeritennialPower
21 Generation Studies
Costs Incurred During
Period
(b)
Account Charged
(c)
elm ursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
83 186200
919 186200
30,000 235400
000 235400
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07)Page 231
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation
(1) An OriQinal (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 04/18/2007
0 HER REGULATORY ASSETS (Account 182.
1. Report below the particulars (details) called for conc~rning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $50 000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of vvrmen 011 uunng vvrmen 011 uunng Current Quarter/Year
Current the Quarter/Year the Period
Quarter/Year Account Charged Amount
(a)(b)(c)(d)(e)(f)
FAS 106 - Post Retirement Benefits (182300)309 264 926400 472 752 836 512
Amortization period is 1996-2012
FAS 158 - Post Retirement Liability (182305)192 195 54,192 195
FAS 109 (182310 & 182320)114 390,454 283170/180 201 214 106,189,240
Idaho AMR (182330)8,404 214 669,175 16,073,389
RTO Deposit - Grid West (182340)354 029 354 029
BPA Residential Exchange (182345 & 182346)454 297 923 979 378,276
WA ERM Deferral (182350)052 195 557290/419 824 960 70,227 235
WA Amortization (182360)342 601 557162/419 342 601
New Generation Installation (182370)368,472 407370 164236 184,236
Wartsilla Units (182372)271 705 378,424 407380 153 132 496 997
Mark-To-Market Short-Term (182374)650 144 650 144
FAS 143 - ARO (182376)968 560 323 434 291,994
OR DSM Lost Margin (182380)( 1 131 560)Various 341 297 472,857
Workers Compensation (182383)199,404 225,159 2,424 563
CS2 Levelized Return (182384)619 155 371 328 990,483
TOTAL 225 248 761 130 087 867 31,520 192 323,816,436
FERC FORM NO. 1/3-0 (REV. 02-04)Page 232
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 2006/04
(2) Fi A Resubmission 04/18/2007
MISCELLANEOUS DEFFERED DEBITS (Account 186)
1. Report below the particulars (details) called for conc~rning 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 $50,000, whichever is less) may be grouped by
classes.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~ccoum Amount End of YearChar~ed
(a)(b)(c)(e)(f)
Colstrip Common Fac.110,999 406 110 999
W A Deferred Power Costs 138 618 206,864 68,246
WA ERM YTD Company Band 000,000 398,336 601 664
W A ERM YTD Contra Account 000 000 398,336 601,664
Regulatory Asset ROT Deposit 711 960 711 960
Colstrip Common Fac.355,642 406 355 642
ID Deferred Power 90,403,623 019 274 VAR 96,422 897
ID Accumulated Surcharge Am 82,416 882 557 648 736 87,065,618
Payroll Accrual 938 970 VAR 39,262 899,708
Payroll Loading Clearing 290,803 290,803
Plant Allocation of clrg jrls 025,687 025,687
Misc Error Suspense 765 VAR 274,577 180,812
Unamortized AIR Sale 937 750 187
Intangible Pension Asset 4,404 832 4,404 832
Nez Perce Settlement 197 233 557 212 192,021
Misc Deferred Debit Centralia 596 927 576 623 503
Centralia Mine Env Balance
Opportunity Sub Sale Proceeds 188,758 188 758
ID Panhandle Forest Use Permit 153,881 730 182 611
Metro-Sunset 115KV TE 309 756 242 312,998
Incremental trans costs 129 374 107 383 236
UPRR Permit Conv 331 696 1,412 333,108
Insurance Recvy CDA Lake 118,287 803 145,090
Corp reorg stk iss. costs 118 086 118 086
Nez Perce Permit Conversion 108 211 454 237 562 448
Misc Work Orders 0::$50 000 150,111 111 155 956
Subsidiary Billings 109,613 615 273 VAR 724 886
Null' Projects directly to 186 208,472 587 250 378,778
Misc. Work in Progress
I Deterred Regulatory Comm.
Expenses (See pages 350 - 351)
TOTAL 675,589 297 127
FERC FORM NO.1 (ED. 12-94)Page 233
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmisslon 04/18/2007
MISCELLANEOUS DEFFERED DEBITS (Account 186)
1. Report below the particulars (details) called for conc~rning 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 $50,000, whichever is less) may be grouped by
classes.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~9coum Amount End of YearChar~ed
(a)(b)(c)(e)(f)
Conservation
Regulatory Assets Consv 124;643,280 293 844 350
Oregon Gas Comm Consvt 25,811 573 34,384
Oregon Common Gas Eff 357 732 703 412 435
WPNG HE Wtr Htrs-Oregon 522,183 046 572 229
WPNG HE Furnaces 388,705 447 692 836 397
WPNG OR Res Low 1 339,876 19,870 908 359 746
Oregon DSM 085 57,085
Consv. & Renewable Disco 644,618 908 644,618
Energy Star Homes 136 212 136 212
Energy Star Manufactored Homes 062 062
HE Washing Machines 55,312 312
Regulatory Assets Consv
' "
556.983 1 01 144 455,839
Regulatory Assets Consv " 1 ,456.849 336,413 120,436
Conservation Rate Credit 286 095 286,095
Conservation Rate Credit CRC 122,612 122 612
Hamilton Street Bridge Site 600 VAR 600
Easy Pay Billing CS 402 3,402
Lake CDA Issues 142,242 483 835 626 077
Shareholder Lawsuit 2002 214 468 746
NE Oil Spill Cleanup 748 675 748,675
Misc. Work in Progress
Deterred Regulatory (,;omm.
Expenses (See pages 350 - 351)
TOTAL 40,675,589 297 127
FERC FORM NO.1 (ED. 12-94)Page 233.
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2007
ACCUMULATED DEFERRED INCOME TAX S (Account 190)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
No.
ocatlon
(a)
Electric
10,500,018 13,452 219
Other
8 TOTAL Electric (Enter Total of lines 2 thru 7)
9 Gas
10,500 018 13,452,219
516 068 953,690
Other
TOTAL Gas (Enter Total of lines 10 thru 15
Other
TOTAL (Acct 190) (Total of lines 8,16 and 17)
516 068
631,314
647,400
953 690
40,196,406
55,602 315
Notes
FERC FORM NO.1 (ED. 12-88)Page 234
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 2006/04
(2)DA Resubmission 04/18/2007
CAPITAL STOCKS (Account 201 and 204)
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (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 authorized 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)
Account 201 - Common Stock Issued
No Par Value 200 000,000
Restricted shares
4 TOTAL COM 200,000,000
7 Account 204 - Preferred Stock Issued 000 000
Cumulative
TOTAL PRE 000,000
FERC FORM NO.1 (ED. 12-91)Page 250
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmlssion 04/18/2007
CAPITAL STOCKS (Account 201 and 204) (Continued)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT Line
(Total amount outstanding without reduction AS REACOUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
:Shares Amount :Sl'\ares ~9st :Sh?lreS Amount
(e)(f)
(g)
(h)(i)
550 506 722 039,406
' 36,180 771,358
52,550,506 722 039 406 18Q
", ,
771 3158
FERC FORM NO.1 (ED. 12-88)Page 251
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
CAPITAL STOCK EXPENSE (Account 214)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
ILine Class ana :series or :stoCK t:Salance at End of Year
No.(a)(b)
1 Common Stock - Public Issue 085,094
$6.95 Preferred Stock, Series K 334 005
22 TOTAL 419,099
FERC FORM NO.1 (ED. 12-87)Page 254b
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 2006/04
(2)D A Resubmission 04/18/2007
LONG-TERM DEBT (Account 221 222,223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221 , Bonds , 222
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation , such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission s authorization of treatment other than as
specified by the Uniform System of Accounts.
Line 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 Ace!. 221 - Bonds:
2 Secured Medium Term Notes $1,185 000,000 023,850,000 10,794 892
3 Discount 320 700
(Premium)266,500
Pollution Control Revenue Bonds:
6% Series due 2023 100 000 115,355
Colstrip 1999A due 2032 66,700 000 700 581
Discount 20,500
Colstrip 1999B due 2034 000 000 954,386
SUBTOTAL 111 650,000 639 914
Acc!. 222 - Reacquired Bonds
Acc!. 223 - Advances from Associated Companies-A. Advantage $1 ,200k; A. Energy $60 800,000
Long Term Debt to Affiliated Trusts-AVA Capital Trust III 856 000 658,634
Long Term Debt to Affiliated Trusts-Avista Capital II 51,547 000 633,783
Ace!. 224 - Other Long-term Debt
Series K Preferred Stock 000 000 089 391
Notes Payable - Banks (local) $320 000,000 2,406 216
Commercial Paper
Unsecured Senior Notes 400 000 000 128 000
(Discount)716 000
Medium Term Notes $1,000 000 000 683,000,000 700,797
TOTAL 344 853,000 39,972 735
FERC FORM NO.1 (ED. 12-96)Page 256
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation
(1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
LONG-TERM DEBT (Account 221,222 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429 , Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427 , interest on
Long-Term Debt and Account 430 , Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD Ul!ISlan!Jln Line
Nominal 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?Mdent)
(i)
597 396 931 339 181
12/18/1984 12/01/2023 12/18/1984 12/01/2023 100 000 246 000
9/01/1999 10/01/2032 9/01/1999 10/01/2032 700 000 335,000
9/01/1999 3/01/2034 9/01/1999 3/01/2034 17,000 000 871,250
685,196 931 791 431
800 000
4/5/2004 4/1/2034 4/30/2004 3/31/2034 856 000 020,640
6/3/1997 6/1/2037 6/30/1997 5/31/2037 547 000 095,789
9/15/1992 9/15/2007 9/15/1992 9/15/2007 26,250,000 915,594
12/17/2004 3/15/2011 12/13/2004 3/15/2001 000,000 704 788
4/03/2001 6/01/2008 4/03/2001 6/01/2008 273,350,402 949 853
1/22/1992 1/22/2007 2/1/1992 2/1/2007 12,000 000 576,884
116,000,333 054 979
FERC FORM NO.1 (ED. 12-96)Page 257
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation
(1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
RECONCILIATION OF REP( RTED NET INCOME WITH TAXABL INCOME FOR FEDERAL INCOME TAXES
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a
separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group
member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of
the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
I LIne I-'artlculars (LJetalls)Amount
No.(a)(b)
1 Net Income for the Year (Page 117)
Taxable Income Not Reported on Books
826,100
9 Deductions Recorded on Books Not Deducted for Return
;;~3 64p,41~,
Federal Income Tax 207 698
Deferred Income Tax 995,071
Investment Tax Credit & State Income Tax 106,662
Income Recorded on Books Not Included in Return
56;61'7;126
Equity in Sub Earnings (Income) / Loss 16,839,461
Corporate Overhead Unallocated Subs 606 646
Deductions on Return Not Charged Against Book Income
, -11 0 167,057
Federal Tax Net Income
Show Computation of Tax:
Federal Tax Net Income 137,140 918
State Tax ig) 2%, Less Idaho ITC 063,970
Federal Tax Net Income, Less State Tax 135,076 947
Federal Tax ig) 35%($135,076,947' 35%)276,931
2005 1 O-k & Mixed Service Cost Adj.225,061
2006 Mixed Service Cost Adj.539,814
Prior Years Tax Return, Revenue Agent Report & Misc True-ups 183 093
Kettle Falls Tax Credit 200 894
Total Federal Tax Expense (agrees to line 11)39,207 697
FERC FORM NO.1 (ED. 12-96)Page 261
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 2006/04
(2)D A Resubmission 04/18/2007
TAXES ACCRUED, PREPAID AND CHA GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
ILlne Kind of Tax BALANCE AT BEGINNING OF YEAR
~.b~xes ~~ras Adjust-C argedNo.(See instruction 5)"(axes Accruep ~repai.d Taxes ~nng ~ring ments(Account 236)(Include In Account 165)ear ear(a)(b)(c)(d)(e)(f)
1 FEDERAL:
2 Income Tax (2003)298,448 298 448
3 Income Tax (2004)25,750,020 1,472 305 253 958
4 Income Tax (2005)619,962 486,674 841 089
5 Income Tax (2006)51,427,073 345 130
6 Unemployment Ins 2003
7 FICA (2006)858 817 193,094 334,277
8 Retained Earnings (2004)1,463,362
9 Retained Earnings (2005)386 815
Retained Earnings (2006)618,425
Total Federal 921 711 708,486 55,538 224 622 960
STATE OF WASHINGTON:
Property Tax (2003)023 023
Property Tax (2004)26,741 26,741
Property Tax (2005)10,279,127 977 904 242 311
Property Tax (2006)152 000
Excise Tax (2002)202 688 202 688
Excise Tax (2004)40,060 204,464 164,404
Excise Tax (2005)560 432 100,595 269,952
Excise Tax (2006)20,766,337 909 992
Natural Gas Use Tax 877 736 128 907
Muni Utility & Occupation Tax 2,470,945 775 855 601 315
Sales & Use Tax (2005)40,333 697 173
Sales & Use Tax (2006)043,048 956 747
Motor Vehicle (2006)817 817
Total Washington 15,475,958 50,779,788 378,142 173
STATE OF IDAHO:
Income Tax (1997-2000)343 399 343 399
Income Tax (2001)080 088 102 358 22,269
Income Tax (2002)470 075 209,108 260 967
Income Tax (2003)191 571 839 219,410
Income Tax (2004)501 348 849
Income Tax (2005)116 763 258 235 35,689 522 495
Income Tax (2006)815 653 961 000
Property Tax (2005)603,487 593 774
Property Tax (2006)355 208 678 097
Excise Tax (2004)142 142
Motor Vehicle Ins. (2006)941 941
TOTAL 112 797 121,414 718 131 812 045 622 960
FERC FORM NO.1 (ED. 12-96)Page 262
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 04/18/2007
TAXES ACCRUED, PREPAID AND CHARGED DU ING 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.
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items AOjUstments to He!.Other No.Acco~nt 236)(Incl. in Account 165)(Account 408., 409.(Account 409.Earnings (Account 439)
(h)(i)(k)(I)
30,476,283 472 305
734 453 353,506 133 168
081 943 36,704 095 722 978
858,817
463 362
386,815
618,425 618 425
128,489 28,350,589 357 897
019
595 147
913 745,000 232 904
10,152,000 896,000 256 000
202 688
40,769 245 233
189,884 26,038 557
856,345 13,143,449 622 888
706 743 993
645,486 260 508 515 348
141,202
86,301 043,045
817
868 433 510,484 269 303
343 399
102 358
839
348
345 334 258,235
145 347 571 847 243,806
691
677 111 768 000 587,208
142
941
887 161 700,334 714 387
FERC FORM NO.1 (ED. 12-96)Page 263
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
TAXES ACCRUED, PREPAID AND CHAF GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Ine Kind of Tax BALANCE AT BEGINNING OF YEAR
::1~xes ~~1a'Adjust-C argedNo.(See instruction 5)1axes Accru~f:I "'Prepai,d Taxes ~rlng ~ring ments(Account 236)(Include In Account 165)ear ear(a)(b)(c)(d)(e)(f)
1 Sales & Use Tax (2005)666 084 173
2 Sales & Use Tax (2006)223,991 206 023
Irrigation Credits (2002)333 333
Irrigation Credits (2003)333 332
Irrigation Credits (2004)
Irrigation Credits (2005)155 155
7 Irrigation Credits (2006)
8 KWH Tax (2004)
9 KWH Tax (2005)094 004
KWH Tax (2006)368 491 343,828
Franchise Tax (2003)
Franchise Tax (2004)
Franchise Tax (2005)357 511 357 510
Franchise Tax (2006)808,938 244 071
Totalldaho 013 866 131 802 660,129 173
STATE OF MONTANA:
Income Tax (1996-2000)184 932 184 932
Income Tax (2001)415,419 676 617 261 198
Income Tax (2002)496 496
Income Tax (2003)134 687 125 102 232 823 223 238
Income Tax (2004)196 156 335 165 531
Income Tax (2005)503 508 106 823 157 723 227 987
Income Tax (2006)797 694 856 000
Property Tax (2000)384 384
Property Tax (2001)166,988 166 988
Property Tax (2002)468 132 520 166 988
Property Tax (2003)572 572
Property Tax (2004)994 994
Property Tax (2005)641 973 31,447 641 973
Property Tax (2006)960,973 983 792
Colstrip Generation Tax 667 667
KWH Tax (2004)81,483 81,484
KWH Tax (2005)258,214 256,938
KWH Tax (2006)165,439 903,532
Motor Vehicle (2006)545 545
Consumer Council Tax 452
Public Commission Tax 790 288
Total Montana 313 807 7,418 884 051 303
TOTAL 112 797 121,414 718 131 812 045 622 960
FERC FORM NO.1 (ED. 12-96)Page 262.
Name of Respondent This (!Jort Is:Date of Report Year/Period of Report
Avista Corporation
(1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
TAXES ACCRUED, PREPAID AND CHARGED DU ING 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.
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items , AdjUstments to ReI.Other No.Acco~nt 236)(Incl. in Account 165)(Account 408., 409.(Account 409.Earnings (Account 439)
(h)(i)(k)(I)
423
968 223,991
333
332
155
779 315
663 373 656 165
564 867 192,415 616,522
494,711 921,434 210 367
184 932
676 617
125,102
156,335
466,950 106,823
58,306 500,022 297,672
384
132 520
572
993
447 312 31,135
977 181 960 973
667
81,484
276 780 780
261 908 165,439
545
431 452
503 10,463 328
681 391 670,439 251 553
887 161 700,334 714 387
FERC FORM NO.1 (ED. 12-96)Page 263.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2)D A Resubmission 04/18/2007
TAXES ACCRUED, PREPAID AND CHA GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
I,-me Kind of Tax BALANCE AT BEGINNING OF YEAR ).b~xes
~~&
Adjust-C argedNo.(See instruction 5)1axes Accruep Prepatd Taxes ~nng ~ring ments(Account 236)(Include In Account 165)ear ear(a)(b)(c)(d)(e)(f)
1 STATE OF OREGON:
2 Income Tax (1999 & Older)75,700 75,700
3 Income Tax (2000)621 55,621
4 Income Tax (2001)298 330 148 595 149,735
5 Income Tax (2002)121 729 254 129 375 858
6 Income Tax (2003)501 861 360
7 Income Tax (2004)144,455 785 - 73 670
8 Income Tax (2005)357 135 043 313 153
9 Income Tax (2006)405 202 368,000
Property Tax (2003)
Property Tax (2004)273 273
Property Tax (2005)475 874 158 767 156,533
Property Tax (2006)315 695 524 642
Motor Vehicle (2006)4,413 4,413
Busn Energy Tax Credit 431 020
Busn Energy Tax Credit 244
Busn Energy Tax Credit -55 790
Busn Energy Tax Credit 865
Busn Energy Tax Credit 059 70,333
Busn Energy Tax Credit 164 041 196,186
Busn Energy Tax Credit 104,808
Franchise Tax (2004)261 094
Franchise Tax (2005)128 382 198 063,999
Franchise Tax (2006)158 085 019 571
Total Oregon 980 400 174 137 158
STATE OF CALIFORNIA:
Income Tax (1996-2000)448 55,448
Income Tax (2001)850 684 834
Income Tax (2002)9,402 402
Income Tax (2003)33,400 225 625
Income Tax (2004)326 051 275
Income Tax (2005)137 098 924 886
Income Tax (2006)200
Property Tax (2004)
Property Tax (2005)
Total California 063 138 33,124
MISCELLANEOUS STATES:
Income Tax (2004 and older)057 057
TOTAL 112,797 121,414 718 131 812 045 622 960
FERC FORM NO.1 (ED. 12-96)Page 262.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/Q4
(2) CiA Resubmission 04/18/2007
TAXES ACCRUED, PREPAID AND CHARGED DU ,ING 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.
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items AdjUstments to He!.Other No.Acco~nt 236)(Incl. in Account 165)(Account 408., 409.(Account 409.Earnings (Account 439)
(h)(i)(k)(I)
75,700
55,621
148,595
254 129
861
70,785
264,467 135,042
202 100 894 304 308
273
473,640 158 767
208,947 315,695
4,413
431 020
244
790
865
274 333
145 196 186
104 808 104 808
168 094
185 198
138 514 158 086
213 035 247,388 152 788
448
75,684
25,225
051
000 098
200
200 138
058
887 161 700 334 46,714 387
FERC FORM NO.1 (ED. 12-96)Page 263.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 04/18/2007
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Kind of Tax BALANCE AT BEGINNING OF YEAR ~1~xes ~~ras Adjust-C argedNo.(See instruction 5)'(axes AccruE;!q F'repatd Taxes ~nng ~ring ments(Account 236)(Include In Account 165)ear ear(a)(b)(c)(d)(e)(f)
Income Tax (2005)
Income Tax (2006)096 058
Total Misc States 095 153 058
5 COUNTY & MUNICIPAL
6 Forrest Fire Protection
7 Greenacres Irrigation
8 City of Spokane PBIA 1,470 125 346
9 WA Renewable Energy 044
Spokane Utility Tax
Columbia Irrigation
Misc.175 738 11,561
Total County 295 569 11,907
TOTAL 112,797 121 414 718 131 812 045 622 960
FERC FORM NO.1 (ED. 12-96)Page 262.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
TAXES ACCRUED, PREPAID AND CHARGED DU ING 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.
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items AdjUstments to ReI.Other No.Acco~nt 236)(Incl. in Account 165)(Account 408.1, 409.(Account 409.Earnings (Account 439)
(h)(i)
(j)
(k)(I)
096
154
125
044 044
738
042 10,569
887 161 700,334 714 387
FERC FORM NO.(ED. 12-96)Page 263.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2)DA Resubmission 04/18/2007
ACCUMULA ED DEFERRED INVESTMENT TAX REDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
non utility operations. Explain by footnote any correction adjustments to the account balance shown in column (g). Include in column (i)
the average period over which the tax credits are amortized.
I,-me Account
No.SUbd~xjSiOnS
of Year Deferred for Year Current Year s Income Adjustments(b) ACCOUr:Jt No. Amount ACCOUnt NO. AmOUnt
( )
(c) (d) (e) (f)
1 Electric Utility
23%
34%
47%
510%
8 TOTAL
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
Gas Propertry (100%521 652 411400 30E
TOTAL PROPERTY 521 652 49,30E
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2) CiA Resubmission 04/18/2007
ACCUMULATED D FER RED INVESTMENT TAX CRED TS (Account 255) (continued)
ADJUSTMENT EXPLANATION Lineof Year of AI ocallon No.to Income
"'--
472 344
472 344
FERC FORM NO.1 (ED. 12-89)Page 267
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 04/18/2007
0 HER DEFFERED CREDITS (Account 253)
1. Report below the particulars (details) called for concerning 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 Account 253 or amounts less than $10 000, 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
Account(a)(b)(c)(d)(e)(f)
CSS Install & Interest (253000)419000 092 17,092
Deferred Revenue Prepayment -802 456/143/146 372 430
Pacific Walla Walla/Enterprise
Amort = 19 yrs (253080)
CIT Oper Lease (253090) 9/2006 29,457 931110 29,457
BPA C&RD Receipts (253100)319 061 Various 210 191 108,870
Trust Fund - Centralia (253110)913 437 186870 327 935 764
Rathdrum Refund (253120)476,332 550000 823 442 509
Amort =25 years, through 1/2020
NE Tank Spill (253130)000 000 552/186200 789,375 210,625
CS2 GE Long Term Service 938 883 232/154 938,883
Agreement (253150)
Supplemental Executive Retire 737,423 426290 845 324 892,099
Plan (SERP) (253290)
SERP - SFAS 158 Unfunded Various 772 012 772 012
Unfunded (253291)
Gain on Sale and leaseback 568 736 931900 261,456 307 280
of Building (Amortization period
is 25 years) (253850)
ID Clark Fork Relicense (253890)462 387 419000 218,831 681 218
Deferred Compensation 870,416 128/431 158 363 028 779
(253900, 253910, 253920)
Amort. Unbilled Revenue Add-ons 880 004 908/557/407 343,385 223,389
(253990)
TOTAL 304 164 336 712 313 179 280 631
FERC FORM NO.1 (ED. 12-94)Page 269
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
ACCUMULATE DEFFERED INCOME TAXES - OT ER PROPERTY (Account 282)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to property not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
Year/Period of Report
End of 2006/04
Line
No.
CHANGES DURING YEARAccountBalance at
Beginning of Year
(a)(b)
Amounts Debited
to Account 410.
(c)
Amounts Credited
to Account 411.
(d)
1 Account 282
2 Electric
3 Gas
4 Other
225,798 912
715,278
727,835
289,242 025
15,684 084
750,063
257 744
691,8915 TOTAL (Enter Total of lines 2 thru 4)
9 TOTAL Account 282 (Enter Total of lines 5 thru
10 Classification of TOTAL
289 242 025 20,691 891
11 Federal Income Tax
12 State Income Tax
280,628,857
613 168
19,163 783
528,108
13 Local Income Tax
NOTES
:ERC FORM NO.1 (ED. 12-96)Page 274
Name of Respondent
A vista Corporation
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
ACCUMULATED DEFERRED INCa E TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
Year/Period of Report
End of 2006/04
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.
Debits
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 275
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2007
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
Year/Period of Report
End of 2006/04
(a)
Balance at
Beginning of Year
(b)
Line
No.
Account
1 Account 283
2 Electric
Electric 564 581 -5,222 170 046,314
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
11 Gas
564 581 222 170 046,314
16,575 034 343,758
17 TOTAL Gas (Total of lines 11 thru 16)
18 Other
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)
20 Classification ofTOT AL
16,575 034
155,147 548
228 287 163
343 758
601 985
18,167 913 046 314
21 Federal Income Tax
22 State Income Tax
224 523 245
763,918
403 995
763 918
046 314
23 Local Income Tax
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
ACCUMULATED DEFERRED INCOME TAXES - OTHE (Account 283) (Continued
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
Name of Respondent
A vista Corporation
Year/Period of Report
End of 2006/04
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.
639,101 182320 836,673 190xxx 589 47,102 114
639 101 836,673 589 47,102 114
780,546 190xxx/2 667 792 679 614
780 546 667 792 679 614
802 731 190/182/502,785 182/219/967 268 156 207 315
2,419,647 802 731 12,339,458 638 649 211 989 043
2,419 647 802 731 339,458 638 649 211 989 043
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 277
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2) fiA Resubmission 04/18/2007
0 HER REGULATORY LIABILITIES (Account 254)
1. Report below the particulars (details) called for conc~rning other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $50 000 which ever is less),may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining DEBITS Balance at EndLineDescription and Purpose of of Current of CurrentNo.Other Regulatory Liabilities OuarterIYear Account Amount Credits QuarterlY earCredited
(a)(b)(c)(d)(e)(f)
Centralia Sale (254110)407 452 407410 2,407,452
2 FAS109-Acctg for Inc. Taxes (254180)280 908 190180 556 254,352
3 Nez Perce - Reg Liability (254220)836,420 557200 008 814,412
4 Senate Bill 408 . Oregon (254250)407330 300 000 300 000
5 BPA Residential Exch (254346 ED WA)32,406 182.34/407 406
6 BPA Residential Exch (254346 ED ID)367 182.34/407 367
7 OPUC Investigate Reserve (254680)805680 478 043 478,043
8 Mark to Market FAS133 (254740)112 689 992 175.7/244.112 689.992
9 Mark to MarketFAS133 (254750)175/244750 15,400 153 15,400 153
TOTAL 116 251 545 115 182 781 17,178 196 246 960
FERC FORM NO. 1/3-0 (REV 02-04)Page 278
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2007
E ECTRIC OPERATING REVENUES (Account 400)
1. The following instructions generally apply to the annual version of these pages, Do not report quarterly data in columns (c), (e), (I), and (g), Unbilled revenues and MWH
related to unbilled revenues need not be reported separately as required in the annual version of these pages.
2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3. Report number of customers, columns (I) and (9), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added
for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of
each month.
4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no Quarterly)
(c)
Line
No.
Title of Account
1 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 Authorities
8 (446) Sales to Railroads and Railways
221 193 283
92,960,960
268 037
203,479,971
551,856
897,543
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers
849,076
554,985 580
175,572 595
730,558,175
825,393
512 689 174
221 803,806
734,492 980
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 730 558 175 734,492 980
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues
18 (453) Sales of Water and Water Power
447 333
230,504
592 254
450 598
191 173
587,47019 (454) Rent from Electric Property
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues 63,726,817 56,829,008
22 (456.1) Revenues from Transmission of Electricity of Others
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
26 TOTAL Other Operating Revenues
27 TOTAL Electric Operating Revenues
996 908
797 555 083
058 249
794 551 229
FERC FORM NO. 1/3-0 (REV. 12-05)Page 300
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
E ECTRIC OPERATING REVENUES (Account 400)
5. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the
respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification
in a footnote.
6. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases,
7. For Lines 2,4,and 6, see Page 304 for amounts relating to unbilled revenue by accounts,
8. Include unmetered sales, Provide details of such Sales in a footnote.
Name of Respondent
A vista Corporation
Year/Period of Report
End of 2006/Q4
MEGAWATT HOURS SOLD
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)(d) (e)
A VG.NO. CUSTOMERS PER MONTH Line
Current Year (no Quarterly) Previous Year (no Quarterly) No.(f)
(g)
109,861 994 216 912 37,282
061 888 090 941 388 1 ,407
24,783 25,060 425 420
776 925
787 002 542,674 340,732 333,214
552 362 144,503
339 364 687 177 340 732 333,260
339 364 687 177 340 732 333,260
Line 12, column (b) includes $
Line 12, column (d) includes
1,428 850
234
of unbilled revenues.
MWH relating to unbilled revenues
FERC FORM NO. 1I3-Q (REV. 12-05)Page 301
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2) Fi A Resubmission 04/18/2007
SALES OF ELECTRICITY BY RATE SC 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 account in the sequence followed in "Electric Operating Revenues,' Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Numoer ana Iitie Of Hate scneaule IVlvvn ;:,010 Hevenue Average Numoer ~wn of :;:;ales rwWR~o~er
No.of Cus~omers Per 9~stomer(a)(b)(c)(f)
1 RESIDENTIAL SALES (440)
2 1 Residential Service 443,131 216 800 781 288,324 942 0630
3 2 Residential Service
4 3 Residential Service
5 12 Res. & Farm Gen. Service 017 571 737 008 5,452 0928
6 15 MOPS II Residential
7 22 Res. & Farm Lg. Gen. Service 517 785,519 494 633 0626
8 30 Pumping-Special
9 32 Res. & Farm Pumping Service 797 802 723 518 771 0680
48 Res. & Farm Area Lighting 029 927,280 1844
49 Area Lighting-High-Press.285 63,473 2227
56 Centralia Refund
95 Wind Power 163 576
72 Residential Service
73 Residential Service
74 Residential Service
76 Residential Service
77 Residential Service
58A Tax Adjustment 509
58 Tax Adjustment 159,435
SubTotal 564 776 233,237 015 300,940 845 0654
Residential-Unbilled 918 477,209 1144
Total Residential Sales 577 694 234 714 224 300 940 888 0656
COMMERCIAL SALES (442)
2 General Service
3 General Service
11 General Service 651 836 939 109 569 20,014 0858
12 Res. & Farm Gen. Service
16 MOPS II Commercial
19 Contract-General Service
21 Large General Service 003,675 134 022 318 392 456,210 0669
25 Extra Lg. Gen. Service 364 097 591,466 007 462 0456
28 Contract-Extra Large Serv
31 Pumping Service 286 549 694 938 254 0615
47 Area Lighting-Sod. Vap 973 153,764 1655
49 Area Lighting-High-Press.260 394 454 1745
56 Centralia Refune
95 Wind Power 23,872
74 Large General Service
TOTAL Billed 340,59f 729 129 325 340 73.0591
Total Unbilled Rev.(See Instr. 6)1,428 850 1.15n
TOTAL 339 36;1 730 558 175 340 732 36,21L 0592
FERC FORM NO.1 (ED. 12-95)Page 304
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation
(1) An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
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 account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
I LIne I\lUmDer ana Ime or Hale scneoUie Mvvn ;:)010 Hevenue Average I\lUmDer ~vvn or ;:)ales ~~R~ofderNo.(a)(b)(c)of c~~)omers Per 9~stomer
(f)
1 75 Large General Service
2 76 Large General Service
3 77 General Service
4 58A Tax Adjustment 791
5 58 Tax Adjustment 584,231
6 SubTotal 119 127 221 221 117 912 273 0709
7 Commercial-Unbilled 266 834 0030
8 Total Commercial 109,861 221 193 283 912 82,028 0711
INDUSTRIAL SALES (442)
2 General Service
3 General Service
8 Lg Gen Time of Use
11 General Service 684 594 294 240 850 0889
12 Res. & Farm Gen. Service
21 Large General Service 184 805 899,490 199 928,668 0644
25 Extra Lg. Gen. Service 794 060 786 229 78,002 609 0417
28 Contract - Extra Large Service 286 209 216 286,000 7315
29 Contract Lg. Gen. Service
30 Pumping Service - Special 158 190 123 568 154 0537
31 Pumping Service 54,485 472 395 733 332 0637
32 Pumping Svc Res & Firm 004 243 375 153 170 0608
47 Area Lighting-Sod. Vap.239 152 1429
49 Area Lighting - High-Press 382 1582
95 Wind Power 120
72 General Service
73 General Service
74 Large General Service
75 Large General Service
76 Pumping Service
77 General Service
58A Tax Adjustment 904
58 Tax Adjustment 544,613
SubTotal 066,774 981 485 388 1,489 030 0450
Industrial-Unbilled 886 525 0042
Total Industrial 061 888 92,960,960 388 1,485,510 0451
STREET AND HWY LIGHTING (444)
6 Mercury Vapor St. Ltg.
7 HP Sodium Vap. St. Ltg
TOTAL Billed 340,59E 729 129,325 340,73:;21 E 0591
Total Unbilled Rev.(See Instr. 6)23~428,850 157
TOTAL 339 36~730 558 175 340 73:;21L 0592
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
SALES OF ELECTRICITY BY RATE SC 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 account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line Numoer ana Ime or Hale scneaUie Mwn t;ola Hevenue Average Numoer ~wn or :;o;ales ~~R'go ~er
No.(c)of cus~omers Per 9~stomer(a)(b)(f)
1 11 General Service 675 000 0954
2 41 Co-Owned St. Lt. Service 222 989 13,875 1486
3 42 Co-Owned St. Lt. Service 19,123 634 010 327 58,480 2423
High-Press. Sod. Vap.
5 43 Cust-Owned St. Lt. Energy 259 31,000 0848
and Maint. Service
7 44 Cust-Owned St. Lt. Energy 823 722 548 1139
and Maint. Svce - High-Pres
Sodium Vapor
45 Cust. Owned St. Lt. Energy Svc 367 112 151 889 0557
46 Cust. Owned St. Lt. Energy Svc 116 231 361 119 846 0742
58A Tax Adjustment 392
58 Tax Adjustment 188 301
SubTotal 783 268 037 425 313 2126
Street & Hwy Lighting-Unbilled
Total Street & Hwy Lighting 783 268 037 425 313 2126
OTHER SALES TO PUBLIC
(445)
None
INTERDEPARTMENTAL SALES 776 849 076 190 687 0665
58 Tax Adjustment
Total Interdepartmental 776 849 076 190 687 0665
SALES FOR RESALE (447)
61 Sales to Other Utilities (NDA)552 362 175,572 595 0494
Total Sales for Resale 552 362 175 572 595 0494
TOTAL Billed 340,591:729,129 325 340 73~21 I:0591
Total Unbilled Rev.(See Instr. 6)1 ,23~1,428 850 1579
TOTAL 339 36~730,558,175 340,73~21~0592
FERC FORM NO.(ED. 12-95)Page 304.
This Page Intentionally Left Blank
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04(2)D A Resubmission 04/18/2007
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 involving a balancing of debits and creditsfor energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., thesupplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service mustbe 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., 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 thedefinition 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 Lessthan 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" meansLonger than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing f\vera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 American Electric Power WSPP-
BC Transmission Corp.Tariff 12
BP Energy Company WSPP-
Arizona Public Service WSPP-
Barclays Bank PLC WSPP-
Benton County Public Utility District WSPP-
Black Hills Power, Inc.WSPP-
Bonneville Power Administration Tariff 8
Bonneville Power Administration ACS-
Bonneville Power Administration WSPP-
Burbank, City of WSPP-
Calpine Corporation WSPP-
Cargill Power Markets, LLC WSPP-
Chelan County PUD No.WSPP-
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 200.6/04
(2)DA Resubmission 0.4/18/200.7
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-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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain ina 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 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)(k)
67,400 136,300.136 30.0
289 289
201 912 804 388 804 388
800 18,10.0 18,100.
000 55,700 70.0.
735 154 670.154,670
625 30,644 644
639 971 949 971 949
449 136,061 136 061
701 992,021 992 021
450.725 725
644 187,488 187,488
800 200 200.
552 362 324 315 158 866 789 381,491 175 572 595
552 362 324 315 158,866,789 381 491 175,572 595
FERC FORM NO.1 (ED. 12-90)Page 311
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
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 involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - 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., 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 RO 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 Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
Chelan County PUD No.Tariff 10
2 Clatskanie Peoples PUD WSPP-
3 Conoco Phillips WSPP-
4 Conoco Phillips Tariff 10
Constellation Energy Commodities Group WSPP-
Constellation Energy Commodities Group Tariff 10
7 Coral Power, LLC WSPP-
8 Douglas County PUD No.WSPP-
9 EI Paso Merchant Energy LP WSPP-
Enmax Energy Marketing, Inc.WSPP-
EPCOR Merchant & Capital US WSPP-
Eugene Water & Electric Board WSPP-
Franklin County PUD No.WSPP-
Grant County PUD No.WSPP-
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements 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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 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 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 ,line 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)(k)
140 140
290 580 580
931 310 983 310 983
344 344
191 ,485 771 663 771,663
123 160 542 060 542 060
556 683 683
267 081 081
390 413,466 413,466
770 260 550 260 550
820 545 545
738 698 020 698,020
552 362 324 315 158,866,789 381,491 175 572 595
552 362 324 315 158 866,789 381 491 175,572 595
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
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 involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - 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 RO 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 Avera Actual Demand (MW)
No.(Footnote Affiliations)Class if i- Schedule or Monthly illing ~vera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
Grant County PUD No.Tariff 10
Grays Harbor County PUD No.WSPP-
Idaho Power Company WSPP-
Idaho Power Company Tariff 12
Idaho Power Company Tariff 10
Klamath Falls, City of WSPP-
Los Angeles Dept of Water & Power WSPP-
8 Modesto Irrigation District WSPP-
9 Morgan Stanley WSPP-
NorthWestern Energy LLC WSPP-
NorthWestern Energy LLC Tariff 10
NorthWestern Energy LLC Tariff 9
NorthWestern Energy LLC Tariff 10
NorthWestern Energy LLC Tariff 9
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
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-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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (D. Explain in a footnote all components of the amount shown in column (D. 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 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-Ran 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 LineTotal ($)
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
545 545
605 610 610
32,127 384 420 384,420
685 685
81,420 81,420
000 289,870 289,870
217 917 734 719 12,734 719
75,668 431 888 3,431 888
380,573 700 846 700 846
843 094 241 094 241
896 066 896 066
202 378 829 378 829
576 175 576 175
487 361 388 361 388
552 362 324 315 158 866 789 381 491 175 572 595
552 362 324 315 158,866,789 381 491 175,572,595
FERC FORM NO.1 (ED. 12-90)Page 311.2
Name of Respondent This
'0ort
Is:Date of Report YearlPeriod of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04(2)0 A Resubmission 04/18/2007
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 involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (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., 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
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" meansLonger than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
NorthWestern Energy LLC Tariff 12
2 Okanogan County PUD WSPP-
3 PNGC Power WSPP-
4 PacifiCorp WSPP-
5 PacifiCorp Tariff 12
6 PacifiCorp Tariff 10
PacifiCorp Tariff 9
8 Peaker LLC Tariff 9
Pend Oreille Public Utility District Tariff 10
Pend Oreille Public Utility District Tariff 9
Pend Oreille Public Utility District Tariff 10
Pend Oreille Public Utility District Tariff 9
Portland General Electric Company WSPP-
Portland General Electric Company Tariff 12
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This '0ort Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/Q4
(2)DA Resubmission 04/18/2007
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-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
5. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 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 RO/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)
110 198 198
10,553 534 929 534 929
924 090 090
446 927 832 927 832
232 989 10,989
830 58,830
220 241 073 241 073
738,851 738 851
400 641 400,641
346 111,484 111,484
141 141
886 245 107 245 107
105,300 146 582 146,582
317 317
552 362 324 315 158,866 789 381 491 175,572 595
552 362 324 315 158,866,789 381 491 175,572 595
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/Q4(2)DA Resubmission 04/18/2007
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 involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - 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., 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 RO 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 Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Avera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
Portland General Electric Company Tariff 10
Powerex WSPP-
P P L Montana WSPP-
P P L Montana Tariff 10
P P L Montana LF,Tariff 9
6 PPM Energy, Inc.WSPP-
Public Service of Colorado WSPP-
Public Service of New Mexico WSPP-
Puget Sound Energy WSPP-
Puget Sound Energy Tariff 12
Puget Sound Energy Tariff 10
Puget Sound Energy IF'Tariff 9
Rainbow Energy Marketing WSPP-
Redding, City of WSPP-
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
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-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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). ' Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the 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)(k)
042 042
273,639 217 861 217 861
121 697 338 697 338
279,406 279,406
641 860 975 860,975
135 750 540,442 540 442
135,411 296 282 296 282
400 100 100
78,094 532 913 532,913
172 172
740 740
861 102 048 102 048
190 626,667 626,667
604 89,768 768
552 362 324 315 158,866 789 381,491 175 572 595
552 362 324 315 158 866,789 381 491 175,572,595
FERC FORM NO.1 (ED. 12-90)Page 311.4
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
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 involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (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., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term " means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing !,\vera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Sacramento Municipal Utility District WSPP-
2 Sacramento Municipal Utility District LF 'WSPP-
3 San Diego Gas and Electric WSPP-
4 Seattle City Light WSPP-
5 Seattle City Light Tariff 12
6 Sempra Energy Solutions WSPP-
7 Sempra Energy Trading WSPP-
8 Sempra Energy Trading o.TF ..'
9 Sierra Pacific Power Company WSPP-
Silicon Valley Power WSPP-
Snohomish County PUD WSPP-
Sovereign Power Tariff 9
Sovereign Power Tariff 10
Suez Energy Marketing NA, Inc WSPP-
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
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-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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column,(j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the 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)(k)
160,518 597 996 597 996
39,600 578 352 578,352
864 056 056
26,945 971 874 971 874
777 777
146 640 10,541,450 541,450
257 665 722 681 722 681
455,407 455,407
032 901 101 901 101
072 678 678
500 930,010 930 010
833 296 223 296 223
174 174
24,360 165 985 165 985
552 362 324 315 158,866,789 381 491 175,572 595
552,362 324 315 158 866 789 381,491 175 572 595
FERC FORM NO.1 (ED. 12-90)Page 311.5
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
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 involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - 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., 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 RO 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.
I U - 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 Actual Demand (MW)
No.(Footnote Affiliations)Class if i- Schedule or Monthly illing Avera Avera
fJ6cationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
Tacoma Power WSPP-
Tacoma Power Tariff 10
TransAlta Energy Marketing WSPP-
4 Turlock Irrigation District WSPP-
5 UBS AG (London Branch)WSPP-
6 IntraCcirl1parjy..wtie~lirlg/
7 IntraCOmpany, (3eneration
" '
Lp"
8 Revenue Adjustment
'.'
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
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-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines , List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/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)(k)
4,412 102 941 102 941
780 780
213,864 984 784 984 784
19,731 145 543 145,543
133,846 677 645 677,645
300 136 300,136
647 991 647,991
337 043 043
552 362 324 315 158,866,789 381,491 175,572 595
552 362 324,315 158 866,789 381 491 175 572 595
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount for
1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
(500) Operation Supervision and Engineering
(501) Fuel
(502) Steam Expenses
(503) Steam from Other Sources
(Less) (504) Steam Transferred-Cr.
(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 Engineering
16 (511) Maintenance of Structures
17 (512) Maintenance of Boiler Plant
18 (513) Maintenance of Electric Plant
19 (514) Maintenance of Miscellaneous Steam Plant
20 TOTAL Maintenance (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-Cr.
30 (523) Electric Expenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
34 Maintenance
35 (528) Maintenance Supervision and Engineering
36 (529) Maintenance of Structures
37 (530) Maintenance of Reactor Plant Equipment
38 (531) Maintenance of Electric Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 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 Waterways
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)
Year/Period of Report
End of 2006/04
Amount forPrevious Year
(c)
255,226
443 765
720,402
016
219,166
116 610
710,478
783,473
794,317
19,628
787 042
724 147
14,476
L:,;iL ;.D 'i;Mij~
;;;
L2.;;i&!:.E,,2:!"~I,G:2LCt--,i.-= .."
30,032 827 27,571 919
433,468
504 566
860 568
649,502
702 446
150 550
38,183,377
417 575
474 041
564 020
402 371
505,402
363 409
32,935 328
~~kiiJ.i18D.2.fKt;i1J.jjE:;\;'
.'. "'
&1.,
.':
567 952
757 070
671,493
507 784
746,756
664 358
10,915,413
527 418
761,465
309 921
160,958
585 348
687 125
032 235
317 169
296,564
604,461
318 232
451 650
988,076
903,489
363,580
598 819
532 575
003,438
431 231
929 643
961 878
FERC FORM NO.1 (ED. 12-93)Page 320
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/18/2007
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 for
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering
63 (547) Fuel
64 (548) Generation Expenses
65 (549) Miscellaneous Other Power Generation Expenses
66 (550) Rents
67 TOTAL Operation (Enter Total of lines 62 thru 66)
68 Maintenance
69 (551) Maintenance Supervision and Engineering
70 (552) Maintenance of Structures
71 (553) Maintenance of Generating and Electric Plant
72 (554) Maintenance of Miscellaneous Other Power Generation Plant
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)
75 E. Other Power Supply Expenses
76 (555) Purchased Power
77 (556) S stem Control and Load Dispatching
78 (557) Other Expenses
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)
80 TOTAL Power Production Expenses (Total of lines 21 , 41 , 59, 74 & 79)
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering
84 (561) Load Dispatching
85 (561.1) Load Dispatch-Reliability
86 (561.2) Load Dispatch-Monitor and Operate Transmission System
87 (561.3) Load Dispatch-Transmission Service and Scheduling
88 (561.4) Scheduling, System Control and Dispatch Services
89 (561.5) Reliability, Planning and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation Interconnection Studies
92 (561.8) Reliability, Planning and Standards Development Services
93 (562) Station Expenses
94 (563) Overhead Lines Expenses
95 (564) Underground Lines Expenses
96 (565) Transmission of Electricity by Others
97 (566) Miscellaneous Transmission Expenses
98 (567) Rents
99 TOTAL Operation (Enter Total of lines 83 thru 98)
1 00 Maintenance
101 (568) Maintenance Supervision and Engineering
102 (569) Maintenance of Structures
103 (569.1) Maintenance of Computer Hardware
104 (569.2) Maintenance of Computer Software
105 (569.3) Maintenance of Communication Equipment
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment
108 (571) Maintenance of Overhead Lines
109 (572) Maintenance of Underground Lines
110 (573) Maintenance of Miscellaneous Transmission Plant
111 TOTAL Maintenance (Total of lines 101 thru 110)
112 TOTAL Transmission Expenses (Total of lines 99 and 111)
Amount forPrevious Year
(c)
016,705
535,646
997,453
350 879
436
933 119
872 108
71,182 560
242 686
372 431
550 181
77,219,966
bNJTE'jili;;,:i; 2~lfdz iBiim'Jd;2E.L,_c.j;:;C.i2,2C;i.&&jr&i2J"iEJj,L'j ,
892
847,959
646,847
171 398
033,178
966 297
111,465
074,490
501 232
265 359
952 546
172 512
200,083,219
638 755
233,654
287 955 628
431,008,791
257 077,620
679 530
517,684
325 274 834
452 344,552
698 115
011
16,212
165,928
770,853
604 219
520 559
274 938
169 000
225 658
139,096
~llli~~J;Ii1ltlli~K8j;Et8~::;i~ ii.;iii:W,zI;jP1i~~fi!20ii~B;' :i,~;k~1d&0.
881 367
718,741
107 794
796 937
846 677
670 773
70,626
077 608
418 687
193,198
368 665
154 312
115 863
962 501
807
287
750 343
19,547 280
786,451
808 075
883
131 689
250 075
16,327,683
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2) FiA Resubmission 04/18/2007
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
.........
No.urrent ear Previous Year(a)(b) (c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Day-Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Rights Market Facilitation
118 (575.4) Capacity Market Facilitation
119 (575.5) Ancillarv Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Facilitation, Monitoring and Compliance Services
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)
124 Maintenance
125 (576.1) Maintenance of Structures and Improvements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Software
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering 914 176 958 296
135 (581) Load Dispatching
136 (582) Station Expenses 399,676 352 654
137 (583) Overhead Line Expenses 748 605 734,484
138 (584) Underground Line Expenses 383,827 1,419,758
139 (585) Street Lighting and Signal System Expenses 173 361 193 835
140 (586) Meter Expenses 882 963 953 987
141 (587) Customer Installations Expenses 916 336 818,573
142 (588) Miscellaneous Expenses 385 283 100 378
143 (589) Rents 138 027 214 555
144 TOTAL Operation (Enter Total of lines 134 thru 143)942 254 746 520
145 Maintenance
146 (590) Maintenance Supervision and Engineering 487 804 140 694
147 (591) Maintenance of Structures 263 589 158,925
148 (592) Maintenance of Station Equipment 920,003 645,406
149 (593) Maintenance of Overhead Lines 7,469 677 287 784
150 (594) Maintenance of Underground Lines 055,849 879 766
151 (595) Maintenance of Line Transformers 497 848 456,523
152 (596) Maintenance of Street Lighting and Signal Systems 389 891 415 324
153 (597) Maintenance of Meters 164 174 129 670
154 (598) Maintenance of Miscellaneous Distribution Plant 377 969 379,012
155 TOTAL Maintenance (Total of lines 146 thru 154)626 804 10,493 104
156 TOTAL Distribution Expenses (Total of lines 144 and 155)569,058 239,624
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 511 548 673,887
160 (902) Meter Reading Expenses 2,415,032 641 237
161 (903) Customer Records and Collection Expenses 718 628 882 859
162 (904) Uncollectible Accounts 537 265 1,461 071
163 (905) Miscellaneous Customer Accounts Expenses 182 081 518 206
164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163)364 554 13,177 260
FERC FORM NO.1 (ED. 12-93)Page 322
Name of Respondent
A vista Corporation
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/18/2007
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 for(a) (b)
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 Cust. Service and Information. Exp. (Total lines 137 thru 140)
171 TOTAL Customer Service and Information Expenses (Total 167 thru 170)
172 7. SALES EXPENSES
1 73 Operation
174 (911) Supervision
175 (912) Demonstrating and Selling Expenses
176 (913) Advertising Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru177)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries
182 (921) Office Supplies and Expenses
183 (Less) (922) Administrative Expenses Transferred-Credit
184 (923) Outside Services Employed
185 (924) Property Insurance
186 (925) Injuries and Damages
187 (926) Employee Pensions and Benefits
188 (927) Franchise Requirements
189 (928) Regulatory Commission Expenses
190 (929) (Less) Duplicate Charges-Cr.
191 (930.1) General Advertising Expenses
192 (930.2) Miscellaneous General Expenses
193 (931) Rents
194 TOTAL Operation (Enter Total of lines 181 thru193)
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)
Year/Period of Report
End of 2006/04
Amount forPrevious Year
(c)
397 769
59,901
107 036
564 706
564 706
729 317
40,594
106,777
10,876 688
10,876,688
521 372 412,421
265 537 136,922
143,953 176
930,862 626 519
17,412,679 783 546
217 501 899,968
28,056 528
988 121 289,933
191 391 052 011
769 353 703,992
106,169 102 278
230 350
887 178 4,471,706
678 950
950 213 933,810
068 064 2,464 363
577 521 664,479
940 101 170,392
517 622 834 871
548 502 873 565,427 197
FERC FORM NO.1 (ED. 12-93)Page 323
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
~CHA~ED POWER hAccou~t 555)nclu 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 affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - 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 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., 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 RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
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 for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
American Electric Power WSPP
2 Arizona Public Service WSPP
3 BP Energy Company WSPP
4 Benton County PUD No.WSPP
5 Black Creek Hydro FERC #1
6 Black Hills Power WSPP
Bonneville Power Administration LF ' WNP#3 Agr.
Bonneville Power Administration WSPP
Bonneville Power Administration PNCA
Bonneville Power Administration BPA OATT
Bonneville Power Administration Tariff #8
Bonneville Power Administration BPA NITSA
Bonneville Power Administration FERC #105
Cargill Power Markets, LLC WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326
Name of Respondent This ooort Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
ccount 55~~) (vonllnuea)
~ ,~ '~
11nCiuding power exchange)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basIs for settlement. Do not report net exchange.
7. Report demand charges in column 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 G+k+l)No.Received Delivered
\~?($)
of Settlement ($)
(g)
(h)(i)(I)(m)
40(041 25(041 250
60C 338,40C 338 400
114,631 966 91 C 966 910
48E 157 149 157 149
122 971 122 971
60C 70C 700
362 07E 498 661 11,498,661
172 97E 705 44/705,447
665 035
",:
1W,?22 197,822
, "
52,450
" "
450
76~514 279 514,279
55E 159 761 159,761
139 1,405 241 405 241
101 760 291 760 291
323 232 101,469 074 286 3,423 860 194 159 018 500 341 200 083 219
FERC FORM NO.1 (ED. 12-90)Page 327
Name of Respondent This ooort Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
~CHA~ED POWER hAccou~t 555)(nclu 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 affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - 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 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., 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 RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
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 for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Chelan County PUD No.Rocky Reach
2 Chelan County PUD No.WSPP
3 Cinergy Marketing & Trading WSPP
4 City of Burbank WSPP
5 City of Klamath Falls WSPP
6 City of Spokane PURPA
7 Clatskanie Peoples PUD WSPP
8 Conoco WSPP
Constellation Energy Commodities Group WSPP
Coral Power WSPP
Douglas County PUD No.Wells
Douglas County PUD No.Wells Settlement
Douglas County PUD No.WSPP
Douglas County PUD No.305
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007PI =1(' CCOU
R\R~~~: (L:ontlnuea)
~ ,~ "'
(inCluding power 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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 Govered 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
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
176,031 031 215
97E 547 39~547 399
40C 60C 600
80C 20C 35,200
11C 99E 10,995
65E 2,499,45E 499,458
92C 139 811 139,811
800 112 13,20C 15,312
92,014 653,991 653 991
49,17E 613,37E 613 375
122 43E 1 ,218 02~218 029
284 546 546 047
661:850 95E 850,956
121 669 121 635 326 773
.""., ,, "
812 328 585
323,232 101,469 074 286 3,423 860 194 159 018 500 341 200,083,
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
~CHA~ED POWER hAccou~t 555)nclu 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 affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (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 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., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
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 for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Duke Energy Trading & Marketing WSPP
2 EI Paso Marketing WSPP
3 EPCOR Merchant & Capital US WSPP
4 Eugene Water & Electric Board WSPP
5 Ford Hydro Limited Partnership PURPA
Franklin County PUD No.WSPP
7 Grant County PUD No.Wanapum
8 Grant County PUD No.Priest Rapids
9 Grant County PUD No.PR Displacement
Grant County PUD No.WSPP
Grant County PUD No.Grant PUD
Grays Harbor County PUD No.WSPP
Haleywest LLC PURPA
Hydro Technology Systems PURPA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)D A Resubmission 04/18/2007
v 'v, ""(1TiCII ccouRt 55~~~ (vontlnUeO)Including power 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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis , enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)
\fi
of Settlement ($)
(g)
(h)(i)(m)
438 00C 12,811 50C 811 500
00C 714 50C 714 500
761:266 664 266 664
14E 819 933 819 933
051:262 693 262 693
22E 03/037
322 681 932 49E 932,496
135 71C 691 ,60f 691 608
177 35"206 481 206,481
08E 673 29,673,293
207 139 207 139
00/137 30,137 303
914 537 537 277
90~305 39::305,392
323 232 101,469 074 286 3,423,860 194 159,018 500 341 200 083 21 ~
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04(2)DA Resubmission 04/18/2007
~CHA~ED POWER ~Accou~t 555)nclu 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 affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - 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 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., 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 RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term " means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term " means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
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 for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Idaho Power Company WSPP
Inland Power & Light Company 208
3 Jim White PURPA
John Day Hydro PURPA
Mirant Americas Energy Marketing LP WSPP
Modesto Irrigation District WSPP
7 Morgan Stanley Capital Group WSPP
8 Morgan Stanley Capital Group WSPP
9 NorthWestern Energy LLC WSPP
Nevada Power WSPP
Okanogan County PUD No.WSPP
Pacific Northwest Generating Co-op WSPP
PacifiCorp WSPP
PPL Montana, LLC WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DAResubmission 04/18/2007
ccouRt 55~~) (vontlnUeCl)(Including power 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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 pow~r 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
($)
of Settlement ($)
(g)
(h)(i)(I)(m)
556 706 87E 706 875
124 18~183
30C 113,33-113 332
906 53l 534
00C 313 25C 313 250
299 84C 840
384 00C 370 75C 370 750
202 058 27E 058,275
27,92C 275 205 275,205
36,578 923 578,923
18"463 274 463,274
120 43"125 447,526 447 651
394 069 18,352,039 352 039
323,232 101 ,469 074 286 3,423 860 194 159,018 500 341 200 083,219
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
~CHA~ED POWER ~Accou~t 555)nclu 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 affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - 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 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., 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 RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
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 for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 PPM Energy PPM Energy
2 PPM Energy WSPP
3 Pend Oreille County PUD No.Pend 0'
4 Pend Oreille County PUD No.NWPP
Phillips Ranch PURPA
6 Pinnacle West Capital Corp WSPP
7 Portland General Electric Company 304
8 Portland General Electric Company 178
9 Portland General Electric Company WSPP
Portland General Electric Company WSPP
Potlatch Corporation PURPA
Potlatch Corporation Potlatch
Powerex Corp WSPP
Public Service of Colorado WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326.4
Name of Respondent This ooort Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
ccouRt 55~~) (Conlinued)(Including power 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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered , used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
78,904 904 934
89,88S 373 58~373 589
113,551 802 802 747
332 923 W4q$408
.,' ,, '~ '
011.014
40C 16,90C 16,900
11,153 438
472 560 471 330
.""
111397 111 397
' "
375 124 375 125 533,000 533 000
981.275 572 572 977
489 21 ,029,21 ~029 212
80C 800
78,44E 349 54f 349,548
977,11C 977 110 14-
323,232 101,469 074 286 3,423 860 194 159,018 500,341 200,083 21 9
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This 78Jort Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
~CHA~ED POWER ~Accou~t 555)nclu 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 party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term " means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Puget Sound Energy WSPP
2 Puget Sound Energy PNCA
3 Rainbow Energy Marketing Corp WSPP
4 Sacramento Municipal Utility District WSPP
5 San Diego Gas & Elec WSPP
6 Seattle City Light WSPP
7 Seattle City Light WSPP
8 Sempra Energy Solutions WSPP
9 Sempra Energy Trading WSPP
Sheep Creek Hydro PURPA
Sierra Pacific Power Company WSPP
Snohomish County PUD No.WSPP
Sovereign Power Sovereign
Stimson Lumber PURPA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
ccount 55~~) (l.;ontlnuea)~ M '~
'(1nCiuding power exchange)
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 G+k+l)No.Received Delivered
($)~~~($)
of Settlement ($)
(g)
(h)(i)(I)(m)
41 ,40~036 44~036,442I '
" "
' 1 ~15 875
131 29~6,469,02C 6,469,020
70~19, 12~19,125
20C 12,20C 200
67~076 84C 076 840
800 800 561 200 561 200
20C 80C 68,800
113,18~889 63l 889,634
371 393 02~393,025
84~571,44C 571 440
44E 433 02C 433 020
28~88,023
21 ,59~994 96~994 965
323,232 101,469 074 286 423 860 194,159 018 500,341 200,083,21 9
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04(2)0 A Resubmission 04/18/2007
~CHA~ED POWER hAccou~t 555)nclu 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 affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (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 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., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
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 for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average '/\veragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Suez Energy Marketing WSPP
2 Tacoma Power WSPP
TransAlta Energy Marketing WSPP
4 UBS AG WSPP
5 Williams Power Co.WSPP
IntraCompany Generation Services
Other - Inadvertent Interchange
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04(2)DA Resubmission 04/18/2007
"""'-
,WE ccouRt
~g~~)
(Continued)(including po er 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 billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
386 64C 386 640
54"375 116 363 116 738
83C , 125,40~125,402
103 15~710 710 293
20C 92C 920
/;"; '
;647.991 647 991
323 232 101,469 074 286 3,423,860 194 159,018 500 341 200 083,21 ~
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
OF "'I T t;'I,.IH ~ ,
..~ "
~~ccount 4bo.(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - 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 Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
Avista Energy Idaho Power Company Chelan Public Utility District
2 Avista Energy Idaho Power Company Bonneville Power Administration
3 Avista Energy NorthWestern Montana Chelan Public Utility District
4 Avista Energy Chelan Public Utility District Idaho Power Company
5 Avista Energy Chelan Public Utility District NorthWestern Montana
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO
Bonneville Power Administration Bonneville Power Administration Idaho Power Company
Consolidated Irrigation District Bonneville Power Administration Consolidated Irrigation District LFP
Grant County Public Utility District Grant County Public Utility Dist Grant County Public Utility Dist LFP
PPL Montana NorthWestern Montana Portland General Electric
PPL Montana NorthWestern Montana Chelan Public Utility District
PPL Montana NorthWestern Montana Grant County Public Utility Dist
PPL Montana PacifiCorp NorthWestern Montana
PPL Montana NorthWestern Montana Idaho Power Company
PPL Montana NorthWestern Montana Puget Sound Energy
PPL Montana NorthWestern Montana Bonneville Power Administration
PPL Montana Portland General Electric NorthWestern Montana
PPL Montana Grant County Public Utility Dist NorthWestern Montana
PPL Montana NorthWestern Montana Idaho Power Company SFP
PPL Montana NorthWestern Montana Bonneville Power Administration SFP
Idaho Power Company Puget Sound Energy Idaho Power Company
Idaho Power Company Grant County Public Utility Dist Idaho Power Company
Idaho Power Company PacifiCorp Idaho Power Company
Idaho Power Company Idaho Power Company Chelan Public Utility District
Idaho Power Company Idaho Power Company Bonneville Power Administration
Idaho Power Company Idaho Power Company NorthWestern Montana
Idaho Power Company Idaho Power Company Portland General Electric
Idaho Power Company Bonneville Power Administration Idaho Power Company
Idaho Power Company Idaho Power Company Grant County Public Utility Dist
Idaho Power Company Tacoma Power Idaho Power Company
Idaho Power Company Chelan Public Utility District Idaho Power Company
Idaho Power Company Bonneville Power Administration Idaho Power Com pany SFP
Idaho Power Company Grant County Public Utility Dist Idaho Power Company SFP
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
OF I::LEC I HILiII Y l~ccount 45b)(LiontlnUeC)(Including transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, .
point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation qr Other (Substation or Other Demand Megawatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(1)
(g)
(h)(i)
FERC Trf No.333
FERC Trf No.100 10(
FERC Trf No.550 55C
FERC Trf No.205 20E
FERC Trf No.
FERC Trf No.780 727 780 72/
FERC Trf No.774 77~
FERC Trf No.Bell Substation Consolidated 555 55E
FERC No.Larson Substation Round Lk Coulee City 540 54C
FERC Trf No.
FERC Trf No.646 64E
FERC Trf No.690 69C
FERC Trf No.220 22C
FERC Trf No.887 88/
FERC Trf No.702 70.
FERC Trf No.173 17~
FERC Trf No.185 18~
FERC Trf No.
FERC Trf No.290 29C
FERC Trf No.370 37C
FERC Trf No.361 361
FERC Trf No.1 E
FERC Trf No.730 73C
FERC Trf No.044 04~
FERC Trf No.92,110 11 C
FERC Trf No.1 ~
FERC Trf No.170 17C
FERC Trf No.259 25~
FERC Trf No.200 20C
FERC Trf No.130 1, 13C
FERC Trf No.234 23l
FERC Trf No.155 925 155 92E
FERC Trf No.160 16C
218 454 585 454 58E
FERC FORM NO.1 (ED. 12-90)Page 329
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
OF ~L~t; I HI.';II y r-YH ,(ACCount 456) (Liontlnuea)(Including transactions reffered to as 'wheeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and U) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)I Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
297 297
400 400
089 089
930 930
160 160
098,634 098,634
336 37,336
299 829 88,128
30,140 30,140
558 558
785 785
810 810
159 159
808 808
245 245
681 681
258 258
000 000
6,460 6,460
343 343
904 904
142 142
376,207 376,207
55,493 493
218,700 218 700
678 678
584 584
042 042
614 221 614 221
432 432
141 733 356,888 106 660 10,605,281
FERC FORM NO.1 (ED. 12-90)Page 330
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
. .
OF ELSC IHI~II T ,:,yn v lr:II:n,?~~ccount45tj.(Including transactIons referred to as 'wheeling
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - 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 Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
Idaho Power Company Bonneville Power Administration Bonneville Power Administration SFP
Idaho Power Company Portland General Electric Idaho Power Company SFP
Idaho Power Company Puget Sound Energy Idaho Power Company SFP
Idaho Power Company Douglas County Public Utility Dis Idaho Power Company SFP
Idaho Power Company Chelan Public Utility District Idaho Power Company SFP
Idaho Power Company NorthWestern Montana Idaho Power Company SFP
NorthWestern Montana NorthWestern Montana Idaho Power Company
NorthWestern Montana NorthWestern Montana Idaho Power Company SFP
NorthWestern Energy NorthWestern Montana Bonneville Power Administration
NorthWestern Energy NorthWestern Montana Puget Sound Energy
NorthWestem Energy NorthWestern Montana Chelan Public Utility District
NorthWestern Energy NorthWestern Montana Portland General Electric
NorthWestern Energy Chelan Public Utility District NorthWestern Montana
NorthWestern Energy NorthWestern Montana Idaho Power Company SFP
PacifiCorp NorthWestern Montana PacifiCorp
PacifiCorp PacifiCorp NorthWestern Montana
PacifiCorp PacifiCorp Bonneville Power Administration
Powerex NorthWestern Montana Bonneville Power Administration
Powerex Bonneville Power Administration NorthWestern Montana
Powerex NorthWestern Montana Idaho Power Company
Powerex Idaho Power Company Bonneville Power Administration
Powerex Bonneville Power Administration Idaho Power Company
Powerex NorthWestern Montana Idaho Power Company SFP
Puget Sound Energy Puget Sound Energy Idaho Power Company
Puget Sound Energy NorthWestern Montana Puget Sound Energy
Portland General Electric NorthWestern Montana Portland General Electric
Portland General Electric Idaho Power Company Bonneville Power Administration
Portland General Electric NorthWestern Montana Bonneville Power Adm inistration
Portland General Electric NorthWestern Montana Bonneville Power Administration SFP
Morgan Stanley Capital Group PacifiCorp Idaho Power Company
Morgan Stanley Capital Group Bonneville Power Administration Idaho Power Company
Morgan Stanley Capital Group Idaho Power Company Bonneville Power Administration
Sierra Pacific Power Company Bonneville Power Administration Idaho Power Company
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04(2)D A Resubmission 04/18/20071:1 t-YH ~
,~. '
v,(fJ ccount 456)(c;ontlnueo)(Including transactions reffered to as 'wtieeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, .
point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and U) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing 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)
FERC Trf No.150 15C
FERC Trf No.860 86C
FERC Trf No.089 08~
FERC Trf No.176 17E
FERC Trf No.
FERC Trf No.200 20C
FERC Trf No.174 17l
FERC Trf No.3,496 3,49E
FERC Trf No.
FERC Trf No.196 19E
FERC Trf No.287 28/
FERC Trf No.
FERC Trf No.
FERC Trf No.
FERC Trf No.119 , 11~
FERC Trf No.518
FERC Trf No.611 611
FERC Trf No.780 , 78C
FERC Trf No.132 132
FERC Trf No.295 29E
FERC Trf No.976 97E
FERC Trf No.666 66E
FERC Trf No.288 28E
FERC Trf No.
FERC Trf No.399 39~
FERC Trf No.188 18E
FERC Trf No.
FERC Trf No.737 737
FERC Trf No.782 782
FERC Trf No.
FERC Trf No.136 13E
FERC Trf No.
FERC Trf No.151 337 151
218 454 585 454,58!
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007, Of r9R
'-':" ,...., .~ ,
(ACCount 456) ((,;ontlnUed)(Including transactions reffered to as 'wheeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)LIne
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
622 622
314 314
282 282
476 476
113 113
540 540
090 090
948 948
340 340
820 820
083 083
260 260
29,400 29,400
699 699
804 804
444 444
53,719 719
776 776
334 334
278 17,278
19,198 19,198
163 163
120 120
559 559
077 077
304 304
949 949
459 983 459 983
156 156
864 864
592 592
376,462 376,462
141,733 356,888 106,660 10,605 281
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
Avista Corporation
(1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
'.01- t:LI::,G I til~11 Y '.,..J~ccount 456.(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, lFP - "long-Term Firm Point to Point
Transmission Service, OlF - Other long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
Sierra Pacific Power Company Bonneville Power Administration Bonneville Power Administration
Sierra Pacific Power Company Chelan Public Utility District Idaho Power Company
3 Sierra Pacific Power Company Bonneville Power Administration NorthWestern Montana
4 Sierra Pacific Power Company Chelan Public Utility District NorthWestern Montana
5 Sierra Pacific Power Company Grant County Public Utility Dist NorthWestern Montana
Sierra Pacific Power Company NorthWestern Montana Bonneville Power Administration
7 Sierra Pacific Power Company Puget Sound Energy Idaho Power Company
8 Sierra Pacific Power Company Bonneville Power Administration Idaho Power Company SFP
9 Sierra Pacific Power Company Grant County Public Utility Dist Idaho Power Company SFP
Cargill Power Markets Bonneville Power Administration Idaho Power Company
Sempra Energy Trading Corp.Bonneville Power Administration Idaho Power Company
Sempra Energy Trading Corp.Bonneville Power Administration Idaho Power Company SFP
Seattle City Light Avista Corporation Bonneville Power Administration SFP
Tacoma Power Avista Corporation Bonneville Power Administration SFP
Vaagen Bros Lumber Vaagen Bros Lumber Idaho Power Company LFP
Pacificorp Pacificorp Pacificorp LFP
Seattle City Light Seattle City Light Bonneville Power Administration LFP
Tacoma Power Tacoma Power Bonneville Power Administration LFP
Spokane Indian Tribes Bonneville Power Administration Spokane Indian Tribes LFP
USBR Bonneville Power Administration East Greenacres LFP
City of Spokane City of Spokane Puget Sound Energy LFP
NorthWestern Energy Avista Corporation NorthWestern Energy LFP
NorthWestern Energy Avista Corporation NorthWestern Energy LFP
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/Q4(2)D A Resubmission 04/18/2007
qF I:.LI:.l,;1 RIr;;ITY t-YH l! I MeH
;;) ,
(ACCount 456)(l,;ontinued)(Including transactions reffered to as 'wtieeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, .
point to point. transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and U) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing 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)
FERC Trf No.150 15C
FERC Trf No.052 05~
FERC Trf No.658 65E
FERC Trf No.
FERC Trf No.330 33C
FERC Trf No.102 10~
FERC Trf No.214 21~
FERC Trf No.236,479 236 47~
FERC Trf No.400 40C
FERC Trf No.290 29C
FERC Trf No.550 55C
FERC Trf No.608 6OE
FERC Trf No.840 84C
FERC Trf No.240 24C
No 228 Colville Substation Lolo-Oxbow 230 kv 282 28.
No 182 Lolo-Oxbow 230 kv Dry Gulch 456 56,45(
FERC Trf No.Main Canal/Summer Fs Bell Substation 221 658 221 65E
FERC Trf No.Main Canal/Summer Fs Bell Substation 221 658 221 65E
FERC Trf No.Sunset Wests ide 826 82E
FERC No. 80.Bell Substation East Greenacres 299 299
No 155 Sunset-Westside 115k Westside 141 325 141 32=
FERC Trf No.Cabinet Gorge Hot Springs 531 531
FERC Trf No.Chelan PUD Hot Springs 127 121
218 454,585 454 58!
FERC FORM NO.1 (ED. 12-90)Page 329.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04(2)DA Resubmission 04/18/2007, OF F9R '-:
,'" ,
(,c ccount 456) (Continued)(Including transactions reffered to as 'wheeling
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)I Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
472 472
740 23,740
729 729
204 204
038 038
446 446
634 634
754,495 754,495
165 165
120 120
200 200
2,455 2,455
580 580
389 389
574 542 743 105 859
279 868 279 868
576,450 576,450
576,450 576,450
539 539
235 235
127 506 32,088 159 594
168 840 168 840
160 83,160
141 733 356,888 106,660 10,605 281
FERC FORM NO.1 (ED. 12-90)Page 330.
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)End of 2006/04
(2)DA Resubmisslon 04/18/2007
TRANSMISSION OF ELECTRICITY BY OTHE S (Account 565)
(Including transactions referred to as "wheeling
1 . Report all transmission , Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-lVIagawan-!,I,emana !;nergy ~mer Total Cost oftiourstioursCharresCharresCharresTrans~issionAuthority (Footnote Affiliations)Classification Received Delivered
(a)(b)(c)(d)(e)(f)
(g)
1 Bonneville Power Admin lFP 172,808 172 808
Bonneville Power Admin lFP 812,746 812 746
3 Bonneville Power Admin lFP 791 646 791 646
Bonneville Power Admin FNS 816,660 486.519 303 179
5 Bonneville Power Admin
, "
309 097
' "
' " 309,097
6 Bonneville Power Admin SFP 140,833 140 833
Bonneville Power Admin 148 148 955 12;215 170
8 Grant PUD OlF 461,160 461 160
Grant PUD I"'::"
" ,'::'
440
,::' ,
v,.,.
Idaho Power
Kootenai Electric Coop lFP 112 112
NorthWestern Energy 835 835 822 822
Northwestern Energy SFP 382 382
Pacificorp
Portland General Elec lFP 642 588 642 588
Portland General Elec SFP 428 428
TOTAL 79,792 876,363 178 519 826,486 881 368
FERC FORM NO. 1/3-0 (REV. 02-04)Page 332
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
TRANSI\ ISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF EN ERG'; EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawan-uemana ~nergy JJtner Total Cost oftioufstiourscharfescharfescharfesTrans~issionAuthority (Footnote Affiliations)Classification Received Delivered
(a)(b)(c)(d)(e)(f)
(g)....
1241 Portland General Elec 478 1,478 484
, ,
e4Q
2 Puget Sound Energy 057 057 767
, ", '" "
57'5 342
Seattle City Light 650 650 600 600
4 Snohomish PUD 795 28,795 448 80,448
5 Tacoma Power 827 827 2,434 2,434
6 TOTAL 792 51,792 10,876 363 178 519 826 486 881 368
TOTAL 79'792 876 363 178 519 826,486 881 368
FERC FORM NO. 1/3-0 (REV. 02-04)Page 332.
Name of Respondent This ~ort Is:Date of ReRort Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2)0 A Resubmission 04/18/2007
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line Descri
ftion
Amount
No.(b)
Industry Association Dues 398,900
Nuclear Power Research Expenses
Other Experimental and General Research Expenses
Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 135,991
Oth Expn ::-=5 000 show purpose, recipient, amount. Group if "$5,000 34:4;618
Community Relations 353,547
Education and Informational 221
Other Miscellaneous General Expenses 244 922
Directors fees and expenses 441;358
, ,
Consulting Fees 13,656
TOTAL 950,213
FERC FORM NO.1 (ED. 12-94)Page 335
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 2006/04(2) riA Resubmission 04/18/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
(Except amortization of aquisition adjustments)
1. Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971 , reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount
account or functional classification , as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant
included in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates , state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Depreciation Amortization of
Line ~reciation Expense for Asset Limited Term Amortization of
No.Functional Classification xpense Retirement Costs Electric Plant Other Electric Total
(Account 403)(Account 403.(Account 404)Plant (Acc 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 751 126 751 126
2 Steam Production Plant 388,514 388 514
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 208,520 208 520
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 625,177 2,450 031 075,208
7 Transmission Plant 049 748 049 748
8 Distribution Plant 17,457 435 457 435
9 Regional Transmission and Market Operation
General Plant 166 338 166,338
Common Plant-Electric 582 059 711 804 293 863
TOTAL 61,477,791 3,462 930 2,450 031 390 752
B. Basis for Amortization Charges
FERC FORM NO.1 (REV. 12-03)Page 336
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaole ~sumaIeo '\leI Applleo Mon:amy Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th
(~)
sandS)
7~f
(pe
rJ)
ent)(Per;tt)ree 7~f
STEAM PLANT
Colstrip No.
311 50,432 35.12.
312 74,021 35.13.43
314 568 34.6.40 16.
315 380 35.6.40 14.
316 698 34.13.
Subtotal 159 099
Colstrip No.
311 49,561 33.13.
312 842 34.15.
314 14,498 31.6.40 17.
315 720 34.16.
316 072 32.15.
Subtotal 119 693
Kettle Falls
310 148 35.
311 538 33.12.
312 891 33.15.
314 134 33.13.
315 262 34.13.
316 397 33.15.
Subtotal 90,370
HYDRO PLANT
Cabinet Gorge
330 7,482 100.93.
331 886 75.44.
332 030 100.75.
333 007 60.52.44
334 180 45.56.20.
335 2,405 45.
336 099 75.31.
Subtotal 79,089
Noxon Rapids
330 974 100.95.
FERC FORM NO.1 (REV. 12-03)Page 337
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2)DA Resubmission 04/18/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle !::sllmatea Net Applleo Monallty Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
la)(In Th
?~)
sandS)
7~~
(pe
rJ)
ent)(pe
r~~nt)r~e 7~f
331 11,496 75.57.
332 31 ,67~100.64.80.
333 347 60.55.
334 664 45.16.42.
335 629 45.17.
336 225 65.47.
Subtotal 120,009
Post Falls
330 732 100.82.
331 613 65.
332 027 90.86.
333 226 60.
334 849 40.11.
335 214 55.48.41
Subtotal 12,661
Long Lake
330 418 100.70.
331 585 75.110.
332 638 95.35.47
333 808 60.28.21.
334 750 45.122.10.
335 388 45.27.23.49
Subtotal 587
Little Falls
330 217 100.81.
331 903 75.13.
332 007 95.57.
333 964 60.
334 662 40.18.10.
335 137 55.21.
Subtotal 15,890
Upper Falls
330 100.60.
331 492 75.
332 790 95.14.77.
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle t:sumalea l'\Iei Appllea MonalilY Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th
?~)
sandS)
7~f
(pe
rg)
ent)(Percent)
YKe 7~~(e)
333 090 60.201.13.
334 776 45.27.
335 107 35.29.
Subtotal 319
Nine Mile
330 100.56.
331 927 75.12.59.
332 841 95.12.74.
333 465 60.18.58.
334 658 45.24.34.
335 282 55.42.
336 625 65.63.
Subtotal 809
Monroe Street
331 189 65.31.65.
332 045 75.34.75.
333 018 60.32.61.72
334 649 45.31.46.
335 45.35.46.
336 65.13.65.
Subtotal 975
OTHER PRODUCTION
Northeast Turbine
341 257 29.0.46
342 589 29.10.
343 090 29.
344 595 29.
345 336 16.
346 241 29.
Subtotal 108
Rathdrum
341 610
342 850
343 658
344 588
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2) DA Resubmission 04/18/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle t:stlmatea Net 1-\pplleU Ivionallly Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th
?~)
sands)
7~f
(pe
rg)
ent)(Percent)
ree 7~~(e)
345 042
Subtotal 748
Kettle Falls CT
342
343 071
344
345
Subtotal 169
Boulder Park
341 725
342 116
343
344 082
345 262
346
Subtotal 236
Coyote Springs 2
341 470
342 153
344 756
345 10,540
346 846
Subtotal 134 765
TRANSMISSION PLANT
350 932
352 974 50.37.
353 143 764 50.25.33.
354 17,069 75.1.40 50.48
355 050 45.33.26.
356 442 55.36.
357 561 60.32.
358 318 60.32.
359 827 75.54.
Subtotal 350 937
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2)DA Resubmission 04/18/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle r.SllmaIea l'IeI AppJlea MOf1aJlIY Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th
?~)
sands)
7~~
(pe
rJ)
ent)(pe
r~fnt)ete 7~f
DISTRIBUTION PLANT
361 10,268 50.10.30.
362 759 40.2.47 R1.27.47
364 165 034 45.31.
365 110 224 50.20.34.
366 076 60.10.49.
367 090 40.17.34.
368 128 124 40.10.23.
369 321 48.10.30.
370 24,207 35.10.23.
373 852 25.10.
373.4 Hi Press Sodium 10,684 20.10.12.
Subtotal 771 639
GENERAL PLANT
390.10 Struc & Improve 973 50.LO.18.
391.1 Comp Hardware 145 20.S1.
393 100 40.2.41 14.
394 766 20.10.4.49
395 997 28.L 1 10.
397 23,952 12.4.42
398 25.
Subtotal 935
MISC POWER
392 013
396 078 7.43
Subtotal 091
TOTAL COMPANY 070,129
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2) FjA Resubmission 04/18/2007
REGULATORY COMMISSION EXPEN
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the current year s expenses that are not deferred and the current year s amortization of amounts
deferred in previous years.
Line Description Assessed by Expenses Total D~terred ,
No.(Furnish name of regulatory commission or body the Regulatory Expense for in Account
Commission Current Year 18~.docket or case number and a description of the case)Utility (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.
5 Fees assessed were a net credit for 2006 due
6 to credits from Other Federal Agencies
7 assessed by the FERC 294 628 047 220,581
9 Washington Utilities and Transportation
Commission: includes annual fee and various
other electric dockets 624 517 366,355 990 872
Includes annual fee and various other natural
gas dockets 349 147 171 097 520,244
Idaho Public Utilities Commission
Includes annual fee and various other electric
dockets 465 237 135 612 600,849
Includes annual fee and various other natural
gas dockets 184 558 354 238,912
Public Utility Commission of Oregon
Includes annual fees and various other natural
gas dockets 392 282 174 713 566,995
Not directly assigned electric 515,809 515 809
Not directly assigned natural gas 185,570 185 570
TOTAL 721 113 677 557 398 670
FERC FORM NO.1 (ED. 12-96)Page 350
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
REG JLATORY COMMISSION EXPENSES (Continued)
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25 000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to Contra Amount Deferred in LineDepartment~~~m Amoum Account 182.Account Account 182.No.End of Year
(f)
(g)
(h)(i)(k)(I)
Electric 928 220,581
Electric 928 990,872
Gas 928 520,244
Electric 928 600 849
Gas 928 238,912
Gas 928 566 995
Electric 928 515 809
Gas 928 185 570
398 670
FERC FORM NO.1 (ED. 12-96)Page 351
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/18/2007
DISTRIBUTION OF SALARIES AND AGES
Report below the distribution of total salaries and wage~ for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Year/Period of Report
End of 2006/04
(a)
Direct PayrollDistribullon
(b)
TotalLine
No.
Classification
Electric
Operation
Production
Transmission
Regional Market
Distribution
7 Customer Accounts
8 Customer Service and Informational
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 Accounts (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 Main!. (Total of lines 20 thru 27)
29 Gas
30 Operation
31 Production-Manufactured Gas
32 Production-Na!. 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
300,368
329,149
300,182
428,000
11,299 946
32,686 832
858,729
329,149
300,182
428 000
299 946
412 037
622 963
118 112
107 851
229,011
976,260
10,695,170
FERC FORM NO.1 (ED. 12-88)Page 354
Name of Respondent
A vista Corporation
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
DIST IBUTION OF SALARIES AND WAG S (Continued)
Year/Period of Report
End of 2006/04
Line Classification
(a)
Direct Payroll
Distribution
(b)
Total
48 Distribution
49 Administrative and General
50 TOTAL Main!. (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 Main!. (Total of lines 52 thru 61)
63 Other Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dep!. (Total of lines 28, 62, and 64)
66 Utility 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 Utility 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 Accounts (Specify, provide details in footnote):
78 Stores Expense (163)
79 Regulatory assets (182)
80 Preliminary Survey and Investigation (183)
81 Small tools expense (184)
82 Miscellaneous Deferred Debits (186)
83 Non-operating expenses (417)
84 Expenditures of Certain Civic, Political and Related Activiti
85 Employee Incentive Plan (232380)
86 DSM Tariff Rider and Payroll Equalization (242600, 242700)
95 TOTAL Other Accounts
96 TOTAL SALARIES AND WAGES
619 584
389
405,430
893,587
118,112
107,851
229,011
976,260
371 224
20,789,909 307 960 097 869
810,892 042 614 853 506
600 801 350,574 951 375
\~llf&Jt: :i,;L'ji~;jj;i2iIjli8 ii",
' c
Ql8 01'ic ill:i1.L.li.2L:J2J.
977 111 231 323 208 434
80,663 097 760
057 774 250,420 308 194
1,455 434 455,434
322 343 322 343
48,931 931
761 334 761 334
374 771 374 771
782 046 782 046
224 544 224 544
113,207 113 207
069,403 13,167,465 901 938
46,054 151
127,495,987
22,497 440 556 711
127,495,990
FERC FORM NO.1 (ED. 12-88)Page 355
Name of Respondent
Avista Corporation
This Report Is:
(1) 00 An Original(2) D A Resubmission
Date of Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/04
COMMON UTILITY PLANT AND EXPENSES
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to
the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including
explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
1 & 2. Common Plant in service and accumulated provislon for depreciation
Acct. No. Description303 Intangible389 Land and Land Rights390 Structures and Improvements391 Office Furniture and Equipment392 Transportation Equipment393 Stores Equipment394 Tools, Shop & Garage Equipment395 Laboratory Equipment396 Power Operated Equipment397 Communications Equipment398 Miscellaneous Equipment399 Asset Retirement Cost
Total Common Plant
Const. Work in Progress
Total Utility Plant
Acc. Provo for Dep. & Amort.
Net Utility Plant
14,542,838
063,259
33,906,705
20,749,481
003,825
952,913
067,942
867,917
384,046
13,593,674
650,006
351,680
----------
93,134 286
620,552
----------
99,754,838
23,348,352
----------
76,406,486
Acct. No.Description
3. Common Expenses allocated to Electric and Gas departments:
----------
901
902
903
903.90-99
904
905
907
Cust acct/collect supervlsion
Meter reading expenses
Cust reG & collectn expenses
AIR misc fees
Uncollectible accounts
Misc Gust acct expenses
Cust svce & Info exp supervlsion
908
909
910
911
912
913
Cust assistance expenses
Info & instruct advert expenses
Misc Gust serv & info expenses
Sales expense -supervislon
Demo and selling expenses
Advertising expenses
FERC FORM NO.1 (ED. 12-87)
Total Electric Gas
961 068
404,580
10,567,606
224,430
888,130
342,083
511,548
120 407
786 745
665,314
537,265
182,081
449,520
284,173
780,861
559,116
350,865
160,002
786,473
039
171,860
837 230
426 353
489,765
569
107,036
521,372
265,537
296,708
470
64,824
315,858
160,816
Page 356
#of Gust & yr end
#of Gust & yr end
#of Gust & yr end
net direct plant
#of Gust & yr end
#of Gust & yr end
#of Gust & yr end
#of Gust & yr end
#of Gust & yr end
#of Gust & yr end
#of Gust & yr end
#of Gust & yr end
#of Gust & yr end
Name of Respondent
Avista Corporation
This Report Is:
(1) 00 An Original(2) D A Resubmission
Date of Report
(Mo, Da, Yr)
04/18/2007
COMMON UTILITY PLANT AND EXPENSES
Year/Period of Report
End of 2006/04
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to
the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including
explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
916
920
921
922
923
924
925
926
927
928
929
930.
930.
931
935
403
404
Misc sales expenses
Admin & gen salaries
Office supplies & expenses
Admin expenses tranf-credi t
Outside services employed
Property insurance
InJuries and damages
Employee pensions&benefi ts
Franchise requirement
Regulatory commiss~on expenses
Duplicate charges-credi t
General advertising expenses
Misc general expenses
Rents
Maint of general plant
Depreciation
Amort of LTD term plant
231,135
22,169,978
462,275
13,388,769
301,293
828,914
33,816,948
701,390
10,822
873,995
469,326
841,105
771,139
327,687
143,953
16,353,914
018,255
846,945,
956,984
629,828
949,382
515,809
679
886,435
068,064
345,465
582,059
711,804
87,182
816,064
444,020
541,824
344,309
199,086
867,566
185,581
143
987,560
401,262
495,640
189,080
615,883
#of cust ~ yr end
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
Note 1: The 4 factor allocator is made up of 25% each -customer counts, direct labor , direct O&M & Net
direct plant
Letters of approval received from staffs of State Regulatory Commissions in 1993
FERC FORM NO.1 (ED. 12-87)Page 356.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmlssion 04/18/2007
PURCHASES AND SALES OF ANCILLAR SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.
(5) On lines 5 and 6 , columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during
the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant
Unit of Unit of
linE Type of Ancillary Service Number of Units Measure Dollars Number of Units Measure Dollars
No.(a)(b)(c)(d)(e)(f)
(g)
1 Scheduling, System Control and Dispatch 577 117 189
2 Reactive Supply and Voltage 577 091
3 Regulation and Frequency Response 305,195 MWh 100,315 762 641 554
4 Energy Imbalance 720 848 126
5 Operating ReselVe - Spinning 995 MWh 437 714
6 Operating ReselVe - Supplement 678 MWh 887 134 568 MWh 103,916
7 Other 532 736 13,702 658 532 736 13,702 658
8 Total (Lines 1thru 7)839,763 973 140 772 781 733 968
FERC FORM NO.1 (New 2-04)Page 398
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
M NTHL Y 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 U) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for
the definition of each statistical classification.
Name of Respondent
A vista Corporation
Year/Period of Report
End of 2006/04
NAME OF SYSTEM:
Monthly Peak
MW - Total
Line
No.Month
Day of Hour of
Monthly MonthlyPeak Peak
(d)
1800
900
1900
(a)
1 January
2 February
3 March
(b)
; l::lii2,,\Llc QL;;4 Total for Quarter
5 April
6 May
7 June
8 Total for Quarter 2
9 July
10 August
11 September
12 Total for Quarter 3
13 October
14 November
15 December
16 Total for Quarter 4
17 Total Year
DateNear 20,
FERC FORM NO. 1/3-0 (NEW. 07-04)
Firm Network Firm Network Long-Term Firm Other Long-Short-Term Firm Other
Service for Sen Service for Point-to-point Term Firm Point-to-point Service
Others Reservations Service Reservation
(e)(f)
(g)
(h)(i)
1,475 238 146 316 226
656 312 146 316
1,427 263 146 316
558 813 438 948 284
234 242 146 322 129
387 265 147 322 382
531 280 149 322 457
152 787 442 966 457 540
590 266 271 346 105
445 242 270 257
339 239 270 150
374 747 811 128 753 244
369 281 269 122
585 345 268
471 308 268
4,425 934 805 106 172
509 281 496 148 382 154
Page 400
Name of Respondent
A vista Corporation
This ~ort Is:(1) ~An Original
(2) A Resubmission
ELECTRIC ENERGY ACCOU T
Date of Report(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/04
Line
No.
Item
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
(a)
1 SOURCES OF ENERGY
2 Generation (Excluding Station Use):
3 Steam
4 Nuclear
5 Hydro-Conventional
6 Hydro-Pumped Storage
7 Other
8 Less Energy for Pumping
9 Net Generation (Enter Total of lines 3
through 8)
10 Purchases
11 Power Exchanges:
12 Received
13 Delivered
14 Net Exchanges (Line 12 minus line 13)
15 Transm ission For Other (Wheeling)
16 Received
17 Delivered
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transm ission By Others Losses
20 TOTAL (Enter Total of lines 9,10,
and 19)
FERC FORM NO.1 (ED. 12-90)
MegaWatt Hours
(b)
Page 401a
Line
No.
Item
(a)
21 DISPOSITION OF ENERGY
22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
23 Requirements Sales for Resale (See
instruction 4, page 311.
24 Non-Requirements Sales for Resale (See
instruction 4, page 311.
25 Energy Furnished Without Charge
26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
27 Total Energy Losses
28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EOUAL LINE 20)
MegaWatt Hours
(b)
787,002
552 362
688
559,724
911 776
This ~ort Is:(1) ~An Original(2) DA Resubmission
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 on line 2 by month the system s output in Megawatt hours for each month.
(3) Report on line 3 by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
(4) Report on line 4 by month the system s monthly maximum megawatt load (60 minute integration) associated with the system.
(5) Report on lines 5 and 6 the specified information for each monthly peak load reported on line 4.
Name of Respondent
A vista Corporation
Date of Report
(Mo, Da, Yr)
04/18/2007
Year/Period of Report
End of 2006/04
NAME OF SYSTEM:
Line Monthly Non-Requirments MONTHLY PEAKSales for Resale &No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(f)
29 January 061,457 201 639 1,475 1800
30 February 048,377 253,049 656 900
31 March 217,058 405,956 1 ,427 1900
32 April 105 703 409,822 234 800
33 May 264 757 550 892 387 1700
34 June 212 576 503,147 531 1600
35 July 178 059 359 034 642 1600
36 August 915 009 136 728 1 ,490 1700
37 September 809 214 117,186 378 1700
38 October 855 134 108 333 1 ,424 800
39 November 097 328 281 695 646 1800
40 December 147 104 224 881 528 1900
TOTAL 911,776 552 362
FERC FORM NO.1 (ED. 12-90)Page 401 b
Name of Respondent
A vista Corporation
Year/Period of Report
End of 2006/Q4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2007
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25 000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item Plant
Name: CoYQtifSprfngsg
. (b)
.: ';'."' ", '
i";
';.,.",,: ";;"
Gas Turbine
Not Applicable
2003
2003
287.
304
5647
279
279
244
1458982000
11294927
148162389
159457316
555.6004
776586
82419671
1737816
19223
66259
8459
1232448
3648
86256814
0591
(a)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
2 Type of Constr (Conventional, Outdoor, Boiler, etc)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
6 Net Peak Demand on Plant - MW (60 minutes)
7 Plant Hours Connected to Load
8 Net Continuous Plant Capability (Megawatts)
9 When Not Limited by Condenser Water
10 When Limited by Condenser Water
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - KWh
13 Cost of Plant: Land and Land Rights
14 Structures and Improvements
15 Equipment Costs
16 Asset Retirement Costs
17 Total Cost
18 Cost per KW of Installed Capacity (line 17/5) Including
19 Production Expenses: Oper, Supv, & Engr
20 Fuel
21 Coolants and Water (Nuclear Plants Only)
22 Steam Expenses
23 Steam From Other Sources
24 Steam Transferred (Cr)
25 Electric Expenses
26 Misc Steam (or Nuclear) Power Expenses
27 Rents
28 Allowances
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Boiler (or reactor) Plant
32 Maintenance of Electric Plant
33 Maintenance of Misc Steam (or Nuclear) Plant
34 Total Production Expenses
35 Expenses per Net KWh
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
38 Quantity (Units) of Fuel Burned
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
40 Avg Cost of FueVunit, as Delvd to.b. during year
41 Average Cost of Fuel per Unit Burned
42 Average Cost of Fuel Burned per Million BTU
43 Average Cost of Fuel Burned per KWh Net Gen
44 Average BTU per KWh Net Generation
Gas
MCF
10049208
1020000
202
202
041
057
7026.000
000
000
000
000
000
000
000
000
000
000
FERC FORM NO.1 (REV. 12-03)Page 402
Plant
Name: Spokane N.E.
(c)
Gas Turbine
Not Applicable
1978
1978
61.
1863000
129664
256733
13034242
13420639
217.1624
25507
162814
19977
11314
22314
869041
149599
16572
460944
2474
Gas
MCF24120
1020000 0750 0.000750 0.000618 0.000087 0.000
13206.000 0.000
000
000
000
000
000
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)2006/04(2)DA Resubmission 04/18/2007 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, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name: Kettle Falls Name:Co/strip Name:Rathdruin No.
(d)(e)(f)
,, , '
ii:
";' .' ;,' "' " """ "' ." ";, ',\ "
Steam Steam Gas Turbine
Conventional Conventional Not Applicable
1983 1984 1995
1983 1985 1995
50.233.40 166.
222 143
7777 8738 494
222 176
222
222
210
353813000 1578798000 21789000
941300 1296910 621682
24524528 99987413 3186951
65886972 184739181 55800831
1114206
92467006 286023504 59609464
1823.8068 1225.4649 358.0148
139983 115243 17689
1 0489971 14953795 1655935
514671 1205731
16016
772066 11407 120122
338784 1357913 168172
19628
79088 354380 2903
50096 454469 17482
1428261 4432308
204600 444902 57466
168202 534244 1 09256
14185722 23900036 2149025
0401 0151 0986
Wood Gas Coal Oil Gas
Tons Mcf Tons BBL MCF
517242 6846 1018938 4019 274097
8500000 1020000 16902000 140000 1020000
20.188 998 000 14.422 64.310 000 041 000 000
20.188 998 000 14.422 64.310 000 041 000 000
380 861 000 850 10.860 000 923 000 000
030 082 000 009 000 000 076 000 000
12468.000 12468.000 000 10916.000 10916.000 000 12831.000 000 000
FERC FORM NO.1 (REV. 12-03)Page 403
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation
(1) An Original (Mo, Da, Yr)2006/Q4(2)DA Resubmission 04/18/2007 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facility.4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.5. If any employees attend
rnore than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
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.
6 Net Peak Demand on Plant - MW (60 minutes)
7 Plant Hours Connected to Load 968
8 Net Continuous Plant Capability (Megawatts)
When Not Limited by Condenser Water
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 17262000
Cost of Plant: Land and Land Rights 144733
Structures and Improvements 724602
Equipment Costs 30535371
Asset Retirement Costs
Total Cost 31404706
Cost per KW of Installed Capacity (line 17/5) Including 1276.6141 0000
Production Expenses: Oper, Supv, & Engr 21596
Fuel 1192385
Coolants and Water (Nuclear Plants Only)
Steam Expenses
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 69617
Misc Steam (or Nuclear) Power Expenses 9742
Rents
Allowances
Maintenance Supervision and Engineering 11138
Maintenance of Structures 441
Maintenance of Boiler (or reactor) Plant
Maintenance of Electric Plant 179591
Maintenance of Misc Steam (or Nuclear) Plant 46498
Total Production Expenses 1531008
Expenses per Net KWh 0887 0000
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas
Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)MCF
Quantity (Units) of Fuel Burned 165682
Avg Heat Cont - Fuel Burned (btulindicate if nuclear)1020000
Avg Cost of Fuel/unit, as Delvd to.b. during year 197 000 000 000 000 000
Average Cost of Fuel per Unit Burned 197 000 000 000 000 000
Average Cost of Fuel Burned per Million BTU 056 000 000 000 000 000
Average Cost of Fuel Burned per KWh Net Gen 069 000 000 000 000 000
Average BTU per KWh Net Generation 9790.000 000 000 000 000 000
FERC FORM NO.1 (REV. 12-03)Page 402.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)2006/04(2)DA Resubmission 04/18/2007 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, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32
, "
Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam , nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name:Name:Name:No.
(d)(e)(f)
0000 0000 0000
0000 0000 0000
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 000 000 000
FERC FORM NO.1 (REV. 12-03)Page 403.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2006/04(2)DA Resubmission 04/18/2007 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10 000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 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)
" "';., ,;., , " ", ',
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)14.10.
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load 667 503
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
(b) Under the Most Adverse Oper Conditions
Average Number of Employees
Net Generation, Exclusive of Plant Use - Kwh 106 272 000 785 000
Cost of Plant
Land and Land Rights 081 854
Structures and Improvements 391 897 491 800
Reservoirs, Dams, and Waterways 045 079 124,352
Equipment Costs 704 055 972 999
Roads, Railroads, and Bridges 448
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)191,479 671 005
Cost per KW of Installed Capacity (line 20 / 5)972.3972 067.1005
Production Expenses
Operation Supervision and Engineering 307 925
Water for Power
Hydraulic Expenses 15,229 525
Electric Expenses 405 695 388,145
Misc Hydraulic Power Generation Expenses 32,600 540
Rents
Maintenance Supervision and Engineering 668 280
Maintenance of Structures 932 339
Maintenance of Reservoirs, Dams, and Waterways 626 38,955
Maintenance of Electric Plant 350 582
Maintenance of Misc Hydraulic Plant 340 501
Total Production Expenses (total 23 thru 33)599,747 611,792
Expenses per net KWh 0056 0089
FERC FORM NO.1 (REV. 12-03)Page 406
Name of Respondent
A vista Corporation
Year/Period of Report
End of 2006/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) DA Resubmission 04/18/2007
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. '2058
Plant Name: Cabinet Gorge
(d)
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.
261
760
Storage
Outdoor
1959
1977
473.40
542
171
Storage
Conventional
1915
1924
70.
7,495
016,640
949,715
21,568,895
39,693,938
098,564
327 752
310.4365
35,377 056
985,734
681 238
011 357
225 369
128 280 754
270.9775
597,959
638,486
638,010
032 490
906 945
455.8135
118 565
210
863,767
219,719
78,174
114 258
024
615 339
542
115 598
0018
93,170
203
981 051
184 514
077
805
812
041 970
261 831
762,433
0015
500
308
497,402
635
913
561
160
136 085
242
819 806
0015
FERC FORM NO.1 (REV. 12-03)Page 407
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
A vista Corporation (1) An Original (Mo, Da, Yr)2006/04(2)0 A Resubmission 04/18/2007 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10 000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.';2p45 , FERC Licensed Project No. ,2545 .
No.Plant Name: Nine Mile Falls Plant Name: Post Falls
(a)(b)(c)
" ", ,' ," '.."
Kind of Plant (Run-of-River or Storage)Run-of-River Storage
Plant Construction type (Conventional or Outdoor)Conventional Conventional
Year Originally Constructed 1908 1906
Year Last Unit was Installed 1994 1980
Total installed cap (Gen name plate Rating in MW)26.40 14.
Net Peak Demand on Plant-Megawatts (60 minutes)
Plant Hours Connect to Load 755 759
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
(b) Under the Most Adverse Oper Conditions
Average Number of Employees
Net Generation, Exclusive of Plant Use - Kwh 110,083,000 841,000
Cost of Plant
Land and Land Rights 33,429 076 554
Structures and Improvements 943,110 701 848
Reservoirs, Dams, and Waterways 840,543 044,594
Equipment Costs 383,935 343 557
Roads, Railroads, and Bridges 625,181
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)28,826 198 13,166,553
Cost per KW of Installed Capacity (line 20 091.9014 892.6477
Production Expenses
Operation Supervision and Engineenng 101 219 861
Water for Power
Hydraulic Expenses 3,424 590
Electric Expenses 468,590 445 025
Misc Hydraulic Power Generation Expenses 51,787 458
Rents
Maintenance Supervision and Engineering 901
Maintenance of Structures 373 159
Maintenance of Reservoirs, Dams, and Waterways 120,745 447
Maintenance of Electric Plant 69,642 103,376
Maintenance of Misc Hydraulic Plant 050 267
Total Production Expenses (total 23 thru 33)821,852 742 084
Expenses per net KWh 0075 0077
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
A vista Corporation
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2007
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Year/Period of Report
End of 2006/04
FERC Licensed Project No.
Plant Name: Little Falls
(d)
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
(e)
Run-of-River
Conventional
1910
1911
32.
533
325,371
919,660
025,360
838 902
109 293
503.4154 0000 0000
28,428
613
393,162
30,261
597,788
28,477
342
136,561
134,386
235
385,253
0062 0000 0000
FERC FORM NO.1 (REV. 12-03)Page 407.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)2006/04(2)DA Resubmission 04/18/2007 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10 000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.FERC Licensed Project No.
No.Plant Name:Plant Name:
(a)(b)(c)
1 Kind of Plant (Run-of-River or Storage)
Plant Construction type (Conventional or Outdoor)
Year Originally Constructed
Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
(b) Under the Most Adverse Oper Conditions
Average Number of Employees
Net Generation, Exclusive of Plant Use - Kwh
Cost of Plant
Land and Land Rights
Structures and Improvements
Reservoirs, Dams, and Waterways
Equipment Costs
Roads, Railroads, and Bridges
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)
Cost per KW of Installed Capacity (line 20 / 5)0000 0000
Production Expenses
Operation Supervision and Engineenng
Water for Power
Hydraulic Expenses
Electric Expenses
Misc Hydraulic Power Generation Expenses
Rents
Maintenance Supervision and Englneenng
Maintenance of Structures
Maintenance of Reservoirs, Dams, and Waterways
Maintenance of Electric Plant
Maintenance of Misc Hydraulic Plant
Total Production Expenses (total 23 thru 33)
Expenses per net KWh 0000 0000
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
A vista Corporation
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/18/2007
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.
6. Report as a separate plant any plant equipped with combinations of steam , hydro, internal combustion engine, or gas turbine equipment.
YearlPeriod of Report
End of 2006104
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
(d)(e)
0000 0000 0000
0000 0000 0000
FERC FORM NO.1 (REV. 12-03)Page 407.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation
(1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
G NERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10 000 Kw installed capacity (name plate rating).2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission , or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project,
give project number in footnote.
Line Year Installed ca~aclty l'!etPea~Net GenerationName of Plant Orig.Name Plate atin!Demand Excluding Cost of PlantNo.Const.(InMW)Plant Use
(a)(b)(c)(60(mln.(e)(f)
Kettle Falls CT 2002 182 000 169,338
FERC FORM NO.1 (REV. 12-03)Page 410
Name of Respondent This 78Jort Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04(2)DA Resubmission 04/18/2007
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11
Page 403.4. If net peak demand for 60 minutes is not available, give the which is available, specifying period.5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset Operation Production Expenses Fuel Costs (in cents LineRetire. Costs) Per MW Exc l. Fuel Fuel Maintenance Kind of Fuel (per Million Btu)
(g)
(h)(i)(k)(I)No.
273,519 60,029 104 842 930 Nat Gas 760
FERC FORM NO.1 (REV. 12-03)Page 411
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04(2) riA Resubmission 04/18/2007
TRANSMISSION LINE STATIST
1. Report information concerning transmission lines, cost of lir:'es, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
)(O!,.T~GE (K':::)LENG;hH role miles)Line JIUI\I Type of(Indicate wtiere ~In t e ascf of NumberNo.other than u dergroun lines
60 cvcle 3 phase)Supporting report circuit miles)
I un ,?lfl,lcmre t:!tru~fWes CircuitsFromOperatingDesignedStructureof Line 'Ll1ot erDesi
Rrated
Ine(a)(b)(c)(d)(e)
(g)
(h)
1 Group Sum 60.60.1.00
3 Group Sum 115.115.541.00
5 Beacon Sub #4 BPA Bell Sub 230.230.Steel Tower
6 Beacon Sub BPA Bell Sub 230.230.H Type
7 Beacon Sub #5 BPA Bell Sub 230.230.H Type
8 Beacon Cabinet Gorge Plant 230.230.Steel Tower 1.00
9 Beacon Cabinet Gorge Plant 230.230.Steel Pole 25.
Beacon Cabinet Gorge Plant 230.230.H Type 52.
Beacon Sub Lolo Sub 230.230.Steel Tower
Beacon Sub Lolo Sub 230.230.H Type 108.
Noxon Plant Pine Creek Sub 2~0.230.H Type 43.
Cabinet Gorge Plant Noxon 230.230.H Type 19.
Benewah Sw. Station Pine Creek Sub 230.230.SteelTower
Benewah Sw. Station Pine Creek Sub 230.230.H Type 43.
Divide Creek Lolo Sub 230.230.Steel Tower
Divide Creek Lolo Sub 230.230.H Type 43.
N. Lewiston Walla Walla 230.230.Steel Tower
N. Lewiston Walla Walla 230.230.H Type 32.
N. Lewiston Shawnee 230.230.Steel Tower
N. Lewiston Shawnee 230.230.H Type 27.
Walla Walla Wanapum 230.230.Alum.
Walla Walla Wanapum 230.230.H Type 78.
BPA (Libby)Noxon Plant 230.230.Steel Tower
BPAlHot Springs #1 Noxon Plant 230.230.Steel Tower
BPAlHot Springs #2 Noxon Plant (dead)230.230.Steel Tower
BPAlHot Springs #2 Noxon Plant 230.230.H Type 68.
BPA Line West Side Sub 230.230.Steel Pole
Hatwai N. Lewiston Sub 230.230.H Type
Divide Creek Imnaha 230.230.H Type 20.
Colstrip Plant Broadview 500.500.
TOTAL 135.
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. ~eport Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns OJ to (I) on the book cost at end of year.
\,;V::'I VI" LINt:: (InCIUae In Column OJ Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)(k)(I)(m)(n)
(p)
136,03E 092 206 130
396 24C 782 372 178 612 169 814 509 508 679,32~
795 McMACSR 91;:307 926 325,839
1272 McMACSR
1272 McMAL 744 943 826 962 070 319 389
795 McMACSR
1590 ACSS
1795 McMACSR 324 007 864 36,332,191 45,477 45,541:
1795 McMACSR
1272 McMAL 456,16,696 327 152,489 743 742
~54 McMAL 105,64 15,480 045 585 692 834 814 641:
~54 McMAL 49,04(066 610 115,659 291 969 291,96S
~54 McMAL
~54 McMAL 157 596,882 754 075 773 822 59~
1272 McMAL
1272 McMAL 228 646 297 732 525 113 112
1272 McMAL
1272 McMAL 623,984 821,525 445 509 645 789 9,434
1272 McMAL
1272 McMAL 872,151 568 673 8,440 824 133 420 552
1272 McMAL
1272 McMAL 781 2,432 304 503 085 231 513 10,744
1272 McMAL
1272 McMAL 521 521 838 668 50E
1272 McMAL
1272 McMAL 144 63E 286 268 3,430 906 824 824
1272 McMAL 36,461 587 224 623 685
1272 McMACSR 106 581 2,498 680 605,261
1272 McMAL 30"297,448 357 750
595,78(28,260 542 856 331 755 201 614 65,802 366,171
321 503 198,171 ,543 208,493 046 301 101 153 656 802 520 559
FERC FORM NO.1 (ED. 12-87)Page 423
Name of Respondent This (8Jort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation , designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
STATE OF WASHINGTON
Airway Heights Distr. Unattended 115.13.
Barker Road Distr. Unattended 110.13.
Beacon Trnsm. Unattended 230.115.13.
Boulder Trnsm. Unattended 230.115.13.
Chester Distr. Unattended 115.13.
Chewelah 115Kv Distr. Unattended 115.13.
Colbert Distr. Unattended 115.13.
College & Walnut Distr. Unattended 115.13.
Colville 115Kv Distr. Unattended 115.13.
Dry Creek Trnsm. Unattended 230.115.13.
Dry Gulch Distr. Unattended 115.13.
East Colfax Distr. Unattended 115.13.
East Farms Distr. Unattended 115.13.
Fort Wright Distr. Unattended 115.13.
Francis and Cedar Distr. Unattended 115.13.
Gifford Distr. Unattended 115.34.
Glenrose Distr. Unattended 115.13.
Greenwood Distr. Unattended 115.13.
Hallett & White 115-13kv Distr. Unattended 115.13.
Industrial Park Distr. Unattended 115.13.
Kettle Falls Distr. Unattended 115.13.
Lee & Reynolds Distr. Unattended 115.13.
Liberty Lake Distr. Unattended 115.13.
Little Falls 115/34Kv Distr. Unattended 115.34.
Lyons & Standard Distr. Unattended 115.13.
Mead Distr. Unattended 115.13.
Metro Distr. Unattended 115.13.
Milan Distr. Unattended 115.13.
Millwood Trnsm & Dist Unattd 115.60.13.
Ninth & Central Distr. Unattended 115.13.
Northeast Distr. Unattended 115.13.
Northwest Distr. Unattended 115.13.
Opportunity Dist. Unattended 115.13.
Othello Distr. Unattended 115.13.
Post Street Distr. Unattended 115.13.
Pound Lane Distr. Unattended 115.13.
Pullman Dist Unattended 115.13.
Ross Park Distr. Unattended 115.13.
FERC FORM NO.1 (ED. 12-96)Page 426
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/Q4
(2)DA Resubmission 04/18/2007
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
Increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease , and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
Frcd Oil & Air Fan
Two Stage Fan
536 Frcd Oil & Air Fan 4 .560
150 Two Stage Fan 250
Frcd Oil & Air Fan
Frcd Ai
Frcd Oil & Air Fan
Two Stage Fan
Frcd Oil & Air Fan
150 Two Stage Fan 250
Fred Oil & Air Fan
FrOil/Air Fan
Two Stage Fan
Fr Oil/Air/2StgFan
Frcd Air Fan
Frcd Oil & Air Fan
FrOil/Air/Two Stage
Two Stg Fan
Two Stg/PtlFrcd Oil
Frcd Oil & Air Fan
Two Stage Fan
Two Stage Fan
Two Stage Fan
Two Stage Fan
Two Stage Fan
Frcd Oil & Air Fan
FrcAir/FrcOiVAirFan
Frcd & Two Stage Fan
Two Stage Fan
Two Stage Fan
Two Stage Fan
FrOiVAirFan
Frcd Oil & Wt Fan
Two Stage Fan
Frcd Oil & Air Fan
Two Stage Fan
FERC FORM NO.1 (ED. 12-96)Page 427
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
Roxboro Distr. Unattended 115.24.
Shawnee Trans. Unattended 230.115.
Silver Lake Distr. Unattended 115.13.
Southeast Distr. Unattended 115.13.
South Othello Distr. Unattended 115.13.
South Pullman Distr. Unattended 115.13.
Sunset Distr. Unattended 115.13.
Third & Hatch Distr. Unattended 115.13.
Waikiki Distr. Unattended 115.13.
West Side Trans. Unattended 230.115.13.
Other: 72substa less than 10MVA Distr. Unattended
STATE OF IDAHO
Appleway Dist & Trfr Unattnd 115.13.
Benewah Trans. Unattended 230.115.13.
Big Creek Distr. Unattended 115.13.
Blue Creek Distr. Unattended 115.13.
Bunker Hill Distr. Unattended 115.13.
Clark Fork Distr. Unattended 115.21.
Coeur d'Alene 15th Ave Distr. Unattended 115.13.
Cottonwood Distr. Unattended 115.24.
Dalton Distr. Unattended 115.13.
Grangeville Dist & Trfr Unattnd 115.13.
Holbrook Distr. Unattended 115.13.
Huetter Distr. Unattended 115.13.
Juliaetta Distr. Unattended 115.13.
Kamiah Dist & Trfr Unattnd 115.13.
Kooskia Distr. Unattended 115.13.
Lolo Tran & Dist Unattnd 230.115.13.
Moscow Distr. Unattended 115.13.
Moscow 230Kv Tran & Dist Unattnd 230.115.13.
North Moscow Distr. Unattended 115.13.
North Lewiston Trans Unattended 230.115.13.
North Lewiston Distr. Unattended 115.13.
aden Distr. Unattended 115.21.
Oldtown Distr. Unattended 115.21.
Orofino Distr. Unattended 115.13.
Osburn Distr. Unattended 115.13.
Pine Creek Tran & Dist Unattnd 230.110.13.
Pleasant View Distr. Unattended 115.13.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/Q4
(2)DA Resubmission 04/18/2007
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transform ers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)
(g)
(h)(i)(k)
Two Stage Fan
250
Frcd Oil & Air Fan
Two Stage Fan
Two Stage Fan
Two Stage Fan 240
PI. & Two Stage Fan
Two Stg Fan & Cap 103
Two Stage Fan
250
186 136
Two Stage Fan
125
Portable Fan
Fred Air Fan
Fred Air Fan
Two Stage Fan
Two Stage Fan
FrcOil/Air2StgFan
FrcdOiVAir/Pt Fan
Two Stage Fan
Two Stage Fan
Frcd Oil & Air Fan
Two Stage Fan
Frcd Air Fan
270 Frcd Oil/Air/Two Stg 262
FrOil/Air/2Stg Fan
137 Capacitors 182
Two Stage Fan
250 Frcd Oil/Air&Cptrs 295
Frcd Air Fan
Frcd Air Fan
Frcd Oil & Air Fan
Portable Fan
262 Capacitors 307
Two Stage Fan
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/04
(2)0 A Resubmission 04/18/2007
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
Post Falls Distr. Unattended 115.13.
Potlatch Dist & Trfr Unattnd 115.13.
Prarie Distr. Unattended 115.13.
Priest River Distr. Unattended 115.20.
Sandpoint Distr. Unattended 115.20.
South Lewiston Distr. Unattended 115.13.
Sweetwater Distr. Unattended 115.24.
St. Maries Distr. Unattended 115.24.
Tenth & Stewart Distr. Unattended 115.13.
Wallace Dist & Whse Unattnd 115.13.
Rathdrum Tran & Dist Unattnd 230.115.13.
Other: 29 substa less than 10 MV A Distr. Unattended
STATE OF MONTANA
1 substation less than 10 MVA Distr. Unattended
SUBSTA. qy GENERATING PLANTS
STATE OF WASHINGTON
Boulder Park Trans Step-115.13.
Kettle Falls Trans Step-115.13.
Long Lake Trans.115.
Nine Mile Trns Step-Up & Dist 115.60.
Little Falls Trans.115.
Northeast Trans. Step-115.13.
STATE OF IDAHO
Cabinet Gorge (Switchyard)230.115.13.
Cabinet Gorge (HED)Trans. Step-230.13.
Post Falls Trans. Step-115.
Rathdrum Trans. Step-115.13.
STATE OF MONTANA
Noxon Trans. Step-230.13.
STATE OF OREGON
Coyote Springs II Trans. Step -500.13.18.
SUMMARY:
Washington:
10 subs Trans. Unattended
113 subs Distr. Unattended
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/Q4(2)DA Resubmission 04/18/2007
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT 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)(k)
Two Stage Fan
Portable Fan
Fred Oil & Air Fan
Frcd Air Fan
Frcd Air Fan
Port Fan/FrcdOil/Air
Frcd Oil & Air Fan
Two Stage Fan
Fred Oil/Airrrwo Stg
462 FrcdOil/AirFan/Cptrs 243 470
Two Stage Fan
Two Stage Fan
Frcd Oil & Air Fan
Fred Oil & Air Fan
Two Stage Fan
125 2 stage fan
Fred Oil and Air Fan
Frcd Air/OiVAir Fan
114 Two Stage Fan 190
532 Frcd Oil Ai 555
213 Two Stage fan 355
1039
1174
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
Avista Corporation
(1) X An Original (Mo, Da, Yr)End of 2006/04
(2)DA Resubmission 04/18/2007
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page , summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
3 subs Tran & Dist Unattnd
Idaho:
6 subs Trans. Unattended
56 subs Distr. Unattended
9 subs Tran & Dist Unattnd
Montana:1 sub Trans. Unattended
1 sub Distr. Unattended
Oregon:1 sub Trans. Unattended
System: 200 subs
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
A vista Corporation (1) X An Original (Mo, Da, Yr)End of 2006/Q4(2)DA Resubmission 04/18/2007
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
Increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT LineTransformersSpare(In Service) (In MVa)In Service Transformers Type of Equipment Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)(i)(k)
604
660
537
1222
533
213
5987
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 103.Line No.13 Column:
All assets owned by Coyote Springs 2, LLC were transfered to Avista Utili ties during 2006.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmlssion 04/18/2007 2006/04
FOOTNOTE DATA
'Schedule Page: 104 Line No.Column:
Effective January 6, 2006 named Senior Vice President and Chief Financial Officer
ISchedule Page: 104 Line No.22 Column:
On January 6, 2006 named Vice President and Treasurer. Ann Wilson was named Vice
President and Controller.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
'Schedule Page: 118 Line No.52 Column:
Line 52 - Subsidiary Expense & Mise Subs Equity Comp Consists of:
($1 445 216)
($ 100,734)
($1 545,950)
Transfers from Account #216150 related to Subsidiary Expenses (agrees to line 37)
Subsidiary (Avista Advantage) Equity Compensation booked to #216150
Line 52 - Subsidiary Expense & Mise Subs Equity Comp
IFERC FORM NO.(ED. 12-87) Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 219 Line No.Column: c
Includes: Accum provision of non-recoverable plant of ~$291, 927~
FAS 143 depreciation of $30,791
Disposals of property - $18,732
ISchedule Page: 219 Line No.16 Column: Includes: Reverse 2005 Removal Work in Progress - $371 816,
2006 Removal Work in Progress - $567 406
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubm ission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 224 Line No.Column:
Line 2 - Avista Capital - Equity in Earnings Consists of:
$16,839,462 Avista Capital YTD Net Income
($ 100,734)Subsidiary (Avista Advantage) Equity Compensation
$16,738,728 Line 2 - Avista Capital - Equity in Earnings
ISchedule Page: 224 Line No.Column:
Line 4 - OCI Investment in Subs:
booked to #123120
Represents the change in accumulated other comprehensive loss for subsidiary companies.
Amount is not included in account 418.1. Offsetting amount is reflected in account 219.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 227 Line No.Column: d(1) Electric
(2) Natural gas and miscellaneous
ISchedule Page: 227 Line No.Column: d
Footnote Linked. See note on 227 , Row:1, col/item:
ISchedule Page: 227 Line No.Column: d
Footnote Linked. See note on 227, Row: 1, col/item:
ISchedule Page: 227 Line No.Column: d
Footnote Linked. See note on 227, Row: 1, col/item:
ISchedule Page: 227 Line No.Column: d
Footnote Linked. See note on 227, Row: 1, col/item:
ISchedule Page: 227 Line No.: 10 Column: d(1) Electric
(2) Natural gas and miscellaneous
ISchedule Page: 227 Line No.11 Column: d
Footnote Linked. See note on 227 , Row:1, col/item:
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 231 Line No.Column:
Facilities Study Agreement Deposit
ISchedule Page: 231 Line No.Column:
System Impact Study Agreement Deposit
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 233.Line No.Column: b
with the implementation of a new financial
equal to the balance on line 2 page 233.
ISchedule Page: 233.Line No.35 Column: b
Footnote Linked. See note on 233.1, Row:
system the following lines were combined to
lines 10,11,12,13,15,16,20,21,23,28,& 31
col/item:
ISchedule Page: 233.Line No.36 Column: b
with the implementation of a new financial system Conservation program balances for lines
14,17,18,19,24 and 25 were combined to equal balances on lines 35 & 36.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 250 Line No.Column: ;
Restricted Shares
Restricted shares vest in equal thirds each year over a three-year period and are payable in Avista Corp. common stock at the end of
each year if the service condition is met. In addition to the service condition, the Company must meet a return on equity target in order
for the CEO's restricted shares to vest. During the vesting period, employees are entitled to dividend equivalents which are paid when
dividends on the Company s common stock are declared. Restricted stock is valued at the average of the high and low market of the
Company s common stock on the grant date. As of December 31 , 2006, the restricted shares had unrecognized compensation expense
of $0.4 million and an intrinsic value of $0.9 million. The intrinsic value represents the total market value of restricted shares as of
December 31 , 2006. The folIowing table summarizes restricted stock activity:
Unvested Shares at December 31 , 2005
Shares granted
Shares cancelIed
Shares vested
Unvested Shares at December 31 , 2006
260
(80)
Weighted average fair value at grant date
36.180
$21.32
ISchedule Page: 250 Line No.Column: j
Restricted Shares
Restricted shares vest in equal thirds each year over a three-year period and are payable in Avista Corp. common stock at the end of
each year if the service condition is met. In addition to the service condition, the Company must meet a return on equity target in order
for the CEO's restricted shares to vest. During the vesting period, employees are entitled to dividend equivalents which are paid when
dividends on the Company s common stock are declared. Restricted stock is valued at the average of the high and low market of the
Company s common stock on the grant date. As of December 31,2006, the restricted shares had unrecognized compensation expense
of $0.4 million and an intrinsic value of $0.9 million. The intrinsic value represents the total market value of restricted shares as of
December 31 , 2006. The folIo wing table summarizes restricted stock activity:
Unvested Shares at December 31, 2005
Shares granted
Shares cancelled
Shares vested
Unvested Shares at December 31 , 2006
36,260
(80)
Weighted average fair value at grant date
36.180
$21.
IFERC FORM NO.1 (ED. 12-87)Page 450.
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 04/18/2007 2006/Q4
FOOTNOTE DATA
!Schedule Page: 261 Line No.Column: b
Taxable Income Not Reported on Books:
BETC Interest - Perm Diff
BP A C&RD Receipts
Contributions in Aid of Construction (CIACs)
CSS Temp Service Fees
Customer Uncollectibles - Sales for Resale
Customer Uncollectibles
Transportation Tax Depreciation Capitalized
TOTAL
(10 792)
(210,191)
801 597
225 122
(339,277)
(158,285)
517 926
826,100
ISchedule Page: 261 Line No.10 Column: b
Deductions Recorded on Books Not Deducted for Return:
Airplane Lease Payments
Amortization of Centralia Gain
Book Depreciation
CIT Operating Lease
DSM - Old Program Amortization
FAS 106 & HRA (68.6% O&M only) 228300 ZZ ZZ & 228330 ZZ ZZ
FASB 1O6-Def Amort-Postretirement Benefits
Hamilton Street Bridge
Meal Disallowances - Perm Diff
Non-monetary Purchased Power
Paid Time Off Equalization
Political Contributions - Perm Diff
Preferred Dividend Requirement - Perm Diff
Rathdrum Turbine Sales Tax Refund
Redemption Expense Amortization
SERP-Supplemental Execitive Retirement Plan
Transportation Book Depreciation
WNP3 - Investment Exchange Power
TOTAL
272,353
(2,407,452)
003 303
(39,276)
717 848
(1,361 703)
394 920
(247 187)
329,217
386 545
246 025
052 120
915 594
(33 815)
735,325
814 154
1,417,417
2,450 028
645 416
ISchedule Page: 261 Line No.15 Column: b
Income Recorded on Books Not Included in Return:
AFUDC
Boulder Park Disallowance IPUC Order October 2004
Clark Fork PMEs
CS2 Retention
Deferred Compensation
ill Deferred Gas Costs & Interest
W A Deferred Gas Costs & Interest
Equity Stock Comp
FASB 87 (68.6% O&M)
Gain General Office Building
Grid WestJRTO Funding - ED ill & W
Idaho PCA & Interest
Injury & Damages
Kettle Falls Disallowance
IFERC FORM NO.1 (ED. 12-87)
(1,460,893)
(103 656)
(218 832)
(371 328)
875,785
714 760
672 197
092 122
(1,476 124)
(261,456)
(1,065,989)
(1,186 302)
164,148
(323,401)
Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubm ission 04/18/2007 2006/04
FOOTNOTE DATA
Liability Stock Camp
NE Tank Spill
Nez Perce Settlement ED ill & W
Officers Life Insurance - Perm Diff
OR Deferred Gas & Interest
OR DSM Deferred & Interest
Oregon Senate Bill 408 (SB 408)
PGE Monetization (Contract Amort & Spokane Energy Net Income)
Section 199 Manufacturing Deduction - Perm Diff
Unbilled Revenue Add-ons
W A Deferred Power Costs & Interest
Wartsilla Units
TOT AL
652,489
(45,700)
(16,796)
(706, I 05)
317,142
(713,714)
300 000
007,807
100 000)
343 385
374 425
153,162
617 126
ISchedule Page: 261 Line No.20 Column: b
Deductions on Return Not Charged Against Book Income:
Basic American Foods - Non-Utility
BPA Residential Exchange - ED ill & WA
DSM Tariff Rider
Removal/Salvage
Tax Depreciation - Common
WPNG Acquisition OR
TOT AL
788
960,752)
957 346)
(967,967)
(105,409,069)
120 289
(110 167 057)
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 310 Line No.Column: b(1) Electric
2) Natural gas and miscellaneous
~chedule Page: 310 Line No.Column: b
Termination upon mutual agreement of contracting parties.
ISchedule Page: 310.Line No.12 Column: b
NorthWestern Energy LLC sale expires October 31, 2008
ISchedule Page: 310.Line No.Column: b
PacifiCorp sale terminates October, 31, 2008.
'Schedule Page: 310.Line No.Column: b
peaker, LLC capacity contract terminates December 31, 2016.
ISchedule Page: 310.4 Line No.Column: b
Footnote Linked. See note on 310.3, Row: 8, col/item:
~chedule Page: 310.4
Puget Sound Energy
ISchedule Page: 310.
Contract expires
ISchedule Page: 310.Line No.Column:
Hedge for Los Angeles Dept of Water and Power
ISchedule Page: 310.Line No.12 Column: b
Sovereign Power contract terminates 1-31-2010
ISchedule Page: 310.Line No.13 Column: b
Sovereign Contract terminates 1-31-2010
ISchedule Page: 310.Line No.Column:
Intracompany Wheeling
ISchedule Page: 310.Line No.Column: b
IntraCompany Wheeling terminates 09/30/2023.
Line No.12 Column: b
sale expires October 31,2008
Line No.Column: b
agreemen t .
ISchedule Page: 310.Line No.Column:
Intracompany generation - sale of ancillary services
ISchedule Page: 310.Line No.Column: b
IntraCompany Generation - Sale of Ancillary Services terminates 12/31/2009.
ISchedule Page: 310.Line No.Column: b
Estimated revenues - true up in later periods.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 326 Line No.Column: b(1) Electric
(2) Natural gas and miscellaneous
ISchedule Page: 326 Line No.Column: I
Storage charges and Non Monetary Accrual
ISchedule Page: 326 Line No.: 10 Column: I
Spin & Supp charges
'Schedule Page: 326 Line No.13 Column: b
Subsequent settlement of deviation energy
ISchedule Page: 326 Line No.13 Column: I
Non Monetary Accrual
ISchedule Page: 326.Line No.14 Column: I
on Monetary Accrual
!Schedule Page: 326.Line No.11 Column: I
Financial Settlement of Losses
ISchedule Page: 326.Line No.Column: b
Service to Deer Lake customers delivered
at time of contract termination 12/31/2005.
from Inland Power & Light.
ISchedule Page: 326.4 Line No.Column: I
Non monetary accrual
ISchedule Page: 326.4 Line No.Column: I
Non Monetary Accrual
ISchedule Page: 326.Line No.Column: I
Pondage purchase
ISchedule Page: 326.Line No.Column: I
IntraCompany Ancillary Services
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
!schedule Page: 332 Line No.Column: g
Ancilliary Services
ISchedule Page: 332 Line No.Column: g
Use of Facility charges
ISchedule Page: 332 Line No.Column: g
Prior Period
ISchedule Page: 332 Line No.Column: 9
O&M payment for capacity rights
ISchedule Page: 332.Line No.Column: 9
Prior period adjustment
ISchedule Page: 332.Line No.Column: 9
Storage charges
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
Column: b
Vendor Purpose Amount
VENDORS LESS THAN $5,000
MAL YN K MALOUIST
THELEN REID & PRIEST LLP
THE MANHATTAN GROUP OF COMPANIES
CAREY INTERNATIONAL INC
GILLESPIE PRUDHON & ASSOCIATES INC
THELEN REID BROWN RAYSMAN & STEINER LLP
GEORGESON SHAREHOLDER
AZAR'S FOOD SERVICES
ADVENTURES IN ADVERTISING
SCOTT L MORRIS
UNION BANK OF CALIFORNIA
DEWEY BALLANTINE LLP
THE DAVENPORT HOTEL
CITY OF SPOKANE
WATSON WYATT & COMPANY
THE WESTIN NEW YORK
MAJOR LINDSEY & AFRICA LLC
DELOITTE & TOUCHE LLP
GARY EL
POTTER CONSULTING
FITCH RATINGS
CITIBANK NA
THE COEUR D ALENE
CORPORATE EXECUTIVE BOARD
JPMORGAN CHASE BANK
NEW YORK STOCK EXCHANGE INC
STANDARD & POORS
BOWNE OF LOS ANGELES INC
ADP INVESTOR COMMUNICATION SERVICES INC
MOODYS INVESTORS SERVICE
CORP CREDIT CARD
THE BANK OF NEW YORK
DEUTSCHE BANK TRUST COMPANY AMERICAS
Employee Misc Expenses
Legal Services
Miscellaneous
Miscellaneous
Professional Services
Legal Services
General Services
Office Supplies
Miscellaneous
Employee Misc Expenses
Miscellaneous
General Services
Miscellaneous
Miscellaneous
Professional Services
Miscellaneous
Miscellaneous
Professional Services
Employee Misc Expenses
Professional Services
Miscellaneous
Miscellaneous
Miscellaneous
Professional Services
Miscellaneous
Miscellaneous
Miscellaneous
Professional Services
General Services
Miscellaneous
Subscriptions
Miscellaneous
Miscellaneous
83,421
891
945
551
309
144
909
927
110
612
085
288
655
13,961
154
708
16,144
18,385
18,875
20,919
23,259
578
28,472
30,581
31,889
32,905
36,912
43,399
45,684
978
58,833
60,023
134 533
289,000
ISchedule Page: 335 Line No.Column: b
/schedule Page: 335 Line No.: 9
Directors 2006 Expenses
HEIDI B STANLEY
ERIK J ANDERSON
KRISTIANNE BLAKE
JOHN F KELLY
I FERC FORM NO.1 (ED. 12-87)
$19,858
$53 084
$60,812
$47 552
Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
MICHAEL L NOEL
DAVID A CLACK
R JOHN TAYLOR
JESSIE J KNIGHT JR
JACK W GUSTAVEL
LURA J POWELL
ROY EIGUREN
$33,135
$30,366
$45,323
$37 892
$6,119
$37,412
$69,804
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Me, Da, Yr)
Avista Corporation (2)A Resubmisslon 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 400 Line No.Column: i
The changes between the first half of 2006 and the second half of 2006 is the result of a
change in methodology for breaking out Long-term Firm Point-to-point Reservations, Other
Long-term Firm Service, Short-term Firm Point-to-point Reservation, and Other Service.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
'Schedule Page: 402 Line No.Column: b
Joint facility with Mirant Oregon,LLC.
ISchedule Page: 402 Line No.Column:
Joint project operated by PPL Montana LLC.
ISchedule Page: 402 Line No.-1 Column:
Avista purchased plant from Lessor 9/20/2005
Operated by Portland General Electric.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/18/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 406 Line No.Column: b
License period from August 1, 1972 to July 31, 2007.
ISchedule Page: 406 Line No.Column:
License period from August 1, 1972 to July 31 , 2007.
ISchedule Page: 406 Line No.-2 Column: d
License period from March 1, 2001 to February 28, 2046
!Schedule Page: 406 Line No.Column: e
License period from March 1, 2001 to February 28, 2046.
!Schedule Page: 406 Line No.-2 Column: f
License period from August 1, 1972 to July 31, 2007.
ISchedule Page: 406.Line No.Column: b
License period from August 1, 1972 to July 31, 2007.
ISchedule Page: 406.Line No.Column: c
Licensed period from August 1, 1972 to July 31, 2007.
ISchedule Page: 406.Line No.Not a licensed proj ect.Column: d
IFERC FORM NO.1 (ED. 12-87)Page 450.
Avv-
A vista Corp.
2006 Form
State Supplements
,.0, "'
' :'
2GO'! !, ,i ..
" i
9:
!,
i,_li!.,C ,;i.i:3Si
WASHINGTON
Name of Respondent This R::E,ort Is:(1) 129 An Original
Date of Report
(Mo, Da, Yr)
State of Wash in ton
Year of Report
Avista Corp (2)A Resubmission Apr. 18,2007 Dec. 31, 2006
STATEMENT OF INCOME FOR THE YEAR
1. Report amounts for accounts 412 and 413, Revenue
and Expenses from Utility Plant Leased to Others, in another
utility colwnn (i,o) in a similar manner to a utility depart-
ment. Spread the amount(s) over lines 01 thru 20 as ap-
propriate. Include these amounts in columns (c) and (d)
totals.
2. Report amounts in account 414, Other Utility Operating
Income, in the same manner as accounts 412 and413 above.
3. Report data for lines 7, 9, and 10 for Natural Gas com-
panies using accounts 404., 404., 404.3, 407.1, and
407.
4. Use page 122 for important notes regarding the state-
ment of income or any account thereof.
Line
No.
Account
(a)
FERC FORM NO.1 (REVISED 12-96)
(Ref.
Page
No.
(b)
300-301
320-325
320-325
336-338
336-338
336-338
262-263
262-263
262-263
234 272-277
234 272-277
266
Page 114
5. 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'
customers or which may result in a material refund to the
utility with respect to power or gas purchases, State for each
year affected the gross revenues or costs to which the con-
tingency relates and the tax effe
tion of the major factors which affect the rights of the utility
to retain such revenues or recover amounts paid with respect
to power and gas purchases.
6. Give concise explanations concerning significant
amounts of any refunds made or received during the year
TOTAL
Current Year Previous Year
$830,746,352 $724 016,704
Name of Respondent This R~ort Is:
(1) 129 An Original
Date of Report
(Mo. Da, Yr)
State of Washin ton
Year of Report
Avista Corp (2) 0 A Resubmission Apr. 18,2007 Dec. 31, 2006
STATEMENT OF INCOME FOR THE YEAR
resulting from settlement of any rate proceeding affecting
revenues received or costs incurred for power or gas pur-
chases, and a summary of the adjustments made to balance
sheet, income, and expense accounts.
7. If any notes appearing in the report to stockholders are
applicable to this Statement of Income, such notes may be at-
tached at page 122.
8. Enter on page 122 a consise explanation of only those
changes in accounting methods made during the year which
had an effect on net income, including the basis of allocations
and apportionments from those used in the preceding year.
Also give the approximate dollar effect of such changes.
9. Explain in a foonote if the previous year s figures are
different from that reported in prior reports.
10. If the columns are insufficient for reporting additional
utility deparunents, supply the appropriate account titles, lines
I to 19, and report the information in the blank space on page
122 or in a supplemental statement.
ELECTRIC UffiITYCurrent Year Previous Year
GAS UTILITYCurrent Year Previous Year
OTHER UTILITY
Current Year Previous Year Line
No.
$564,491 589 $509,490,290 $266 254 763 $214 526,414
FERC FORM NO.1 (REVISED 12-96)Page 115
State of W asbington
Name of Respondent This Re
oort Is:
Date of Report Year of Report (1) X An Original (Mo, Da, Yr)
Avista Corp.(2)A ResubmisslOn April 18, 2007 082.
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103, 106)
1. Report below the original cost of electric plant in service ae-estimated basis if necesS8I)', and include the en1ries in column
cording 10 the prescribed accounts.(c). Also 10 be included in cohmm (c) are en1ries for reversals
2. In addition 10 Account 101. Electric Plant in Service (Clas-of tentative distributions of prior year reported in column (b).
sifJed). this page and the next include Accounts 102, Electric Plant Likewise, if the respondent has a significant amount of plant
Purchased or Sold; Account 103. Experimental Electric Plant Un-retirements which have not been classified 10 primary accounts
Classified: and Account 106, Completed Construction Not Clas-at the end of the year, include in cohmm (d) a tentative distriIr
sifJed - Electric.ution of such retirements on an estimated basis. with approp-
3. Include in column (c) or (d), as appropriate, cOiTections of add-riate contra enlly 10 the account for accumulated depreciation
itions and retirements for the current or preceding year.provision. Include also in column (d) reversals of tentative !lis-
4. Enclose in parentheses credit adjustments of plant accounts 10 tributions of prior year of unclassified retirements. Attach sup-
indicate the negative effect of such accounts.plemental statement showing the account distributions of these
5. CJassify AccountlO6 according 10 prescribed accounts, on an tentative cJassifications in cohmms (c) and (d). including the
Balance at
Line Account Beginning of Year Additions
No.(a)(b)(c)
1. INTANGIBLE PLANT
(301)Organization
(302)Franchises and Consents
(303)Miscellaneous Intanro,ble Plant 149 355
TOTAL Intancible Plant (Enter Total of lines 2. 3 , and 4)149 355
2. PRODUCTION PLANT
A Steam Production Plant
(310)Land and Land Ri,ghts 941 300
(311)Structures and ImDrovements 513,824 10,704.
(312)Boiler Plant Equipment 042 097 332 983.
(313)Engines and Engine Driven Generators
(314)Turbogenerator Units 084 997 105 911.60
(315)Accessory Electric Equipment 10,261 817
(316)Misc. Power Plant Equipment 300,123 644.
(317)Asset Retirement Costs for Steam Production 114 206
TOTAL Steam Production Plant (Enter Total oflines 8 tbru 15)92,258 364 468 244.
B. Nuclear Production Plant
(320)Land and Land Rights
(321)Structures and ImDrovements
(322)Reactor Plant Equipment
(323)Turbogenerator Units
(324)Accessory Electric Equipment
(325)Misc. Power Plant Equipment
(326)Asset Retirement Costs for Nuclear Production
TOTAL Nuclear Production Plant (Enter Total of lines 18 tbru 24)
C. Hydraulic Production Plant
(330)Land and Land Ri,ghts 038 614
(331)Structures and ImDrovements 100 535 295,489.
(332)Reservoirs, Dams, and Waterways 657 050 292.
(333)Water Wheels, Turbines, and Generators 365,484
(334)Accessorv Electric Equipment 584,162 817.
(335)Misc. Power Plant Equipment 937 304 941.91
(336)Roads, Railroads, and Bridges 675 629
(337)Asset Retirement Costs for Hvdraulic Production
TOTAL Hydraulic Production Plant (Enter Total oflines 27 tbru 34)116 358 778 408 540.
D. Other Production Plant
(340)Land and Land Ri,ghts 255 874
(341)Structures and lmProvements 981 334
(342)Fuel Holders, Products and Accessories 236,662
(343)Prime Movers 218,452
(344)Generators 692,219
(345)Accessorv Electric Equipment 604,314
FERC FORM NO.1 (ED. 12-91)Page 204
State of W asbington
Name of Respondent This ~ort Is:Date of Report Year of Report(1) X An Original (Mo, Da, fr)
Avista Corp.(2)A Resubmission April 18, 2007 December 31 2006
ELECTRIC PLANT IN SERVICE (Accounts 101 102 103, and 106) (Continued)
reversals of the prior years tentative account distributions of umn (1) only the offset to the debits or credits distributed in
these amounts. Careful observance of the above instructions column (1) to primary account classifications.
and the texts of Accounts 101 and 106 will avoid senous DInis-7, For Account 399, state the nature and use of plant included
sions of the reported amount of respondenfs plant actually in the account and if substantial in amount submit a supple-
in service at end of year.mentaIy statement showing subaccount classification of such
Show in column (1) reclassiflCBtions or transfers within plant conformmg to the requirements of these pages.
utility plant accounts. Include also in column (1) the additions 8. For each amount comprising the reported balance and
or reductions of primary account classifICations arising from changes in Account 102, state the prop~ purchased or sold,
distribution of amounts initiaJly recorded in Account 102. name of vendor or purchaser, and date of transaction. Hpro-
showing the clearance of Account 102, include in column (e)posed journal entries have been fiJed with the Commission
the amounts with respect to accumulated provision for as required by the Uniform System of Accounts give also
depreciation, acquistion adjustments, etc., and show in col-date of such filing.
Balance at
Retirements Adjustments Transfers End of Year Line
(d)(e)(f)
(~)
No.
(301)
(302)
149 355 (303)
149,355
941 300 (310)
524,529 (311)
164 154 210 927 (312)
(313)
446 095,463 (314)
261 817 (315)
318 767 (316)
114 206 (317)
259 600 92,467 008
(320)
(321)
(322)
(323)
(324)
(325)
(326)
038 614 (330)
071 385 953 (331)
48,673 342 (332)
365,484 (333)
329 619 651 (334)
947 246 (335)
675 629 (336)
(337)
61,400 116 705 919
(25 562)281 436 (340)
981 334 (341)
236 662 (342)
18,218,452 (343)
32,692,219 (344)
604 314 (345)
FERC FORM NO.1 (ED. 12-87)Page 205
State ofWash1ngton
Name of Respondent This R~rt Is:Date of Report Year of Report (I) X An Original (Mo Va, Yr)
Avista Corp.(2)A Resubmission April 18, 2007 082.
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103, 106)
Balance at
Line Account Beginning of Year Additions
No.(a)( IT)(c)
(346)Misc. Power Plant Equipment 245 344 844.
(347)Asset Retirement Costs for Other Production
TOTAL Other Production Plant (Enter Total of lines 37 thru 44)234,199 844.
TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 45)261,851,341 886 629.
3. TRANSMISSION PLANT
(350)Land and Land Ril!hts 734,645 725.
(352)Structures and ImProvements 093,698 88,414.
(353)Station EQuipment 67,438 940 300 922.
(354)Towers and Fixtures 499,054
(355)Poles and Fixtures 201 170 874 878.
(356)Overhead Conductors and Devices 969 540 138 076.
(357)Underground Conduit 561,148
(358)Underground Conductors and Devices 317 910
(359)Roads and Trails 366
(359.Asset Retirement Costs for TransmissiOn Plant
TOTAL Transnnssion Plant (Enter Total of lines 48 thru 57)163 901,471 7,462,017.43
4. DISTRIBUTION PLANT
(360)Land and Land Ril!hts 914 636
(361)Structures and Improvements 551 822 837.
(362)Station Equipment 615 988 772,427.50
(363)Storage Battery Equipment
(364)Poles, Towers, and Fixtures 102,510,128 802,972.69
(365)Overhead Conductors and Devices 857 227 2,497 538.
(366)Underground Conduit 544,052 526 243.
(367)Underground Conductors and Devices 58,160 560 622 132.
(368)Line Transformers 301 014 128,493.
(369)Services 393 966 096 211.24
(370)Meters 608 006 890 701.05
(371)Installations on Customer Premises
(372)Leased Property on Customer Premises
(373)Street Lil!hting and Signal SYStems 13,198 791 707 685.
(374)Asset Retiremetn Costs for Distribution Plant
TOTAL Distribution Plant (Enter Total of lines 60 thru 74)491 656,190 095 243.
5. GENERAL PLANT
(389)Land and Land Ril!hts
(390)Structures and ImProvements 399,420 538.
(391)Office Furniture and EQuimnent
(392)Transportation EQuipment 509,308 729,806.
(393)Stores EQuipment 952
(394)Tools, Shop and Garage Equipment 108 300 822.
(395)Laboratorv Bouiy ment 359,450
(396)Power Operated :!Ouipment 737,478 549 854.
(397)Communication ~uipment 953 856 165 816.32
(398)Miscellaneous B(juipment
SUBTOTAL (Enter Total of lines 77 thru 86)089,764 519 838.
(399)Other Tangible PrOPertv
(399.Asset Retirement Costs for Genereal Plant
TOTAL General Plant (Enter Total of lines 87 thru 89)089,764 519 838.35
TOTAL (Accounts 101 and 106)935 648 121 39,963 729.30
(102)Electric Plant Purchased
(Less)(102) Electric Plant Sold
(103)Experimental Plant Unclassified
TOTAL Electric Plant in Service 935,648 121 39,963 729.30
FERC FORM NO.1 (ED. 12-87)Page 206
State of Washington
Name of Respondent This fRlort Is:Date of Report Year of Report(1) X An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission April 18, 2007 December 31,2006
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103, and 106) (Continued)
Balance at
Retirements Adjustments Transfers End of Year Line
(d)(e)(f!)No.
255 189 (346)
(347)
(25 562)269 606
295 438 262,442 533
971 792,399 (350)
7,182,113 (352)
195 877 145 620 689,607 (353)
499,054 (354)
383 917 (10 580)681,551 (355)
623 170 (1,578)31,482 868 (356)
561,148 (357)
317 910 (358)
366 (359)
(359.
204,935 133,462 170 292 016
914 591 (360)
144,305 458 354 (361)
310 237 (7,218)070 961 (362)
(363)
306,706 107 006 394 (364)
188 883 165 883 (365)
37,495 032 800 (366)
362 612 62,420 081 (367)
388,466 041 042 (368)
561 61,414 616 (369)
906 944 591 764 (370)
(371)
(372)
159,428 747 049 (373)
(374)
880 681 (7,218)516 863 535
(389)
426 959 (390)
(391)
377 205 737 (392)
952 (393)
198 100 924 (394)
697 358,753 (395)
287,333 (396)
17,359 (756 304)346 009 (397)
(398)
105 631 (756 304)18,747 667 87 i
(399)88
(399.
105,631 (756 304)18,747 667
486 685 (630 060)968,495 105
(102)
(103)
6,486 685 (630 060)968,495 105
FERC FORM NO.1 (ED. 12-87)Page 207
Name of Respondent This R~ort Is:
(1) 129 An Original
A vista Corporation (2)
Date of Report
(Mo, Da, Yr)
State of Wash in ton
Year of Report
A Resubmission April 18, 2007 December 31,2006
ELECTRIC OPERATING REVENUES (Account 400)
Line
No.
Title of Account
I. Report below operating revenues for each prescribed
account, and manufactured gas revenues in total.
2. Report number of customers, columns (f) and (g), on
the basis of meters, in addition to the number of flat rate
accounts; except that where separate meter readings are
added for billing purposes, one customer should be counted
(a)
Sales of Electrici
(440) Residential Sales
(442) Commercial and Industrial Sales (3)
Small (or Commercial)
Lar e (or Industrial)
(444) Public Street and Hi hwa Li htin
(445) Other Sales to Public Authorities
(446) Sales to Railroads and Railwa s
(448) Interde artmental Sales10 TOTAL Sales to Ultimate Consumers
11 (447) Sales for Resale12 TOTAL Sales of Electricit
13 (Less) (449.1) Provision for Rate Refunds14 TOTAL Revenues Net of Provision for Refunds15 Other 0 eratin Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Pro eft
20 (455) Interde artmental Rents
21 (456) Other Electric Revenues
FERC FORM NO.1 (ED. 12-89)
for each group of meters added. The average number of
customers means the average of twelve figures at the close
of each month.
3. If previous year (columns (c), (e), and (g), are not
derived from previously reported figures, explain any incon-
sistencies in a footnote.
Page 300
OPERATING REVENUES
Amount for Amount forYear Previous Year(b) (c)
157 200 672 141 993 348
335,190 39,045 236
627,865 289 060
732 964 712 660
363 127 729 (1)326 376 032
160 120,645 162 882 986
523 248 374 489 259,018
523 248 374 489,259,018
280,713 295 570
230 504 191 173
825 262 854 249
906 736 890,280
243 215
$564,491 589
231 272
$509,490 290
Name of Respondent This R~rt Is:(1) 129 An Original
Date of Report
(Mo, Da, Yr)
State of Washin ton
Year of Report
A vista Corporation (2)A Resubmission April 18, 2007 December 3 I, 2006
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4. Commercial and Industrial Sales, Account 442, may
be classified according to the basis of classification (Small
or Commercial, and Large or Industrial) regularly used by
the respondent if such basis of classifcation is not generally
greater than 1000 Kw of demand. (See Account 442 of the
Unifonn System of Accounts. Explain basis of classification
in a footnote.
5. See page 108, Important Changes During Year, for
important new territory added and important rate increases
or decreases.
6. For lines 2, 4, 5, and 6, see page 304 for amounts
relating to unbilled revenue by accounts.
7. Include unmetered sales. Provide details of such sales
in a foonote.
MEGA WAIT HOURS SOLD
Amount for Year
(d)
Line
No.
134 250 052 868 158 855
817 901 823 133 894 905
652 068 292 284
013 230
5,411,417 (2)232 594 224 661 220,271
246,674 264,440
658 091 497 034 224 661 220 309
658 091 8,497 034 224 661 220 309
Amount for
Previous Year
(e)
A YG. NO. OF CUSTOMERS PER MONTH
Number for
Number for Year Previous Year
(1) Includes $1 383,097 of unbilled revenues.
(2) Includes (2,481) MWH relating to unbilled revenues.
(3) Segregation of Commerical and Industrial made on basis of utilization of energy and not on size of account.
FERC FORM NO.1 (ED. 12-89)Page 301
Washington
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original
Avista Cor (2)A Resubmlssion April 18,2007 December 31 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line
No.Account Amount for Current Year lAmount for Prior Year
(a)(b)(c)
(1) POWER PRODUCTION EXPENSES
A. Steam Power Generation
Operation
500 Operation Supervision and Enaineerina 139,983 123,918
501 Fuel 10,784,256 10,296,104
502 Steam Expenses 514,671 547,937
503 Steam from Other Sources
Less) (504) Steam Transferred-Cr.
505 Electric Expenses 772 066 729,234
506 Miscellaneous Steam Power Expenses 403 048 393,132
507 Rents 856
509 Allowances
TOTAL Operation (Enter Total of Lines 4 thru 11)614,023 091 180
Maintenance
510 Maintenance Supervision and Enaineerina 79,088 93,705
511 Maintenance of Structures 50,096 68,255
512 Maintenance of Boiler Plant 1,428 261 954,483
513 Maintenance of Electric Plant 204,600 420,469
514 Maintenance of Miscellaneous Steam Plant 168,202 151 342
TOTAL Maintenance (Enter Total of Lines 14 thru 18)930,247 1 ,688,254
TOTAL Power Production Expenses-Steam Plant (Enter Total of lines 12 and 19)14,544,270 13,779,435
B. Nuclear Power Generation
Operation
517 Operation Supervision and Enaineerina
518 Fuel
519 Coolants and Water
520 Steam Expenses
521 Steam from Other Sources
Less) (522) Steam Transferred-Cr.
523) Electric Expenses
524) Miscellaneous Nuclear Power Expenses
525) Rents
TOTAL Operation (Enter Total of liens 23 thru 31)
Maintenance
528 Maintenance Supervision and Enaineerina
529 Maintenance of Structures
530 Maintenance of Reactor Plant Eauipment
531 Maintenance of Electric Plant
532 Maintenance of Miscellaneous Nuclear Plant
TOTAL Maintenance (Enter Total of lines 34 thru 38)
TOTAL Power Production Expenses-Nuclear Power(Enter total of lines 32 and 39)
C. Hydraulic Power Generation
Operation
535 Operation Supervision and Engineering 940,411 902,345
536 Water for Power 498 379 497,770
537 Hydraulic Expenses 1 ,844 214 1,484 540
538 Electric Expenses 195 748 065 503
539 Miscellaneous Hydraulic Power Generation Expenses 271 040 300 444
540 Rents 641 611 664 047
TOTAL Operation (Enter Total of lines 43 thru 48)391 405 914 648
FERC FORM NO.1 (12-96)Page 320
Washington
Name of Respondent This Report Is: Date of Report Year of Report
(1)An Original
Avista Cor (2)A Resubmission April 18 2007 December 31 , 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line
No.Account Amount for Current Year ount for Previous Ye
(a)(b)(c)
C. HYdraulic Power Generation (Continued)
Maintenance
541 Maintenance Supervision and Engineering 147 070 153 297
542 Maintenance of Structures 113,970 374 052
543 Maintenance of Reservoirs, Dams, and Waterways 435 697 282,840
544 Maintenance of Electric Plant 515,586 732 392
545 Maintenance of Miscellaneous Hydraulic Plant 545 330
TOTAL Maintenance (Enter Total of lines 52 thru 56)292,868 624,911
TOTAL Power Production Expenses-Hydraulic Power (Enter total of lines 49 and 57)684 273 539,559
D. Other Power Generation
Operation
546 Operation Supervision and Engineering 165,003 107 866
547 Fuel 1 ,460,041 567 712
548 Generation Expenses 139,136 157 332
549 Miscellaneous Other Power Generation Expenses 116,166 133,651
550 Rents 122 265 120,267)
TOTAL Operation (Enter Total of lines 61 thru 65)858 080 946,293
Maintenance
551 Maintenance Supervision and Enaineerina 323 42,358
552 Maintenance of Structures 1865 440 068,873
553 Maintenance of Generatina and Electric Plant 356,866 194,345
554 Maintenance of Miscellaneous Other Power Generation Plant 65,042 928
TOTAL Maintenance (Enter Total of lines 68 thru 71)1395,210 367,504
TOTAL Power Production Expenses-Other Power (Enter Total of lines 66 and 72)462 871 313,798
E. Other Power Supply Exoenses
555) Purchased Power 131 714 783 165 572,990
556) Svstem Control and Load Dispatchina 420,493 444 209
557) Other Expenses 623 876 51,111,227
TOTAL Other Power Supply Expenses (Enter Total of lines 75 thru 77)200,759,151 217 128,426
TOTAL Power Production Expenses (Enter Total of lines 20, 40, 58, 73 and 78)224,450 565 241 761 218
2. TRANSMISSION EXPENSES
Operation
560) Operation Supervision and Engineerina 1 ,125 845 032 534
561) Load Dispatching 271 288 981 699
561.Load Dispatching Reliability 10,673
561.Load Dispatching Monitor and Operate Transmission Svstem 756,744
561.Load Dispatching Transmission Service and Sched 507,452
561.4 Scheduling Sysemt Control and Dispatch Services
561.Reliability, Planning and Standards Development
561.Transmission Service Studies
561,Generation Interconnection Studies
561.Reliability, Planning and Standards Development Services
562 Station Expenses 171 885 104 301
563 Overhead Line Expenses 45,462 56,711
564 Underground Line Expenses
565 Transmission of Electricity by Others 821,504 6,436,773
566 Miscellaneous Transmission Expenses 474,416 435,878
567 Rents 644
TOTAL Operation (Enter Total of lines 82 thru 89\12,212,913 047 981
Maintenance
100 568 Maintenance Supervision and Engineering 297,767 261 900
101 569 Maintenance of Structures 609 217
102 570 Maintenance of Station Eauipment 877,832 542 985
103 571 Maintenance of Overhead Lines 147 315 190 896
104 572 Maintenance of Underground Lines 805 164
105 573 Maintenance of Miscellaneous Transmission Plant 35,167 87,428
106 TOTAL Maintenance (Enter Total of lines 92 thru 97\442,495 166,590
107 TOTAL Transmission Exoenses (Enter Total of lines 90 and 98\13,655,409 214 571
108 3. DISTRIBUTION EXPENSES
109 Operation
110 580) Operation Supervision and Engineering 620,718 653,550
FERC FORM NO.(12-96)Page 321
Washington
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original
Avista Cor (2)A Resubmission April 18, 2007 December 31 , 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line
No.Account Amount for Current Year iAmount for Prior Year
(a)(b)(c)
103 3. DISTRIBUTION EXPENSES (Continued)
104 581 Load Disoatchina
105 582 Station Exoenses 241 907 218,550
106 583 Overhead Line ExDenses 737 220 210,525
107 584 Underaround Line ExDenses 885 131 849,332
108 585 Street Liahtina and Sianal System Exoenses 563 858
109 586 Meter EXDenses 895,819 919 841
110 587 Customer Installations EXDenses 494 245 442,439
111 588 Miscellaneous Distribution EXDenses 031 597 723,102
112 589 Rents 365 143,905
113 TOTAL Operation (Enter Total of lines 102 thru 112\059 565 235,101
114 Maintenance
115 590 Maintenance Supervision and Engineerina 974 197 780 265
116 591 Maintenance of Structures 190,092 120 839
117 592 Maintenance of Station EQuipment 724 580 511 273
118 593 Maintenance of Overhead Lines 758,276 136 653
119 594 Maintenance of Underground Lines 764 838 608 856
120 595 Maintenance of Line Transformers 443,579 412 910
121 596 Maintenance of Street Lighting and Signal Systems 293 064 305,772
122 597 Maintenance of Meters 76,442 62,024
123 598 Maintenance of Miscellaneous Distribution Plant 253,826 153 399
124 TOTAL Maintenance (Enter Total of lines 115 thru 123\8,478,892 091,992
125 TOTAL Distribution Expenses (Enter Total of lines 113 and 124\15,538,457 327,093
126 4. CUSTOMER ACCOUNTS EXPENSES
127 Operation
128 901 SuDervision 337 233 444 651
129 902 Meter Readina ExDenses 728 782 740,545
130 903 Customer Records and Collection ExDenses 790 728 233,421
131 904 Uncollectible Accounts 013,427 964 059
132 905 Miscellaneous Customer Accounts ExDenses 120,036 341 927
133 TOTAL Customer Accounts ExDenses (Enter Total of lines 128 thru 132\990,206 724 604
134 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
135 Operation
136 907 Supervision
137 908 Customer Assistance Expenses 624 298 027 854
138 909 Informational and Instructional Expenses 44,214 28,010
139 910 Miscellaneous Customer Service and Informational Expenses 70,562 70,454
140 TOTAL Cust. Service and Informational Expenses (Enter Total of lines 136 thru 139\739,074 126 318
141 6. SALES EXPENSES
142 ODeration
143 911 SuDervision
144 912 Demonstratina and Sellina Exoenses 333,599 261 524
145 913 Advertisina ExDenses 178 745 90,492
146 916 Miscellaneous Sales ExDenses 143 953 176
147 TOTAL Sales ExDenses (Enter Total of lines 143 thru 146\656 297 429,192
148 7. ADMINISTRATIVE AND GENERAL EXPENSES
149 Operation
150 920) Administrative and General Salaries 11,493 206 11,549,436
151 921) Office Supplies and Expenses 791 875 542,204
152 Less) (922) Administrative expenses Transferred-Credit 118 576 (15,343
FERC FORM NO.1 (12-96)Page 322
Washington
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original
Avista Cor (2)A Resubmission April 18 2007 December 31. 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line
No.Account Amount for Current Year .!\.mount for Prior Year
(a)(b (c)
153 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
154 923 Outside Services Emoloved 613,135 057 965
155 924 Prooertv Insurance 788,820 686,016
156 925 Iniuries and Damaaes 495,688 763 273
157 926 Emolovee Pensions and Benefits 758,281 748 354
158 927 Franchise Reauirements
159 928 Reaulatorv Commission Exoenses 186.343 901 767
160 Less) (929) Duolicate Charaes-Cr.
161 930.1) General Advertisina Exoenses 679 (11,083
162 930.2) Miscellaneous General Exoenses 027 828 955 562
163 931) Rents 707 526 070 847
164 TOTAL Operation (Enter Total of lines 150thru 163)852,805 30,248 999
165 Maintenance
166 935) Maintenance of General Plant 4,435 303 787 868
167 TOTAL Administrative and General Exoenses (Enter Total of lines 164 and 166)33,288,108 036,868
168 TOTAL Electric Operation and Maintenance Expenses (Enter TDtal Df lines 304 318,115 316.619,864
79,125,133,140,147.and 167)
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1. The data on number of empl construction employees in a footnote.
for the payroll period ending neare 3. The number of employees assignable to the electric
payroll period ending 60 days befcdepartment from joint functions of combination utilities may
2. If the respondent's payroll for be determined by estimate, on the basis of employee equiva-
eludes any special construction lents.Show the estimated number of equivalent employees
employees on line 3, and show th attributed to the electric department from joint functions.
1 Payroll Period Ended (Date! December 31 , 2006
2 Total Reaular Full-Time Emolovees 396 394
3 Total Part-Time and TemDorarv Emolovees
4 Allocation of General Employees 231 330
5 Total Empioyees (See Note 1)651 748
FERC FORM NO.1 (12-96) Page 323
Avista Corp.
Name of Respondent This report is:
(1) (X)An Original
Date of Report
(Mo, Da, Yr)
State of Washinaton
Year of Report
(2) ( ) A Resubmission 04/18/2007 Dec. 31,2006
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uni-form System of Accounts. Do not report substation
costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole, wood or steel; (2) H-frame, wood, or steel poles; (3) tower; or (4)
underground construc-tion. If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of
brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for
the line designated;conversely, show in column(g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on
leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are
DESIGNATION
VOLTAGE (KV)
(Indicating where other
than 60 cvcle,3 thase)
Type of
Supporting
Structure
LENGTH (pole miles) (In
the case of underground lines,
reDort circuit miles.
On structure On structureof Line of AnotherDesignated Line
(h)
Number
CircuitsLine
No.From Operating Designed
(a)
Group Sum
(b)(J?)(d)(e)(e)
Group Sum 115 115 935.
230 Steel Tower
230 H Type
230 H Type
230 Steel Tower
230 Steel Pole
230 H Type
230 Steel Tower
230 H Type
230 Steel Tower
230 H Type
230 Steel Tower
230 H Type
230 Alum.
230 H Type
230
230
230
230
230
230
230
230
230
230
230
230
230
230
BPA Bell Sub
BPA Bell Sub
BPA Bell Sub
Cabinet Gorge Plant
Cabinet Gorge Plant
Cabinet Gorge Plant
Lolo Sub
Lolo Sub
Walla Walla
Walla Walla
Shawnee
Shawnee
Wanapum
Wanapum
Beacon Sub #4
Beacon Sub
Beacon Sub #5
Beacon
Beacon
Beacon
Beacon Sub
Beacon Sub
North Lewiston
North Lewiston
North Lewiston
North Lewiston
Walla Walla
Walla Walla
15.
21.
31.
26.
78.
BPA Line West Side Sub 230 230 Steel Pole
TOTAL 133.
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent
Avista Corp.
This Report Is:
(1)~ An Original
(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
04/18/2007
State of Washinaton
Year of Report
Dec. 31 2006
TRANSMISSION 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
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms 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 bome by the respondent are accounted for, and accounts affected. Specify whether lessor, co-
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 OJ to (I) on the book cost at end of year.
Size ofl
Conductor
and Material
COST OF LINE (Include in column (j) land, Expenses, except Depreciation and Taxes
Land Rights, and clearing right-of-way)
Land Construction and Total Cost
Other Costs
Operation
Expenses
Ii)(i)
136,038
(k)
70,092
(I)
206,130
(m)
79,555
795 McMACSR
1272McMACSR
1272 McMAL
795 McMACSR
1590 ACSS
795 McMACSR
795 McMACSR
1272 McMAL
1272 McMAL
1272 McMAL
1272 McMAL
1272 McMAL
1272 McMAL
1272 McMAL
17,912 307,926
49,827 342 53 964 890
325,838
137,548
82,019 744 943 826,962 070
92,558 332,788
741,789 15,855,199
1,425,346
113,410
502694120 5,292,286598,166
862 135 389,801
432,304 2,503 086 10,23170,781
1272 McMAL 36,461 587,224
251,936 133
623,685
94,490147,028 128,329 90,275,358
Page 423FERC FORM NO.1 (ED. 12-87)
Maintenance
Expenses
(n)
127,811
380
40,872
199,984
790
301
Rents
(0)
319
513
Total
Expenses
Line
No.
(fJ)
207 366 3
389 7
21,380 10
40,872 12
291 14
7,433 16
10,744 18
294,474 37
Data Request for Statistics Report - 2006
Line No
Electric Service Revenues
234,714,224 211,934 411 160,231,038 141 335 728
314 154,243 295,031 827 198,535,862 181 038,584
268,037 897 543 627,865 289,060
849 076 825,393 732,964 712 660
175,572 595 221 ,803,806 160,120,645 162 882,986
66,996,908 60,058,249 243 215 20,231 272
Total Electric Service Revenues
Dis osition of Ener
577 694 419 532 2,431,601 328 295
171,749 085 157 952 151 876,001
24,783 25,060 16,652 068
12,776 925 013 11,230
552,362 144,503 246,674 264,440
Total Dis osition of Ener
Avera e Number of Electric Customers Per Month
300 940 294,036 201 ,276 197,187
300 689 23,052 760
425 420 292 284
Miles of Transmission Pole Lines Rounded 135 136 134 133
Number of Line Transformers 107 624 105 292 75,762 139
Ca aci of All Line Transformers 352 217 357 295
Number of Meters 356 506 344 231 239 211 229,123
Electric Statistic DATA.XLS
IDAHO
Name of Respondent This R~rt Is:
(1) 129 An Original
Date of Report
(Mo, Da, Yr)
State of Idaho
Year of Report
Avista Corp (2)A Resubmission Apr. 18,2007 Dec. 31, 2006
STATEMENT OF INCOME FOR THE YEAR
1. Report amounts for accounts 412 and 413, Revenue
and Expenses from Utility Plant Leased to Others, in another
utility column (i,o) in a similar manner to a utility depart-
ment. Spread the amount(s) over lines 01 thru 20 as ap-
propriate. Include these amounts in columns (c) and (d)
totals.
2. Report amounts in account 414, Other Utility Operating
Income, in the same manner as accounts 412 and413 above.
3. Report data for lines 7,9, and 10 for Natural Gas com-
panies using accounts 404.1, 404.2, 404.3, 407.1. and
407.
4. Use page 122 for important notes regarding the state-
ment of income or an account thereof.
Line
No.
Account
(a)
FERC FORM NO.1 (REVISED 06-04)
(Ref.
Page
No.
(b)
300-301
320-325
320-325
336-338
336-338
336-338
262-263
262-263
262-263
234,272-277
234,272-277
266
Page 114
5. 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
customers or which may result in a material refund to the
utility with respect to power or gas purchases. State for each
year affected the gross revenues or costs to which the con-
tingency relates and the tax effects together with an expIa-
tion of the major factors which affect the rights of the utility
to retain such revenues or recover amounts paid with respect
to power and gas purchases.
6. Give concise explanations concerning significant
amounts of any refunds made or received during the year
TOTAL
CUD'ent Year Previous Year
$285,679,270 $280,597,321
Name of Respondent This R~rt Is:
(1) 129 An Original
A vista Corp (2)A Resubrnission Apr. 18,2007 Dec. 31, 2006
Dale of Report
(Mo, Da, Yr)
Stale of Idaho
Year of Report
STATEMENT OF INCOME FOR THE YEAR
resulting from settlement of any rate proceeding affecting
revenues received or costs incurred for power or gas pur-
chases, and a summary of the adjustments made to balance
sheet, income, and expense accounts.
7. If any notes appearing in the report to stockholders are
applicable to this Statement of Income, such notes may be at-
tached at page 122.
8. Enter on page 122 a consise explanation of only those
changes in accounting methods made during the year which
had an effect on net income, including the basis of allocations
and apportionments from those used in the preceding year.
Also give the approximate dollar effect of such changes.
9. Explain in a foonote if the previous year's figures are
different from that reported in prior reports.
10. If the colulJU1s are insufficient for reporting additional
utility departments, supply the appropriate account titles, lines
1 to 19, and report the infonnation in the blank space on page
122 or in a supplemental statement.
OTHER UTILITYELECTRIC UTILITYCurrent Year Previous Year
GAS UTILITYCurrent Year Previous Year Current Year Previous Year Line
No.
$199,286,135 $194,621 447
FERC FORM NO.1 (REVISED 06-04)
$86,393,135 $85,975,874
Page 115
Name of Respondent This Report Is:
(1)I29An Original
A vista Corporation (2)DA Resubmission
Date of Report
(Mo, Da, fr)
State of Idaho
Year of Report
April 18, 2007 December 31 2006
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Line
No.
Item
(a)
UTILITY PLANT
In Service
Plant in Service (Classified)
Pro ert Under Ca ital Leases
Plant Purchased or Sold
Com leted Construction not Classified
Investment in Kettle Falls
TOTAL (Enter Total of lines 3 thru 7)
Leased to Others
JO Held for Future Use
11 Construction Work in Pro ress
12 Ac uisition Ad'ustments13 TOTAL Utilit Plant (Enter Total of lines 8 thru 12 )
14 Accum. Prov. for De L, Amort., & De l.15 Net Utilit Plant (Enter total of line 13 less 14)
DETAIL OF ACCUMULATED PROVISIONS FOR
16 DEPRECIATION, AMORTIZATION AND DEPLETION
17 In Service:18 De reciation19 Amort. and De l. of Producin Nat. Gas Land and Land Ri hts20 Accumulated De reciation - Kettle Falls21 Amort. of Other Utilit Plant22 TOTAL in Service (Enter Total oflines 18 thru 21)
23 Leased to Others24 De reciation25 Amortization and De letion26 TOTAL Leased to Others (Enter Total of lines 24 and 25)
27 Held for Future Use28 De reciation29 Amortization30 TOTAL Held for Future Use (Ent. Tot. of lines 28 and 29)31 Abandonment of Leases (Natural Gas)32 Amort. of Plant Ac uisition Ad'ustment
TOTAL Accumulated Provisions (Should agree with line 14 above)
(Enter Total of lines 22, 26, 30, 31 , and 32)
FERC FORM NO.1 (ED. 12-89)Page 200
Total Electric
742 055 194
654 635
628,051 134
743 709,829 628 051,134
827,584
752,537,413
752 537.413
329,879
635 381,013
635,381 013
Name of Respondent This R~ort Is:
(1) 129 An Original
Date of Report
State of Idaho
Year of Report
A vista Corporation (2) D A Resubmission April 18,2007 December 31, 2006
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION (Continued)
Gas Other (Specify)Other (Specify)Other (Specify)Common Line
No.
334 933
137,659 3
251 446 4
389,105
162,772
551 877
551,877
108,866,401
403,189
109,269,590
110,604 523
110 604 523
FERC FORM NO.1 (ED. 12-89)Page 201
Name of Respondent This Re~rt Is:Date of Report Year of Report (1) X An Original (Mo, Va, Yr)
Avista Corp.(2)A ResubI1l1ssion April 18 2007 082
ELECTRIC PLANT IN SERVICE (Accounts 101 102 103,106)
1. Report below the original cost of electric plant in service ac-estimated basis if necessary, and include the entries in column
cording to the prescribed accounts.(c). Also to be included in column (c) are enb:ies for reversals
2. In addition to Account 101, Electric Plant in Service (Clas-of tentative distributions of prior year reported in column (b).
sified), this page and the next include Accounts 102, Electric Plant Likewise, if the respondent has a significant amount of plant
Purchased or Sold; Account 103, Experimental Electric Plant Un-retirements which have not been classified to primary accounts
Classified; and Account 106, Completed Construction Not Clas-at the end of the year, include in column (d) a tentative distrib-
sified - Electric.ution of such retirements on an estimated basis, with approp-
3. Include in column (c) or (d), as appropriate, corrections of add-riate contra entry to the account for accumulated depreciation
itions and retirements for the current or preceding year.provision. Include also in column (d) reversals of tentative dis-
4. Enclose in parentheses credit adjustments of plant accounts to tributions of prior year of unclassified retirements. Attach sup-
indicate the negative effect of such accounts.plemental statement showing the account distributions of these
5. Classify Accountl06 according to prescribed accounts, on an tentative classifications in columns (c) and (d), including the
Balance at
Line Account Beginning of Year Additions
No.(a)(b)(e)
1. INTANGIBLE PLANT
(301)Or,ganization
(302)Franchises and Consents 036 684
(303)Miscellaneous Intan.e;ible Plant
TOTAL Jntan.e;ible Plant (Enter Total of lines 2, 3, and 4)036 684
2. PRODUCTION PLANT
A. Stearn Production Plant
(310)Land and Land Ri.$ts
(311)Structures and Imvrovements
(312)Boiler Plant Equipment
(313)En,gines and En,gine Driven Generators
(314)Turbo!!enerator Units
(315)Accessory Electric Equipment
(316)Misc. Power Plant Equipment
(317)Asset Retirement Costs for Steam Production
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)
B. Nuclear Production Plant
(320)Land and Land Ri.$ts
(321)Structures and Jrnvrovements
(322)Reactor Plant Equipment
(323)Turbo,generator Units
(324)Accessory Electric Equipment
(325)Misc. Power Plant Equipment
(326)Asset Retirement Costs for Nuclear Production
TOTAL Nuclear Production Plant (Enter Total of lines 18 tbru 24)
C. Hydraulic Production Plant
(330)Land and Land Ri.$ts 053 598 776
(331)Structures and hnprovements 10,115 993 109,839
(332)Reservoirs, Dams, and Waterways 059,991 233 110
(333)Water Wheels, Turbines, and Generators 237 616 265
(334)Accessory Electric Equipment 073,258 000
(335)Misc. Power Plant Equipment 600,300 50,946
(336)Roads, Railroads, and Brid!!es 098,564
(337)Asset Retirement Costs for Hydraulic Production
TOTAL Hydraulic Production Plant (Enter Total of lines 27 tbru 34)239,320 450,936
D. Other Production Plant
(340)Land and Land Ri.$ts 621 682
(341)Structures and hnprovements 3,186 951
(342)Fuel Holders, Products and Accessories 700 144
(343)Prime Movers 658,328
(344)Generators 574 276
(345)Accessory Electric Equipment 879 612
FERC FORM NO.1 (ED. 12a91)
State of Idaho
Page 204
State of Idaho
Name of Respondent This
ooort Is:
Date of Report Year of Report(1) X An Original (Mo, Da, Yr)
Avista Corp.(2)A ResubmisslOn Apri118, 2007 December 31,2006
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103, and 106) (Continued)
r~versals of th~ prior years tentativ~ account distributions of umn (f) only th~ offset to th~ debits or credits distributed in
these amounts. Car~ful observance of the above instructions column (f) to primary account classifications.
and the texts of Accounts 101 and 106 will avoid serious omis-7. For Account 399, state the natur~ and use of plant included
sions of the reported amount of respondent's plant acmally in the account and if substantial in amount submit a supple.-
m servic~ at end of year.mentary statement showing subaccount classification of such
Show in column (f) reclassifications or transfers within plant conforming to the requirements of these pages.
utility plant accounts. Include also in column (f) the additions 8. For each amount comprising the reported balanc~ and
or reductions of primary account classifICations arising from changes in Account 102, state the property purchased or sold
distribution of amounts initially recorded in Account 102. name of vendor or purchaser, and date of transaction. If pro-
showing the clearance of Account 102, include in column (e)posed journal entries hav~ been filed with the Commission
the amounts with respect to accumulated provision for as required by the Uniform System of Accounts,giv~ also
depr~ciation, acquistion adjustments, etc., and show in col-date of such filing.
Balance at
Retirements Adjustments Transfers End of Year Line
(d)(e)(f)(fl)No.
(301)
036 684 (302)
(303)
036 684
(310)
(311)
(312)
(313)
(314)
(315)
(316)
(317)
(320)
(321)
(322)
(323)
(324)22!
(325)
(326)
056,374 (330)
10,225 832 (331)
293,101 (332)
237 881 (333)
6,127 258 (334)
651 246 (335)
098 564 (336)
(337)
690 256
621 682 (340)
186 951 (341)
700,144 (342)
658,328 (343)
574 276 (344)
11,528 868 084 (345)
FERC FORM NO.1 (ED. 12-87)Page 205
State of Idaho
Name of Respondent This Re~rt Is:Date of Report Year of Report (I) X An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission Apri118, 2007 082
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102 103,106)
Balance at
Line Account Begmning of Year Additions
No.(a)(b)(c)
(346)Misc. Power Plant Equipment
(347)Asset Retirement Costs for Other Production
TOTAL Other Production Plant (Enter Total of lines 37 thru 45)59,620 993
TOTAL Production Plant (Enter Total of lines 16, 25, 35 , and 45)145 860 313 450 936
3. TRANSMISSION PLANT
(350)Land and Land Rights 959,664 299,185
(352)Structures and Improvements 5,469,469 674 995
(353)Station Equipment 59,210 969 955 732
(354)Towers and Fixtures 556 655
(355)Poles and Fixtures 307 021 602 518
(356)Overhead Conductors and Devices 702 869 078,699
(357)Underground Conduit
(358)Underground Conductors and Devices
(359)Roads and Trails 374,002
(359.Asset Retirement Costs for Transmission Plant
TOTAL Transmission Plant (Enter Total of lines 48 thru 57)138 580,649 611 129
4. DISTRIBUTION PLANT
(360)Land and Land Rights 819 234
(361)Structures and Improvements 726 057 865
(362)Station Equipment 910,468 340 227
(363)Storage Battery Equipment
(364)Poles, Towers, and Fixtures 637 912 924,826
(365)Overhead Conductors and Devices 754 239 864 541
(366)Underground Conduit 031,577 873 360
(367)Underground Conductors and Devices 33,320 931 869,450
(368)Line Transfonners 47,499 076 956 292
(369)Services 35,984 812 458 760
(370)Meters 955 094 176 022
(371)Installations on Customer Premises
(372)Leased Propertv on Customer Premises
(373)Street Lighting and Signal Systems 10,018 231 892 001
(374)Asset Retirement Costs for Distribution Plant
TOTAL Distribution Plant (Enter Total of lines 60 thru 74)298 657 631 17,450,345
5. GENERAL PLANT
(389)Land and Land Rights 101 907
(390)Structures and Improvements 975 391 44,754
(391)Office Furniture and Equipment
(392)Transuortation Equipment 063 833 239 001
(393)Stores Equipment 30,140
(394)Tools, Shop and Garage Equipment 436 234 313
(395)laboratory Equit ment 315 728
(396)Power Operated :!quipment 946 584 733 249
(397)Connnunication !auipment 301 131 445 929
(398)Miscellaneous B uimnent 486 299
SUBTOTAL (Enter Total of lines 77 thru 86)10,171,434 472 544
(399)Other Tangible Propertv
(399.Asset Retirement Costs for General Plant
TOTAL General Plant (Enter Total of lines 87 and 90)10,171,434 1,472,544
TOTAL (Accounts 101 and 106)602 306 711 984,954
(102)Electric Plant Purchased
(Less)(102) Electric Plant Sold
(103)Exuerimental Plant Unclassified
TOTAL Electric Plant in Service 602 306 711 27,984 954
FERC FORM NO.1 (ED. 12-87)Page 206
State of Idaho
Name of Respondent This R~ort Is:Date of Report Year of Report(I) X An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission April 18, 2007 December 31,2006
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103, and 106) (Continued)
Balance at
Retirements Adjustments Transfers End of Year Line
(d)(e)(J!)No.
(346)
(347)
11,528 609,465
11,528 146 299,721
258 849 (350)
6,144,464 (352)
396,190 (145 620)624,891 (353)
556 655 (354)
105 858 580 814 261 (355)
23,175 578 759,971 (356)
(357)
(358)
374 002 (359)
(359.
525 223 (133,462)146 533 093
819 234 (360)
49,360 771 562 (361)
337 103 218 27,920 810 (362)
(363)
141 246 68,421,492 (364)
123 395 46,495 385 (365)
50,438 854 500 (366)
339 435 850 946 (367)
35,487 50,419,881 (368)
683 376 889 (369)
131,116 (370)
(371)
(372)
690 852,542 (373)
(374)
200 836 218 314 914 358
101 907 (389)
038 017 107 (390)
(391)
777 293 057 (392)
140 (393)
739 422 808 (394)
874 314 854 (395)
679 833 (396)
258 (341,014)2,404 789 (397)
785 (398)
685 (341 014)267,279
(399)
(399.
685 (341 014)11,267 279
773,273 (467 258)628 051,134
(102)
(103)
773 273 (467 258)628 051 134
FERC FORM NO.1 (ED. 12-87)Page 207
Name of Respondent This R~rt Is:
(1 ) 129 An Original
Date of Report
(Mo. Da, Yr)
State of Idaho
Year of Report
A vista Corporation (2)A Resubmission
ELECTRIC OPERATING REVENUES (Account 400)
April 18,2007
I. Report below operating revenues for each prescribed
account, and manufactured gas revenues in total.
2. Report number of customers, columns (f) and (g), on
the basis of meters, in addition to the number of flat rate
accounts; except that where separate meter readings are
added for billing purposes, one customer should be counted
Line
No.
Title of Account
(a)
Sales of Electricit
(440) Residential Sales
(442) Commercial and Industrial Sales (3)
Small (or Commercial)
Lar e (or Industrial)
(444) Public Street and Hi hwa Li htin
(445) Other Sales to Public Authorities
(446) Sales to Railroads and Railwa s
(448) Interde artmental Sales10 TOTAL Sales to Ultimate ConsumersII (447) Sales for Resale12 TOTAL Sales of ElectricitJ3 (Less) (449.1) Provision for Rate Refunds14 TOTAL Revenues Net of Provision for Refunds15 Other 0 eratin Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Pro ert
20 (455) Interde artmental Rents
21 (456) Other Electric Revenues
FERC FORM NO.1 (ED. 12-90)
Dec. 31, 2006
for each group of meters added. The average number
customers means the average of twelve figures at the close
of each month.
3. If previous year (columns (c), (e), and (g), are not
derived from previously reported figures, explain any incon-
sistencies in a footnote.
OPERATING REVENUES
Amount for Amount forYear Previous Year(b) (c)
63,990,388 61,484 647
625 770 506,620
640 172 608,483
108 667 106,340
191 841 036 (1)186 297 815
853 338 249 035
192,694 374 187 546 850
192 694 374 187,546,850
166 620 155 028
721 856 689 835
703 285 229 734
591 761
$199,286 135
074 597
$194,621,447
Page 300
Name of Respondent This R~rt Is:
(1 ) lliI An Original
Date of Report
(Mo, Da, Yr)
State of Idaho
Year of Report
A vista Corporation (2)A Resubmission April 18, 2007 Dec. 31 2006
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4. Commercial and Industrial Sales, Account 442, may
be classified according to the basis of classification (Small
or Commercial, and Large or Industrial) regularly used by
the respondent if such basis of classifcation is not generally
greater than 1000 Kw of demand. (See Account 442 of the
Uniform System of Accounts. Explain basis of classification
in a footnote.
5. See page 108, Important Changes During Year, for
important new territory added and important rate increases
or decreases.
6. For lines 2, 4, 5 , and 6, see page 304 for amounts
relating to unbilled revenue by accounts.
7. Include unmetered sales. Provide details of such sales
in a foonote.
MEGA WATT HOURS SOLD
Line
No.
975 577 941 318 15,753 15,426
243 987 267 808 494 502
131 992 133 136
648 599
375 278 (2)309,801 116,052 112 924
029 878
3,405 307 331 679 116 052 112 926
3,405 307 331 679 116 052 112 926
Amount for
Previous Year
(e)
A VG. NO. OF CUSTOMERS PER MONTH
Number for
Number for Year Previous Year
(1) Includes $45 753 of unbilled revenues.
(2) Includes 1 247 MWH relating to unbilled revenues.
(3) Segregation of Commerical and Industrial made on basis of utilization of energy and not on size of account.
FERC FORM NO.1 (ED. 12-89)Page 301
SALES OF ELECTRICITY BY RATE SCHEDULES
I. Report below for each rate schedule in effect during the (such as a general residential schedule and an off peak water
year the mWh of electricity sold, revenue, average number of heating schedule), the entries in column (d) for the special
customers, 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 number
2. Provide a subheading and total for each prescribed of bills rendered during the year divided by the number of
operating revenue account in the sequence followed in "Elec- billing periods during the year (12 if all billings are made
tric Operating Revenues " page 301. If the sales under any rate monthly).
schedule are classified in more than one revenue account, lis! 5. For any rate schedule having a fuel adjustment clause
the rate schedule and sales data under each applicable revenue state in a footnote the estimated additional revenue billed pur-account subheading. suant thereto.
3. Where the same customers are served under more than 6. Report amount of unbilled revenue as of end of year for
one rate schedule in the same revenue account classification each applicable revenue account subheading.
Average KWH
Number of Sales perCustomers Customer(d) (e)
Name of Respondent
A vista Corporation
Line
No.
Number and Title of Rate Schedule
(a)
I RESIDENTIAL SALES (440)
I Residential Service3 2 Residential Service
3 Residential Service
12 Res. & Fann Gen. Service
6 22 Res. & Fann Lg. Gen. Service
7 30 Pumping-Special
8 32 Res. & Fann PumpIng Service
9 48 Res. & Fann 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-Unbilled
21 COMMERCIAL SALES (442)
22 2 General Service
23 3 General Service24 II General Service
25 19 Contract-General Service
26 21 Large General Service
27 25 Extra Lg. Gen. Service
28 28 Contract-Extra Large 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 Total
42 Commercial-Unbilled
43 Total Billed
44 Total Unbilled Rev. (See Instr. 6)
45 TOTAL
FERC FORM NO.1 (ED 12-90)
This Report Is:
~An Original
DA Resubmission
MWH Sold
(b)
110,816
838
877
169
282
285
142 267
668
290,664
581,525
113
26,835
196
260
976,593
(1,016)
118,860
652
121,512
Date of Report
(Mo, Da, Yr)
Year of Report
April 18, 2007 Dec. 31, 2006
State of Idaho
Revenue
Revenue
(cents) per
KWH Sold
(f)(c)
70,744 675
528,336
487,168
95,255 11 ,661
851 632
554 813
226,207
214 904
63,473
531 968
43,060
924 668
74,232,491
243 548
99,653 462
575,296 059 20,675
055,119
103,257
285 452 549
704,333
687 263
141 486
394,454
406 096
322
166 859
132 056
(141 668)
138 364 547
101 880
138 466,427
15,753 61,994
115,406
115,406
Page 304
5.49
16.
22.
11.
17.45
Name of Respondent This Report Is:~An Original
Date of Report
(Mo, Da, Yr)
Year of Report
April 18, 2007 Dec. 31, 2006
State of Idaho
SALES OF ELECTRICITY BY RATE SCHEDULES
I. Report below for each rate schedule in effect during the (such as a general residential schedule and an off peak water
year the mWh of electricity sold, revenue, average number of heating schedule), the entries in column (d) for the special
customers, 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 number
2. Provide a subheading and total for each prescribed of bills rendered during the year divided by the number of
operating revenue account in the sequence followed in "E\ec- billing periods during the year (12 if all billings are made
tric Operating Revenues," page 301. If the sales under any rate monthly).
schedule are classified in more than one revenue account, list 5. For any rate schedule having a fuel adjustment clause
the rate schedule and sales data under each applicable revenue state in a footnote the estimated additional revenue billed pur-account subheading. suant thereto.
3. Where the same customers are served under more than 6. Report amount of unbilled revenue as of end of year for
one rate schedule in the same revenue account classification each applicable revenue account subheading.
Average KWH
Number of Sales perCustomers Customer(d) (e)
A vista Corporation DA Resubmission
Lint
No.
Number and Title of Rate Schedule MWH Sold
(a)
INDUSTRIAL SALES (442)
2 General Service
3 General Service
8 Lg Gen Time of Use
11 General Service
21 Large General Service
25 Extra Lg. Gen. Service
28 Contract-Extra Large Service
29 Contract Lg. Gen. Service
30 Pumping Service -Special
31 Pumping Service
32 Pumping Svc Res & Fnn
47 Area Lighting-Sod. Yap.
49 Area Lighting-High-Press.
56 Centralia Credit
72 General Service
73 General Service
74 Large General Service
75 Large General Service
76 Pumping Service
77 General Service
78 Lg Gen Tim of Use
58 Tax Adjustment
Total
Industrial-Unbilled
(b)
27 STREET AND HWY LIGHTING (444)
28 11 General Service
29 41 Co.Owned St. Lt. Service
30 42 Co.Owned St. Lt. Service
31 High-Press. Sod. Yap.
32 43 Cust.-Owned St. Lt. Energy33 and Maint. Service
34 44 Cust.Owned St. Lt. Energy35 and Maint. Svce.High-36 Press. Sod. Yap.
37 45 Cust.Owned St. Lt. Energy Service
38 46 Cust.Owned St. Lt. Energy Service
39 High-Press. Sod. Yap.
40 56 Centralia Credit
41 58 Tax Adjustment42 Total43 Street and Hwy Lighting-Unbilled
44 Total Billed
45 Total Unbilled Rev. (See Instr. 6)
46 TOTAL
FERC FORM NO.1 (ED 12-90)
580
745
139,603
566
772
245,392
(1,405)
117
175
559
283
897
131
372,383
247
373 630
Revenue
(c)
299,863
4,420,094
45,169,155
133
530,828
163 171
028
382
220
376
681 897
(56,127)
494
214
14,863
445,988
259
623
680
036
25,509
640,172 133
191,686,616
45,753
191 732,369
116 033
116 033
Page 304.
26,917
879,353
966,917
111,664
000
521 036
333
23,400
68,611
000
882
333
700
135
Revenue
(cents) per
KWH Sold
if)
11.00
15.
8.46
12.
23.42
8.48
12.
SALES OF ELECTRICITY BY RATE SCHEDULES
I. Report below for each rate schedule in effect during the (such as a general residential schedule and an off peak water
year the mWh of electricity sold, revenue, average number of heating schedule), the entries in column (d) for the special
customer~, 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 number
2. Provide a subheading and total for each prescribed of bills rendered during the year divided by the number of
operating revenue account in the sequence followed in "Elec- billing periods during the year (12 if all billings are made
triG Operating Revenues " page 301. If the sales under any rate monthly).
schedule are classified in more than one revenue account, list 5. For any rate schedule having a fuel adjustment clause
the rate schedule and sales data under each applicable revenue state in a footnote the estimated additional revenue billed pur-account subheading. suant thereto.
3. Where the same customers are served under more than 6. Report amount of unbilled revenue as of end of year for
one rate schedule in the same revenue account classification each applicable revenue account subheading.
Average KWH
Number of Sales perCustomers Customer(d) (e)
10 SALES FOR RESALE (447) (1)
II 61 Sales to Other Utilities - ID
17 Note: Sch. 61 is a state assigned rate schedule for Sales/Resale
39 Total Billed
40 Total Unbilled Rev.
41 TOTAL
FERC FORM NO.1 (ED 12-90)
Name of Respondent
A vista Corporation
Line
No.
Number and Title of Rate Schedule
(a)
OTHER SALES TO PUBLIC
AUTHORITIES (445)
None
mTERDEP ARTMENT AL
SALES (448)
58 Tax Adjustment
Total
Total
This Report Is:
(2g An Original
DA Resubmission
MWH Sold
(b)
648
648
30,029
30,029 I
404 060
247
405,307
Date of Report
(Mo, Da. Yr)
Year of Report
April 18, 2007 Dec. 31, 2006
State of Idaho
Revenue
Revenue
(cents) per
KWH Sold
if)(c)
108,667 737
108,667 86,737
853 338
853,338
192,648,621
45,753
192 694 374
Page 304.
116,052
116 052
29,332
29,343
This Page Intentionally Left Blank
Idaho
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Origina
Avista Cor (2)A Resubm April 18 2007 December 31, 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line
No.Account Amount for Current Year Amount for Prior Year
la)Ib)Ie)
(1) POWER PRODUCTION EXPENSES
A. Steam Power Generation
Operation
500 Operation Supervision and Enaineerina 18,211
501 Fuel
502 Steam Expenses (3,230
503 Steam from Other Sources
Less) (504) Steam Transferred-Cr.
505 Electric Expenses 13,723
506 Miscellaneous Steam Power Expenses 33,357 18,593
507 Rents
509 Allowances
TOTAL Operation (Enter Total of Lines 4 thru 1 1)357 3,429
Maintenance
510 Maintenance Supervision and Enaineerina (571
511 Maintenance of Structures 1115
512 Maintenance of Boiler Plant 988
513 Maintenance of Electric Plant 1466
514 Maintenance of Miscellaneous Steam Plant (923
TOTAL Maintenance (Enter Total of Lines 14 thru 18)063
TOTAL Power Production Expenses-Steam Plant (Enter Total of 33,357 1634
B. Nuclear Power Generation
Operation
517 Operation Supervision and Enaineerina
518 Fuel
519 Coolants and Water
520 Steam Expenses
521 Steam from Other Sources
Less I (522) Steam Transferred-Cr.
523)Electric Expenses
524)Miscellaneous Nuclear Power Expenses
525)Rents
TOTAL Ooeration (Enter Total of liens 23 thru 31)
Maintenance
528 Maintenance Supervision and EnQineerinQ
529 Maintenance of Structures
530 Maintenance of Reactor Plant Eauipment
531 Maintenance of Electric Plant
532 Maintenance of Miscellaneous Nuclear Plant
TOTAL Maintenance (Enter Total of lines 34 thru 38)
TOTAL Power Production Expenses-Nuclear Power(Enter total c
C. Hydraulic Power Generation
Operation
535 Operation Supervision and Enoineerina 534,370 489,563
536 Water for Power 258,691 263,695
537 Hvdraulic Expenses 750,076 763,857
538 Electric Expenses 330,985 295,532
539 Miscellaneous Hvdraulic Power Generation Expenses 291 202 205,936
540 Rents 747 23,079
TOTAL Operation (Enter Total of lines 43 thru 48)188,07t 041 662
FERC FORM NO.1 (12-96)Page 320
Idaho
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Origina
Avista COil (2)A Resubm April1B 2007 December 31 , 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line
No.Account Amount for Current Year Amount for Previous Year
(b)
C. Hvdraulic Power Generation (Continued)
Maintenance
541 Maintenance Suoervision and Enoineerino 136,022 B6,9B3
542 Maintenance of Structures 127,7B9 151,462
543 Maintenance of Reservoirs, Dams, and Waterways 134,952 190,501
544 Maintenance of Electric Plant 760,676 5B7 959
545 Maintenance of Miscellaneous HVdraulic Plant 109,274 174,65B
TOTAL Maintenance (Enter Total of lines 52 thru 56)26B 713 191 563
TOTAL Power Production Exoenses-Hvdraulic Power (Enter total 4,456 7B3 233 225
D. Other Power Generation
Operation
546 Operation Suoervision and Enaineerina 115 32,193
547 Fuel 655,935 711,402
54B Generation Expenses 120,501 110,2B2
549 Miscellaneous Other Power Generation Exoenses 215,4B9 211 B03
550 Rents (11 557 3,497 025
TOTAL Ooeration (Enter Total of lines 61 thru 65)055,4B4 562 704
Maintenance
551 Maintenance Supervision and Ennlneerina 110 B17
552 Maintenance of Structures 17,4B2 617
553 Maintenance of Generatina and Electric Plant 57,533 133
554 Maintenance of Miscellaneous Other Power Generation Plant 110,005 79,942
TOTAL Maintenance (Enter Total of lines 6B thru 71\191 130 116,509
TOTAL Power Production ExDe!nses-Other Power (Enter Total of I 246,613 679,213
E. Other Power Suoolv Expenses
555\ Purchased Power 6B,36B,436 504,630
556\ System Control and Load Diwatchina 21B,263 235,321
557) Other Expenses 1B,609,77B 16,406,456
TOTAL Other Power Supplv Expenses (Enter Total of lines 75 thr 196,477 1 OS, 146,40B
TOTAL Power Production Expenses (Enter Total of lines 20, 40, 5 933,231 117 05B,212
2. TRANSMISSION EXPENSES
Operation
560\ Operation Supervision and En(;jneerino 54B,22B 550 B92
561) Load Disoatchina 657 026 519 710
561.Load Dispatchina Reliabilitv 540
561.2 Load Dispatchina Monnor and Operate Transmission System 390 517
561.3 Load Dispatchina Transmission Service and Sched 263,400
(561.4 SchedulinG Svsemt Control and Disoatch Services
561.Reliabilitv, PlanninG and Standards Development
561.Transmission Service Studies
561.Generation Interconnection Studies
561.B Reliability, PlanninG and Standards Develonment Services
562 Station Expenses B5,369 B2,319
563 Overhead Line Expenses 66,030 B66
564 UnderGround Line Expenses
565 Transmission of ElectriCiiVbvOthers 059,B63 409 904
566 Miscellaneous Transmission Expenses 244 325 234,B95
567 Rents 14,349 719
TOTAL Operation (Enter Total of lines B2 thru B9\334,647 B61 ,303
Maintenance
100 56B Maintenance Supervision and Enaineerina 72B 345
101 569 Maintenance of Structures 104 065 957
102 570 Maintenance of Station EOUioment 1B1 341 200 592
103 571 Maintenance of Overhead Lines 45B,974 542 1B5
104 572 Maintenance of UnderGround Lines 001 I2BO
105 573 Maintenance of Miscellaneous Transmission Plant 19,120 261
106 TOTAL Maintenance (Enter Total of lines 92 thru 97\B5B,229 942,060
107 TOTAL Transmission Expenses (Enter Total of lines 90 and 9B)192 B76 B03,364
10B 3. DISTRIBUTION EXPENSES
109 Operation
110 5BO\ Operation Supervision and Enaineerina 293,45B 304 746
FERC FORM NO.1 (12-96)Page 321
Idaho
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Origina
Avista Co~(2)A Resubm April 18, 2007 December 31, 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line
No.Account Amount for Current Year Amount for Prior Year
(a)(b)
103 3. DISTRIBUTION EXPENSES (Continued)
104 581 Load Dispatchina
105 582 Station Excenses 157 769 134,104
106 583 Overhead Line Expenses 385 523,959
107 584 Underaround Line Expenses 498,697 570,427
108 585 Street Liahtina and Sianal Svstem Expenses 115,798 119,976
109 586 Meter Expenses (12 856 34,146
110 587 Customer Installations Exoenses 422 091 376,134
111 588 Miscellaneous Distribution Excenses 353,687 377,277
112 589 Rents 42,662 70,650
113 TOTAL Oceration (Enter Total of lines 102 thru 112)882,689 511 419
114 Maintenance
115 590 Maintenance Supervision and Enaineerina 513 607 360,429
116 591 Maintenance of Structures 73,497 38,086
117 592 Maintenance of Station Epuipment 195,423 134,133
118 593 Maintenance of Overhead Lines 711,401 151,130
119 594 Maintenance of Underaround Lines 291 011 270,910
120 595 Maintenance of Line Transformers 269 43,613
121 596 Maintenance of Street Liohtina and Sianal Svstems 96,827 109 552
122 597 Maintenance of Meters 732 646
123 598 Maintenance of Miscellaneous Distribution Plant 124,143 225,613
124 TOTAL Maintenance (Enter Total of lines 115 thru 123)147,910 3,401 112
125 TOTAL Distribution Expenses (Enter Total of lines 113 and 124)030 599 912 532
126 4. CUSTOMER ACCOUNTS EXPENSES
127 Operation
128 901 Supervision 174 315 229,236
129 902 Meter Readino Exoenses 686,250 900,692
130 903 Customer Records and Collection Excenses 927,898 649,438
131 904 Uncollectible Accounts 523,839 497 013
132 905 Miscellaneous Customer Accounts Exnenses 62,046 176,277
133 TOTAL Customer Accounts Exoenses IEnterTotalof lines 128 th 374 348 4,452 656
134 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
135 Operation
136 907 Suoervision
137 908 Customer Assistance Expenses 773,471 701,463
138 909 Informational and Instructional Emenses 687 585
139 910 Miscellaneous Customer Service and Informational Expenses 36,474 36,322
140 TOTAL Cust Service and Informational Expenses (Enter Total of 825,631 750,370
141 6. SALES EXPENSES
142 Ooeration
143 911 Supervision
144 912 Demonstratina and Sellina EXDenses 187 773 150,897
145 913 Advertisina Exoenses 86,793 46,430
146 916 Miscellaneous Sales Exoenses
147 TOTAL Sales Excenses (Enter Total of lines 143 thru 146)274 565 197 327
148 7. ADMINISTRATIVE AND GENERAL EXPENSES
149 Operation
150 920) Administrative and General Salaries 919,473 234 111
151 921) Office Supplies and Exnenses 1,425,626 357 764
152 Less) (922) Administrative exoenses Transferred-Credn (9,480 18,185
FERC FORM NO.1 (12-96)Page 322
Idaho
(2)
Date of Report Year of ReportName of Respondent This Report Is:
(1)An Origina
Avista Co~A Resubm April 18 2007 December 31, 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line
No.
153
154
155
156
157
158
159
160
161
162
163
164
165
166
167
168
Account
(a)
7. ADMINISTRATIVE AND GENERAL EXPENSES
923 Outside Services Emoloved
924 Prooertv Insurance
925 Iniuries and Damaaes
926 Emolovee Pensions and Benefits
927 Franchise Reouirements
928 Reoulatorv Commission Exoenses
Less) (929) Duolicate Charaes-Cr.
930.1) General Advertisino Exnenses
930.2) Miscellaneous General Exoenses
931) Rents
TOTAL Ooeration (Enter Totaf of lines 150 thru 163)
Maintenance
935) Maintenance of General Plant
TOTAL Administrative and General Exoenses (Enter Total of line
TOTAL Electric Ooeration and Maintenance Exoenses (Enter To
79,99,125,133,140,147,and 167Y
Amount for Current Year
(b)
Continued)
Amount for Prior Year(c)
374 986
402,571
273,664
347,888
230
700,607
231,968
365,995
940,719
353,924
350
569,939
18,868
978,249
393,515
15,415,480
922,385
360,538
14,724,488
1,495,039
16,219,527
132,850,777
367 039
16,782 519
154 956,979
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1. The data on number of empll construction employees in a footnote.
for the payroll period ending neare 3. The number of employees assignable to the electric
payroll period ending 60 days befo department from joint functions of combination utilities may
2. If the respondenfs payroll for be determined by estimate, on the basis of employee eouiva-
cludes any special construction lents.Show the estimated number of equivalent emolovees
employees on line 3, and show tho attributed to the electric department from joint functions.
1 Pavroll Period Ended !Date) December 31 2006
2 Total Reaular Full-Time Emolovees
3 Total Part-Time and TemoorarvEmniovees
4 Allocation of General Emolovees 106 162
5 Total Emolovees (See Note 1)196 253
FERC FORM NO.1 (12-96) Page 323
This Page Intentionally Left Blank
OREGON
Name of Respondent This R~rt Is:
(1) 129 An Original
Avista Corp (2)A Resubmission
Date of Report
(Mo, Da, Yr)
State of Ore on
Year of Report
Apr. 18, 2007 Dec. 31, 2006
STATEMENT OF INCOME FOR THE YEAR
1. R~port amounts for accounts 412 and 413, R~v~nue
and Exp~nses from Utility Plant Leased to Oth~rs, in another
utility column (i,k,m o) in a similar mann~r to a utility d~part-
ment. Spread the amount(s) over lines 01 thru 20 as ap-
propriate. Includ~ these amounts in columns (c) and (d)
totals.
2. Report amounts in account 414, Other Utility Operating
Income, in the sam~ manner as accounts 412 and413 above.
3. Report data for lines 7 9, and 10 for Natural Gas com-
panies using accounts 404.1, 404., 404.3, 407.1, and
407.
4. Use page 122 for important notes regarding the state-
ment of income or an account thereof.
Line
No.
Account
(a)
UTILITY OPERATING INCOME
Revenues (400) Note (1)
Ex enses
TOTAL Utility Operating Expenses
(Enter Total of lines 4 Ibm 18)
Net Utility Operating Income (Enter Total of
line 2 less 19) (Carry forward to page 117
line 21)
(Ref.
Page
No.
(b)
300-301
320-325
320-325
336-338
336-338
336-338
262-263
262-263
262-263
234 272-277
234 272-277
266
5. Give concise ~xplanations concerning unsettled rate
proceedings wher~ a contingency exists such that r~funds
of a material amount may need to be made to th~ utility
customers or which may result in a material refund to the
utility with respect to power or gas purchases. State for each
year affected the gross revenues or costs to which the con-
tingency relates and the tax ~ffects together with an ~xpla-
tion of the major factors which affect the rights of the utility
to retain such revenues or recover amounts paid with respect
to power and gas purchases.
6. Give concise explanations concerning significant
amounts of any refunds made or received during the year
TOTAL
Current Year Previous Year
$188,675 613 $212 417 865
Note: (1) Infonnation other than operating revenue not available by state.
FERC FORM NO.1 (REVISED 06-04)Page 114
Name of Respondent This R:::e,ort Is:(1) ug An Original
Date of Report
(Mo, Da, Yr)
State of Ore on
Year of Report
Avista Corp (2)A Resubmission Apr. 18,2007 Dec. 31, 2006
STATEMENT OF INCOME FOR TIIE YEAR
resulting from settlement of any rate proceeding affecting
revenues received or costs incurred for power or gas pur-
chases, and a summary of the adjustments made to balance
sheet, income, and expense accounts.
7. If any notes appearing in the report to stockholders are
applicable to this Statement of Income, such notes may be at-
tached at page 122.
8. Enter on page 122 a consise explanation of only those
changes in accounting methods made during the year which
had an effect on net income, including the basis of allocations
and apportionments from those used in the preceding year.
Also give the approximate dollar effect of such changes.
9. Explain in a foonote if the previous year s figures are
different from that reported in prior reports.
10. If the columns are insufficient for reporting additional
utility departments, supply the appropriate account titles, lines
1 to 19, and report the infonnation in the blank space on page
122 or in a supplementaJ statement.
ELECTRIC UTILITY
CUITent Year Previous Year
GAS UTILITY
CUITent Year Previous Year
OTHER UTILITY
CUITent Year Previous Year Line
No.
$169,657 722 $132 856 140
FERC FORM NO.1 (REVISED 06-04)Page 115
State of Oregon
Name of Respondent This R~ort Is:Date of Report Year of Report (1) X An Original (Mo, Va, Yr)
Avista Corp.(2)A ResubmisslOn April 18 2007 December 31, 2006
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102 103, 106)
1. Report below the original cost of electric plant in service ac-estimated basis if necessary, and include the entries in column
cording to the prescribed accounts.(c). Also to be included in column (c) are entries for reversals
2. In addition to Account 101, Electric Plant in Service (Clas-of tentative distributions of prior year reported in column (b).
sified), this page and the next include Accounts 102, Electric Plant Likewise, if the respondent has a signifICant amount of plant
Purchased or Sold; Account 103, Experimental Electric Plant Un-retirements which have not been classified to primary accounts
Classified: and Account 106, Completed Construction Not Clas-at the end of the year, include in column (d) a tentative distrib-
sified - Electric.ution of such retirements on an estimated basis, with approp-
3. Include in column (c) or (d), as appropriate, COITections of add-riate con1ra enlly to the account for accumulated depreciation
itions and retirements for thecwrent or preceding year.provision. Include also in column (d) reversals of tentative dis-
4. En.close in parentheses credit adjustments of plant accounts to tributions of prior year of unclassified retirements. Attach sup-
indicate the negative effect of such accounts.plemental statement showing the account dis1ributions of these
5. Classify AccountlO6 according to prescribed accounts, on an tentative classifications in columns (c) and (d), including the
Balance at
Line Account Beginning of Year Additions
No.(a)(b)(c)
1. INTANGIBLE PLANT
(301)Organization
(302),Franchises and Consents
(303)Miscellaneous Intangible Plant 205 162,604
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)205 162 604
2. PRODUCTION PLANT
A Steam Production Plant
(310)Land and Land Rights
(311)Structures and Improvements
(312)Boiler Plant Equipment
(313)Engines and Engine Driven Generators
(314)Thrbogenerator Units
(315)Accessory Electric Equipment
(316)Misc. Power Plant Equipment
(317)Asset Retirement Costs for Steam Production
TOTAL Steam Production Plant (Enter Total of lines 8 tbru 15)
B. Nuclear Production Plant
(320)Land and Land Rights
(321)Structures and Improvements
(322)Reactor Plant Equipment
(323)Thrbogenerator Units
(324)Accessory Electric Equipment
(325)Misc. Power Plant Equipment
(326)Asset Retirement Costs for Nuclear Production
TOTAL Nuclear Production Plant (Enter Total of lines 18 tbru 24)
C. Hydraulic Production Plant
(330)Land and Land Rights
(331)Structures and Improvements
(332)Reservoirs, Darns, and Waterways
(333)Water Wheels, Thrbines, and Generators
(334)Accessory Electric Equipment
(335)Misc. Power Plant Equipment
(336)Roads, Railroads, and Bridges
(337)Asset Retirement Costs for Hvdraulic Production
TOTAL Hydraulic Production Plant (Enter Total of lines 27 tbru 34)
D. Other Production Plant
(340)Land and Land Rights
(341)Structures and Improvements 670 958 (376 031)
(342)Fuel Holders, Products and Accessories 739,558 (611 571)
(343)Prime Movers
(344)Generators 119 882 291 520 307)
(345)Accessory Electric Equipment 848 034 (358 070)
FERC FORM NO.1 (ED. 12-91)Page 204
fOrState 0 egon
Name of Respondent This R~ort Is:Date of Report Year of Report(1) X An Original (Mo, Da, fr)
Avista Corp.(2)A Resubmission April 18, 2007 December31 , 2006
ELECTRIC PLANT IN SERVICE (ACCOWlts 101, 102, 103 , and 106) (Continued)
reversals of the prior years tentative accowlt dis1ributions of unm (f) only the offset to the debits or credits dis1ributed in
these amounts. Careful observance of the above inslructions column (f) to primary account classifications.
and the texts of Accounts 101 and 106 will avoid serious omis-7. For Account 399, state thenatore and use ofpJant included
sions of the reported amount of respondenes plant actually in the account and if substantial in amount submit a supple-
in service at end of year.mentary statement showing subaccount classifICation of such
Show in column (f) reclassifications or transfers within plant confonning to the reqUIrements of these pages.
utility plant accounts. Include also in column (f) the additions 8. For each amount comprising the reported balance and
or reductions of primary account classifICations arising from changes in Account 102, state the property purchased or sold
distribution of amounts initially recorded in Account 102. name of vendor or purchaser, and date of transaction. lipro-
showing the clearance of Account 102, include in column (e)posed journal entries have been filed with the Commission
the amounts with respect to accumulated provision for as required by the Uniform System of Accounts give also
depreciation, acquistion adjustments, etc., and show in col-date of such filing.
Balance at
Retirements Adjustments Transfers End of Year Line
(d)(e)(f)(Il)No.
(301)
(302)
163 809 (303)
163 809
(310)
(311)
(312)
(313)
(314)
(315)
(316)
(317)
(320)
(321)
(322)
(323)
(324)
(325)
(326)
(330)
(331)
(332)
(333)
(334)
(335)
(336)
(337)
(340)
294 927 (341)
362 19,127 625 (342)
(343)
819,944 115 542 040 (344)
489 964 (345)
FERC FORM NO.1 (ED. 12-88)Page 205
Name of Respondent
Avista Corp.
This R~ort Is:(1) 129 An Original
(2) 0 A Resubmission
Date of Report
(Mo, Da, Yr)
April 18 2007
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103 106)
Balance at
Begmnillg of Year
(b)
034 507
351,682
165 527,030
165 527 030
Line
No.43 (346)44 (347)
60 (360)61 (361)62 (362)
63 (363)64 (364)65 (365)66 (366)67 (367)68 (368)69 (369)
70 (370)71 (371)
72 (372)73 (373)74 (374)
77 (389)
78 (390)
79 (391)80 (392)81 (393)
82 (394)
83 (395)
84 (396)
85 (397)86 (398)
88 (399)
89 (399.
92 (102)
93 (Less)94 (103)
Account
(a)
Misc. Power Plant Eauimnent
Asset Retirement Costs for Other Production
TOTAL Other Production Plant (Enter Total of lines 37 tbru 44)
TOTAL Production Plant (Enter Total of lines 16, 25 , 35, and 45)
3. TRANSMISSION PLANT(350) Land and Land Ricl1ts(352) Structures and Improvements(353) Station Equipment(354) Towers and Fixtures(355) Poles and Fixtures(356) Overhead Conductors and Devices(357) Underground Conduit(358) Underground Conductors and Devices(359) Roads and Trails
(359.1) Asset Retirement Costs for Transmission Plant
TOTAL Transmission Plant (Enter Total of lines 48 tbru 57)
4. DISTRIBUTION PLANT
Land and Land Rights
Structures and ImProvements
Station Eauipment
Storage Battery Equipment
Poles, Towers, and Fixtures
Overhead Conductors and Devices
Underground Conduit
Underground Conductors and Devices
Line Transformers
Services
Meters
Installations on Customer Premises
Leased Property on Customer Premises
Street Lighting and Signal Systems
Asset Retirement Costs for Distribution Plant
TOTAL Distribution Plant (Enter Total of lines 60 tbru 74)
5. GENERAL PLANT
Land and Land Ricl1ts
Structures and Improvements
Office Furniture and Eauipment
Transportation Eauipment
Stores Eauipment
Tools, Shop and Gara,ge Equimnent
Laboratory Eaui ment
Power Operated ~uipment
Communication !Quipment
Miscellaneous Equipment
SUBTOTAL (Enter Total of lines 77 tbru 86)
Other Tan,gible Property
Asset Retirement Costs for General Plant
TOTAL General Plant (Enter Total of lines 88 and 89)
TOTAL (Accounts 101 and 106)
Electric Plant Purchased
(102) Electric Plant Sold
Experimental Plant Unclassified
TOTAL Electric Plant in Service
FERC FORM NO.1 (ED. 12-88)Page 206
302
724,014
993,472
291 387
069 175
444
444
444
175 635 854
175 635 854
State of Oregon
Year of Report
December 31,2006
Additions
(c)
(31,747)
897,726)
897 726)
(206 719)
589
(194 130)
929 252)
929 252)
fOrtate 0 egon
Name of Respondent This R
iRlort Is:
Date of Report Year of Report
(1 ) An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission April 18 2007 December 31 , 2006
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103, and 106) (Continued)
Balance at
Retirements Adjustments Transfers End of Year Line
(d)(e)(fJ (If)No.
002 760 (346)
351 682 (347)
820 306 159,808 998
820 306 159 808 998
302 (350)
(352)
517 295 (353)
(354)
993 472 (355)
303 976 (356)
(357)
(358)
(359)
(359.
875 045
(360)
(361)
(362)
(363)
(364)
(365)
(366)
(367)
(368)
(369)
(370)
(371)
(372)
(373)
(374)
(389)
(390)
(391)
(392)
(393)
(394)
(395)
(396)
(38 444)(397)
(398)
(38 444)
(399)
(399.
(38 444)
820 306 (38 444)169,847 852
(102)
(103)
820 306 (38,444)169,847 852
FERC FORM NO.1 (ED. 12-88)Page 207
Name of Respondent This R~rt Is:
(1) 129 An Original
Date of Report
(Mo, Da, Yr)
State of Ore on
Year of Report
A vista Corporation (2)A Resubmission
ELECTRIC OPERATING REVENUES (Account 400)
April 18, 2007
I. Report below operating revenues for each prescribed
account, and manufactured gas revenues in total.
2. Report number of customers, columns (f) and (g), on
the basis of meters, in addition to the number of fIat rate
accounts; except that where separate meter readings are
added for billing purposes, one customer should be counted
Line
No.
Title of Account
(a)
Sales of Electricit
(440) Residential Sales
(442) Commercial and Industrial Sales (3)
Small (or Commercial)
Lar e (or Industrial)
(444) Public Street and Hi hwa Li htin
(445) Other Sales to Public Authorities
(446) Sales to Railroads and Railwa s
(448) Interde artmental Sales10 TOTAL Sales to Ultimate Consumers
11 (447) Sales for Resale12 TOTAL Sales of Electricit
13 (Less) (449.1) Provision for Rate Refunds14 TOTAL Revenues Net of Provision for Refunds15 Other 0 eratin Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Pro ert
20 (455) Interde artmental Rents
21 (456) Other Electric Revenues
FERC FORM NO.1 (ED. 12-89)
Dec. 31 , 2006
for each group of meters added. The average number of
customers means the average of twelve figures at the close
of each month.
3. If previous year (columns (c), (e), and (g), are not
derived from previously reported figures, explain any incon-
sistencies in a footnote.
OPERATING REVENUES
Amount for Amount forYear Previous Year(b) (c)
19,017 891 7J9,538
017 891
$19,017 891
719,538
$31 719,538
Page 300
State of Ore on State of Ore on
This R
rRrt
Is:Date of Report Year of Report(1) X An Original (Mo, Da, Yr)
(2)A Resubmlssion April 18, 2007 Dec. 31 2006
Name of Respondent
A vista Corporation
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4. Commercial and Industrial Sales, Account 442, may
be classified according to the basis of classification (Small
or Commercial, and Large or Industrial) regularly used by
the respondent if such basis of classifcation is not generally
greater than 1000 Kw of demand. (See Account 442 of the
Uniform System of Accounts. Explain basis of classification
in a footnote.
MEGA WATT HOURS SOLD
Amount for Year
Amount for
Previous Year
(e)
5. See page 108, Important Changes During Year, for
important new territory added and important rate increases
or decreases.
6. For lines 2, 4, 5, and 6, see page 304 for amounts
relating to unbilled revenue by accounts.
7. Include unmetered sales. Provide details of such sales
in a foonote.
A VG. NO. OF CUSTOMERS PER MONTH
Number for
Number for Year Previous Year Line
No.
FERC FORM NO.1 (ED. 12-89)
725,554
725,554
725 554
Page 301
Oregon
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original
Avista Cor (2)A Resubmission April 18 2007 December 31,2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line
No.Account Amount for Current Year Amount for Prior Year
(a)(b)
(1) POWER PRODUCTION EXPENSES
A. Steam Power Generation
Operation
500 ODe ration Suoervision and Enaineerina
501 Fuel
502 Steam Expenses
503 Steam from Other Sources
Less) (504) Steam Transferred-Cr.
505 Electric Expenses
506 Miscellaneous Steam Power Exoenses
507 Rents
509 Allowances
TOTAL Operation (Enter Total of Lines 4 thru 11 \
Maintenance
510 Maintenance Supervision and EnQineerina
511 Maintenance of Structures
512 Maintenance of Boiler Plant
513 Maintenance of Electric Plant
514 Maintenance of Miscellaneous Steam Plant
TOTAL Maintenance (Enter Total of Lines 14 thru 18\
TOTAL Power Production Expenses-Steam Plant (Enter Total of lines 1
B. Nuclear Power Generation
Operation
517 Operation Supervision and EnQineerinQ
518 Fuel
519 Coolants and Water
520 Steam Expenses
521 Steam from Other Sources
Less) (522) Steam Transferred-Cr.
523) Electric Expenses
524) Miscellaneous Nuclear Power Expenses
525) Rents
TOTAL ODe ration (Enter Total of liens 23 thru 31)
Maintenance
528 Maintenance Supervision and EnQineerina
529 Maintenance of Structures
530 Maintenance of Reactor Plant Equipment
531 Maintenance of Electric Plant
532 Maintenance of Miscellaneous Nuclear Plant
TOTAL Maintenance (Enter Total of lines 34 thru 38\
TOTAL Power Production Expenses-Nuclear Power(Enter total of lines
C, Hvdraulic Power Generation
Operation
535 Operation Supervision and EnQineerinQ
536 Water for Power
537 Hvdraulic Expenses
538 Electric Expenses
539 Miscellaneous Hvdraulic Power Generation Expenses
540 Rents
TOTAL Operation (Enter Total of lines 43 thru 48)
FERC FORM NO.1 (12-96)Page 320
Oregon
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original
Avista Cor (2)A Resubmission April 18 2007 December 31 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line
No.Account Amount for Current Year Amount for Previous Year
(a)(b)(c)
C. Hvdraulic Power Generation (Continued)
Maintenance
541 Maintenance Supervision and Enaineerina
542 Maintenance of Structures
543 Maintenance of Reservoirs, Dams. and Waterways
544 Maintenance of Electric Plant
545 Maintenance of Miscellaneous Hvdraulic Plant
TOTAL Maintenance (Enter Total of lines 52 thru 56)
TOTAL Power Production Expenses-Hvdraulic Power (Enter total of lines
D. Other Power Generation
Ooeration
546 Operation SliDervision and Enaineerina 776,586 732,049
547 Fuel 82,419,671 903.447
548 Generation Expenses 737,816 975,072
549 Miscellaneous Other Power Generation Expenses 19.223 977
550 Rents 66,259 73,424
TOTAL Operation (Enter Total of lines 61 thru 65)019,554 710.969
Maintenance
551 Maintenance Supervision and Enaineerina 8,459 59.289
552 Maintenance of Structures
553 Maintenance of Generating and Electric Plant 1 ,232 448 285.753
554 Maintenance of Miscellaneous Other Power Generation Plant (3,648)123,490
TOTAL Maintenance (Enter Total of lines 68 thru 71)237 258 1 ,468.532
TOTAL Power Production Expenses-Other Power (Enter Total of lines 66 86.256 813 72.179 501
E. Other Power Suoplv Exoenses
555) Purchased Power
556) System Control and Load Disoatchina
557\ Other Exoenses
TOTAL Other Power Supply Expenses (Enter Total of lines 75 thru 77)
TOTAL Power Production Expenses (Enter Total of lines 20, 40, 58. 73 a 256.813 179 501
2. TRANSMISSION EXPENSES
Operation
560) Operation Supervision and Enaineerina
561) Load Dispatchina
561.Load Dispatchina Reliability
561.Load Dispatchina Monitor and Operate Transmission System
561.Load Dispatchina Transmission Service and Sched
561.4 Schedulina Svsemt Control and Dispatch Services
561.Reliability. Plannina and Standards Development
561.Transmission Service Studies
561.Generation Interconnection Studies
561.Reliability. Plannina and Standards Development Services
562 Station Expenses 15.994 876
563 Overhead Line Expenses 123
564 Underaround Line Expenses
565 Transmission of Electricity bv Others
566 Miscellaneous Transmission Expenses
567 Rents
TOTAL Ooeration (Enter Total of lines 82 thru 89)994 36.999
Maintenance
100 568 Maintenance Suoervision and Enaineerina
101 569 Maintenance of Structures
102 570 Maintenance of Station Eauipment
103 571 Maintenance of Overhead Lines 10,433 174
104 572 Maintenance of Underaround Lines
105 573 Maintenance of Miscellaneous Transmission Plant
106 TOTAL Maintenance (Enter Total of lines 92 thru 97\10,433 174
107 TOTAL Transmission Expenses (Enter Total of lines 90 and 98\26,428 44,172
108 3. DISTRIBUTION EXPENSES
109 Operation
110 580) ODe ration Supervision and Enaineerina
FERC FORM NO.1 (12-96)Page 321
Oregon
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original
Avista Cor (2)A Resubmission April 18 2007 December 31 , 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line
No.Account Amount for Current Year Amount for Prior Year(a)(b)(c)
103 3. DISTRIBUTION EXPENSES (Continued)
104 581 Load DispatchinQ
105 582 Station Expenses
106 583 Overhead Line Expenses
107 584 UnderQround Line Expenses
108 585 Street LiQhtinQ and SiQnal System Expenses
109 586 Meter Expenses
110 587 Customer Installations Expenses
111 588 Miscellaneous Distribution Expenses
112 589 Rents
113 TOTAL Operation (Enter Total of lines 102 thru 112)
114 Maintenance
115 590 Maintenance Supervision and EnQineerinQ
116 591 Maintenance of Structures
117 592 Maintenance of Station Equipment
118 593 Maintenance of Overhead Lines
119 594 Maintenance of UnderQround Lines
120 595 Maintenance of Line Transformers
121 596 Maintenance of Street LiQhtinQ and SiQnal Systems
122 597 Maintenance of Meters
123 598 Maintenance of Miscellaneous Distribution Plant
124 TOTAL Maintenance (Enter Total of lines 115 thru 123)
125 TOTAL Distribution Expenses (Enter Total of lines 113 and 124)
126 4. CUSTOMER ACCOUNTS EXPENSES
127 Operation
128 901 Supervision
129 902 Meter Readina Exoenses
130 903 Customer Records and Collection Expenses
131 904 Uncollectible Accounts
132 905 Miscellaneous Customer Accounts Expenses
133 TOTAL Customer Accounts Expenses (Enter Total of lines 128 thru 132)
134 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
135 Operation
136 907 Supervision
137 908 Customer Assistance Expenses
138 909 Informational and Instructional Expenses
139 (910 Miscellaneous Customer Service and Informational Expenses
140 TOTAL Cust. Service and Informational Expenses (Enter Total of lines 1
141 6. SALES EXPENSES
142 Operation
143 911 Supervision
144 912 Demonstratina and Sellina Expenses
145 913 Advertisina Exoenses
146 916 Miscellaneous Sales Expenses
147 TOTAL Sales Exoenses (Enter Total of lines 143 thru 146)
148 7. ADMINISTRATIVE AND GENERAL EXPENSES
149 Operation
150 920) Administrative and General Salaries
151 921) Office Supplies and Expenses
152 Less) (922) Administrative expenses Transferred-Credit
FERC FORM NO.1 (12-96)Page 322
Oregon
Name of Respondent This Report Is:Date of Report Year of Report
(1)An Original
Avista Cor (2)A Resubmission April 18,2007 December 31 2006
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Line
No.Account Amount for Current Year Amount for Prior Year
(a)(b)rci
153 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
154 923 Outside Services Emoloved
155 924 Propertv Insurance
156 925 Injuries and Damaaes
157 926 Emplovee Pensions and Benefits
158 927 Franchise Reouirements
159 928 ReQulatorv Commission Exoenses
160 Less) (929) Duplicate Charaes-Cr.
161 930.1) General AdvertisinQ Exoenses
162 930.2) Miscellaneous General Exoenses
163 931) Rents
164 TOTAL Operation (Enter Total of lines 150 thru 163)
165 Maintenance
166 935) Maintenance of General Plant
167 TOTAL Administrative and General Expenses (Enter Total of lines 164 a
168 TOTAL Electric Operation and Maintenance Expenses (Enter Total of lin 86,283,240 223 674
79,125,133,140 147 and 167)
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1. The data on number of empl construction employees in a footnote.
for the payroll period ending neare 3. The number of employees assignable to the electric
payroll period ending 60 days bele department from joint functions of combination utilities mav
2. If the respondent's payroll for be determined by estimate, on the basis of employee eQuiva-
cludes any special construction lents.Show the estimated number of equivalent emplovees
employees on line 3. and show th attributed to the electric department from joint functions.
1 Payroll Period Ended (Date) December 31, 2006
2 Total Reaular Full-Time Emolovees
3 Total Part-Time and Temoorarv Emolovees
4 Allocation of General Emolovees
5 Total Emolovees (See Note 1
FERC FORM NO.1 (12-96) Page 323
This Page Intentionally Left Blank
MONT ANA
Name of Respondent This R~rt Is:
(1) Qg An Origjnal
Date of Report
(Mo, Da, Yr)
State of Montana
Year of Report
Avista Corp (2) 0 A Resubmission Apr. 18, 2007 Dec. 31, 2006
STATEMENT OF INCOME FOR THE YEAR
1. Report amounts for accounts 412 and 413, Revenue
and Expenses from Utility Plant Leased to Others, in another
utility column (i,k,m o) in a similar manner to a utility depart-
ment. Spread the amount(s) over lines 01 thN 20 as ap-
propriate. Include these amounts in columns (c) and (d)
totals.
2. Report amounts in account 414, Other Utility Operating
Income, in the same manner as accounts 412 and413 above.
3. Report data for lines 7, 9. and 10 for Natural Gas com-
panies using accounts 404.1. 404.2, 404., 407.1, and
407.
4. Use page 122 for important notes regarding the state-
ment of income or any account thereof.
Line
No.
Account
(a)
FERC FORM NO.1 (REVISED 06-04)
(Ref.
Page
No.
(b)
300-301
320-325
320-325
336-338
336-338
336-338
262-263
262-263
262-263
234,272-277
234 272-277
266
Page 114
5. Give concise explanations concemingunsettled rate
proceedings where a contingency exists such that refunds
of a material amount may need to be made to the utility
customers or which may result in a material refund to the
utility with respect to power or gas purchases. State for each
year affected the gross revenues or costs to which the con-
tingency relates and the tax effects together with an expIa-
tion of the major factors which affect the rights of the utility
to retain such revenues or recover amounts paid with respect
to power and gas purchases.
6. Give concise explanations concerning significant
amounts of any refunds made or received during the year
TOTAL
Current Year Previous Year
$14 759,468 $10 877,767
Name of Respondent This R~rtIs:
(1 ) 129 An Original
Date of Report
(Mo, Da, Yr)
State of Montana
Year of Report
Avista Corp (2)A Resubrnission Apr. 18, 2007 Dec. 31, 2006
STATEMENT OF INCOME FOR THE YEAR
resulting from settlement of any rate proceeding affecting
revenues received or costs incurred for power or gas pur-
chases, and a sununary of the adjustments made to balance
sheet, income, and expense accounts.
7. If any notes appearing in the report to stockholdern are
applicable to this Statement of Income, such notes may be at-
tached at page 122.
8. Enter on page 122 a consise explanation of only those
changes in accounting methods made during the year which
had an effect on net income, including the basis of allocations
and apportionments from those used in the preceding year.
Also give the approximate dollar effect of such changes.
9. Explain in a foonote if the previous years figures are
different from that reported in prior reports.
10. If the colunms are insufficient for reporting additional
utility departments. supply the appropriate account titles, lines
1 to 19, and report the infonnation in the blank space on page
122 or in a supplemental statement.
ELECTRIC UTILITY
CUITent Year Previous Year
GAS UTILITY
CUITent Year Previous Year
OTHER UTILITY
CUITent Year Previous Year Line
No.
$14 759,468 $10,877 767
FERC FORM NO.1 (REVISED 06-04)Page 115
Name of Respondent This Re Is:Date of Report Year of Report (I) X An Original (Mo, Da, Yr)
Avi5ta Corp.(2)A ResubmisslOn April 18 2007 December 31. 2006
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103, 106)
1. Report below the original cost of electric plant in service ac-estimated basis if necessary, and include the entries in column
cording to the prescribed accounts.(c). Also to be inch1ded in column (c) are entries for reversals
2. In addition to Account 101, E1c:ctric Plant in Savice (CJas-of tentative cfistributions of prior year reported in column (b).
silled), this page and the next include Accounts 102, E1c:ctric Plant Likewise, if the respondent bas a significant amount of plant
Purchased or Sold; Account 103, Experimental Electric Plant Un-retirements which have not been classified to primary accounts
Classified; and Account 106, Completed Construction Not Clas-at the end of the year, include in column (d) a tentative distrib-
sifred - Electric.ution of such retirements on an estimated basis, with approp-
3. Include in column (c) or (d), as appropriate, coITections of add-riate contra entry ID the account for accumulated depreciation
itions and retirements for the CUITent or preceding year.provision. Include also in column (d) reversals of tentative dis-
4. Enclose in parentheses credit adjustments of plant accounts ID tributions of prior year of unclassified retirements. Attach sup-
indicate the negative effect of such accounts.plemental statement showing the account distributions of these
5. Classify Accountl06 according to prescribed accounts, on an tentative classifications in columns (c) and (d), including the
Balance at
Line Account Beginnmg of Year Additions
No.(a)(b)(c)
1. INTANGIBLE PLANT
(301)Organization
(302)Franchises and Consents 222 448
(303)Miscellaneous Intangible Plant 164 808
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)387 256
2. PRODUCTION PLANT
A Steam Production Plant
(310)Land and Land Rights 299 299
(311)Structures and Improvements 99,988 600 422
(312)Boiler Plant Eauipment 120,425 088 412 060
(313)En,gines and En,gine Driven Generators
(314)Turbogenerator Units 32,121,484 868 078
(315)Accessory Electric Equipment 14,425 012 574 903
(316)Misc. Power Plant Equipment 781,406 131,147
(317)Asset Retirement Costs for Steam Production 134 589
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)281 175,478 986 610
'17 B. Nuclear Production Plant
(320)Land and Land Rights
(321)Structures and Improvements
(322)Reactor Plant Equipment
(323)Turbogenerator Units
(324)Accessory Electric Equipment
(325)Misc. Power Plant Equipment
(326)Asset Retirement Costs for Nuclear Production
TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
C. Hydraulic Production Plant
(330)Land and Land Rights 41,455 568 958 308
(331)Structures and Improvements 896 299 515 828
(332)Reservoirs, Dams, and Waterways 994 267 360
(333)Water Wheels, Turbines, and Generators 135,439 213,491
(334)Accessory Electric Eauipment 11,767 699 908 894
(335)Misc. Power Plant Equipment 649,480 125 955
(336)Roads, Railroads, and Bridges 225 369
(337)Asset Retirement Costs for Hydraulic Production
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 35)134 124,121 729 836
D. Other Production Plant
(340)Land and Land Rights
(341)Structures and Improvements
(342)Fuel Holders, Products and Accessories
(343)Prime Movers
(344)Generators
(345)Accessory Electric Equipment
State of Montana
FERC FORM NO.1 (ED. 12-91)Page 204
State of Montana
Name of Respondent This
:wort
Is:Date of Report Year of Report(1) X An Original (Mo, Va, Yr)
Avista Corp.(2)A Resubmission April 18 2007 December 31,2006
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103, and 106) (Continued)
reversals of the prior years tentative account distributions of umn (f) only the offset to the debits or credits distributed in
these amounts. Careful observance of the above instructions column (f) to primary account classifications.
and the texts of Accounts 101 and 106 will avoid serious omi&-7. For Account 399, state the nature and use of plant included
sions of the reported amount of respondenfs plant actually in the account and if substantial in amount submit a supple-
m service at end of year. mentary statement showing subaccount classifICation of such
Show in column (f) reclassifICations or transfers within plant conformmg to the requirements of these pages.
utility plant accounts. Include also in colunm (f) the additions 8. For each amount comprising the reported balance and
or reductions of primary account classifications arising from changes in Account 102, state the property purchased or sold,
distribution of amounts initially recorded in Account 102. name of vendor or purchaser, and date of transaction. If pro-
showing the clearance of Account 102, include in column (e)posed journal entries have been filed with the Commission
the amounts with respect to accumulated provision for as required by the Uniform System of Accounts,give also
depreciation. acquistion adjustments, etc., and show in col-date of such filing.
Balance at
Retirements Adjustments Transfers End of Year Line
(d)(e)(f)
(g)
No.
(301)
222,448 (302)
185 339 (20 531)(303)
185 339 201,917
2,388 296 911 (310)
608 987 414 (311)
121,837,148 (312)
(313)
989 562 (314)
999 915 (315)
912 553 (316)
134,589 (317)
996 286 158 093
(320)
(321)
(322)
(323)
(324)
(325)
(326)
42,413 876 (330)
661 12,411,466 (331)
001 627 (332)
498 266,432 (333)
685 993 990 599 (334)
775 435 (335)
225 369 (336)
(337)
769 152 137 084 804
(340)
(341)
(342)
(343)
(344)
(345)
FERC FORM NO.1 (ED. 12-88)Page 205
Name of Respondent This Re
lRlort Is:
Date of Report Year of Report (I) X An Original (Mo Va, Yr)
Avista Corp.(2)A Resubmission April 18 2007 December 31, 2006
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103 , 106)
Balance at
Line Account Beginning of Year Additions
No.(a)(b)(c)
(346)Misc. Power Plant Equipment
(347)Asset Retirement Costs for Other Production
TOTAL Other Production Plant (Enter Total of lines 37 thru 44)
TOTAL Production Plant (Enter Total of lines 16 , and 45)415 299,599 716 446
3. TRANSMISSION PLANT
(350)Land and Land Ri2hts 883 384
(352)Structures and lmprovements 461,581
(353)Station Equipment 371 268 184 225
(354)Towers and Fixtures 013 530
(355)Poles' and Fixtures 173 299
(356)Overhead Conductors and Devices 745 311
(357)UnderJUound Conduit
(358)UnderJUound Conductors and Devices
(359)Roads and Trails 367,476
(359.Asset Retirement Costs for Transmission Plant
TOTAL Transmission Plant (Enter Total of lines 48 thru 57)015 849 184 225
4. DISTRIBUTION PLANT
(360)Land and Land Rights
(361)Structures and hnprovements 881
(362)Station Equipment 152 268
(363)Stora~e Battery Equipment
(364)Poles, Towers, and Fixtures 080
(365)Overhead Conductors and Devices 676
(366)Underground Conduit
(367)UnderJUound Conductors and Devices 637
(368)Line Transfonners 897
(369)Services 127
(370)Meters
(371)Installations on Customer Premises
(372)Leased Property on Customer Premises
(373)Street Li2htin~ and Signal Systems
(374)Asset Retirement Costs for Distribution Plant
TOTAL Distribution Plant (Enter Total oflines 60 thru 74)186 641
5. GENERAL PLANT
(389)Land and Land Rights
(390)Structures and lmprovements
(391)Office Furniture and Equipment
(392)Transportation Equipment 520 151 411
(393)Stores Equipment
(394)Tools, Shop and Gara~e EQuipment
(395)Laboratorv EQuil ment
(396)Power Operated Equipment 660
(397)Communication Equipment 881 126
(398)Miscellaneous Eauipment
SUBTOTAL (Enter Total of lines 77 thru 86)47,401 186 197
(399)Other TanJdble Property
(399.Asset Retirement Costs for General Plant
TOTAL General Plant (Enter Total of lines 87 thru 89)47,401 186,197
TOTAL (Accounts 101 and 106)478 936 746 086 868
(102)Electric Plant Purchased
(Less)(102) Electric Plant Sold
(103)Experimental Plant Unclassified
TOTAL Electric Plant in Service 478 936 746 086 868
State of Montana
FERC FORM NO.1 (ED. 12-88)Page 206
State of Montana
Name of Respondent This
wort
Is:Date of Report Year of Report(1) X An Original (Mo Va, Yr)
Avista Corp.(2)A Resubmission April 18 2007 December 31, 2006
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103 , and 106) (Continued)
Balance at
Retirements Adjustments Transfers End of Year line
(d)(e)(If)No.
(346)
(347)
773 148 423 242 897
883 384 (350)
461 581 (352)
483 16,479 010 (353)
013,530 (354)
173 299 (355)
745 311 (356)
(357)
(358)
367,476 (359)
(359.
483 123 591
(360)
881 (361)
152 268 (362)
(363)
080 (364)
676 (365)
(366)
637 (367)
897 (368)
127 (369)
(370)
(371)
(372)
(373)
(374)
186 641
(389)
(390)
(391)
174 931 (392)
(393)
(394)
(395)
660 (396)
007 (397)
(398)
233 598
(399)
(399.
233 598
034 970 486 988 644
(102)
(103)
034 970 486 988 644 95 i
FERC FORM NO.1 (ED. 12-88)Page 207
Name of Respondent This R~rt Is:
(1 ) 119 An Original
Date of Report
(Mo. Da, Yr)
State of Montana
Year of Report
Avista Corporation (2)A Resubmission April 18, 2007 Dec. 31 2006
ELECTRIC OPERATING REVENUES (Account 400)
I. Report below operating revenues for each prescribed
account, and manufactured gas revenues in total.
2. Report number of customers, columns (f) and (g), on
the basis of meters, in addition to the number of flat rate
accounts; except that where separate meter readings are
added for billing purposes, one customer should be counted
Line
No~
Title of Account
(a)
Sales of Electricit
(440) Residential Sales
(442) Commercial and Industrial Sales (3)
Small (or Commercial)
Lar e (or Industrial)
(444) Public Street and Hi hwa Li htin
(445) Other Sales to Public Authorities
(446) Sales to Railroads and Railwa s
(448) Interde artmental Sales10 TOTAL Sales to Ultimate Consumers
11 (447) Sales for Resale12 TOTAL Sales of Electricit
13 (Less) (449.1) Provision for Rate Refunds14 TOTAL Revenues Net of Provision for Refunds15 Other 0 eratin Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Pro ert
20 (455) Interde artmental Rents
21 (456) Other Electric Revenues
FERC FORM NO.(ED. 12-89)
for each group of meters added. The average number of
customers means the average of twelve figures at the close
of each month.
3. If previous year (columns (c), (e), and (g), are not
derived from previously reported figures, explain any incon-
sistencies in a footnote.
OPERATING REVENUES
Amount for Amount forYear Previous Year(b) (c)
223
7,445
815 (1)
14,598 612
615,427
393
327
829 598
844 925
615,427 844 925
45,136 43,386
98,905 989,456
144 041
$14 759,468
032 842
$10 877 767
Page 300
Name of Respondent This R~rt Is:
(1 ) 129 An Original
Date of Report
(Mo, Da, Yr)
State of Montana
Year of Report
A vista Corporation (2)A Resubmission Dec. 31 2006
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
April 18 2007
4. Commercial and Industrial Sales, Account 442, may
be classified according to the basis of classification (Small
or Commercial , and Large or Industrial) regularly used by
the respondent if such basis of classifcation is not generally
greater than 1000 K w of demand. (See Account 442 of the
Uniform System of Accounts. Explain basis of classification
in a footnote.
MEGA WAIT HOURS SOLD
Amount for
Previous Year
(e)
5. See page 108, Important Changes During Year, for
important new territory added and important rate increases
or decreases.
6. For lines 2, 4, 5, and 6, see page 304 for amounts
relating to unbilled revenue by accounts.
7. Include unmetered sales. Provide details of such sales
in a foonote.
A YG. NO. OF CUSTOMERS PER MONTH
Number for
Number for Year Previous Year
115
307 (2)279
275 659 132 631
275,966 132 910
275 966 132 910
(1) Includes $(0) of unbilled revenues.
(2) Includes 0 MWH relating to unbilled revenues.
(3) Segregation of Commerical and Industrial made on basis of utilization of energy and not on size of account.
FERC FORM NO.1 (ED. 12-89)Page 301
Line
No.
Avista Cor
I Date of Report
An Original
A Resubmj April 18 2007
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Name of Respondent This Report Is:
(1)
(2)
Year of Report
"the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line
No,Account Amount for Current Year(a) (b)
(1) POWER PRODUCTION EXPENSES
A. Steam Power Generation
Operation
500 Operation Supervision and EnQineerinQ
501 Fuel
502 Steam Expenses
503 Steam from Other Sources
Less) (504) Steam Transferred-Cr.
505 Electric Expenses
506 Miscellaneous Steam Power Expenses
507 Rents
509 Allowances
TOTAL Operation (Enter Total of Lines 4 thru 11)
Maintenance
510 Maintenance Supervision and EnQineerinQ
511 Maintenance of Structures
512 Maintenance of Boiler Plant
513 Maintenance of Electric Plant
514 Maintenance of Miscellaneous Steam Plant
TOTAL Maintenance fEnter Total of Lines 14 thru 18)
TOTAL Power Production Expenses-Steam Plant (Enter Total of
B. Nuclear Power Generation
115,243
14,659 509
205,731
016
11,407
357 913
628
385 447
354 380
454 469
4,432 308
444 902
534,244
220,303
605 750
Operation
517 Operation Supervision and Enaineerina
518 Fuel
519 Coolants and Water
520 Steam Expenses
521 Steam from Other Sources
Less) (522) Steam Transferred-Cr.
523) Electric Expenses
524) Miscellaneous Nuclear Power Expenses
525) Rents
TOTAL Operation (Enter Total of liens 23 thru 31)
Maintenance
528 Maintenance Supervision and Enaineerina
529 Maintenance of Structures
530 Maintenance of Reactor Plant Eauipment
531 Maintenance of Electric Plant
532 Maintenance of Miscellaneous Nuclear Plant
TOTAL Maintenance (Enter Total of lines 34 thru 38)
TOTAL Power Production Expenses-Nuclear Power(Enter total
C. Hvdraulic Power Generation
Operation
535 Operation Supervision and Enaineerina
536 Water for Power
537 Hvdraulic Expenses
538 Electric Expenses
539 Miscellaneous Hvdraulic Power Generation Expenses
540 Rents
TOTAL Operation (Enter Total of lines 43 thru 48)
93,170
203
981,051
184,514
335,938
FERC FORM NO.1 (12-96)Page 320
Montana
December 31,2006
Amount for Prior Year(a)
103 458
820,507
165,77t
61,531
312,422
13,621
15,477,309
324,441
405 900
611 525
(17 631
354 983
679 218
19,t56,527
135,509
525
799 923
968
075,925
Montana
Name of Respondent This Report Is:I Date of Report Year of Report
(1)An Original
A Resub~~APril 25, 2005Avista Cor (2)December 31 2006
AND MAINTENANCE EXPENSES
Line
No.Account Amount for Current Year Amount for Previous Year
(a)(b)(c)
C. Hvdraulic Power Generation (Continued)
Maintenance
541 Maintenance SuDervision and Enaineerina 34,077 123,300
542 Maintenance of Structures 805 73,305
543 Maintenance of Reservoirs, Dams, and Waterways 33,812 59,234
544 Maintenance of Electric Plant 041,970 683 087
545 Maintenance of Miscellaneous Hvdraulic Plant 261 831 174,242
TOTAL Maintenance (Enter Total of lines 52 thru 56)1,426 495 113,168
TOTAL Power Production ExDenses-Hvdraulic Power (Enter total 762,433 189,093
D. Other Power Generation
ODe ration
546 ODeration SuDervision and Enaineerina
547 Fuel
548 Generation ExDenses
549 Miscellaneous Other Power Generation EXDenses
550 Rents
TOTAL Ooeration (Enter Total of lines 61 thru 65)
Maintenance
551 Maintenance SuDervision and Enaineerina
552 Maintenance of Structures
553 Maintenance of Generatina and Electric Plant
554 Maintenance of Miscellaneous Other Power Generation Plant
TOTAL Maintenance (Enter Total of lines 68 thru 71)
TOTAL Power Production Exoenses-Other Power (Enter Total of
E. Other Power SuDDlv ExDenses
555) Purchased Power
556) System Control and Load DisDatchina
557) Other ExDenses
TOTAL Other Power SuDDlv Exoenses (Enter Total of lines 75 th
TOTAL Power Production Exoenses (Enter Total of lines 20, 40 368 183 345,620
2. TRANSMISSION EXPENSES
ODeration
560) ODeration SuDervision and EnnineerinD 24,D43 20,794
561) Load DisDatchina 667 19,150
561.1 Load DisDatchina Reliabilitv
561.Load DisDatchina Monitor and ODerate Transmission System 18,667
561.Load DisDatchina Transmission Service and Sched
561.4 Schedulina Sysemt Control and DisDatch Services
561.Reliabilitv, Plannina and Standards DeveloDment
561.Transmission Service Studies
561.Generation Interconnection Studies
561.Reliabilitv, Plannina and Standards DeveloDment Services
562 Station ExDenses 689 162
563 Overhead Line ExDenses 507 21,397
564 Underaround Line ExPenses
565 Transmission of Electricitv bv Others
566 Miscellaneous Transmission ExDenses
567 Rents 65,802 822
TOTAL ODe ration (Enter Total of lines 82 thru 89)186 376 131,325
Maintenance
100 568 Maintenance SuDervision and Enaineerinn 192 23,419
101 569 Maintenance of Structures 523 138
102 570 Maintenance of Station EDuiDment 691 42,874
103 571 Maintenance of Overhead Lines 345 778 820
104 572 Maintenance of Underaround Lines
105 573 Maintenance of Miscellaneous Transmission Plant
106 TOTAL Maintenance (Enter Total of lines 92thru 97)439,184 134 251
107 TOTAL Transmission EXDenses (Enter Total of lines 90 and 98)625,560 265 576
108 3. DISTRIBUTION EXPENSES
109 ODeration
110 580) ODe ration SuDervision and EnOlneerina
FERC FORM NO.1 (12-96)Page 321
Montana
Name of Respondent This Report Is:I Date of Report Year of Report
(1)An Original
A Resub
~j
April 18, 2007Avista Cor (2)December 31 , 2006
AND MAINTENANCE EXPENSES
Line
No.Account Amount for Current Year Amount for Prior Year
(a)(b)(c)
103 3. DISTRIBUTION EXPENSES (Continued)
104 581 Load DisDatchinc
105 582 Station EXDenSeS
106 583 Overhead Line Exoenses
107 584 Undercround Line ExDenses
108 585 Street Lichtinc and Sicnal Svstem EXDenSeS
109 586 Meter ExDenses
110 587 Customer Installations ExDenses
111 588 Miscellaneous Distribution ExDenses
112 589 Rents
113 TOTAL ODeration (Enter Total of lines 102 thru 112)
114 Maintenance
115 590 Maintenance SuDervision and Encineerinc
116 591 Maintenance of Structures
117 592 Maintenance of Station EouiDment
118 593 Maintenance of Overhead Lines
119 594 Maintenance of Underaround Lines
120 595 Maintenance of Line Transformers
121 596 Maintenance of Street Liahtino and Sional Svstems
122 597 Maintenance of Meters
123 598 Maintenance of Miscellaneous Distribution Plant
124 TOTAL Maintenance (Enter Total of lines 115 thru 123)
125 TOTAL Distribution Expenses (Enter Total of lines 113 and 124)
126 4. CUSTOMER ACCOUNTS EXPENSES
127 ODeration
128 901 SuDervision
129 902 Meter Readinc ExDenses
130 903 Customer Records and Collection ExDenses
131 904 Uncollectible Accounts
132 905 Miscellaneous Customer Accounts Ewenses
133 TOTAL Customer Accounts EXDenses TEnter Total of lines 128 tt
134 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
135 Operation
136 907 Supervision
137 908 Customer Assistance Ex(ienses
138 909 Informational and Instructional Expenses
139 910 Miscellaneous Customer Service and Informational Expenses
140 TOTAL Cust. Service and Informational Expenses (Enter Total 0
141 6. SALES EXPENSES
142 ODeration
143 911 SuDervision
144 912 Demonstratina and Sellinc Exoenses
145 913 Advertisina EXDenses
146 916 Miscellaneous Sales ExDenses
147 TOTAL Sales Exoenses (Enter Total of lines 143 thru 146)
148 7. ADMINISTRATIVE AND GENERAL EXPENSES
149 Operation
150 920) Administrative and General Salaries
151 921) Office SuDDlies and Ewenses
152 Less) (922\ Administrative eXDenses Transferred-Credit
FERC FORM NO.1 (12-96)Page 322
Montana
Avista Cor
I Date of Report Year of Report
An Original
A Resub
~j
April 18. 2007 December 31, 2006
Name of Respondent This Report Is:
(1)
(2)
AND MAINTENANCE EXPENSES
Line
No.
153
154
155
156
157
158
159
160
161
162
163
164
165
166
167
168
Account Amount for Current Year(a) (b)
7. ADMINISTRATIVE AND GENERAL EXPENSESrContinued)
923 Outside Services Emoloved
924 Property Insurance
925 Injuries and Damaoes
926 Employee Pensions and Benefits
927 Franchise Requirements
928 ReQulatory Commission Exoenses
Less) (929) Duplicate CharQes-Cr.
930,1) General AdvertisinQ Expenses
930.2) Miscellaneous General Expenses931) Rents
TOTAL Operation (Enter Total of lines 150 thru 163)
Maintenance
935) Maintenance of General Plant
TOTAL Administrative and General Expenses (Enter Total of line
TOTAL Electric Operation and Maintenance Expenses (Enter To
99.125,133,140,147 and 167)
Amount for Prior Year
(c)
228
228
760
988
003 731
15,484
15,484
626 680
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1. The data on number of em pi, construction employees in a footnote.
for the payroll period ending neare 3. The number of employees assignable to the electric
payroll period ending 60 days befo department from joint functions of combination utilities mav
2. If the respondent's payroll for be determined by estimate. on the basis of emolovee eauiva-
eludes any special construction lents.Show the estimated number of equivalent emolovees
employees on line 3. and show th, attributed to the electric department from joint functions.
1 Pavroll Period Ended (Date) December 31 , 2006
2 Total Reaular Full-Time Emolovees
3 Total Part-Time and Temoorary Emplovees
4 Allocation of General Emolovees
5 Total Emolovees (See Note 1)
FERC FORM NO.1 (12-96) Page 323
This Page Intentionally Left Blank
NOT DIRECTLY ASSIGNED
TO STATES
Not Directly Assigned To States
Name of Respondent This R~ort Is:Date of Report Year of Report (I) X An Original (Mo, Va, Yr)
Avista Corp.(2)A ResubrnisslOn April 18, 2007 December 31 2006
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103 , 106)
1. Report below the original cost of electric plant in service ac-estimated basis if necessary, and include the entries in column
cording to the prescribed accounts.(c). AJso to be included in column (c) are entries for reversals
2. In addition to Account 101, Electric Plant in Service (CIas-of tentative distributions of prior year reported in column (b).
silled), this page and the next include Accounts 102, Electric Plant Lilrewise, if the respondent has a significant amount of plant
Purchased or SoW; Account 103, ExperimentalE1ectric Plant Un-retirements which have not been classilied to primary accounts
Classified; and Account 106, Completed Cons1ruction Not CIas-at the end of the year, include in column (d) a tentative distrib-
sified - Electric.ution of such retirements on an estimated basis, with approp-
3, Include in column (c) or (d), as appropriate, COlTections of add-riate contra entry to the account for accumulated depreciation
itions and retirements for the current or preceding year.provision. Include also in column (d) reversals of tentative dis-
4. Enclose in parentheses credit adjustments of plant accounts to tributions of prior year ofunclassif1ed retirements. Attach sup-
indicate the negative effect of such accounts.plemental statement showing the account distributions of these
5. Classify AccountlO6 according to prescribed accounts, on an tentative classifications in columns (c) and (d), including the
Balance at
Line Account Beginning of Year Additions
No.(a)(b)(c)
1. INTANGIBLE PLANT
(301)Organization
(302)Franchises and Consents
(303)Miscellaneous Intangible Plant 540 571 321 609
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)540 571 321 609
2. PRODUCTION PLANT
A. Steam Production Plant
(310)Land and Land Rights
(311)Structures and Improvements
(312)Boiler Plant Equipment
(313)Engines and Engine Driven Generators
(314)Turbogenerator Units
(315)Accessory Electric Equipment
(316)Misc. Power Plant Equipment
(317)Asset Retirement Costs for Steam Production
TOTAL Steam Production Plant (Enter Total of lines 8 tbru 15)
B. Nuclear Production Plant
(320)Land and Land Rights
(321)Structures and Improvements
(322)Reactor Plant Equipment
(323)Turbogenerator Units
(324)Accessory Electric Equipment
(325)Misc. Power Plant Equipment
(326)Asset Retirement Costs for Nuclear Production
TOTAL Nuclear Production Plant (Enter Total of lines 18 tbru 24)
C. Hydraulic Production Plant
(330)Land and Land Rights
(331)Structures and Improvements
(332)Reservoirs, Dams, and Waterways
(333)Water Wheels, Turbines, and Generators
(334)Accessory Electric Equipment
(335)Misc. Power Plant Equipment
(336)Roads, Railroads, and Bridges
(337)Asset Retirement Costs for Hydraulic Production
TOTAL Hydraulic Production Plant (Enter Total of lines 27 tbru 34)
D. Other Production Plant
(340)Land and Land Rights
(341)Structures and Improvements
(342)Fuel Holders, Products and Accessories
(343)Prime Movers
(344)Generators
(345)Accessory Electric Equipment
FERC FORM NO.1 (ED. 12-91)Page 204
Name of Respondent Date of Report
(Mo, Da, Yr)
Not DIrectly Assl,gned To States
Year of ReportThis R;gort Is:(I) 129 An Original
Avista Corp.December 31,2006(2)A ResubmisslOn April 18, 2007
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102, 103, and 106) (Continued)
reversals of the prior years tentative account distributions of umn (f) only the offset to the debits or credits distributed in
these amounts. Careful observance of the above instructions column (f) to primary account classifications.
and the texts of Accounts 101 and 106 will avoid serious omis. 7. For Account 399, state thenatnre and use of plant included
sions of the reported amount of respondenfs plant actuaJly in the account and if substantial in amount submit a supple-in service at end of year. mentary statement showing subaccount classification of such
6. Show in column (f) reclassifications or transfers within plant conforming to the reqUIrements of these pages.
utility plant accounts. Include also in column (f) the additions 8. For each amount comprising the reported balance and
or reductions of primary account cwssifications arising from changes in Account 102, state the property purchased or sold
distribution of amounts initially recorded in Accounll02. In name of vendor or purchaser, and date of transaction. If pro-
showing the clearance of Account 102, include in column (e) posed journal entries have been fIled with the Commission
the amounts with respect to accumulated provision for as required by the Uniform System of Accounts, give also
depreciation, acquistion adjustments, etc., and show in col- date of such filing.
Retirements
(d)
Balance at
End of Year
(1')
Adjustments
(e)
Transfers
(f)
(310)
(311)
(312)
(313)
(314)
(315)
(316)
(317)
Line
No.
734 542
734 542
(301)
(302)
127 637 (303)
127 637
FERC FORM NO.1 (ED. 12-88)Page 205
(320)
(321)
(322)
(323)
(324)
(325)
(326)
(330)
(331)
(332)
(333)
0 (334)
0 (335)
(336)
0 (337)
(340)
(341)
(342)
(343)
0 (344)
0 (345)
T SNot Directlv Assl,gned 0 tates
Name of Respondent This R
iRlort Is:
Date of Report Year of Report(1) X An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission April 18, 2007 December 31,2006
ELECTRIC PLANT IN SERVICE (Accounts 101, 102, 103, 106)
Balance at
Line Account Beginmng of Year Additions
No.(a)(b)(c)
(346)Misc. Power Plant Equipment
(347)Asset Retirement Costs for Other Production
TOTAL Other Production Plant (Enter Total of lines 37 tbru 44)
TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 45)
3. TRANSMISSION PLANT
(350)Land and Land RiJilits
(352)Structures and Improvements
(353)Station Equipment
(354)Towers and Fixtures
(355)Poles and Fixtures
(356)Overhead Conductors and Devices
(357)Underground Conduit
(358)Underground Conductors and Devices
(359)Roads and Trails
(359.Asset Retirement Costs for Transmission Plant
TOTAL Transmission Plant (Enter Total of lines 48 tbru 57)
4. DISTRIBUTION PLANT
(360)Land and Land RiJilits
(361)Structures and Improvements
(362)Station Equipment
(363)Stora.l(e Battery Equipment
(364)Poles, Towers, and Fixtures
(365)Overhead Conductors and Devices
(366)Underground Conduit
(367)Underground Conductors and Devices
(368)Line Transfonners
(369)Services
(370)Meters
(371)Installations on Customer Premises
(372)Leased Property on Customer Premises
(373)Street LiJilitin.l( and Si,gnal Systems
(374)Asset Retirement Costs for Distribution Plant 129 707
TOTAL Distribution Plant (Enter Total of lines 60 tbru 74)129 707
5. GENERAL PLANT
(389)Land and Land RiJilits 774
(390)Structures and Improvements 598 452
(391)Office Furniture and Equipment 144 700 284
(392)Transportation Equipment 649 444 285
(393)Stores Equipment 48,104 365
(394)Tools, Shop and Gara.l(e Equipment 219 164 309 778
(395)Laboratory EquiJ ment 372 559
(396)Power Operated Equipment 672 522
(397)Communication EQuipment 343 342 112 386
(398)Miscellaneous Bquipment 216
SUBTOTAL (Enter Total of lines 77 tbru 86)072 277 1,479 099
(399)Other Tancible Property
(399.Asset Retirement Costs for General Plant
TOTAL General Plant (Enter Total of lines 87 tbru 89)072 277 479 099
TOTAL (Accounts 101 and 106)742 555 800 708
(102)Electric Plant Purchased
(Less)(102) Electric Plant Sold
(103)Experimental Plant Unclassified
TOTAL Electric Plant in Service 742 555 800 708
FERC FORM NO.1 (ED. 12-88)Page 206
ot ITec Iy, slgne tates
Name of Respondent This R
iRlort Is:
Date of Report Year of Report (1) X An Original (Mo, Da, Yr)
Avista Corp.(2)A Resubmission April 18 2007 December 31, 2006
ELECTRIC PLANT IN SERVICE (Accounts 101 , 102 , 103, and 106) (Continued)
Balance at
Retirements Adjustments Transfers End of Year Line
(d)(e)(f)(J!)No.
(346)
(347)
(350)
(352)
(353)
(354)
(355)
(356)
(357)
(358)
(359)
(359.
(360)
(361)
(362)
(363)
(364)
(365)
(366)
(367)
(368)
(369)
(370)
(371)
(372)
(373)
129 707 (374)
129,707
774 (389)
598,452 (390)
383 136 601 (391)
702 602 027 (392)
469 (393)
310 464 633 (394)
6,494 366 065 (395)
672 522 (396)
695 1,152 026 556 059 (397)
1,188 (398)
214 612 1,152 026 34,488 790
(399)
(399.
214 612 152 026 34,488 790
949 154 1,152 026 746 135
(102)
(103)
949,154 1,152 026 746 135
D' t1 As'd T S
FERC FORM NO.1 (ED. 12-88)Page 207
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