2008Annual Report.pdf

..
. Item 1: l! An Initial (Original). Submission....................................
. Exact Legal Name of Respondent (Company)
. Avista Corporation
I
I
: FERC FORM NO.1I3Q (REV. 02-()
Avu-Ë
Form 1 Approved
OMS No, 1902-0021
(Expires 2/29/2009)
Form 1-F Approved
OMS No, 1902-0029
(Expires 2/28/2009)
Form 3-Q Approved
OMS No. 1902-0205
(Expires 2/28/2009)
THIS FILING IS
OR 0 Resubmission No.
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FERC FINANCIAL REPORT
FERC FORM No.1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3.Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act. Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines. civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Year/Period of Report
End of 2008/Q4
............................................
FERC FORM NO.1/3-Q:
REPORT OF MAJOR ELECTRIC UTILITIES. LICENSEES AND OTHER
IDENTIFICATION
02 Year/Period of Report
End of 2008lQ4
01 Exact Legal Name of Respondent
Avista Corporation
03 Previous Name and Date of Change (if name changed during year)
1 1
04 Address of Principal Offce at End of Period (Street, City, State, Zip Code)
1411 East Mission Avenue, Spokane, WA, 99202
05 Name of Contact Person
Christy Burmeister-Smith
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 IsArea Code (1) IX An Original
[phone]
06 Title of Contact Person
VP and Controller
(2) 0 A Resubmission
10 Date of Report
(Mo,Da, Yr)
04/16/2009
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned offcer 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 correc statements
of the business affairs of the respondent and the financial statements. and other financial information contained in this repo. conform in all material
respec to the Uniform System of Accunts.
01 Name 03 Signature ~
Mark T. Thies
02 TitleSr. VP and CFO Mark T. Thies ¥ fill ')cJ~
Title 18, U.S.C. 1001 makes it a crme for any person to knowingly and willngly to make to any Agency or Departent of th United States any
false, fictitious or frudulent statements as to any matter within its jurisdicton.
04 Date Signed
(Mo,Da, Yr)
FERC FORM No.1/3-Q (REV. 02-04)Page 1
FERC FORM NO.1 (ED. 12-96)Page 2
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/Q4
(2) DA Resubmission 04/16/2009
LIST OF SCHEDULES (Electric U lily)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
1 General Information 101
2 Control Over Respondent 102
3 Corporations Controlled by Respondent 103
4 Offcers 104
5 Directors 105
6 Important Changes During the Year 108-109
7 Comparative Balance Sheet 110-113
8 Statement of Income for the Year 114-117
9 Statement of Retained Earnings for the Year 118-119
10 Statement of Cash Flows 120-121
11 Notes to Financial Statements 122-123
12 Statement of Accum Comp Income, Comp Income, and Hedging Actvities 122(a)(b)
13 Summary of Utilty Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
14 Nuclear Fuel Materials 202-203
15 Electric Plant in Service 204-207
16 Electric Plant Leased to Others 213
17 Electric Plant Held for Future Use 214
18 Constrction Work in Progress-Electric 216
19 Accumulated Provision for Depreciation of Electrc Utilily Plant 219
20 Investment of Subsidiary Companies 224-225
21 Materials and Supplies 227
22 Allowances . 228-229
23 Extraordinary Propert Losses 230
24 Unrecovered Plant and Regulatory Study Costs 230
25 Transmission Service and Generation Interconnection Study Costs 231
26 Other Regulatory Assets 232
27 Miscellaneous Deferred Debits 233
28 Accumulated Deferred Income Taxes 234
29 Capital Stock 250-251
30 Other Paid-in Capital 253
31 Capital Stock Expense 254
32 Long-Term Debt 256257
33 Reconcilation of Reported Net Income with Taxable Inc for Fed Inc Tax 261
34 Taxes Accrued, Prepaid and Charged During the Year 262-263
35 Accumulated Deferred Investment Tax Credits 266-267
36 Other Deferred Credits 269
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo. Da, Yr)End of 2008/04
(2) Fi A Resubmission 04/16/2009
LI T OF SCHEDULES (Electric Utilty) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
37 Accumulated Deferred Income Taxes-Accelerated Amortization Propert 272-273
38 Accumulated Deferred Income Taxes-Other Propert 274-275
39 Accumulated Deferred Income Taxes-Other 276-277
40 Other Regulatory Liabilties 278
41 Electric Operating Revenues 300-301
42 Sales of Electricily by Rate Schedules 304
43 Sales for Resale 310-311
44 Electric Operation and Maintenance Expenses 320-323
45 Purchased Power 326-327
46 Transmission of Electricity for Others 328-330
47 Transmission of Electricity by ISOIRTOs 331
48 Transmission of Electricity by Others 332
49 Miscellaneous General Expenses-Electric 335
50 Depreciation and Amortization of Electrc Plant 336-337
51 Regulatory Commission Expenses 350-351
52 Research, Development and Demonstration Activities 352-353
53 Distribution of Salaries and Wages 354-355
54 Common Utilty Plant and Expenses 356
55 Amounts included in ISOIRTO Settlement Statements 397
56 Purchase and Sale of Ancilary Services 398
57 Monthly Transmission System Peak Load 400
58 Monthly ISOIRTO Transmission System Peak Load 400a
59 Electric Energy Account 401
60 Monthly Peaks and Output 401
61 Steam Electric Generating Plant Statistics 402-403
62 Hydroelectric Generating Plant Statistics 406-407
63 Pumped Storage Generating Plant Statistics 408-409
64 Generating Plant Statistics Pages 410-411
65 Transmission Line Statistics Pages 422-423
66 Transmission Lines Added During the Year 424-25
FERC FORM NO.1 (ED. 12-96)Page 3
(c)
............................................
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2008/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) FiA Resubmission 04/16/2009
U T OF SCHEDULES (Electric Utilty) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
(a)
Reference
Page No.
(b)
426-427
450
RemarksLine
No.
Title of Schedule
67 Substations
68 Footnote Data
Stockholders' Reports Check appropriate box:
I! Four copies will be submitted
D 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) IX An Original
(2) D A Resubmission
Date of Report
(Mo,Da, Yr)
04/16/2009
Year/Period of Report
End of 2008/04
GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of
offce where the general corporate books are kept, and address of offce where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
C. Burmeister-Smth, Vioe President and Controller
1411 E. Mission Avenue
Spkane, 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, Inoorporated Maroh 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 Aplioable
4. State the classes or utilty and other services furnished by respondent during the year in each State in which
the respondent operated.
Eleotrio servioe in the states of Washington, Idaho and Montana
Natural gas serioe in the states of Washington, Idaho and Oregon
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?
(1) 0 Yes...Enter the date when such independent accountant was initially engaged:
(2) ~ No
FERC FORM NO.1 (ED. 12-S7)PAGE 101
FERC FORM NO.1 (ED. 12-96)Page 103
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 04/16/2009
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 interpsition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each part holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless ofthe relative voting rights of each part.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owed Ref.
(a)(b)(c)(d)
1 Avista Capital, Inc.Parent company to the 100
2 Company's subsidiaries.
3
4 Advantage 10. Inc.Provider of utilily bil 75.11 Subsidiary of
5 processing, payment and Avista Capital
6 information services to multi
7 site customers in Nort Amer.
8
9 Avista Communications, Inc.Inactive 100 Subsidiary of
10 Avista Capital
11
12 Avista Development, Inc.Maintains an investment 100 Subsidiary of
13 portlio of real estate and Avista Capital
14 other investments.
15
16 Avista Energy, Inc.Inactive 100 Subsidiary of
17 Avista Capital
18
19 Avista Power, LLC Inactive 100 Affliate of
20 Avista Capital
21
22 Avista Turbine Power, Inc.Receives assignments of 100 Subsidiary of
23 purchase power agreements.Avista Capital
24
25 Avista Ventures. Inc.Inactive 100 Subsidiary of
26 Avista Capital
27
...........................................
. FERC FORM NO.1 (ED. 12-96)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) Fi A Resubmission 04/16/2009
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 part.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
1 Pentzer Corporation Parent company of Bay Area 100 Subsidiary of
2 Manufacturing and Pentzer Avista Capital
3 Venture Holdings.
4
5 Pentzer Venture Holdings Inactive 100 Subsidiary of
6 Pentzer Corporatin
7
8 Bay Area Manufacturing Holding Company 100 Subsidiary of
9 Pentzer Corporation
10
11 Advanced Manufacturing and Development, Inc.Performs custom sheet metal 82.95 Subsidiary of
12 dba Metaltx manufacturing of electronic Bay Area
13 enclosures, parts and systems Manufcturing.
14 for the computer, telecom and
15 medical industries. AM&D
16 also has a wod products
17 division.
18
19 Avista Receivables Corporation Acquires and sells accunts 100 Subsidiary of
20 receivable of Avista Corp.Avista Corp.
21
22 Spokane Energy, LLC Marketing of energy.100 Affliate of
23 Avista Corp.
24
25 Avista Capital II An affliated business trust 100 Affliate of
26 formed by the Company.Avista Corp.
27 Issued Pref. Trust Securities
Page 103.1
FERC FORM NO.1 (ED. 12-96)Page 103.2
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 04/16/2009
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 part holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each part.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.
(a)(b)(c)(d)
1
2 AVA Capital Trust III An affliated business trst 100 Affliate of
3 formed by the Company.Avista Corp.
4 Issued Pref. Trust Securities
5
6 Steam Plant Square, LLC Commercial offce and retail 90 Affliate of
7 leasing.Avista Development
8
9 Courtard Offce Center Commercial offce and retail 100 Affliate of
10 leasing.Avista Development
11
12 AVA Formation Corp.Holding Company 100 Formed in 2006 for
13 the purpose of
14 completing proposed
15 statutory share
16 exchange and
17 holding company
18 structure. Currently
19 a subsidiary of
20 Avista Corp.
21
22 Coyote Springs 2, LLC Owned an interest in a 100 inactive
23 generation plant.
24
25
26
27
............................................
This Page Intentionally Left Blank
FERC FORM NO.1 (ED. 12-96)Page 104
............................................
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corpration (1) An Original (Mo, Da, Yr)End of 2008104
(2) FiA Resubmission 04/161009
OFFICERS
1. Report below the name, title and salary for each executive offcer whose salary is $50,000 or more. An "executive offcer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or functon
(such as sales, administtion or finance), and any other persn who perfrms similar policy making functons.
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.
iune TiUe Name ot unlcer , ::alary
No.
for Year
(a)(b)(c)
1 Chirman of the Board, President S. L. Morrs
2 and Chief Executive Ofcer (Effective 01/01/08)
3
4 Executive Vice President M. K. Malquist
5
6 Senior Vice President and Chief Financial Ofcer M. T. Thies
7 (Effective September 29, 2008)
8
9 Senior Vice President, General Counsel M. M. Durkin
10 and Chief Compliance Ofcer
11
12 Senior Vice President and Corporate Secetary K. S. Feltes
13 with responsibilily for Human Resource
14
15 Vice President, Controller and C. M. Burmeister - Smith
16 Principal Accunting Ofce
17
18 Vice President and Chief Information Ofcer J.M. Kensok
19
20 Vice President with responsibllly for Transmission D. F. Kopcznski
21 and Distrbution Operations
22
23 Vice President and Chief Counsel for Regulatory and D. J. Meyer
24 Governmental Affairs
25
26 Vice President, with responsibilly for State and K. O. Norwd
27 Federal Regulation
28
29 Vice President and Environmental Compliance Ofcer D. P. Vermillon
30 (Title change effective 08115/2008)
31
32 Vice President of Finance and Treasurer A. M. Wilson
33
34 Vice President, with reponsibilly for R. D. Woodwrt
35 Sustainable Energy Solutions
36
37
38
39
40
41
42
43
44
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 04/16/2009
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 direcors who are officers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairmn of the Executive Committee by a double asterisk.
ii.n,ie Name (anp .1 lUe) or Director l"nnClpal I:usiness AooressNo.(a)(b)
1 Scott L. Morris**1411 E Mission Ave., Spokane, WA, 99202
2 (Chairman of the Board, President & CEO, as of 01/01/08)
3
4 Erik J. Anderson 3720 Carillon Point, Kirkland, WA 98033
5
6 Kristianne Blake***P.O. Box 28338, Spokane, WA 99228
7
8 Brian W. Dunham (Effective 03/01/2008)5721 SE Columbia Way, Suite 200, Vancouver, WA 986661
9
10 Roy Lewis Eiguren 702 W. Idaho St., Suite 1000, Boise, ID 83702
11
12 Jack W. Gustavel ***1260 Riverstone Dr., 3rd Floor, Coeur d Alene, ID 83814
13
14 John F. Kelly 142 Isla Dorada Blvd., Coral Gables, FL 33143
15
16 Michael L. Noel 11960 W. Six Shooter Rd. , Prescott, AZ 86305
17
18 Heidi B. Stanley 111 N. Wall St., Spokane, WA 99201
19
20 R. John Taylor***111 Main Street, Lewiston ID 83501
21
22 Lura J. Powell (Resigned 05/08/2008)1009 Countr Ct., Richland, WA 99352
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39 .
40
41
42
43
44
45
46
47
48
FERC FORM NO.1 (ED. 12-95)Page 105
This Page Intentionally Left Blank
............................................
............................................
Name of Respondent
Avista Corporation
Date of Report Year/Penod of Report
End of 2008/Q4
This Report Is:
(1) 12 An Original
(2) 0 A Resubmission
1M ORTANT CHANGES DURING THE OUARTERIEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: . Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the propert, 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 surrndered: 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
appropnate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an offcer,
director, security holder reported on Page 106, voting trustee, associated company or known associate of any of these persons was a
party or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in offcers, directors, major security holders and voting powers of the respondent that may have
occurred during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its 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 affliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
04/16/2009
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 108
1. None2. None
3. None4. None5. None
6. Avista Receivables Corporation (ARC) is a wholly owned, bankptcy-remote subsidiar of Avista Corp.
formed for the purpose of acquirng or purchasing interests in certain accounts receivable, both biled and unbiled, of the
Company. On March 14,2008, Avista Corp., ARC and a thrd-pary fincial institution amended a Receivables
Purchase Agreement. The most significant amendment extended the termination date to March 13,2009. Under the
Receivables Purchase Agreement, ARC can sell without recourse, on a revolvig basis, up to $85.0 milion 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. The amount of such fees is included in other operating expenses of A vista
Corp. The Receivables Purchase Agreement has fmancial covenants, which are substantially the same as those of A vista
Corp. 's $320.0 milion commtted line of credit. As of December 31, 2008, ARC had the abilty to sell up to $85.0
milion of receivables and there was $17.0 millon in accounts receivable sold under this revolvig agreement, a decrease
from the $85.0 milion available and sold as of December 31,2007.
The Company has a committed line of credit agreement with varous bans in the total amount of $320.0
milion with an expiration date of April 5, 2011. Under the credit agreement, the Company can request the issuance of up
to $320.0 milion in letters of credit. The Company had $250.0 milion of borrowings outstanding as of December 31,
2008 and no borrowings outstanding as of December 31, 2007. Total letters of credit outstanding were $24.3 milion as
of December 31,2008 and $34.8 milion as of December 31,2007. The committed line of credit is secured by $320.0
millon of non-transferable First Mortgage Bonds of the Company issued to the agent ban that would only become due
and payable in the event, and then only to the extent, that the Company.defaults on its obligations under the committed
line of credit.
On November 26, 2008, the Company entered into a 364-day committed line of credit agreement with
various banks in the total amount of $200.0 milion with an expiration date of November 24,2009. The Company had no
borrowings outstanding as of December 31,2008. The committed line of credit is secured by $200.0 milion of
non-transferable First Mortgage Bonds ofthe Company issued to the agent ban that would only become due and payable
in the event, and then only to the extent, that the Company defaults on its obligations under the committed line of credit.
This credit facility was approved by the respective regulatory commissions as follows: WUC (Docket No. UE-081842);
IPUC (A VU-U-08-02); and OPUC (NI A).
On April 3, 2008, the Company issued $250.0 milion of5.95 percent First Mortgage Bonds due in 2018.
The net proceeds from the issuance of $249.2 milion (net of issuance discount and before Avista Corp.'s expenses),
together with other available fuds, were used to pay the $272.9 milion of9.75 percent Unsecured Senior Notes that
matured on June 1,2008. This debt issuance was approved by the respective regulatory commissions as follows: WUC
(Docket No. U-080182 Order No.1); IPUC (Case No. A VU-U-08-01 Order No. 30509); and OPUC (Docket UP 4246
Order No. 08-143).
On December 16,2008, the Company issued $30.0 milion of7.25 percent First Mortgage Bonds due in
2013. The net proceeds from the issuance of $29.9 milion (net of placement agent fees and before Avista Corp.'s
expenses) were used to repay $25.0 milion of medium term notes that matured on December 10, 2008 and repay a
portion of the borrowings outstanding under the Company's $320.0 milion committed line of credit. This debt issuance
was approved by the respective regulatory commissions as follows: WUTC (Docket No. UE-080182); IPUC
(A VU-U-08-03); and OPUC (U 4246).
On December 31, 2008, $66.7 milion of the City of Forsyth, Montana Pollution Control Revenue Refunding
Bonds, Series 1999A (Avista Corporation Colstrip Project) due 2034 were remarketed. Avista Corp. purchased these
Pollution Control Bonds and expects that at a later date, subject to market conditions, these bonds wil be remarketed to
unaffliated investors or refuded by a new issue. Although Avista Corp. is now the holder of these Pollution Control
Bonds, the bonds wil not be cancelled but wil remain outstanding under the City of Forsyth's indenture. However, so
IFERC FORM NO.1 (ED. 12-96) Page 109.1
............................................
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 04/16/2009 2008104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
........................
.,...................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008104
IMPORTANT CHANGES DURING THE OUARTERIEAR (Continued)
long as Avista Corp. is the holder, the bonds wil not be reflected as an asset or a liabilty on Avista Corp.'s Consolidated
Balance Sheet. This debt transaction was approved by the respective regulatory commissions as follows: WUTC (Docket
No. UE-081859); IPUC (AVU-U-08-03); and OPUC (UF 4253).
On December 30, 2008, the City of Forsyth, Montana issued $17.0 milion of its Pollution Control Revenue
Refuding Bonds, Series 2008 (Avista Corporation Colstrip Project) due 2034 on behalf of Avista Corp. The proceeds of
these bonds were used to refund $17.0 milion of Pollution Control Revenue Refunding Bonds, Series 1999B (Avista
Corporation Colstrip Project) issued by the City of Forsyth, Montana on behalf of Avista Corp. These bonds are included
in the current portion oflong-term debt because they are subject to purchase at any time at the option of the bond holder.
This debt transaction was approved by the respective regulatory commissions as follows: WUC (Docket No.
UE-081859); IPUC (AVU-U-08-03);and OPUC (UF 4253).
7. At the May 8, 2008 Anual Meeting, the shareholders of Avista Corporation approved a proposal for an
amendment of the Restated Aricles of Incorporation to change from a plurality voting standard to a majority voting .
standard in uncontested elections of directors and to eliminate cumulative voting, For further details, see Avista
Corporation's Definitive Proxy Statement fied with the Securities and Exchange Commission on March 31, 2008.
As a result of the amendment to the Restated Aricles of Incorporation, a conforming amendment was made
to the bylaws of Avista Corporation on May 9,2008. Specifically, section 5 of Aricle II and Section 11 of Aricle il of
the Bylaws of A vista Corporation was changed to eliminate references to cumulative voting.
8. Average anual wage increases were 3.4% for non-exempt employees effective March 1, 2008. Average
anual wage increases were 3.9% for exempt employees effective March 1,2008. Average anual wage increases were
7.4% for offcers effective March 1,2008. Certain bargaining unit employees received increases ranging from 3.0% to
3.5% effective in March and April 2008.
9. Reference is made to Note 25 of the Notes to Financial Statements, page 123 of this Report.10. None
11. Reserved
12. See page 123 of this Report.
13. Gary G. Ely, Chairman of the Board and Chief Executive Offcer of Avista Corp., retired from the Company and
the board, effective December 31,2007. The Company's board of directors elected Scott L. Morrs to the positions of
Chairman of the Board, President and Chief Executive Officer of Avista Corp., effective January 1,2008.
On February 15, 2008, An Wilson was appointed Vice President of Finance and Treasurer.
On February 15, 2008, the Board of Directors appointed Brian W. Dunham to serve as a director on the board
effective March 1, 2008. Mr. Dunham is the president and chief executive officer of Northwest Pipe Company, which
manufactures welded steel water transmission lines.
On February 15,2008, Lura J. Powell provided notification to Avista Corp. that she wil not stand for re-election
to the board when her term expires in May 2008 to focus on her professional commitments in technology and healthcare.
Mark Thies joined the Company as Senior Vice President and Chief Financial Officer in September 2008. The
Chief Financial Offcer position was previously held by Malyn Malquist. Malyn Malquist stayed on with the Company
as Executive Vice President and then retired from the Company effective March 31,2009.
On December 8,2008, Dennis Vermilion was appointed President of Avista Utilties effective Januar 1, 2009.
He wil remain Vice President of Avista Corp.
On December 8, 2008, Richard Storro was appointed Vice President of Energy Resources.
14. Proprietary capital is not less than 30 percent.
I FERC FORM NO.1 (ED. 12-96)Page 109.2
Name of Respondent This Report Is:Date of Report Year/Period of Report
Avista Corporation (1 )~An Original (Mo,Da, Yr)
(2)0 A Resubmission 04/16/2009 End of 2008104
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Accunt Page No.Balance 12/31
(a)(b)(c)(d)
1 UTILITY PLAT
2 Utilly Plant (101-106, 114)200-201 3,340,068,198 3,131,916,272
3 Construction Work in Progress (107)200-201 75,568,224 75,679,838
4 TOTAL Utilly Plant (Enter Total of lines 2 and 3)3,415,636,22 3,207,596,110
5 (Less) Accum. Provo for Depr. Amort. Depl. (108, 110, 111, 115)200-201 1,142,578,137 1,090,037,407
6 Net Utilty Plant (Enter Total of line 4 less 5)2,273,058,285 2,117,558,703
7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)202-203 0 0
8 Nuclear Fuel Materials and Assemblies-Stock Account (120.2)0 0
9 Nuclear Fuel Assemblies in Reactor (120.3)0 0
10 Spent Nuclear Fuel (120.4)0 0
11 Nuclear Fuel Under Capital Leases (120.6)0 0
12 (Less) Accum. Provo for Amort. of Nucl. Fuel Assemblies (120.5)202.203 0 0
13 Net Nuclear Fuel (Enter Totai oflines 7-11 less 12)0 0
14 Net Utilty Plant (Enter Total of lines 6 and 13)2,273,058,285 2,117,558,703
15 Utilty Plant Adjustments (116)122 0 0
16 Gas Stored Underground - Noncurrent (117)0 0
17 OTHER PROPERTY AND INVESTMENTS
18 Nonutilty Propert (121)4,991,551 4,670,595
19 (Less) Accum. Provo for Depr. and Amort. (122)890,639 897,192
20 Investments in Associated Companies (123)13,903,000 13,903,000
21 Investment in Subsidiary Companies (123.1)224-225 77,487,962 71,371,272
22 (For Cost of Account 123.1, See Footnote Page 224, line 42)
23 Noncurrent Portion of Allowances 228-229 0 0
24 Other Investments (124)26,240,546 28,691,550
25 Sinking Funds (125)0 0
26 Depreciation Fund (126)0 0
27 Amortization Fund - Federal (127)0 0
28 Other Special Funds (128)10,234,544 15,878,558
29 Special Funds (Non Major Only) (129)0 0
30 Long-Term Portion of Derivative Assets (175)49,312,596 55,312,881
31 Long-Term Portion of Derivative Assets - Hedges (176)0 0
32 TOTAL Other Property and Investments (Lines 18-21 and 23-31)181,279,560 188,930,664
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds (Non-major Only) (130)0 0
35 Cash (131)1,674,372 5,264,119
36 Special Deposits (132-134)1,600,000 5,668,267
37 Working Fund (135)619,853 679,537
38 Temporary Cash Investments (136)2,684,444 2,608,103
39 Notes Receivable (141)63,451 0
40 Customer Accounts Receivable (142)207,867,900 87,238,080
41 Other Accounts Receivable (143)6,188,61 (9,920,307
42 (Less) Accum. Provo for Uncollectible Acct.-Credit (144)5,844,603 2,965,676
43 Notes Receivable from Associated Companies (145)0 0
44 Accounts Receivable from Assoc. Companies (146)120,021 502,535
45 Fuel Stock (151)227 3,673,039 2,213,923
46 Fuel Stock Expenses Undistributed (152)227 0 0
47 Residuals (Elec) and Extracted Products (153)227 0 0
48 Plant Materials and Operating Supplies (154)227 17,455,835 17,365,306
49 Merchandise (155)227 0 0
50 Other Materials and Supplies (156)227 0 0
51 Nuclear Materials Held for Sale (157)202-203/227 0 0
52 Allowances (158.1 and 158.2)228-229 0 0
:.
FERC FORM NO.1 (REV. 12-03)Page 110
............................................
............................................
Name of Respondent This Report Is:Date of Report YearlPeriod of Report
Avista Corporation (1 )IZ An Original (Mo,Da, Yr)
(2)0 A Resubmission 04/16/2009 End of 2008104
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS.Continued)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
53 (Less) Noncurrent Portion of Allowances 0 0
54 Stores Expense Undistributed (163)227 0 0
55 Gas Stored Underground - Current (164.1)30,720.371 13,414,238
56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)0 0
57 Prepayments (165)8,415.670 6,438,702
58 Advances for Gas (166-167)0 0
59 Interest and Dividends Receivable (171)10,93~0
60 Rents Receivable (172)646,271 509,924
61 Accrued Utilly Revenues (173)0 0
62 Miscellaneous Current and Accrued Assets (174)194,919 6,153,636
63 Derivative Instrument Assets (175)60,546,323 67,390,448
64 (Less) Long-Term Portion of Derivative Instrument Assets (175)49,312,596 55,312,881
65 Derivative Instrument Assets - Hedges (176)874,944 0
66 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 0 0
67 Total Current and Accrued Assets (Lines 34 through 66)288,199,765 167,088,568
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (181)15,852,599 11,576,174
70 Extraordinary Propert Losses (182.1)230 0 0
71 Unrecovered Plant and Regulatory Study Costs (182.2)230 0 0
72 Other Regulatory Assets (182.3)232 455,580,547 281,620,776
73 Prelim. Survey and Investigation Charges (Electric) (183)3,088,816 234.518
74 Preliminary Natural Gas Survey and Investigation Charges 183.1)0 0
75 Other Preliminary Survey and Investigation Charges (183.2)0 0
76 Clearing Accounts (184)0 0
77 Temporary Facilties (185)0 0
78 Miscellaneous Deferred Debits (186)233 32,008.980 40,642,265
79 Def. Losses from Disposition of Utiity PIt. (187)0 0
80 Research, Devel. and Demonstration Expend. (188)352-353 0 0
81 Unamortized Loss on Reaquired Debt (189)17,151,844 20,965,705
82 Accumulated Deferred Income Taxes (190)234 131,055,525 90,823,103
83 Unrecovered Purchased Gas Costs (191)-18,646.016 2,374,110
84 Total Deferred Debits (lines 69 through 83)636.092,295 448,236.651
85 TOTAL ASSETS (lines 14-16, 32, 67, and 84)3.378,629,905 2,921,814,586
FERC FORM NO.1 (REV. 12-03) Page 111
Name of Respondent This Report is:Date of Report Year/Period of Report
Avista Corporation (1 )~An Original (mo, da, yr)
(2). D A Rresubmission 0411612009 end of 2008/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201)250-251 755,903,11ll 727,945,794
3 Preferred Stock Issued (204)250-251 0 0
4 Capital Stock Subscribed (202, 205)252 0 0
5 Stock Liabilty for Conversion (203, 206)252 0 0
6 Premium on Capital Stock (207)252 0 0
7 Other Paid-In Capital (208-211)253 19,170,532 2,281,868
8 Installments Received on Capital Stock (212)252 0 0
9 (Less) Discount on Capital Stock (213)254 0 0
10 (Less) Capital Stock Expense (214)254 87,394 3,294,916
11 Retained Earnings (215, 215.1, 216)118-119 253,478,332 221,313,566
12 Unappropriated Undistributed Subsidiary Earnings (216.1)118-119 -25,488,897 -14,672,673
13 (Less) Reaquired Capital Stock (217)250-251 0 0
14 Noncorporate Proprietorship (Non-major only) (218)C 0
15 Accumulated Other Comprehensive Income (219)122(a)(b)-6,092,318 -19,607,486
16 Total Proprietary Capital (lines 2 through 15)996,883,374 913,966,153
17 LONG-TERM DEBT
18 Bonds (221)256-257 824,970,979 671,733,175
19 (Less) Reaquired Bonds (222)256-257 0 0
20 Advances from Associated Companies (223)256-257 114,603,000 114,603,000
21 Other Long-Term Debt (224)256-257 0 273,010,231
22 Unamortized Premium on Long-Term Debt (225)239,850 248,733
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)1,752,256 1,328,472
24 Total Long-Term Debt (lines 18 through 23)938,061,573 1,058,266,667
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent (227)0 75,206
27 Accumulated Provision for Propert Insurance (228.1)0 0
28 Accumulated Provision for Injuries and Damages (228.2)1,579,821 344,000
29 Accumulated Provision for Pensions and Benefits (228.3)184,587,850 90,554,881
30 Accumulated Miscellaneous Operating Provisions (228.4)2,936,173 1,826,000
31 Accumulated Provision for Rate Refunds (229)C 0
32 Long-Term Portion of Derivative Instrument Liabilties 7,140,857 1,899,098
33 Long-Term Portion of Derivative Instrument Liabilties - Hedges 0 10,501,880
34 Asset Retirement Obligations (230)4,208,32/3,990,011
35 Total Other Noncurrent Liabilties (lines 26 through 34)200,453,028 109,191,076
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)250,000,000 0
38 Accunts Payable (232)153,032,40e 114,760,498
39 Notes Payable to Associated Companies (233)2,854,178 2,182,637
40 Accounts Payable to Associated Companies (234)737,710 600,647
41 Customer Deposits (235)6,979,171 6,331,722
42 Taxes Accrued (236)262-263 6,105,577 -4,717,808
43 Interest Accrued (237)10,871,471 12,577801
44 Dividends Declared (238)0 0
45 Matured Long-Term Debt (239)0 0
FERC FORM NO.1 (rev. 12-03)Page 112
............................................
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
Avista Corporation (1 )~An Original (mo, da, yr)
(2)0 A Rresubmission 04/16/2009 end of 2008104
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIT(Sntinued)
Line Current Year Prior Year
No.Ref.End of OuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
46 Matured Interest (240)0 0
47 Tax Collections Payable (241)0 252
48 Miscellaneous Current and Accrued Liabilties (242)32,188.393 41,016,254
49 Obligations Under Capital Leases-Current (243)75.206 295,029
50 Derivative Instrument Liabilties (244)78,603,554 21,148,085
51 (Less) Long-Term Portion of Derivative Instrument Liabilties 7,140,857 1,899,098
52 Derivative Instrument Liabilties - Hedges (245)0 10,501,880
53 (Less) Long-Term Portion of Derivative Instrument Liabilties-Hedges 0 10,501,880
54 Total Current and Accrued Liabiliies (lines 37 through 53)534,306,811 192.296,019
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)1,263,08€1,265,933
57 Accumulated Deferred Investment Tax Credits (255)266-267 373,728 423,036
58 Deferred Gains from Disposition of Utilty Plant (256)0 0
59 Other Deferred Credits (253)269 24.985,882 18,072,332
60 Other Regulatory Liabilties (254)278 55,429,522 65,481,339
61 Unamortized Gain on Reaquired Debt (257)3,237,373 3,528,194
62 Accum. Deferred Income Taxes-Accl. Amort.(281)272-277 0 0
63 Accum. Deferred Income Taxes-Other Propert (282)334,892,041 320,049,323
64 Accum. Deferred Income Taxes-Other (283)288,743,487 239,274,514
65 Total Deferred Credits (lines 56 through 64)708,925,11!J 648,094,671
66 TOTAL LIABILITIES AND STOCKHOLDER EOUITY (lines 16, 24, 35, 54 and 65)3,378.629,905 2,921,814,586
FERC FORM NO.1 (rev. 12-03) Page 113
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da. Yr)End of 2008104
(2) nA Resubmission 04/16/2009
STATEMENT OF INCOME
Ouarterly
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 utilly functon; in column (h) the quarter to date amounts for gas utilty, and in 0) the
quarter to date amounts for other utilty function for the current year quarter.
3. Report in column (g) the quarter to date amounts for electric utilily function; in column (i) the quarter to date amounts for gas utilty, and in (k) the
quarter to date amounts for other utilty function for the prior year quarter.
4. If additional columns are needed place them in a footnote.
Annual or Ouarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utilily Plant Leased to Others, in another utilly columnin a similar manner to
a utilly department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in accunt 414, Other Utilily 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 404.1, 404.2, 404.3, 407.1 and 407.2.
Line Total Total Current 3 Month Prir 3 Months
No.Currnt Year to Prior Year to Ended Ended
(Ret)Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Accunt Page No. QurtrlY ear QuartrlY ear No 4th Qurter No 4th Quarter
(a)(b)(c)(d)(e)(I)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)30301 1,657,671,994 1,321,662,326
3 Operating Expenses
4 Operation Expenses (401)320.323 1,278,636,823 965,325,057
5 Maintenance Expenses (402)320323 47,636,921 45,512,775
6 Depreciation Expense (403)33.337 82,388,834 81,802,514
7 Depreciation Expense for Asset Retirement Cost (403.1)336.337
8 Amort. & Dep!. of Utility Plant (404-405)336.337 7,905,829 6,738,44
9 Amort. of Utility Plant Acq. Adj. (406)336-337 99,047 99,047
10 Amort. Properl Losses, Unrecov Plant and Regulatory Study Cost (407)
11 Amort. of Conversion Expenses (407)
12 Regulatory Debits (407.3)382,274 2,979,998
13 (Less) Regulatory Credits (407.4)8,388,441 8,618,156
14 Taxes Other Than Income Taxes (408.1)262-263 72,057,352 72,443,295
15 Income Taxes. Federal (409.1)262.263 3,249,258 22,447,987
16 -Other(409.1)262.263 53,201 520,211
17 Provision for Deferred Income Taxes (410.1)23, 272-277 42,60,284 12,026,706
18 (Less) Provision for Deferred Income Taxes-Cr. (411.)23, 272-277 4,970,670 4,122,957
19 Investment Tax Credit Adj. - Net (411.4)266 -49,30 .49,308
20 (Less) Gains from Disp. of Utility Plant (411.6)
21 Losses from Disp. of Utility Plant (411.7)
22 (Less) Gains from Disposition of Allowances (411.8)
23 Losss from Disposition of Allowances (411.9)
24 Accretion Expense (411.10)
25 TOTAL Utilty Operating Expenses (Enter Total of lines 4 thru 24)1,521,601,404 1,197,105,613
26 Net Util Oper Inc (Enter Tot line 21e55 25) Carry to Pgl17,line 27 136,070,590 124.556,713
...........................................
. FERC FORM NO.1 (ED. 12-96)
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2008104
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2009
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for important notes regarding the statement of income for any accunt thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utilily'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 utilly 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 settement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accounts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income.
including the basis of allocations and apportionments from those used in the preceding year. Also. give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
15. If the columns are insuffcient for reportng additional utilty departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(g) (h)
GAS UTiLITY
Current Year to Date Previous Year to Date
(in dollars) (in dollars)(i) 0)
Line
No.
811.918.216
109,467,920
639,011,602
105,119,951
709,683,188
26.602.670
558,094,011
19,436,762
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
624,698,493 467,293,942 653.938,330 498,031,115
40,308.817 37.501,902 7,328,104 8.010,873
67,721,188 64,517,110 14,667,646 17,285,404
6,448,003 5,686,773 1,457,826 1,051,671
99,047 99,047
153,132 337,368 229,142 2,642,630
6,730,732 7,499,030 1,657,709 1,119,126
47,356,209 46,412,373 24,701,143 26,030,922
143,777 14,193,471 3,105,481 8,254,516
-192,188 378,906 245,389 141.305
36,623,690 13,472,601 5,976,594 -1,445,895
4,711,220 3,382,861 259,450 740,096
-49,308 -49,308
Page 115
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 04/16/2009
STA EMENT OF INCOME FOR THE YEAR (continued)
Line TOTAL \.urrent ¡s Months Prior 3 Months
No.Ended Ended
(Ref.)Quarterl Only Quarterl Only
Title of Account Page No.Current Year Previous Year No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(f)
27 Net Utility Operating Income (Carried forward from page 114)136,070,590 124,556,713
28 Oter Income and Deducions
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 Nonutilty Operations (417)
34 (Less) Expenses of Nonutlity Operations (417.1)3,869,058 4,477,623
35 Nonoperating Rental Income (418)7,726 -18,512
36 Equity in Earnings of Subsidiary Companies (418.1)119 4,123,038 -4,595,749
37 Interest and Dividend Income (419)10,085,671 7,743,889
38 Allowance for Other Funds Used During Constrction (419.1)5,692,491 4,736,330
39 Miscllaneous Nonoperating Income (421)16,000
40 Gain on Disposition of Propert (421.1)810,694 257,380
41 TOTAL Other Income (Enter Total of lines 31 thru 40)16,866,562 3,645,715
42 Oter Income Deductions
43 Loss on Disposition of Propert (421.2)2,289,978
44 Miscellaneous Amortization (425)34 1,110,571 1,110,572
45 Donations (426.1)34 956,059 622,859
46 Life Insurance (426.2)2,100,235 2,557,490
47 Penalties (426.3)138,152 37,60
48 Exp. for Certin Civic, Political & Related Actiities (426.4)1,211,097 1,097,891
49 Other Deductions (426.5)-1,891,457 3,799,017
50 TOTAL Other Income Deductions (Total of lines 43 thru 49)3,624,657 11,515,407
51 Taxes Applic. to Other Income and Deductions
52 Taxes Other Than Income Taxes (408.2)262-26 547,911 251,464
53 Income Taxes-Federal (409.2)262-263 2,415,034 149,939
54 Income Taxes-Other (409.2)262-263 -288,122 -4,584
55 Provision lor Deferred Inc. Taxes (410.2)23,272-277 1,523,886 -257,145
56 (Less) Provision for Deferred Incme Taxes-Cr. (411.2)23, 272-277 3,29,942 4,052,315
57 Investment Tax Credit Adj.-Net (411.5)
58 (Less) Investment Tax Credits (420)
59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)903,767 .4,312,641
60 Net Oter Income and Deductions (Total of lines 41, 50, 59)12,338,138 -3,557,051
61 Interest Charges
62 Interest on Long-Term Debt (427)62,954,659 69,538,504
63 Amort. of Debt Disc. and Expense (428)922,381 1,063,487
64 Amortizatin of Loss on Reaquired Debt (428.1)3,759,437 5,290,891
65 (Less) Amort. of Premium on Debt-Credit (429)8,885 8,885
66 (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67 Interest on Debt to Assoc. Companies (430)340 6,218,511 7,605,326
68 Other Interest Expense (431)34 5,554,756 2,899,617
69 (Less) Allowance for Borrowed Funds Used During Consction-Cr. (432)4,611,851 3,864,363
70 Net Interest Charges (Total of lines 62 thru 69)74,789,008 82,524,577
71 Income Before Extaordinary Items (Total of lines 27, 60 and 70)73,619,720 38,475,085
72 Extraordinary Items
73 Extraordinary Income (434)
74 (Less) Extaordinary Deductions (435)
75 Net Extraordinary Items (Total of line 73 less line 74)
76 Income Taxes-Federal and Other (409.3)262-263
77 Extraordinary Items After Taxes (line 75 less line 76)
78 Net Income (Total of line 71 and 77)73,619,720 38,475,085
FERC FORM NO. 1/3-0 (REV. 02-04)Page 117
............................................
.....................
. This Page Intentionally Left Blank......................
1,334,004)
4,392,647)
............................................
Name of Respondent
Avista Corporation
Date of Report
(Mo, Da, Yr)
04/16/2009
INGS
YeadPerod of Report
End of 2008104
This ~ort Is:
(1) ~An Original
(2) A Resubmission
STATEMENT OF RETAINED EAR
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 ItemNo. (a)
UNAPPROPRIATED RETAINED EARNINGS (Accunt 216)
1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Accunt 439)
4
5 Tax Benefit Received from 401k
6 Dividends received from Subsidiaries
7 Prior period adjustment for benefit plan restatement
8 Stock compensation dividend adjustment
9 TOTAL Credits to Retained Eamings (Acct. 439)
10
11 Stock Options Exercised
12 Preferred Series K Reclass
13 Debt Repurchase Adjustment
14 Subsidiary Federal Tax Credits (Avista Energy)
15 TOTAL Debits to Retained Earnings (Acct. 439)
16 Balance Transferred from Income (Accunt 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
18
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acet. 437)
30 Dividends Declared-Common Stock (Account 438)
31
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acct. 438)
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38 Balance - End of Period (Total 1,9,15, 16,22,29,36,37)
Contra Primary
ccunt Affected
(b)
Current
OuarterlYear
Year to Date
Balance
(c)
Previous
OuarterlYear
Year to Date
Balance
(d)
I~..
I
I
( 14,870)
48,260,105
2,471,138)
15,913
45,790,010
-796,180
-796,180
69,496,662
5,726,651)
43,070,834
-37,070,823 ( 31,450,517)
-37,070,823
535,087
251,930,211
31,450,517)
1,547,552
219,765,445
FERC FORM NO. 1/3-Q (REV. 02-04)Page 118
............................................
Name of Respondent
Avista Corporation
Date of Report
(Mo, Da, Yr)
04/16/2009
INGS
Year/Period of Report
End of 2008/04
This ~ort Is:
(1) ~An Original
(2) A Resubmission
STATEMENT OF RETAINED EAR
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 ItemNo. (a)
APPROPRIATED RETAINED EARNINGS (Account 215)
39
40
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Accunt 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Accunt 215.1)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Ouarterly
49 BalanceBeginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52 Subsidiary Expense & Misc Subs Equity Comp
53 Balance-End of Year (Total lines 49 thru 52)
Current
OuarterlYear
Year to Date
Balance
Previous
OuarterlY ear
Year to Date
Balance
1,548,121 1,548,121
1,548,121 1,54,121
1,548,121
253,478,332
1,548,121
221,313,566
I- - I - -
-14,672,673
4,123,038
51,109,032
4,595,749)
48,260,105
12,925,851)
14,672,673)
-14,939,262
-25,488,897
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
FERC FORM NO.1 (ED. 12-96)Page 120
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) nA Resubmission 04/1612009
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proeeds or Payments;(b )Bonds, debentures and other long-term debt: (c) Include commercial paper; and (d) Identif 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 betwn "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Shet.
(3) Operating Activities - Other: Include gains and losses pertining to operating activities only. Gains and losses pertining 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 incme taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outfow to acquire othr companies. Provide a reconcilation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalize per the USofA General Instruction 20; instead provide a reconcilation of the
dollar amount of leases capitalized with th plant cost.
Line Description (See Instruction NO.1 for Explanation of Codes)Current Year to Date Previous Year to Date
No.OuarterlYear Ouarteriyear
(a)(b)(c)
1 Net Cash Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117)73,619,720 38,75,085
3 Noncash Charges (Credits) to Income:
4 Depreciation and Depletion 90,390,864 88,540,958
5 Amortization of deferred power and natural gas costs 45,835,653 19,629,891
6 Amortization of debt expense 4,672,935 6,345,95
7 Amortization of investment in exchange power 2,450,031 2,450,030
8 Deferred Income Taxes (Net)41,798,683 4,003,423
9 Investment Tax Credit Adjustment (Net)-49,308 -49,308
10 Net (Increase) Decrease in Receivables -116,961,581 1,881,714
11 Net (Increase) Decrease in Inventory -18,855,778 -3,940,327
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Acced Expenses 2,228,853 -28,529,359
14 Net (Increase) Decrease in Other Regulatory Assets -20,468,183 -8,395,908
15 Net Increase (Decrease) in Other Regulatory Liabilties 2,372,800 1,888,830
16 (Less) Allowance for Other Funds Used During Construction 5,692,491 4,736,330
17 (Less) Undistrbuted Earnings from Subsidiary Companies 4,123,038 -4,595,749
18 Other (provide details in footnote):601,532 696,571
19 Write-down of asset 2,289,978
20 Change in other current assets and liabilties -10,063,226 -2,782,552
21 Net change in receivables allowance 2,878,927 235,324
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)90,636,393 122,599,264
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utilty Plant (less nuclear fuel)-219,796,264 -196,772,585
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utiily Plant
29 Gross Additions to Nonutilty Plant
30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33
34 Cash Outfows for Plant (Totai of lines 26 thru 33)-219,796,264 -196,772,585
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)7,998,322
38
39 Investments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc. and Subsidiary Companies 1,191,118 170,364,287
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
............................................
Name of Respondent
Avista Corporation
This ~ort Is:
(1) LS An Originai
(2) A Resubmission
STATEMENT OF CASH FLOWS
Date of Report
(Mo, Da, Yr)
04/16/2009
YearlPeriod of Report
End of 2008/04
(1) Coes 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 betwn "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Oter: Include gains and losses pertining 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 outfow 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 reoncilation of the
dollar amount of leases capitalized with the plant cost.
(a)
Current Year to Date
OuarterlYear
(b)
Previous Year to Date
OuarterlYear
(c)
Line
No.
Description (See Instruction NO.1 for Explanation of Codes)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (Increase) Decrease in Receivabies
50 Net (Increase) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Acced Expenses
53 Other (provide details in footnote);
54 Changes in other propert and investments
55
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68
69
70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote):
77 Long-term debt and short-term borrowing issuance costs
78 Net Decrease in Short-Term Debt (c)
79 Cash paid for settement of interest rate swap agreements
80 Dividends on Preferred Stock
81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83)
87
88 Cash and Cash Equivalents at Beginning of Period
89
90 Cash and Cash Equivalents at End of period
6,013 17.967
2,006,496 -2,942,625
296,165,000
28.564,671 4,971,331
250,000,000
574,729,671 4,977.331
-401,855.029 -26,156,580
-26,250,000
-5,023,987 -164,700
-4,000,000
-16,395,000
-37,070,823 -31,450,517
4.978,669 8,551,759
FERC FORM NO.1 (ED. 12-96)Page 121
This Report Is:
(1) ~ An Original
(2) D A Resubmission
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilties 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 utilty. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures. respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
04/16/2009 ............................................
Name of Respondent
Avista Corporation
Date of Report Year/Period of Report
End of 2008/Q4
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 122
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 041612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIICANT ACCOUNTING POLICIES
Natre of Business
Avista Corporation (Avista Corp. or the Company) is an energy company engaged in the generation, tranmission and distrbution of
energy as well as other energy-related businesses. A vista Corp. generates, transmits and distrbutes electrcity in par of eastern
Washington and nortern Idaho. In addition, Avista Corp. has electric generating facilties in western Montana and nortern Oregon.
Avista Corp. also provides natual gas distribution service in par of eastern Washington and nortern Idaho, as well as pars of
norteast and southwest Oregon. Avista Capital, Inc. (Avista Capita), a wholly owned subsidiar of Avista Corp., is the parent
company of all of the subsidiar companes in the non-utilty businesses including Avista Energy, Inc. (A vista Energy) and Advantage
IQ, Inc. (Advantage IQ). Avista Energy was an electrcity and natual gas maketing, trading and resource maagement business. On
Jun 30, 2007, Avista Energy completed the sale of substantially all of its contracts and ongoing operations. See Note 3 for fuer
information. Advantage IQ is a provider of facilty information and cost management serces for multi-site customers thoughout
Nort America.
The Company's operations are exposed to risks including, but not limted to:
· global financial and economic conditions (including the availabilty of credit) and their effect on the Company's abilty to obta
funding for working capital and long-term capita requiements on acceptable term,
· economic conditions in the Company's service areas, including the effect on the demand for, and customers' abilty to pay for, the
Company's utility services,
· streamow and weather conditions that impact hydroelectrc generation, utility operations and customer demand,
· maket prices and supply of wholesale energy, which the Company purchases and sells, including power, fuel and natual gas,
· regulatory disallowance of the recovery of power and natual gas costs, operating costs and capita investments and the allowance
of a reasonable rate of retu on investment,
· the effects of changes in legislative and governenta reguations, including restrctions on emissions from generating plants and
requiements for the acquisition of new resources,
· changes in regulatory requiements,
· availabilty of generation facilties,
· rate increases may change customer demad for electricity and natural gas, and
. competition.
Also, like other utilities, the Company's facilties and operations are exposed to natual disasters and 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 Reportng
The financial statements include the assets, liabilties, revenues and expenses of the Company and have been prepared in accordance
with the accounting requirements of the Federal Energy Reguatory Commssion as set fort in its applicable Uniform System of
Accounts and published accounting releases, which is a comprehensive basis of accounting other than accountig principles generally
accepted in the United States of America. As requied by the Federal Energy Reguatory Commssion (FC), the Company accounts
for its investment in majority-ownd subsidiares on the equity method rather than consolidating the assets, liabilties, revenues, and
expenses of these subsidiares, 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 relate operations resultig from its
interests in jointly owned plants. In addition, under the requiements of the FEC, there are differences from accounting principles
generally accepted in the Uniìe States of America in the presentation of (1) curent porton of long-term debt (2) assets and liabilties
for cost of removal of assets, (3) assets held for sale, (4) reguatory assets and liabilties, (5) deferred income taes, and (6)
comprehensive income.
Use of Estiates
The preparation of the financial statements in conformty with accounting principles generally accepted in the Unite States of
America requires maagement to make estimates and assumptions that affect amounts reported in the financial statements. Signficant
estimates include:
IFERC FORM NO.1 (ED. 12-SS) Page 123.1
Page 123.2
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/161209 200804
NOTES TO FINANCIAL STATEMENTS (Continued)
. determning the market value of energy commodity derivative assets and liabilties,
. pension and other postretirement benefit plan obligations,
. contingent liabilties,
. recoverabilty of regulatory assets,
. stock-based compensation, and
. unbiled revenues.
Changes in these estiates and assumptions are considered reasonably possible and may have a material effect on the financial
statements and thus actul results could differ from the amounts report and disclosed herein.
System of Accounts
The accounting records of the Company's utility operations ar mantaed in accordance with the unform systenl of accounts
prescribed by the PERC and adopted by the state regulatory commssions in Washingtn, Idaho, Montana and Oregon.
Regulatin
The Company is subject to state regulation in Washington, Idaho, Montaa and Oregon. The Company is also subject to federal
regulation by the PERC.
Operating Revenues
Operating revenues related to the sale of energy are generaly reorded when service is rendered or energy is delivered to customers.
The determnation of the energy sales to individua customers is base on the reading of their meters, which occurs on a systematic
basis thoughout the month. At the end of each calenda month, the amount of energy delivered to customers since the date of the last
meter reading is estimated and the corresponding unbiled revenue is estited and recorded. Accounts receivable includes unbiled
energy revenues of $84.3 millon (net of $11.4 millon of unbiled receivables sold) as of December 31, 2008 and $16.1 millon (net of
$57.2 millon of unbiled receivables sold) as of December 31, 2007. See Note 6 for informtion relate to the sale of accounts
receivable.
Advertsing Expenses
The Company expenses advertising costs as incured. Advertsing expenses were not a material porton of the Company's operating
expenses in 2008, 2007 and 2006.
Taxes Other Than Income Taxes
Taxes other than income taxes include state excise taes, city occupationa and franchise taes, real and personal property taes and
certain other taxes not based on net income. These taes are generaly based on revenues or the value of propert. Utility related taxes
collecte from customers (prily state excise taes and city utility taes) ar recorded as operating revenue and expense and totaled
$53.9 millon in 2008, $51.0 milion in 2007 and $48.3 millon in 200.
Income Taxes
The Company accounts for income taes under Statement of Finacial Accounting Stadards (SFAS) No. 109, "Accountig for
Income Taxes." Under SFAS No. 109, a deferred tax asset or liabilty is determned based on the enacte ta rates that will be in
effect when the differences between the financial statement caring amounts and ta basis of existing assets and liabilties are
expected to be reported in the Company's income ta retu. The deferred ta expense for the period is equal to the net chage in the
deferred tax asset and liabilty accounts from the beginnng to the end of the period. The effect on deferred taes of a change in ta
rates is recognized in income in the period that includes the enactment date. Deferred ta liabilties and reguatory assets are
established for tax benefits flowed though to customers as prescribed by the respective reguatory commssions.
Stock-Based Compensatin
On Janua 1,2006, the Company adopted SFAS No. 123R, which supersedes APB No. 25 and SFAS No. 123 and their related
implementation guidance. The statement requies that the compensation cost relatig to share-based payment transactions be
recognized in financial statements based on the fai value of the equity or liabilty intrents issued. The Company adopted SF AS
No. 123R using the modified prospective method and, accordingly, financial statement amounts for prior periods presented were not
restated to reflect the fair value method of recognzing compensation expense relatig to share-based payments. See Note 24 for
fuer information.
Earnings Per Common Share
Basic earings per common share is computed by dividing income available for common stock by the weighte average number of
common shares outstanding for the period. Diluted earngs per common share is calculated by dividing income available for common
IFERC FORM NO.1 (ED. 12-88)
............................................'
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 04/1612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued
stock by diluted weighted average common shares outstading durng the period, including common stock equivalent shaes
outstanding using the treasur stock method, unless such shares are anti-dilutive. Common stock equivalent shares include shares
issuable upon exercise of stock options and contingent stock awards. See Note 23 for eargs per common share calculations.
Cash and Cash Equivalents
For the puroses of the Statements of Cash Flows, the Company considers all temporar investments with a maturty of thee months or
less when purchased to be cash equivalents. Cash and cash equivalents include cash deposits from counterpares. See Note 8 for
fuer informtion related to cash deposits from counterpares.
AUowance for Doubtful Accounts
The Company maintains an allowance for doubtf accounts to provide for estiated and potential losses on accounts receivable. . The
Company determnes the allowance for utility and other customer accounts receivable based on historical wrte-offs as compared to
accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certn individual
accounts. The following table presents the activity in the allowance for doubtf accounts durng the yeas ended December 31
(dollars in thousands):
Allowance as of the beginnng of the yea
Additions expensed durng the year
Net deductions
Allowance as of the end of the yea
2008
$2,966
6,336
(3.457)~
207
$2,730
3,078
(2,842)~
200
$3,228
2,888
(3.386)~
Materils and Supplies, Fuel Stock and Natural Gas Stored
Inventories of materials and supplies, fuel stock and natual gas stored are recorded at the lower of cost or maket, prily using the
average cost method.
Utilit Plant in Service
The cost of additions to utilty plant in service, including an allowance for fuds used durng constrction and replacements of unts of
propert and improvements, is capitaized. Costs of depreciable units of propert retied plus costs of removal less salvage are charged
to accumulated depreciation.
Allowance for Funds Used During Constrction
The Allowance for Funds Used Durng Constrction (AFC) represents the cost of both the debt and equity funds used to finance
utilty plant additions durng the constrction period. In accordance with the unform system of accounts prescrbed by reguatory
authorities, AFC is capitaized as a par of the cost of utility plant and the debt related porton is credte curently against tota
interest expense in the Statements of Income. The Company generally is permtted, under established regulatory rate practices, to
recover the capitaized AFC, and a fai retu thereon, though its inclusion in rate base and the provision for depreciation afer the
related utility plant is placed in servce. Cash infow related to AFC generally does not occur until the related utility plant is placed
in service and included in rate base. The effective AFC rate was 8.2 percent in 2008, and 9.11 percent in 2007 and 2006. The
Company's AFC rates do not exceed the maxium allowable rate as determned in accordance with the requiements of reguatory
authorities.
Deprecian
For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing composite rates for utility
plant. Such rates are designed to provide for retiements of propertes at the expiration of their service lives. For utiity operations, the
ratio of depreciation provisions to average depreciable propert was 2.77 percent in 2008,2.89 percent in 2007 and 2.89 percent in
2006.
The average service lives for the following broad categories of utility propert are:
· electric therma production - 32 yeas,
. hydroelectric production - 77 yeas,
. electrc transmission - 49 years,
· electric distribution - 39 years, and
. natual gas distrbution property - 51 years.
IFERC FORM NO.1 (ED. 12-88) Page 123.3
Page 123.4
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Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corpration (2) A Resubmission 0411612009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Regulatory Deferred Charges and Credits
The Company prepares its fmancial statements in accordance with the provisions of SFAS No.7 1, "Accounting for the Effects of
Certin Typs of Regulation." The Company prepares its fiancial statements in accordance with SFAS No. 71 because:
. rates for regulated services are established by or subject to approval by independent third-par regulators,
. the reguated rates are designed to recover th cost of providing the reguted servces, and
. in view of demand for the reguated services and the level of competition, it is reasonable to assume that rates can be chaged
to and collected from customers at levels that wi recover costs.
SF AS No. 71 requies the Company to reflect the impact of reguatory decisions in its financial statements. SF AS No. 71 requires that
certin costs and/or obligations (such as incured power and natual gas costs not curently recovered though rate, but expecte to be
recovered in the futue) 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 durg which matching revenues are recognzed.
If at some point in the futue the Company determnes that it no longer meets the criteria for continue application of SFAS No. 71 for
all or a porton of its reguated operations, the Company could be:
. requied to wrte off its reguatory assets, and
. precluded from the futue deferral of costs not recovered though rates at the time such costs are incured, even if the
Company expeted to recover such costs in the futue.
The Company's primar regulatory assets include:
. power and natural gas deferrals,
. investment in exchange power,
. regulatory asset for deferred income taes,
. unamortzed debt expense,
. assets offsetting net utility energy commodity derivative liabilties (see Note 7 for fuer informtion),
. expenditues for demand side maagement program,
. expenditues for conservation program,
. payments to the Coeur d Alene Tribe for past water storage, and
. unded pensions and other postretiement benefits.
Regulatory liabilties include:
. natural gas deferrals, and
. liabilties offsetting net utility energy commodity derivative assets (see Note 7 for fuer information).
Investment in Exchange Power-Net
The investment in exchange power represents the Company's previous investment in Washington Public Power Supply System Project
3 (WN-3), a nuclear project that was termnated prior to completion. Under a settlement agreement with the Bonnevile Power
Administration in 1985, Avista Corp. began receiving power in 1987, for a 32.5-year period, related to its investment in WN-3.
Through a settement agreement with the Washington Utilities and Tranporttion Commssion (WUTC) in the Washington
jurisdiction, A vista Corp. is amortzing the recoverable porton of its investment in WN-3 (recorded as investment in exchange
power) over a 32.5 year period beginnng in 1987. For the Idaho jursdiction, Avista Corp. fuy amorted the recoverable porton of
its investment in exchange power.
Unamortzed Debt Expense
Unamortzed debt expense includes debt issuance costs that are amortzed over the life of the related debt, as well as premium paid to
repurchase debt. For the Company's primay reguatory jursdiction and for any debt repurchases beginnng in 2007 in all
jurisdictions, premium paid to repurchase debt are amortized over the remaning life of the original debt that was repurchased or, if
new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. In the Company's other
regulatory jursdictions, premium paid to repurchase debt prior to 2007 are being amortzed over the average remaining maturty of
outstading debt when no new debt was issued in connection with the debt repurchase. These costs are recovered though retal rates
as a component of interest expense.
Power Cost Deferrals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge on the Balance Sheets for futue review and recovery though reta
IFERC FORM NO.1 (ED. 12-88)
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corpration (2) A Resubmission 0411612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
rates. The power supply costs deferred include certn differences between actual net power supply costs incurd by A vista Corp. and
the costs included in base retail rates. This difference in net power supply costs prily results from changes in:
· short-term wholesale market prices and sales and purchase volumes,
. the level of hydroelectric generation,
· the level of thermal generation (including changes in fuel prices), and
. retail loads.
In Washington, the Energy Recovery Mechanism (ERM) allows A vista Corp. to penodcally increase or decrease electrc rates
periodically with WUTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certn
differences between actual net power supply costs and the amount included in base retail rates for Washington customers. Avista
Corp. accrues interest on deferred power costs in the Washington jursdiction at a rate, which is adjusted semi-annually, of 6.7 percent
as of December 31, 2008.
The initial amount of power supply costs in excess or below the level in retal rates, which the Company either incurs the cost of, or
receives the benefit from, is referred to as the deadband. The anual (calendar year) deadband amount is curently $4.0 millon. The
Company wil incur the cost of, or receive the benefit from, 100 percent of ths initial power supply cost varance. The Company
shares annual power supply cost varances between $4.0 millon and $10.0 millon with its customers. Through December 31, 2008,
50 percent of the annual power supply cost variance in this range was deferred for future surcharge or rebate to customers and the
Company incur the cost of, or receives the benefit from, the remaning 50 percent. To the extent that the anual power supply cost
varance from the amount included in base rates excee $10.0 millon, 90 percent of the cost varance is deferred for future surcharge
or rebate. The Company incurs the cost of, or receives the benefit from, the remaning 10 percent of the anua varance beyond $10.0
millon without affecting curent or futue customer rates. The following is a sum of the ERM (thugh December 31, 2008):
Deferred for Futue
Surcharge or Rebate
to Customers
0%
50%
90%
Annual Power Supply
Cost Variabilty
+/- $0 - $4 millon
+/- between $4 millon - $10 millon
+/- excess over $10 millon
Expense or Benefit
to the Company
100%
50%
10%
Effective Janua 1,2009, the ERM was adjusted for the sharng level for the anual power supply cost varance in the $4.0 millon to
$10.0 millon band. The adjustment resulted in a 75 percent customers/25 percent Company sharng when actu power supply
expenses are lower (rebate to customers) than the amount included in base retal rates withn this band. The 50 percent customers/50
percent Company sharng was mantained when actua power supply expenses ar higher (surcharge to customers) than the amount
included in base retal rates withn ths band. The following is a sum of the revised ER:
Anual Power Supply
Cost Varabilty
+/- $0 - $4 millon
+ between $4 millon - $10 millon
- between $4 millon - $10 millon
+/- excess over $10 millon
Deferred for Futue
Surcharge or Rebate
to Customers
0%
50%
75%
90%
Expense or Benefit
to the Company
100%
50%
25%
10%
Avista Corp. has a power cost adjustment (PCA) mechansm in Idaho that allows it to modify electrc rates on October 1 of each year
with Idaho Public Utilities Commssion (IPUC) approvaL. Under the PCA mechanism, A vista Corp. defers 90 percent of the difference
between certin actul net power supply expenses and the amount included in base retal rates for its Idaho customers. In June 2007,
the IPUC approved continuation of the PCA mechanism with an anual rate adjustment provision. These annual October 1 rate
adjustments recover or rebate power costs deferred durg the precding July-June twelve-month penod. Avista Corp. accrues interest
on deferred power costs in the Idaho jurisdiction at a rate, which is adjusted anually, of 5.0 percent as of Decmber 31, 2008.
The following table shows activity in deferred power costs for Washington and Idaho during 2006, 2007 and 2008 (dollars in
thousands):
IFERC FORM NO.1 (ED. 12-88)
Washingtn
Page 123.5
Idaho Total
Effective December 31, 2006, SF AS No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretiement Plans -
an amendment of F ASB Statements No. 87, 88, 106, and 132 (R)" requied the Company to recognze the overfded or underfded
status of defined benefit postretiement plan in the Company's Balance Sheet measured as the difference between the fai value of
plan assets and the benefit obligation. For a pension plan, the benefit obligation is the projected benefit obligation; for any other
postretirement benefit plans, the benefit obligation is the accumulated postretiement benefit obligation. Previously, the Company only
recognzed the underfuded status of defined benefit pension plans as the difference between the fai value of plan assets and the
accumulated benefit obligation. As the Company has historically recovered and curently recovers its pension and other postretiement
benefit costs related to its reguated operations in retal rates, the Company records a reguatory asset for that porton of its pension and
other postretiement benefit fuding deficiency. As such, the underfded status of the Company's pension and other postretiement
benefit plans under SFAS No. 158 resulted in the recogntion as of December 31, 2006 of:
IFERC FORM NO.1 (ED. 12-88) Page 123.6
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corpration I (2) A Resubmission 0411612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
Deferred power costs as of December 31, 2005 $96,191 $7,987 $104,178
Activity from Janua 1 - Decembe 31, 2006:
Power costs deferred 5,718 5,718
Interest and other net additions 4,291 300 4,591
Recovery of deferred power costs though retal rates (30,323)(4,648)(34,971)
Deferred power costs as of December 31, 2006 $70,159 $9,357 $79,516
Activity from Janua 1- December 31, 2007:
Power costs deferred $16,344 $16,750 $33,094
Interest and other net additions 3,023 788 3,811
Recovery of deferred power costs though retail rates (31,002)(5,732)(36,734)
Deferred power costs as of December 31, 2007 58,524 21,163 79,687
Activity from Januar 1 - December 31, 2008:
Power costs deferred 7,049 10,029 17,078
Interest and other net additions 2,231 1,153 3,384
Recovery of deferred power costs though retal rates (30,852)01,690)(42,542)
Deferred power costs as of December 31, 2008 $36,952 $20,655 $57,607
Unrecovered Purchased Gas Costs and Recovery Mechanims
Avista Corp. fies a purchased gas cost adjUSbnent (pGA) in al thee states it serves to adjust natual gas rates for: 1) estited
commodity and pipeline tranporttion costs to serve natual gas customers for the coming year, and 2) the difference between actua
and estimated commodity and transportation costs for the prior yea. These anual PGA filings in Washington and Idaho provide for
the deferral, and recovery or refud, of 100 percent of the differenc between actu and estited commodity and pipeline
transporttion costs for the prior year, subject to applicable reguatory review. The anua PGA filing in Oregon provides for deferral,
and recovery or refud, of 100 percent of the difference between actul and estite pipeline tranporttion costs and commodity
costs that are fixed though hedge transactions. Commodty costs that are not hedged for Oregon customers are subject to a sharng
mechanism whereby A vista Corp. defers, and recovers or refuds, 90 percent of the difference between these actul and estited
costs.
NOTE 2. NEW ACCOUNTING STANDARDS
Effective Janua 1,2008, the Company adopted the provisions of SFAS No. 157, "Fair Value Measurements" related to its financial
assets and liabilties and nonfnancial assets and liabilties measured at fai value on a recurng basis. In Febru 2008, the F ASB
issued Staff Position No. 157-2, which deferred the effective date for certn portons of SFAS No. 157 related to nonrecuring
measurements of nonfinancial assets and liabilties. The Company will be requied to adopt those provisions of SF AS No. 157 in
200. The adoption of the provisions of SFAS No. 157 that became effective on Janua 1,2008, did not have a material impact on
the Company's financial condition and results of operations. However, the Company expanded disclosures with respect to fair value
measurements. See Note 21 for the expanded disclosures.
Effective Janua 1,2008, the Company adopted SFAS No. 159, "The Fai Value Option for Financial Assets and Financial
Liabilties." This statement permts entities to choose to measure may financial assets and finacial liabilties at fai value.
Unrealized gains and losses on items for which the fai value option is electe would be reported in net income. The Company did not
elect to use the fair value option under SFAS No. 159 for any financial assets and liabilties at implementation and as such the adoption
of SFAS No. 159 did not have any material impact on its financial condition and results of operations.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 0411612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
· a liabilty of $60. 1 millon (associate deferred taes of $21.0 millon) for pensions and other postretiement benefits,
. a reguatory asset of $54.2 millon (associated deferred taes of $19.0 millon) for pensions and other postretiement benefits,
· an increase to accumulated other comprehensive loss of $3.7 millon (net of taxes of $2.1 millon), and
· the removal of the intagible pension asset of $3.7 millon (was included in other deferred charges).
As such, the total effect on the deferred income tax liabilty for the adoption of SFAS No. 158 was a net decrease of $2.1 millon. The
adoption of this statement did not have any effect on the Company's net income.
In December 2007, the FASB issued SFAS No. 141(R), "Business Combinations." This statement replaces SFAS No. 141 and
addresses the accounting for all transactions or other events in which an entity obtans control of one or more businesses. This
statement requies the acquiring entity in a business combination to recognize the assets acquied, the liabilties assumed, and any
noncontrolling interest in the transaction at the acquisition date, measured at their fair values as of that date, with limted exceptions.
The Company wil be requied to begin applying this statement to any business combinations in 200.
In December 2007, the FASB issued SFAS No. 160, "Noncontrollng Interests in Consolidated Finacial Statements." This statement
amends Accounting Research Bulletin No. 51, "Consolidated Financial Statements," to establish accounting and reportg stadards
for noncontrollng (minority) interest in a subsidiar and for the deconsolidation of a subsidiar. This statement clarfies that a
noncontrolling interest in a subsidiar is an ownership in the consolidated entity that should be reported as equity in the consolidated
financial statements. The Company wil be requied to adopt SFAS No. 160 in 2009. The Company does not expect the adoption of
SFAS No. 160 to have any material impact on its financial condition and results of operations. The Company is still in the process of
evaluating the full impact SFAS No. 160 will have on its financial statements.
In March 2008, the FASB issued SFAS No. 161, "Disclosures about Derivative Instrents and Hedging Activities." This statement
wil require disclosure of the fair value of derivative instrents and their gains and losses in a tabular formt. The statement will also
require disclosure of derivative featues that are relate to credit risk. The Company will be requied to adopt SFAS No. 161 in 200.
The Company wil have expanded disclosures with respect to derivatives and hedging activities.
In December 2008, the FASB issued FSP FAS 132(R)-1, ''Employers' Disclosures about Postretiement Benefit Plan Assets". Ths
FSP amends FASB statement No. 132(R) ''Employer's Disclosures about Pensions and Other Postretiement Benefits." Th statement
provides guidance on an employer's disclosures about plan assets of a defined benefit pension or other postretiement plan. The
Company wil be requied to adopt FSP FAS 132(R)-1 at the end of 200. The Company will have expanded disclosures with respect
to its pension and other postretirement benefit plan assets.
NOTE 3. DISPOSITION OF A VISTA ENERGY
On June 30, 2007, Avista Energy and Avista Energy Canada completed the sale of substatially all of their contracts an ongoing
operations to Shell Energy Nort America (U.S.), L.P. (Shell Energy), formerly known as Coral Energy Holding, L.P., as well as to
certn other subsidiaries of Shell Energy. Proceeds from the transaction included cash consideration for the net assets acquied by
Shell Energy and the liquidation of the remaining net curent assets of Avista Energy not sold to Shell Energy (prily reeivables,
restrcted cash and deposits with counterpares).
Certin assets of Avista Energy with a net book value of approximtely $30 millon were not sold or liquidated. These primaly
include natural gas storage and deferred tax assets. The Company expects that the natural gas storage will ultimately be transferred to
Avista Corp., subject to futue reguatory approval. Avista Energy also has a power purchase agreement, relate to a 270 MW natual
gas-fired combined cycle combustion turbine plant located in Idaho (Lancaster Plant). The Lancaster Plant is owned by an unelated
third-pary and all of the output from the plant is contracted to A vista Energy though 2026. The majority of the rights and obligations
of the power purchase agreement were assigned to Shell Energy though the end of 200. The Company expects that the power
purchase agreement for the period 2010 though 2026 wil be transferred to Avista Corp., subject to futue reguatory approval,
In connection with the transaction, on June 30, 2007, A vista Energy and its affliate entered into an Indemnfication Agreement with
Shell Energy and its affilates. Under the Indemnfication Agreement, Avista Energy and Shell Energy each agree to provide
indemnfication of the other and the other's affliates for certn events and mattrs described in the purchase and sale agreement and
certn other transaction agreements. Such events and matters include, but are not limted to, the refud proceedings arsing out of the
western energy markets in 2000 and 2001 (see Note 25), existing litigation, ta liabilties, matters with respect to natual gas storage
rights, and any potential issues associated with the power purchase agreement for the Lacaster Plant. In general, such indemnfication
IFERC FORM NO.1 (ED. 12-88) Page 123.7
Page 123.8
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corpration (2) A Resubmission 041612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued
is not requied unless and until a par's claim excee $150,00 and is limte to an aggregate amount of $30 millon and a term of
thee years (except for agreements or tranactions with term longer than thee years). These litations do not apply to certn third
pary claims.
Avista Energy's obligations under the Indemnfication Agreement are guante by Avista Capital pursuant to a Guaanty dated June
30, 2007. This Guaanty is limted to an aggregate amount of $30 millon plus certn fees and expenses. The Guaranty will termnate
April 30, 2011 except with respect to claim made pnor to termnation.
As of Februar 27, 2009, neither par has made any claims under the Indemnfication Agreement or Guaranty.
NOTE 4. IMPAIRMENT OF ASSETS
During the third quarer of 2007, the Company recorded an impairent charge of $2.3 millon for a turbine and related equipment.
The Company onginally planned to use the tubine in a reguate utlity generation project. At the end of the thd quaer of 2007, the
Company reached a conclusion to sell the tubine and related equipment, which were classified as assets held for sale as of December
31, 2007, and included in other curent assets on the Balance Sheet. The imaient charge reduced the carng value of the assets to
the estimated fai value. The tubine was sold in 2008.
Pursuant to a settlement agreement in its Washingtn general rate cas enteed into in October 2007 and approved by the WUTC in
December 2007, A vista Corp. agreed to wrte off $3.8 millon of unortzed debt repurchase costs. These costs were for premium
paid to repurchase debt prior to its scheduled maturty. In accordace with reguatory accountig practices, these premium were
recorded as a regulatory asset in unamortzed loss on reacqui debt on the Balance Sheet and were being amorted over the average
remaining maturty of outstading debt.
NOTE 5. ADVANTAGE IQ ACQUISITION
Effective July 2, 2008, Advantage IQ complete the acquisition of Cadence Network, a privately held, Cincinnati-based energy and
expense management company. As consideration, the owners of Cadence Network received a 25 percent ownership interest in
Advantage IQ. The total value of the tranaction was $37 milion.
The acquisition of Cadence Network was fuded with the issuace of Advantage IQ common stock. Under the transaction agreement,
the previous owners of Cadence Network can exercise a nght to reeem their shares of Advantage IQ common stock durng July 2011
or July 2012 if Advantage IQ is not liquidated though either an intial public offerng or sale of the business to a thd pary. Their
redemption rights expire July 31, 2012. The redemption pnce would be determned based on the fai maket value of Advantage IQ at
the time of the redemption election as determed by cern independent pares.
NOTE 6. ACCOUNTS RECEIVABLE SALE
Avista Receivables Corporation (ARC) is a wholly owned, banptcy-remote subsidiar of Avista Corp. formed for the purose of
acquiing or purchasing interests in certin accounts receivable, both biled and unbiled, of the Company. On March 14,2008, Avista
Corp., ARC and a thd-par financial institution amended a Receivables Purchase Agreement. The most signficant amendment
extended the termnation date to March 13, 2009. Under the Receivables Puchase Agreement, ARC can sell without recourse, on a
revolving basis, up to $85.0 millon of those receivables. ARC is obligate to pay fees that approxite the purchaser's cost of issuing
commercial paper equa in value to the interests in receivables sold. The amount of such fees is included in other operating expenses
of Avista Corp. The Receivables Puchase Agreement has finacial covenats, which are substatially the same as those of Avista
Corp.'s commtted lines of credit (see Note 14). At each of Decmber 31, 2008 and 2007, ARC had the abilty to sell up to $85.0
millon of receivables under this revolving agreement. There was $17.0 milion in accounts receivable sold as of December 31,2008
and $85.0 millon in accounts receivable sold as of December 31, 2007 under this revolving agreement.
NOTE 7. ENERGY COMMODITY DERIVATIVE AND RISK MANAGEMENT
Avista Corp. is exposed to risks relating to changes in certin commodity prices. Avista Corp. utilizes denvative instrents, such as
forwards, futures, swaps and options in order to maage the varous nsks relating to these commodity pnce exposures. The Company
has an energy resources risk policy and control procedures to maage these risks, both qualitative and quantitative. The Company's
Risk Management Commttee establishes the Company's energy resources nsk policy and monitors compliance. The Risk
Management Commttee is compnsed of certn Company offcers and other management. The Audit Commttee of the Company's
Board of Directors periodically reviews and discusses nsk assessment and risk maagement policies, including the Company's material
IFERC FORM NO.1 (ED. 12-88)
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation .(2)A Resubmission 041612009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
financial and accounting risk exposures and the steps management has undertaken to control them.
Avista Corp. engages in an ongoing process of resource optimization, which involves the economic selection from available energy
resources to serve A vista Corp.' s load obligations and using these resources to captue available economic value. A vista Corp. sells
and purchases wholesale electrc capacity and energy and fuel as par of the process of acquing resources to serve its load
obligations. These transactions range from terms of one hour up to multiple years.
Avista Corp. maes continuing projections of:
;, electrc loads at various points in time (ranging from one hour to multiple years) based on, among other things, estites of
factors such as customer usage and weather, as well as historical data and contract term, and
· resource availabilty at these points in tie based on, among other thngs, fuel choices and fuel makets, estimates of streaows,
availabilty of generating units, historic and forward maket informtion, contract term, and experience.
On the basis of these projections, Avista Corp. maes purchases and sales of energy to match expected resources to expecte electrc
load requirements. Resource optimization involves generating plant dispatch and scheduling available resources and also includes
transactions such as:
. purchasing fuel for generation,
. when economic, sellng fuel and substitutig wholesale purchases for the operation of Avista Corp.'s resources, and
. other wholesale transactions to captue the value of generation and tranmission resources.
Avista Corp.'s optimization process includes enterng into hedging transactions to maage risks.
As par of its resource optimization process described above, A vista Corp. manages the impact of fluctutions in electrc energy prices
by measurng and controllng the volume of energy imbalance between projected loads and resources and though the use of derivative
commodity instrents for hedging purses. Load/resource imbalances within a planng horizon up to 36 months ahead are
compared against established volumetrc gudelines. Management determnes the ting and actions to manage these energy
imbalances. Mangement also assesses available resource decisions and actions that are appropriate for longer-term planng periods.
Avista Corp. makes continuing projections of its natual gas loads and assesses available natual gas resources. Forward natual gas
contracts are typically for monthy delivery periods. However, daily varations in natural gas demad can be significantly different
than monthly demand projections. On the basis of these projections, Avista Corp. plans and executes a series of tranactions to hedge
a signficant porton of its projected natural gas requiements though forward market tranactions and derivative instrents. These
transactions may extend as much as four years into the futue with the highest volumes hedged for the curent and most imdiately
upcoming gas operating year (November though October). Avista Corp. also purchases a signficant porton of its gas supply
requirements in short-term and spot makets. Natual gas resource optimization activities include:
. wholesale market sales of surlus gas supplies,
· purchases and sales of natual gas to use under utilized pipeline capacity, and
. sales of excess natual gas storage capacity.
Avista Corp. enters into forward contracts to purchase or sell electrcity and natual gas. Under these forward contracts, Avista Corp.
commts to purchase or sell a specified amount of energy at a specified time, or durng a specified period, in the futue. Certin of
these forward contracts are considered derivative instrents. Avista Corp. also records derivative commodity assets and liabilties
for over-the-counter and exchange-traded derivative instrents as well as certin long-term contracts.
SFAS No. 133, as amended, establishes accounting and reportng standards for derivative instrents, including certn derivative
instruments embedded in other contracts, and for hedging activities. It requies the recording of all derivatives as either assets or
liabilties. on the balance sheet measured at estimated fai value and the recogntion of the unealized gains and losses. In cerain
defined conditions, a derivative may be specifically designated as a hedge for a paricular exposure. The accounting for derivatives
depends on the intended use of the derivatives and the resulting designation.
In conjunction with the provisions of SFAS No. 133, the WUC and the IPUC issued accounting orders authoriing Avista Corp. to
offset any derivative assets or liabilties with a reguatory asset or liabilty. This accountig treatment is intended to defer the
recogntion of mak-to-maket gains and losses on energy commodity transactions until the period of settement. The orders provide
for Avista Corp. to not recognze the unrealized gain or loss on utility derivative commodity instrents in the Statements of Income.
Realized gains or losses are recognied in the eriod of settlement, subject to a roval for recovery thou retal rates. Reaize
FERC FORM NO.1 ED. 12-88 Page 123.9
Page 123.10
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 0411612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
gains and losses, subject to regulatory approval, result in anua adjustments to retal rate though purchased gas cost adjustments, the
ER and the PCA mechasm.
Substantially all forward contracts to purchase or sell power and natu gas ar recorded as assets or liabilties at maket value with an
offsettng regulatory asset or liabilty. 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 fai value of the contract that is determned to be other than
temporar.
Market Risk
Market risk is, in general, the risk of fluctution in the maket price of the commodty being traded and is infuenced priarly by
supply and demad. Market risk includes the fluctuation in the maket price of associated derivative commodity instrents. Market
risk may also be infuenced to the extent that nonperformce by market parcipants of their contractua obligations and commtments
affects the supply of, or demad for, the commodity.
Credit Risk
Credit risk relates to the potential losses that the Company would incur as a result of non-peormce by counterpares of their
contractual obligations to deliver energy or mae financial settements. The Company often extends credit to counterpares and
customers and is exposed to the risk that they may not be able to collect amounts owed to them. Changes in maket prices may
dramatically alter the size of credit risk with counterpares, even when consrvative credit limits are established. Credit risk includes
potential counterpar default due to circumtaces:
· relating directly to it,
· caused by maket price changes, and
· relating to other market parcipants that have a direct or indit relationship with such counterpar.
Should a counterpary, customer or supplier fail to perform the Company may be requied to honor the underlying commtment or to
replace existing contracts with contracts at then-curent maket prices. The Company seeks to mitigate credit risk by:
· entering into bilateral contracts that specify credt term and protetions agaist default,
· applying credit limits and duration criteria to existing and prospective counteares, and
· actively monitoring curent credit exposures, and
· conducting some of its transactions on exchanges with clearng arangements that essentially eliminate counterpar default risk.
These credit policies include an evaluation of the financial condition and credt ratings of counterparties, collateral requiements or
other credit enhancements, such as letters of credt or parent company guantees. The Company also uses stadardized agreements
that allow for the netting or offsetting of positive and negative exposures associate with a single counterpar or affliated group.
The Company has concentrations of suppliers and customers in the electrc and natual gas industres including:
. electrc utilities,
. electrc generators and transmission providers,
· natural gas producers and pipelines,
. financial institutions,.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 counterpares and concentrations of geographic location may impact the Company's overal
exposure to credit risk, either positively or negatively, because the countearies may be similarly affected by changes in conditions.
Credit risk also involves the exposure that counterpares pereive relate to the abilty of the Company to perform deliveries and
settlement under physical and financial energy contracts. These counterpares may sek assurances of performce in the form of
lettrs of credit, prepayment, or cash deposits.
In periods of price volatility, the level of exposure can change signficantly. As a result, sudden and signficant demads may be made
agaist the Company's credit facilties and cash. The Company actively monitors the exposure to possible collateral cals and taes
steps to minimize capital requiements.
Other Operatonal and Event Risks
IFERC FORM NO.1 (ED. 12-SS)
.............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 041161209 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
In addition to maket and credit risk, the Company is subject to operationa and event risks including, among others:
· blackouts or disruptions to distribution, transmission or transporttion systems,
· forced outages at generating plants,
. fuel quality and availabilty,
· disruptions to informtion systems and other administrative resources requied for norm operations, and
· weather conditions and natural disasters that can cause physical damge to propert, requing repairs to restore utility service.
Terrorism and other macious theats are a risk to the entire utility industr. Potential disruptions to operations or destrction of
facilties from terrorism or other maicious acts are not readily detenable. The Company has taen various steps to mitigate
terrorism risks and prepare contingency plan in the event that its facilties are tageted.
NOTE 8. CASH DEPOSITS FROM COUNTERPARTIES
As is common industr practice, A vista Corp. maintains magin agreements with certn counterpares. Margin calls are trggered
when exposurs exceed predetermned contractual limits or when there are changes in a counterpar's creditwortess. Price
movements in electrcity and natual gas can generate exposure levels in excess of these contractul limits. From tie to tie, margin
calls are made and/or received by A vista Corp. Negotiating for collateral in the form of cash, letters of credit, or performane
guarantees is common industr practice.
Cash deposits from counterpares totaed $0.2 millon as of December 31, 2008 and $12.5 millon as of December 31, 2007. These
funds were held by Avista Corp. to mitigate the potential impact of counterpar default risk. These amounts are subject to retu if
conditions warant becaus of continuing portolio value fluctuations with those pares or substitution of non-cash collateral.
NOTE 9. JOINTLY OWND ELECTRIC FACILITIES
The Company has a 15 percent ownership interest in a twin-unt coal-fired generating facilty, the Colstrp Generating Project
(Colstrp) 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 Colstrp was $330.9 millon and accumulated depreciation was $204.0
millon as of December 31, 2008.
NOTE 10. ASSET RETIREMENT OBLIGATIONS
The Company follows SFAS No. 143, "Accounting for Asset Retiement Obligations," and records the fai value of a liabilty for an
asset retirement obligation in the period in which it is incured. When the liabilty is initially recorded, the associate costs of the asset
retiement obligation are capitalized as par of the carng amount of the related long-lived asset. The liabilty is accreted to its
present value each period and the related capitaized costs are depreciated over the usefu life of the related asset. Upon retiement of
the asset, the Company either settles the retiement obligation for its recorded amount or incurs a gain or loss. The Company records '
regulatory assets and liabilties for the difference between asset retiement costs curently recovered in rates and asset retiment
obligations recorded since asset retirement costs are recovered though rates charged to customers. The reguatory assets do not ea a
retur.
Speifically, the Company has recorded liabilties for futue asset retiement obligations to:
. restore ponds at Colstrp,
· cap a landfill at the Kettle Falls Plant,
· remove plant and restore the land at the Coyote Springs 2 site at the termation of the land lease,
· remove asbestos at the corprate offce building, and
· dispose of PCBs in certin transformers.
Due to an inabilty to estimate a range of settlement dates, the Company cannot estimate a liabilty for the:
· removal and disposal of certin tranmission and distribution assets, and
· abandonment and decommssioning of certn hydroelectrc generation and natual gas storage facilties.
The following table documents the changes in the Company's asset retiement obligation durng the years ended December 31 (dollars
IFERC FORM NO.1 (ED. 12-88) Page 123.11 I
Asset retirement obligation at beginnig of yea
New liabilty recognized
Liabilty adjustment due to revision in estited cash flows
Liabilty setted
Accretion expense
Asset retirement obligation at end of year
2008
$3,990
2007
$4,810
2006
$4,529
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corpration (2) A Resubmission 0416/209 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
in thousands):
(29)
247~(1,063)
(71)
314~(51)
332~
NOTE 11. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a defined benefit pension plan covering substatially all reguar ful-tie employees at A vista Corp. Individual
benefits under ths plan are based upon the employee's yeas of service and average compensation as specified in the plan. The
Company's fuding policy is to contrbute at least the minium amounts that are requied to be fuded under the Employee Retirement
Income Security Act, but not more than the maum amounts that are curntly deductible for income tax puroses. The Company
contributed $28 millon in cash to the pension plan in 2008 and $15 milion each of 2007 and 2006. The Company expects to
contribute $48 millon to the pension plan in 200.
The Company also has a Supplementa Executive Retiment Plan (SER) that provides additiona pension benefits to executive
offcers of the Company. The SER is intended to provide benefits to executive offcers whose benefits under the pension plan are
reduced due to the application of Section 415 of the Inte Revenue Code of 1986 and the deferral of salar under deferred
compensation plans. The liabilty and expense for this plan are included as pension benefits in the tables included in ths Note.
The Company expects that benefit payments under the pension plan and the SER will tota $17.5 millon in 2009, $18.1 millon in
2010, $19.0 millon in 2011, $20.0 millon in 2012 and $21.2 milion in 2013. For the ensuing five years (2014 though 2018), the
Company expects that benefit payments under the pension plan and the SERP will tota $127.0 millon.
The Finance Commttee of the Company's Board of Directors:
· establishes investment policies, objectives an strategies that seek an appropriate retu for the pension plan, and
· reviews and approves changes to the investmnt and funding policies.
The Company has contracted with an investment consultat who is responsible for maaging/monitoring the individual investment
managers. The investment maagers' performce and relate individua fud performance is periodically reviewed by an internal
benefits commttee and by the Finace Commttee to monitor compliance with investment policy objectives and strategies. Pension
plan assets are investe primly in maketable debt and equity securties. Pension plan assets may also be Iiveste in real estate,
absolute retu, venture capitaprivate equity and commodity funds. In seeking to obtain the desired retu to fud the pension plan
the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the intern
benefits commttee, which then recommends their adoption by the Finance Commttee. The Finance Commttee has established
investment allocation percentages by asset classes as indicated in the table in ths Note.
The expeted long-term rate of retur on plan assets is based on past performce and economic forecasts for the tyes of investments
held by the plan. The market-related value of pension plan assets invested in debt and equity securties was based priy on fair
value (maket prices).
The market-related value of pension plan assets invested in real estate was determned based on thee basic approaches:
· curent cost of reproducing a propert less deterioration and fuctional economic obsolescence,
· capitalization of the propert's net earings power, and
· value indicated by recent sales of comparable propertes in the maket.
The maket-related value of plan assets was determned as of December 31, 2008 and 2007.
In selecting a discount rate, the Company considers yield rates for highly rate corprate bond portolios with matuties simlar to that
of the expected term of pension benefits.
In 2008, the rates at which parcipants are assumed to retire by age were analyzed based upon historical trends and future projections.
The Company revised the rates to assume that a greater percentage of parcipants would retie between the ages of 55 and 65. The
assumed rates were revise to range from 5 percent to 40 percent and 100 percent at age 65. The previous rates ranged from 2 percent
IFERC FORM NO.1 (ED. 12-SS) Page 123.12 I
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/1612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
to 30 percent and 100 percent at age 65. The change resulted in an increase of $1 1.0 millon to the pension benefit obligation as of
December 31, 2008. The change will also increase futue years' pension costs.
The Company provides cert heath care and life insurance benefits for substatially all of its retied employees. The Company
accrues the estited cost of postretiement benefit obligations durng the years that employee provide servces. The Company
elected to amortze the transition obligation of $34.5 millon over a period of twenty yeas, beginnng in 1993.
The Company established a Health Reimbursement Arangement to provide employees with tax-advantaged fuds to pay for allowable
medical expenses upon retirement. The amount eared by the employee is fixed on the retiement date based on employees' years of
service and the ending salar. The liabilty and expense of ths plan are included as other postretiement benefits.
The Company provides death benefits to beneficiaries of executive officers who die durng their term of offce or aftr retiement.
Under the plan, an executive offcer's designated beneficiar will receive a payment equal to twice the executive offcer's annual base
salar at the time of death (or if death occurs after retiement, a payment equal to twice the executive offcer's tota anua pension
benefit). The liabilty and expense for ths plan are included as other postretiement benefits. Effective December 31, 2007, ths plan
was amended to eliminate a provision that allowed an executive offcer to elect for their beneficiares to receive one quarr of such
payment each year over a ten-year period commencing withn 30 days of the executive offcer's death. The plan was also amended to
provide that those who beome executive offcers after December 31, 2007 will no longer be eligible to receive benefits after
retiement. The amendments to the plan reduced the benefit obligation by $1.6 millon as of December 31, 2007.
The Company expects that benefit payments under other postretirement benefit plans wil be $4.0 millon in 200, $3.8 millon in
2010, $3.7 millon in 2011, $3.6 millon in 2012 and $3.6 millon in 2013. For the ensuig five years (2014 though 2018), the
Company expects that benefit payments under other postretiement benefit plans will tota $16.6 millon. The Company expects to
contribute $4.0 millon to other postretiement benefit plan in 2009, representing expected benefit payments to be paid durng the
year.
The Company uses a December 31 measurement date for its pension and other postretiement plans. The following table sets fort the
pension and other postretiement plan disclosures as of December 31, 2008 and 2007 and the components of net periodic benefit costs
for the years ended December 31, 2008, 2007 and 2006 (dollar in thousands):
Oter Post-
Pension Benefits retiement Benefits
2008 2007 20082007
Change in benefit obligation:
Benefit obligation as of beginning of year $323,090 $315,691 $34,352 $33,632
Service cost 10,209 10,694 772 672
Interest cost 20,812 19,161 2,371 2,159
Plan amendment (1,601)
Actuaral loss (gain)17,041 (5,245)5,611 2,612
Tranfer of accred vacation 365 585
Benefits paid (17,580)(16,912)(4,518)(3,707)
Expenses paid (299)----
Benefit obligation as of end of year $353,572 $323,090 $38,953 $34352
Change in plan asets:
Fai value of plan assets as of beginnng of year $242,561 $225,079 $22,718 $20,878
Actul retur on plan assets (63,575)18,799 (6,670)1,840
Employer contrbutions 28,000 15,000
Benefits paid (16,349)(16,018)
Expenses paid (299)----
Fair value of plan assets as of end of year $190,637 $242,561 $16,048 $22,718
Funded statu $(162,935)$(80,529)$(22,905)$(11,634)
Unrecognize net actual loss 160,280 62,174 18,357 4,472
Unrecognized prior servce cost 2,444 3,098 (1,452)(1,600)
IFERC FORM NO.1 (ED. 12-88) Page 123.13
2,021 2,526
(3,979)(6,236)
(18,926)(5,398)
$(22,905)$(11,634)
$18,821 $18,572
$8,903 $9,675
$11,229 $6,105
$1,313 $1,642
(943)(1,040)
11.932 2,907
12,302 3,509
(13,131)(4.594)~$(1085)
51%62%
49%38%
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 041612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
Unrecognized net transition obligation
Accrued benefit cost
Additional liabilty
Accrued benefit liabilty
Accumulated pension benefit obligation
Accumulated postretirement benefit obligation:
For retirees
For fully eligible employees
For other paricipants
Included in accumulted comprehensive los (income) (net of ta):
Unrecognized net tranition obligation $ $Unrecognized prior service cost 1,589 2,013Unrecognized net actuial loss 104,182 40,414Tota 105,771 42,427Less regulatory asset (98,850) (28.560)
Accumulated other comprehensive loss (income) ~ $13,867
Weighted-average asset allocations as of December 31:Equity securities 48%Debt securties 32%Real estate 6%Absolute return 11 %Oth~ 3%
Target aset alocations as of December 31:
Equity securties
Debt seurties
Real estate
Absolute retu
Other
Weighted average asmptions as of December 31:
Discount rate for benefit obligation
Discount rate for annual expense
Expected long-term retu on plan assets
Rate of compensation increase
Medical cost trend pre-age 65 - initial
Medical cost trend pre-age 65 - ultite
Ultimate medical cost trend year pre-age 65
Medical cost trend post-age 65 - initial
Medcal cost trend post-age 65 - ultimte
Ultimate medical cost trend year post-age 65
2008
(211)
(162,724)
$(162,935)
$300413
39-61%
27-33%
3-7%
10-14%
0-8%
6.25%
6.34%
8.50%
4.72%
2007
(15,257)
(65,272)
$(80,529)
$275,159
49%
31%
6%
11%
3%
39-61%
27-33%
3-7%
10-14%
0-8%
6.34%
6.15%
8.50%
4.66%
2006
52-72%
28-48%
52-72%
28-48%
6.25%
6.20%
8.50%
6.20%
6.15%
8.50%
9.00% 9.00%
5.00% 5.00%
2017 2012
9.00% 9.00%
6.00% 6.00%
2015 2011
2008 2007 2006
Components of net periodic benefi cost:
Service cost $10,209 $10,694 $ 9,963 $772 $672 $639
Interest cost 20,812 19,161 17,158 2,371 2,1591,956
Expected retur on plan assets (21,138)(19,217)(16,997)(1,931)(1,775)(1,562)
Transition obligation recogntion 505 505 505
Amortization of prior service cost 654 653 653 (149)
Net loss recognition 3,345 2,978 3,772 575 193 ~
Net periodic benefit cost $13,882 $14,269 $14,549 :¡~~
Assumed health care cost trnd rates have a signficant effect on the amounts report for the health care plans. A
one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulate postretiement
benefit obligation as of December 31, 2008 by $2.1 millon and the service and interest cost by $0,2 millon. A one-percentage-point
IFERC FORM NO.1 (ED, 12-88)Page 123.14
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 0411612009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretiement benefit obligation as
of December 31, 2008 by $1.8 millon and the service and interest cost by $0.2 millon.
The Company and its most signficant subsidiares have salar deferral 40 1 (k) plan that are defined contrbution plans and cover
substatially all employees. Employees can make contrbutions to their respective accounts in the plan on a pre-tax basis up to the
maxium amount permtte by law. The respective company matches a porton of the salar deferred by each parcipant according to
the schedule in the respective plan. Employer matching contrbutions were $4.3 millon in 2008, $4.6 millon in 2007 and $4.4
millon in 2006.
The Company has an Executive Deferral Plan. This plan allows executive offcers and other key employees the opportunity to defer
until the earlier of their retiement, termnation, disabilty or death, up to 75 percent of their base salar and/or up to 100 percent of
their incentive payments. Deferred compensation fuds are held by the Company in a Rabbi Trut. At December 31, 2008 and 2007,
there were deferred compensation assets of $8.8 millon and $12.1 millon included in other special fuds and corresponding deferred
compensation liabilties of $8.8 milion and $12.1 millon included in other deferred credits on the Balance Sheets.
NOTE 12. ACCOUNTING FOR INCOME TAXE
Deferred income taes reflect the net ta effects of temporar differences between the carg amounts of assets and liabilties for
financial reportng puroses and the amounts used for income ta puroses and ta credit carorwards. The realization of defered
tax assets is dependent upon the abilty to generate taxable income in future periods. The Company evaluated avaiable evidence
supporting the realization of its deferred tax assets and determned it is more likely than not that deferred ta assets will be realzed.
The Company and its eligible subsidiares fie consolidated federal income ta retus. The Company also files state income ta
returs in cert jursdictions, including Idaho, Oregon, Montan and Calforna. Subsidiares are charged or credte with the ta
effects of their operations on a stand-alone basis. The Internal Revenue Service (mS) has completed its examnation of the 2004 and
2005 tax years and all issues were resolved related to these years. The ms is curently conducting an examnation of the Company's
2006 and 2007 federal income ta returs. This exanation could result in a change in the liabilty for uncertn ta positions.
However, an estimate of the range of any such possible change cannot be made at ths time. The Company does not believe that any
open tax year with respet to state income taxes could result in any adjustments that would be signficant to the financial statements.
In August 2005, the Treasury Deparent issued regulations and the ms issued a revenue rung that affects the ta treatment by
Avista Corp. of certin indirect overhead expenses. Avista Corp. had previously made a ta election to curently deduct certn
indirect overhead costs, starng with the 2002 ta retur, that were capitaized for financial accounting puroses. This election
allowed A vista Corp. to tae ta deductions resulting in a total reduction of approxiately $40 millon in curent ta liabilties for
2002, 2003 and 2004. These curent tax benefits were deferred on the balance sheet in accordance with the provisions of SFAS No.
109 and did not affect net income.
On the basis of the revenue ruing and related reguations, the ms disallowed the tax deduction of indiect overhead expenses durng
their examnation of the Company's 2001, 2002 and 2003 federal income tax retus. The Company believed that the ta deductions
claimed on tax returs were appropriate based on the applicable statutes and reguations in effect at the tie. Avista Corp.
appealed the proposed ms adjustment in April 2006. The Company repaid a porton of the previous tax deductions though ta
payments in 2005, 2006 and 2008.
On September 10, 2008, the Company entered into a Settlement Agreement with the Appeals Division of the ms that resolved al
items noted during their audit of the Company's 2001 though 2003 tax years, including, among other things, indirect overhead
expenses. The agreement was reviewed and approved by the Joint Commtte on Taxation, and a settement payment was received in
December 2008. The original ms disallowance and the Company's appeal of the indirect overhead issue caused a delay in associated
tax refuds for net operating losses that were cared back to several earlier years. The final settement with the ms freed up the
refund years and set the amount owed for the 2001-2003 tax years. The net result was a refud to the Company of $14.7 millon, plus
interest of $5.7 millon.
The Company had net regulatory assets of $115.0 millon at December 31, 2008 and $117.5 millon at Decmber 31, 2007 related to
the probable recovery of certn deferred tax liabilties from customers though futue rates.
NOTE 13. ENERGY PURCHASE CONTRACTS
IFERC FORM NO.1 (ED. 12-88) Page 123.15
200 2010 2011 2012 2013 Thereafter Tota
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 041612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
A vista Corp. has contracts for the purchase of fuel for therm generation, natual gas for resale and varous agreements for the
purchase or exchange of electrc energy with other entities. The termnation dates of the contracts range from one month to the yea
2055. Total expenses for power purchased, natual gas purhased, ful for generation and other fuel costs, which are included in
operation expenses in the Statements ofIncome, were $951.4 millon in 2008, $733.5 milion in 2007 and $682.5 millon in 2006. The
following table details Avista Corp.'s futue contractu commtments for power resources (including tranmission contracts) and
natual gas resources (including transportation contracts) (dollar in thousands):
2009 2010 2011 2012 2013 Thereafter Total
Power resources $246,114 $127,118 $95,029 $ 82,093 $68,928 $390,303 $1,009,585
Natual gas resources 164,323 94,612 68,038 50,663 44,175 474,329 896,140
Total $410.437 $221,730 $163.067 $132.756 $113.103 $864.632 $1,905.725
All of the energy purchase contracts were entered into as par of A vista Corp. ' s obligation to serve its retail electrc and natual gas
customers' energy requiements. As a result, these costs are generaly reovere either though base retail rates or adjustments to retail
rates as par of the power and natual gas cost deferral and recovery mechansms.
In addition, Avista Corp. has operational agreements, settements and other contractu obligations for its generation, transmission and
distrbution facilties. The expenses assoiate with these agreements are reflecte as operation expenses and maintenance expenses in
the Statements of Income. The following table detals futue contractual commtments for these agreements (dollars in thousands):
Contractual obligations
2009
$24,546
2010
$27.895
2011
$26353
2012
$29.116
2013
$29.987
Thereafter
$247381
Total
$385.188
A vista Corp. has fixed contracts with certn Public Utiity Distrcts (PUD) to purchase portons of the output of certn generating
facilties. Although A vista Corp. has no investment in the PUD generatig facilties, the fixed contracts obligate A vista Corp, to pay
certn minimum amounts (based in par on the debt service reuiements of the PUD) whether or not the facilties are operating. The
cost of power obtained under the contracts, including payments made when a facilty is not operatig, is included in operation expenses
in the Statements of Income. Expenses under thes PUD contracts were $14.9 millon in 2008, $18.0 millon in 2007 and $13.1
millon in 2006. Information as of December 31, 2008 pertning to thes PUD contracts is sumed in the following table (dollars
in thousands):
Company's Curent Share of
Debt Expira-
Kilowatt Anual Service Bonds tion
Output Capabilty Costs (1)Costs (1)Outstanding Date
Chelan County PUD:
Rocky Reach Project 2.9%37,00 $ 2,116 $1,026 $1,320 2011
Douglas County PUD:
Wells Project 3.5%30,000 1,791 793 4,411 2018
Grant County PUD:
Prest Rapids Project 33%28,00 5,253 727 8,485 2055
Wanapum Projet (2)8.2%78,00 5,715 2,663 15,143 2055
Totas 173,00 $14.875 ~$29359
(1) The annual costs will change in proporton to the percentage of output allocated to Avista Corp. in a parcular year. Amounts
represent the operating costs for the year 2008. Debt servce costs are included in annual costs.
(2) The curent contract expires October 31, 2009. A new contract was complete in 2001 with an expiration date of 2055.
Beginnng in November 2009, our rights to the output will be reduced to 3.3 percent. Under the new contract we will have the
rights to the output but not the obligation to tae the output. In September of each year we will be requied to determne if we will
tae the output for the subsequent year.
The estimated aggregate amounts of requied minium payments (Avista Corp.'s share of exiting debt service costs) under these PUD
contracts are as follows (dollars in thousands):
IFERC FORM NO.1 (ED. 12-SS) Page 123.16
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corpration (2)A Resubmission 0411612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
Minium payments ~~W1~~$33,698 $49.020
In addition, A vista Corp. will be required to pay its proportonate share of the varable operatig expenses of these projects.
Avista Energy's contractual commtments to purchase energy commodties as well as commtments related to transmission,
transporttion and other energy-related contracts in futue periods are as follows (dollars in thousands):
Energy purchase contracts
2009
$21.700
2010
$26.728
2011
$26,728
2012
$26.530
2013
$25.543
Thereaftr Tota
$290,482 $417,711
These contractual commtments of Avista Energy are primarily related to the power purchase agreement for the Lancaster Plant. The
majority of the rights and obligations of this agreement were assigned to Shell Energy though the end of 2009. Beginnng in 2010
though 2026, the rights and obligations of the power purchase agreement for the Lacaster Plant are contracted to A vista Energy. The
Company expects that these rights and obligations will be transferred to Avista Corp., subject to futue reguatory approval.
NOTE 14. COMMITTED LINE OF CREIT AGREEMENTS
The Company has a commtted line of credit agreement with varous banks in the tota amount of $320.0 millon with an expiration
date of April 5, 2011. Under the credt agreement, the Company can request the issuace of up to $320.0 millon in letters of credt.
Tota letters of credit outstanding were $24.3 millon as of December 31, 2008 and $34.8 millon as of December 31,2007. The
commtted line of credit is secured by $320.0 millon 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 commtted line of credit.
Additionaly, the Company has a commtted line of credit agreement with varous bank in the total amount of $200.0 millon with an
expiration date of November 24, 200. The commtted line of credit is secured by $200.0 millon of non-tranferable 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 commtted line of credit.
The commtted line of credit agreements contan customar covenants and default provisions, including a covenant requing the ratio
of "earngs before interest, taes, depreciation and amortzation" to "inteest expense" of Avista Corp. for the precedng
twelve-month period at the end of any fiscal quaer to be greater than 1.6 to 1. As of Decembe 31, 2008, the Company was in
compliance with this covenant with a ratio of 3.27 to 1. The commtt line of credt agreements also have a covenant which does not
permit the ratio of" tota debt" to " tota capitaization" of Avista Corp. to be greater than 70 percent at any time. As of December 31,
2008, the Company was in compliance with this covenant with a ratio of 54.5 percent. If the proposed change in organzation becomes
effective, the commtted line of credit agreements will remain at Avista Corp. The commtted line of credit agreements also have a
covenant which requires the Company to maintain a minimum funded ratio of the pension plan assets to liabilties. The Pension
Protection Act of 2006 (that was implemented in 2008) modified the liabilty calculation utilized to calculate the fuded ratio. A vista
Corp. amended the covenant related to the pension fuded ratio, under its $320.0 millon commtt line of credit agreement, to
conform with the calculations under the Pension Protetion Act of 2006.
Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company's revolving commtt lins 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 outstading during the period
Average balance outstading durng the period
Average interest rate durng the period
Average interest rate at end of period
2008 2007 200
$ 250,00 $$ 4,00
$ 250,00 $48,00 $77,00
$ 48,426 $ 6,833 $16,740
3.04%7.91%6.07%
0.81%- %8.25%
NOTE 15. BONDS AND OTHER LONG-TERM DEBT
The following detals the interest rate and maturity dates of bonds and other long-term debt outstading as of December 31 (dollars in
thousands):
Maturity
IFERC FORM NO.1 (ED. 12-SS)
Interest
Page 123.17
Debt matuties
2009
$17.000
2010
$35.00
20111.2012 2013~$75,OO Thereafter
$818.503
Total
$952503
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 0411612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
Year Descrìption Rate 2008 2007
2008 Secured Medìum- Term Notes 6.06%-6.95%$$45,00
2010 Secured Medìum- Term Notes 6.67%-8.02%35,00 35,00
2012 Secured Medìum- Term Notes 737%7,00 7,00
2013 Fìrst Mortgage Bonds 6,13%45,00 45,000
2013 Fìrst Mortgage Bonds (1)7,25%30,00
2018 Fìrst Mortgage Bonds (2)5,95%250,00
2018 Secured Medìum- Term Notes 739%-7.45%22,500 22,500
2019 Fìrst Mortgage Bonds 5.45%90,00 90,00
2023 Secured Medìum- Term Notes 7.18%-754%13,500 13,500
2028 Secured Medìum-Term Notes 6.37%25,000 25,00
2032 Secured Pollution Control Bonds (3)5.00%66,700
2034 Secured Pollution Control Bonds (4)1.20%17,000 17,00
2035 Fìrst Mortgage Bonds 6.25%150,000 150,00
2037 Fìrst Mortgage Bonds 5,70%150,00 150,00
Total secured bonds and other long-term debt 835,00 666,700
2008 Unsecured Senìor Notes 9,75%272,860
2023 Unsecured Pollution Control Bonds 6,00%4,100 4,100
Tota unsecured bonds and other long-term debt 4,100 276,960
Interest rate swaps (14,129)1,083
Total long-term debt $824.971 $244,743
(1) On December 16,2008, the Company ìssued $30.0 mìllon of 7.25 percent Fìrst Mortgage Bonds due ìn 2013. The net
proceeds from the ìssuace of $29.9 mìllon (net of placement agent fees and before Avìsta Corp.'s expenses) were used to
repay $25.0 mìllon of medìum term notes that matued on December 10,2008 and repay a porton of the borrowìngs
outstanclng under the Company's $320.0 mion commtt lìne of credìt.
On April 3,2008, the Company ìssued $250.0 milìon of 5.95 percent Firt Mortgage Bonds due ìn 2018. The net proceeds from
the ìssuance of $249.2 milìon (net of ìssuae clscount and before A vìsta Corp,' s expenses), together wìth other avaìlable
funds, were used to pay the $272.9 mìllon of 9.75 pecent Unsecured Seruor Notes that matUed on June 1, 2008.
On December 31, 2008, $66.7 milìon of the Cìty of Forsyt, Monta Pollution Control Revenue Refudìng Bonds, Series 1999A
(Avìsta Corpration Colstrp Project) due 2034 were remaketed. Avìsta Corp. purchased these Pollution Control Bonds and
expects that at a later date, subject to maket condìtions, these bonds wìll be remarkete to unafflìated ìnvestors or refuded
by a new ìssue. Although A vìsta Corp. ìs now the holder of these Pollutìon Control Bonds, the bonds wìl not be cancelled
but wìll remaìn outstanclng under the Cìty of Forsyt's ìndentue. However, so long as Avìsta Corp. ìs the holder, the bonds
wìl not be reflected as an asset or a lìabìlty on A vìsta Corp, 's Balance Sheet.
On December 30, 2008, the Cìty of Forsyt, Montaa ìssued $17.0 mìllon ofìts Pollution Control Revenue Refuclng Bonds,
Series 2008 (Avìsta Corporation Colstrp Project) due 2034 on behalf of Avìsta Corp. The proceeds of these bonds were used
to refund $17.0 mìllon of Pollution Control Revenue Refudìng Bonds, Series 1999B (Avìsta Corporation Colstrp Project)
ìssued by the Cìty of Forsyt, Monta on behalf of Avìsta Corp.
The followìng table detals future long-term debt matuìties ìncludìng long-term debt to afflìated trts (see Note 16) (dollars ìn
thousands):
Substantially all utilìty propertes owned by the Company are subject to the lìen of the Company's varous mortgage ìndentues.
Under the Mortgage and Deed of Trut securng the Company's Fìrst Mortgage Bonds (ìncludìng Secured Meclum-Term Notes), the
Company may ìssue addìtìonal Fìrst Mortgage Bonds ìn an aggregate princìpal amount equal to the sum of: 1) 70 percent of the cost or
faì value (whìchever ìs lower) of propert addìtions whìch have not prevìously been made the basìs of any applìcation under the
Mortgage, or 2) an equal princìpal amount of retied Firt Mortgage Bonds whìch have not prevìously ben made the basìs of any
applìcatìon under the Mortgage, or 3) deposìt of cash; provìded, however, that the Company may not ìssueany adcltional Fìrst
Mortgage Bonds (wìth certn exceptions in the case of bonds ìssued on the basìs of retied bonds) uness the Company's "net
earngs" (as defined ìn the Mortgage) for any perìod of 12 consecutive calendar months out of the prececlng 18 calendar months
were at least twìce the annual ìnterest r uìements on all mort age securìties at the tie outstaclng, ìnclucln the Fìrst Mort age
FERC FORM NO.1 ED. 12-88 Page 123.18
............................................
Name of Respondent This Report is:Date of Report Year/Period of Repor
(1) XAn Original (Mo, Da, Yr)
Avista Corpration (2)A Resubmission 0411612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
Bonds to be issued, and on all indebtedness of prior ran. As of December 3 i, 2008, property additions and retied bonds would have
entitled the Company to issue $688.9 millon in aggregate principal amount of additional First Mortgage Bonds. However, using an
interest rate of 8 percent on additional First Mortgage Bonds, and based on net earngs for the 12 months ended December 31, 2008,
the net earngs test would limt the principal amount of additional bonds the Company could issue to $545.9 millon.
See Note 14 for informtion regarding First Mortgage Bonds issue to secure the Company's obligations under its $320.0 millon and
$200.0 millon çommtted line of credit agreements.
NOTE 16. ADVANCES FROM ASSOCIATED COMPANIES
In 2004, the Company issued Junior Subordinated Debt Securities, with a principal amount of $61.9 millon to A V A Capita Trust m,
an affiliated business trst formed by the Company. Concurently, A V A Capital Trut m issued $60.0 millon of Preferred Trust
Securties to third pares and $1.9 millon of Common Trut Securties to the Company. All of these securties have a fixed interest
rate of 6.50 percent for five years (though March 31, 2009). Subsequent to the intial five-year fixed rate period, the securties wil
either have a new fixed rate or an adjustable rate. These debt securties may be redeemed by the Company on or aftr March 31, 200
and wil mature on April 1, 2034.
In 1997, the Company issued Floating Rate Junor Subordinate Deferrable Interest Debentues, Series B, with a principal amount of
$51.5 millon to Avista Capita II, an affliated business trst formed by the Company. Avista Capita II issued $50.0 millon of
Preferred Trust Securties with a floating distribution rate of LffOR plus 0.875 percent, calculated and reset quarly. The anua
distribution rate paid durng 2008 ranged from 3.06 percent to 6.00 percent. As of December 31, 2008, the anua distrbution rate
was 3.06 percent. Concurent with the issuace of the Preferred Trust Securties, Avista Capita II issued $1.5 millon of Common
Trut Securties to the Company. These debt seurities may be redeemed at the option of Avista Capita II on or aft June 1,2007 and
mature on June 1, 2037. In December 2000, the Company purchased $10.0 millon of these Preferred Trut Securties.
The Company has guarantee the payment of distrbutions on, and redemption price and liquidation amount with respt to, the
Preferred Trust Securities to the extent that AVA Capita Trust m and Avista Capita II have fuds available for such payments from
the respective debt securities. Upon matuty or prior redemption of such debt securties, the Preferred Trust Securties will be
mandatorily redeemed.
NOTE 17. INTRET RATE SWAP AGREEMENTS
Avista Corp. enters into forward-stang interest rate swap agreements 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 anticipate
issuaces of debt. These interest rate swap agreements are considered economic hedges against fluctutions in futue cash flows
associated with changes in interest rates.
In December 2006, Avista Corp. cash settled an interest rate swap agreement and paid $3.7 milion. In March 2008, the Company
cash setted two interest rate swap agreements and paid a tota of $16.4 millon. These settlements were deferred as reguatory items
(par of long-term debt) and wil be amorted as a component of interest expense over the remaning ten year term of the interest rate
swap agreements (forecasted interest payments) in accordance with reguatory accounting practices.
In December 2008, the Company entered into two interest rate swaps totaing $50.0 millon, Under the term of the outstading
interest rate swap agreements as of Decmber 31, 2008, the value of the interest rate swaps is determned based upon A vista Corp.
paying a fixed rate and receiving a varable rate based on LffOR for a term of ten years beginng in 200. As of Decembe 31, 2008,
Avista Corp. had a curent derivative asset of $0.9 millon and offsettng reguatory liabilty on the Balance Sheets in accordance with
regulatory accounting practices. Upon settement of the interest rate swaps, the reguatory asset or liabilty (included as par of
long-term debt) will be amortzed as a component of interest expense over the life of the forecasted interest payments. The interest
rate swap agreements provide for mandatory cash settlement of these contracts in 2009.
In Januar 2009, the Company entered into two interest rate swaps totaing $50.0 millon. Under the term of the outstanding interest
rate swap agreements, the value of the interest rate swaps is determned based upon A vista Corp. paying a fixed rate and receiving a
variable rate based on LffOR for a term of ten years beginnng in 200. Upon settement of the inteest rate swaps, the regulatory
asset or liabilty (included as par of long-term debt) will be amorted as a component of interest expense over the life of the
forecasted interest payments. The interest rate swap agreements provide for mandatory cash settlement of these contracts in 200.
NOTE 18. LEASES
IFERC FORM NO.1 (ED. 12-SS) Page 123.19
Minimum payments required
NOTE 19. GUARANTEES
2009~2010~2011W 2012
1W
2013
1W
ThereaferW1 Totaäm
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
Avista Corporation (2) . A Resubmission 041612009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The Company has multiple leae arangements involving varous assets, with minimum term ranging from one to fort-five years.
Rental expense under operating leases was $4.8 millon in 2008, $4.8 milion in 2007 and $5.4 millon in 2006. Futue minium lease
payments required under operating leases having initial or remaining noncancelable lease term in excess of one year as of December
31,2008 were as follows (dollars in thousands):
The Company has guaranteed the payment of distrbutions on, an redemption pnce and liquidation amount with respect to, the
Preferred Trust Securties issued by its affliates, A V A Capita Trut il and A vista Capita II, to the extent that these entities have
fuds available for such payments from the respective debt securties.
The output from the Lancaster Plant is contracted to A vista Energy thugh 2026 under a power purchase agreement. Avista Corp. has
guaranteed the power purchase agreement for the performce of Avista Energy. The majority of the rights and obligations of ths
agreement were assigned to Shell Energy though the end of 200. Beginnng in 2010, the Company expets that these nghts and
obligations will be transferred to A vista Corp., subject to futue reguatory approval.
In connection with the transaction, on June 30, 2007, A vista Energy and its afliates entered into an Indemnfication Agreement with
Shell Energy and its affiliates. Under the Indemnfication Agreement, A vista Energy and Shell Energy each agree to provide
indemnfication of the other and the other's affliates for cert events and mattrs descrbe in the purchase and sale agreement
entered into on Apnl 16, 2007 and certn other tranaction agrments. Such events and mattrs include, but are not limted to, the
refud proceedings arising out of the western energy makets in 200 and 2001 (see Note 25), existing litigation, ta liabilties, mattrs
with respect to storage rights at Jackson Prame, and any potential issues associate with the power purchase agreement for the
Lancaster Plant. In general, such indemnfication is not requied uness and until a par's claim excee $150,00 and is limted to an
aggregate amount of $30 millon and a term of thee years (except for agreements or transactions with term longer than thee years).
These limtations do not apply to certin thd par claims.
Avista Energy's obligations under the Indemnfication Agreement are guanteed by Avista Capita pursuat to a Guaanty date June
30, 2007. This Guaanty is limted to an aggregate amount of $30 millon plus certin fee and expenses. The Guaranty wil termnate
Apnl 30,2011 except with respect to clai made pnor to termnation.
NOTE 20. PREFERRED STOCK-CUMULTIVE (SUBJECT TO MANDATORY REDEMPTION)
The Company has 10 millon authorized shaes of preferred stock. The Company did not have any preferred stock outstading as of
December 31, 2008 and 2007. In September 2007, the Company redeemed the 262,500 remaning outstanding shares of preferred
stock for $26.25 millon. In September 2006, the Company made a madatory redemption of 17,500 shares of preferred stock for
$1.75 millon.
NOTE 21. FAIR VALUE
The carng values of cash and cash equivalents, restrcted cash, accounts and notes receivable, accounts payable and the commttd
lines of credit are reasonable estimates of their fai values. Long-term debt and long-term debt to affliate trts are reportd at
carying value on the Balance Sheets. The following table sets fort the carng value and estite fai value of the Company's
financial instrents not reported at estited fai value on the Balance Sheets as of December 31, 2008 and 2007 (dollar in
thousands) :
2008 2007
Long-term debt
Long-term debt to affliated trts
Carng
Value
$839,100
113,403
Estite
Fai Value
$875,451
102,027
Carng
Value
$943,660
113,403
Estimate
Fai Value
$969,899
109,109
These estimtes of fair value were pnmarly based on available maket informtion.
IFERC FORM NO.1 (ED. 12-88) Page 123.20
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 0411612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
Energy commodity derivative assets and liabilties, deferred compensation assets, as well as derivatives related to interest rate swap
agreements, are reported at estite fair value on the Balance Sheets. As disclosed in Note 2, on Januar 1, 2008, the Company
adopted the provisions of SFAS No. 157 related to its financial assets and liabilties and nonfinancial assets and liabilties mesured at
fai value on a recuring basis. SFAS No. 157 establishes a fai value hierarhy that prioritizes the inputs used to measure fai value.
The hierarchy gives the highest priority to unadjusted quoted prices in active makets for identical assets or liabilties (Lvel 1
measurement) and the lowest priority to unobservable inputs (Lvel 3 measurement).
The thee levels of the fai value hierarchy defined by SFAS No. 157 are as follows:
Level 1 - Quoted prices are available in active makets for identical assets or liabilties. Active makets are those in which
transactions for the asset or liabilty occur with suffcient frequency and volume to provide pricing informtion on an ongoing
basis.
Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either diectly or
indirectly observable as of the reporting date. Level 2 includes those finacial instrents that are valued using models or
other valuation methodologies. These models are prily industr-standard models that consider varous assumptions,
including quoted forward prices for commodities, time value, volatility factors, and curent maket and contractual prices for
the underlying instrents, as well as other relevant economic measures. Substantially al of these assumptions are .
observable in the marketplace thoughout the full term of the instrent, can be derived from observable data or are
supportd by observable levels at which transactions are executed in the marketpla"e.
Level 3 - Pricing inputs include signficant inputs that are generally unobservable from objective sources. These inputs may
be used with internally developed methodologies that result in mangement's best estimate of fai value. Level 3 instrents
include those that may be more strctued or otherwse talored to the Company's needs.
As required by SFAS No. 157, financial assets and liabilties are classified in their entiety based on the lowest level of input that is
signficant to the fai value measurement. The Company's assessment of the significance of a parcular input to the fai value
measurement requires judgment, and may affect the valuation of fair value assets and liabilties and their placement withn the fai
value hierarchy levels.
The following table discloses by level within the fai value hierarchy the Company's assets and liabilties measured and report on the
Balance Sheet as of December 31, 2008 at fai value on a recurng basis (dollars in thousands):
Counterpar
Level 1 Level 2 Level 3 Netting Total
Assets:
Energy commodity derivatives $$40,104 $68,047 $(47,604)$60,547
Deferred compensation assets 6,990 6,990
Interest rate swaps -875 875-Tota ~$40,979 $68,047 $(47,604)$68:412
Liabilties:
Energy commodity derivatives ~$110,123 $16,085 $(47,694)$78,60
A vista Corp. enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or durng a speified
perod, in the future. These contracts are entered into as par of our management of loads and resources and certn contracts are
considered derivative instrents. The difference between the amount of derivative assets and liabilties disclosed in respetive levels
and the amount of derivative assets and liabilties disclosed on the Balance Sheets and at Note 7 is due to nettng arangements with
certn counterpares. The Company uses quoted maket prices and forward price cures to estite the fai value of our utilty
derivative commodity instrents included in Level 2. In parcular, electrc derivative valuations are performed using broker quotes,
adjusted for periods in between quotable periods. Natual gas derivative valuations are estited using New York Mercantile
Exchange (NYMX) pricing for similar instrents, adjusted for basin differences, which are also quote under NYX. Where
observable inputs are available for substatially the ful term of the contract. the derivative asset or liabilty is included in Level 2. The
Company also has certn contracts that. primaly due to the length of the respective contract, requie the use of internally developed
forward price estimates, which include signficant inputs that may not be observable or corroborated in the maket. These derivative
IFERC FORM NO.1 (ED. 12-SS) Page 123.21
(22,586)
(8,310)
............................................
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 0411612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
contracts are included in Level 3. Refer to Note 7 for fuer discussion of the Company's energy commdity derivative assets and
liabilties.
Deferred compensation assets and liabilties represent fuds held by the Company in a Rabbi Trust for an Executive Deferral Plan.
These fuds consist of actively traded equity and bond fuds with quote price in active makets. The balance disclosed excludes
cash and cash equivalents of $1.8 millon.
The following table presents activity for energy commodity derivative assets meaured at fair value using significant unobservable
inputs for the year ended Decmber 31 (dollars in thousands):
Balance as of Janua 1,2008
Total gains or losses (realized/unealized)
Included in net income
Included in other comprehensive income
Included in regulatory assetsiabilties (1)
Puchases, issuances, and settlements, net
Tranfers to other categories
Balance as of December 31, 2008
2008
$98,943
$68,04
The following table presents activity for energy commity derivative liabilties measured at fai value using signficant unobservable
inputs for the year ended December 31 (dollars in thousands):
Balance as of Janua 1,2008
Total gains or losses (realized/unealized)
Included in net income
Included in other comprehensive income
Included in regulatory assetsiabilties (1)
Purchases, issuances, and settements, net
Transfers to other categories
Balance as of December 31, 2008
2008
$36,506
(18,715)
(1,706)
$16,085
(1) In conjunction with the provisions of SFAS No. 133, the WUC an the IPUC issued accounting orders authorizing Avista Corp.
to offset any derivative assets or liabilties with a reguatory asset or liabilty. This accounting treatment is intended to defer the
recognition of mak-to-maket gains and losses on energy commodity transactions until the period of settement. As such, the
Company does not recognze unealized gains or losses on utility energy commodity derivative instrents in the Statements of
Income. The Company recognizes realize gains or losses in the period of contract settement, subject to reguatory approval for
recovery though retail rates. Realize gains and losses, subject to reguatory approval, result in adjustments to retail rates though
purchased gas cost adjustments, the ERM and the PCA mechanism.
NOTE 22. COMMON STOCK
In November 1999, the Company adopted a shareholder rights plan pursuat to which holders of common stock outstanding on
Februar 15, 1999, or issued thereaftr, were grante one preferred share purchase right (Right) on each outstading 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 acquies 10
percent or more of the outstading shares of common stock or commences a tender or exchange offer, the consumation of which
would result in the beneficial ownership by a person or group of 10 percent or more of the outstading 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
acquirng person or group) that has a market value at that tie equa to twice the purchase price. In no event wil 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 $0.01 per Right, by the Board of Directors of the Company at any tie until any person or group has acquired 10
IFERC FORM NO.1 (EO". 12-88)Page 123.22
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) XAn Original (Mo, Da, Yr)
Avista Corporation I (2) A Resubmission 041612009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
percent or more of the common stock. In connection with the proposed statutory shae exchange (see Note 27), the shareholder rights
plan was amended to provide that the Rights wil expire upon the earlier of the effective time of the statutory share exchange or March
31,200 (the originally scheduled expiration date).
The Company has a Direct Stock Purchase and Dividend Reinvestment Plan under which the Company's shareholders may
automatically reinvest their dividends and make optional cash payments for the purchase of the Company's common stok at curent
market value.
The payment of dividends on common stock is restrcte by provisions of certan covenants applicable to preferred stock contaed in
the Company's Arcles of Incorporation, as amended.
In December 2006, the Company entered into a sales agency agreement with a sales agent, to issue up to 2 millon shares of its
common stock from time to time. In 2008, the Company issued 750,000 shares (total net proceeds of $16.6 millon) under the sales
agency agreement.
NOTE 23. EARNINGS PER COMMON SHARE
The following table presents the computation of basic and diluted eangs per common share for the years ended December 31 (in
thousands, except per share amounts):
2008 2007 2006
Numerator:
Net income $73,620 $38,475 $72,941
Subsidiary earings adjustment for dilutive securties ~(349)--
Adjusted net income for computation of
diluted earngs per common share $73371 $38,126 $72,941
Denominator:
Weighted-average number of common shares
outstading-basic 53,637 52,796 49,162
Effect of dilutive securties:
Contingent stock awards 213 168 371
Stock options --299 364
Weighte-average number of common shares
outstanding-diluted ~~49,897
Total eargs per common share, basic li ~~
Total earngs per common share, diluted ~mi ~
Total stock options outstading that were not included in the calculation of diluted earings per commn share were 250,950 for 2008,
303,950 for 2007 and 26,200 for 2006. These stock options were excluded from the calculation because they were antidilutive bas
on the fact that the exercise price of the stock options was higher than the average maket price of Avista Corp. common stock durng
the respective period.
NOTE 24. STOCK COMPENSATION PLANS
1998 Plan
In 1998, the Company adopted, and shareholders approved, the Long-Term Incentive Plan (1998 Plan), Under the 1998 Plan, certn
key employees, offcers and non-employee directors of the Company and its subsidiares may be granted stock options, stok
appreciation rights, stock awards (including restricted stock) and other stock-based awards and dividend equivalent rights. The
Company has available a maimum of 3.5 millon shares of its common stock for grant under the 1998 Plan. As of Deember 31,
2008,0.7 millon shares were remaining for grant under ths plan.
2000 Plan
In 2000, the Company adopted a Non-Offcer Employee Long-Term Incentive Plan (200 Plan), which was not requied 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 avaiable a maimum of 2.5 millon
IFERC FORM NO.1 (ED. 12-88) Page 123.23
Weighte
Average
Remang
Life (in yeas)
3.4
1.
1.9
1.2
2.6
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) XAn Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 0411612009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
shares of its common stock for grant under the 200 Plan. However, the Company curently does not plan to issue any fuer options
or securties under the 200 Plan. As of December 31, 2008, 1.7 milion shares were remaning for grant under this plan.
Stock Compensatn
On Janua 1,2006, the Company adopted SFAS No. 123R, which supersedes APB No. 25 and SFAS No. 123 and their relate
implementation guidance. The statement requires that compensation cost relating to share-based payment transactions be recognized
in the financial statements based on the fai value of the equity or liabilty instrents issued. The Company adopted SF AS No. 123R
using the modified prospective method and, accordingly, financial statement amounts for prior periods presented were not restated to
reflect the fair value method of recognizing compenstion expens relatig to share-based payments. The Company recorded
stock-based compensation expense of $3.0 milion for 2008, $2.7 millon for 2007 and $4.0 millon for 200. The tota income tax
benefit recognized in the Statements of Income was $1.1 millon for 2008, $1.0 millon for 2007 and $1.5 millon for 2006.
Stock Options
The following sumarizes stock options activity under the 1998 Plan and the 200 Plan for the yeas ended December 31:2008 2007 2006
Number of shares under stock options:
Options outstanding at beginning of year 1,411,911 1,541,045 2,095,211
Options granted
Options exercised (582,238)(123,134)(504,452)
Options canceled (81.00)(6,00)(49,714)
Options outstanding at end of yea 748.673 1.411.911 1,541.045
Options exercisable at end of year 748,673 1.411.911 1541,045
Weighte average exercise price:
Options granted $$$
Options exercised $13.91 $15.14 $16.12
Options canceled $21.70 $26.59 $20.77
Options outstanding at end of yea $15.85 $15.38 $15.41
Options exercisable at end of year $15.85 $15.38 $15.41
Intrnsic value of options exercised (in thousands)$4,248 $1,022 $3,520
Intrinsic value of options outstanding (in thousands)$2,643 $8,697 $15,256
Informtion for options outstading and exercisable as of Decmber 31, 2008 was as follows:
Range of
Exercise Prces
$10.17-$12.41
$15.88-$17.31
$19.34-$23.00
$26.59-$28.47
Tota
Weighte
Average
Exercise
Prce
$11.04
17.19
22.41
27.63
$15.85
Number
of Shares
393,323
104,40
230,750
20,200
748.673
Total cash received from the exercise of stock options was $8.1 millon for 2008, $1.9 millon for 2007 and $9.9 millon for 2006. As
of December 31, 2008 and 2007, the Company's stock options were fuly veste and expensed.
Restrted Shares
Restrcted shares vest in equal thirds each year over a thee-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 retu on equity taget in order
for the CEO's restrcted 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. Restrcte stock is valued at the close of market of the Company's common
stock on the grant date. The weighted average remaning vesting period for the Company's restrcted shares outstading as of
December 31, 2008 was one year. The following table sumarizes restrcted stock activity for the years ended December 31:
IFERC FORM NO.1 (ED. 12-88) Page 123.24
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) lÇ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 0411612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
Unvested shares at beginning of yea
Shares granted
Shares cancelled
Shares veste
Unvested shares at end of year
Weighted average fair value at grant date
Unrecognzed compensation expense at end of year (in thousands)
Intrinsic value, unveste shares at end of year (in thousands)
Intrinsic value, shares vested during the year (in thousands)
2008 2007 2006
28,137 36,180
43,400 31,860 36,260
(1,230)(19,936)(80)
04,368)09,967)--~~~
$20.05 $25.60 $21.32
$691 $517 $439
$1,084 $606 $916
$293 $461 $
Performance Shares
Performance share grants have vesting periods of thee yeas. Pedormnce awards entitle the recipients to dividend equivalent rights,
are subject to fodeitue under certain circumtaces, and are subject to meeting specific peormance conditions. Based on the
attinment of the pedormnce condition, the amount of cash paid or common stock issued wil range from 0 to 150 percent of the
pedormnce shares granted depending on the change in the value of the Company's common stock relative to an extern benchmk.
Dividend equivalent rights are accumulated and paid out only on shars that eventuly vest.
Pedormance share awards entitle the grantee to shares of common stock or cash payable once the servce condition is satisfied. Based
on attainment of the pedormnce condition, grantees may receive 0 to 150 percent of the original shares grante. The pedormance
condition used is the Company's Total Shareholder Retu (TSR) pedormce over a thee-year period as compared against other
utilities; under SPAS 123R this is considered a maket based condition. Pedormce shares may be setted in common stock or cash
at the discretion of the Company. Historically, the Company has settled these awards thugh issuance of stock and intends to
continue this practice. These awards vest at the end of the thee-year period. Under Statement SPAS 123R, pedormce shares are
equity awards with a market base condition, which results in the compensation cost for these awards being recogned over the
requisite serice period, provided that the requisite service period is rendered, regardless of when, if ever, the maket condition is
satisfied.
The Company measures (at the grant date) the estimated fai value of pedormnce shares grante in accordance with the provisions of
SPAS No. 123R. The fair value of each pedormnce share award was estimate on the date of grant using a statistical model that
incorporates the probabilty of meeting performance tagets based on historical retu relative to a peer group. Expecte volatility
was based on the historical volatilty of Avista Corp. common stock over a thee-year period. The expected term of the pedormance
shares is thee years based on the pedormnce cycle. The risk-free interest rate was based on the U.S. Treasur yield at the time of
grant. The compensation expense on these awards will only be adjuste for changes in fodeitues.
The following sumarizes th weighted average assumptions used to deterne the fair value of pedormce shares and related
compensation costs as well as the resulting estiated fair value of pedormce shares granted:
Risk-free interest rate
Expected life, in yeas
Expected volatility
Dividend yield
Weighted average grant date fai value (per share)
2008
2.2%
3
20.2%
2.8%
$16.96
The fai value includes both pedormance shares and dividend equivalent rights.
The following sumares pedormance share activity:
2008
207,841
170,100
(5,239)
019,779)
252,923
$4,902
Opning balance of unvested pedormance shares
Performce shares granted
Pedormce shares canceled
Pedormance shares vested
Ending balance of unveste performance shares
Intrnsic value of unvested edormce shares (in thousands)
FERC FORM NO.1 ED. 12.88 Page 123.25
2007
4.8%
3
19.4%
2.5%
$18.71
2007
300,406
114,640
(45,632)
061.573)
207,841
$4,477
200
4.6%
3
21.9%
2.9%
$18.08
2006
318,331
138,710
(1,404)
055.231)
300406
$7,603
Page 123.26
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation : (2) A Resubmission 0411612009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Unrecognzed compensation expense (in thousands) $2,227 $2,058 $2,400
The weighte average remaining vesting peod for the Company's peormce shares outstading as of December 31, 2008 was 1.7
years. Unrecognized compensation expense as of Decmber 31, 2008 wil be recogned durng 200 and 2010. The following
sumzes the impact of the market condition on the veste performe shaes:
2008 2007 2006Performace shares vested 119,779 161,573 155,231
Impact of market condition on shares vested 21.560 (56.551) 34.151Shares of common stock eared 141.339 105,022 189,382
Intrinsic value of common stock eared (in thousands) $2,739 $2,262 $4,793
In 2008, 2007 and 2006, the number of performance shares veste was adjuste by 18 percent, (35) percent and 22 percent due to the
performance condition achieved. Shares eared under ths plan are distrbuted to parcipants in the quarr following vesting.
Awards outstading under the performce share grants include a dividend component that is paid in cash. This component of the
performance share grants is accounted for as a liabilty awar under the gudance of SFAS No. 123R. These liabilty awards are
revalued on a quarrly basis tang into account the number of awards outstading, historical dividend rate, and the change in the
value of the Company's common stock relative to an extern benchmk. Over the life of these awards, the cumulative amount of
compensation expense recognzed wil match the actu cash paid. As of Dember 31, 2008 and 2007, the Company had recognzed
compensation expense and a liabilty of $0.5 millon and $0.4 millon relate to the dividend component of performance share grants.
NOTE 25. COMMITMENTS AND CONTINGENCIES
In the course of its business, the Company becomes involved in varous clai, controversies, disputes and other contigent matters,
including the items described in this Note. Some of these clai, contrversies, disputes and other contingent mattrs involve
litigation or other contested proceedings. With respet to these proceeings, the Company intends to vigorously protect and defend its
interests and pursue its rights. However, no assurance can be given as to the ultite outcome of any parcular matter because
litigation and other contested proceengs are inerently subject to numerous uncenties, With respect to mattrs that affect A vista
Corp. 's operations, the Company intends to seek, to the extent appropriate, recovery of incured costs though the rate makg process.
With respect to matters discussed in this Note tht afect A vista Energy (parcularly the Calforna Refud Proceeing), any potential
liabilties or refuds remain at Avista Corp. and/or its subsidiares and were not assumed by Shell Energy and/or its affliates.
Federal Energ Regulaory Commission Inquir
On April 19, 2004, the FEC issue an order approving the conteste Agreement in Resolution of Section 206 Proceeding (Agreement
in Resolution) reached by Avista Corp. Avista Energy and the FERC's Trial Staff with respect to an investigation into the activities of
Avista Corp. and A vista Energy in western energy markets durng 200 and 2001. In the Agreement in Resolution, the FEC Trial
Sta state that its investigation found: (1) no evidence that any executives or employees of Avista Corp. or Avista Energy knowingly
engaged in or faciltated any imroper trading strategy; (2) no evidence that Avista Corp. or Avista Energy engaged in any effort to
manpulate the western energy markets durng 200 and 2001; and (3) that Avista Corp. and Avista Energy did not withold relevant
informtion frm the FERC's inquir into the western energy markets for 200 and 2001. In April 2005 and June 2005, the California
Paries and the City of Tacoma, respectively, fied petitions for review of the FERC's decisions approving the Agreement in Resolution
with the United States Cour of Appeals for the Ninth Circuit (Ninth Circuit). Based on the FERC's order approving the Agreement in
Resolution and the FERC's denial of rehearng requests, the Company does not expet that ths proceeding wil have any material
adverse effect on its financial condition, results of operations or cash flows.
California Refund Proceeding
In July 2001, the FEC ordered an evidentiar hearng to determne the amount of refunds due to Californa energy buyers for
purchases made in the spot markets operated by the Californa Independent System Operator (CalISO) and the Californa Power
Exchange (CalPX) during the period from October 2, 2000 to June 20, 2001 (Refud Period). The findings of the FERC
administrative law judge were largely adopted in March 2003 by the FERC. The refuds ordered are based on the development of a
mitigated market clearing price (MMCP) methodology. If the refuds requied by the formula would cause a seller to recover less than
its actual costs for the Refud Period, the FERC has held that the seller would be allowed to document these costs and limit its refud
liabilty commensurately. In September 2005, Avista Energy submitt its cost filing claim pursuant to the FEC's Augut 2005 order
and demonstrated an overall revenue shortall for sales into the Californa spot markets durng the Refund Period after the MMCP
methodology is applied to its transactions. That filing was accepted in orders issued by the FERC in Januar 2006 and November
IFERC FORM NO.1 (ED. 12-88)
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corpration (2) A Resubmission 0411612009 2008104
,
NOTES TO FINANCIAL STATEMENTS (Continued
200. In its Febru 2007 status report, the CalISO stated that it intends to process Avista Energy's cost offset filing (se fuer
discussion regarding the Californa refud rerun below).
In 2001, Pacific Gas & Electrc (pG&E) and Southern Californa Edison (SCE) defaulte on payment obligations to the CalPX and the
CalISO. As a result, the CalPX and the CalISO failed to pay varous energy sellers, including Avista Energy. Both PG&E and the
CalPX declared banptcy in 2001. In March 2002, SCE paid its defaulted obligations to the CalX. In April 200, PG&E paid its
defaulted obligations into an escrow fund in accordance with its bankptcy reorganization. Funds held by the CalX and in the
PG&E escrow fud are not subject to release until the PERC issues an order directing such release in the Californa refud proceedng.
As of December 31, 2008, Avista Energy's accounts receivable outstading related to defaulting paries in Californa were fuly offset
by reserves for uncollected amounts and fuds collecte from defaulting paries.
In addition, in June 2003, the PERC issued an order to review bids above $250 per MW made by paricipants in the short-te energy
markets operated by the CalISO and the CalPX from May 1,200 to October 2, 200. In May 2004, the PERC provided notice that
Avista Energy was no longer subject to ths investigation. In March and April 2005, the Californa Pares and PG&E, respectively,
petitioned for review of the PERC's decision by the Ninth Circuit. In addition, many of the other orders that the PEC has issued in
the Californa refud proceedings are now on appeal before the Ninth Circuit. Some of those issues were consolidate as a result of a
case management conference conducted in September 200. In October 2004, the Ninth Circuit ordered that briefing proceed in two
rounds. The first round is limite to thee issues: (1) which pares are subject to the PERC's refud jursdiction in light of the
exemption for governent-owned utiities in section 201(f) of the Federal Power Act (FPA); (2) the temporal scope of refuds under
section 206 of the FP A; and (3) which categories of transactions are subject to refuds. In September 2005, the Ninth Circuit held that
the PERC did not have the authority to order refunds for sales made by municipal utilties in the Californa Refud Case. In its Order
on Remand, issued in October 2007, the PERC ordered the CalISO and the CalX to complete their refud calculations, includng all
entities that parcipated in the CalISO/CalX makets (including those amounts that would have ben paid by muncipal utiity entities
for their sales into the CalISO and the CalX spot markets durng the refud period). The PERC then directed the CalISO to redue
refunds owed to refud recipients by the amounts attbutable to muncipal sales to the Californa makets.
In August 2006, the Ninth Circuit upheld October 2, 200 as the refud effective date for the FP A section 206 Refud Proceeng, but
remanded to the PEC its decision not to consider a FP A section 309 remedy for tarff violations prior to October 2, 2000. The Ninth
Circuit also grante California's petition for review challenging the PERC's exclusion of the energy exchange tranactions as well as
the PEC's exclusion offorward market transactions from the Californa refud proceedings. Petitions for rehearing were fied on
November 16,2007. It is unclea at ths time what imact, if any, the Cour'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.
The CalISO continues to work on its compliance filing for the Refud Period, which will show ''who owes what to whom." On
September 3, 2008, the CalISO fied its 42nd status report on the Californa recalculation process confirng that the preparatory and
the PEC refund recalculations are complete (as are calculations related to fuel cost allowance offsets, emission offsets, cost-recovery
offsets, and the majority of the interest calculations). The CalISO states that there are eleven (11) open issues that the PERC must rue
on before any distrbution can be made. Once these issues are rued on, the CalISO states that it then intends to: (1) perform the
necessar adjustment to remove refuds associated with non-jursdictional entities and allocate that shortall to net refud recipients;
and (2) work with the pares to the varous global settements to mae appropriate adjustments to the CalSO's data in order to
properly reflect those adjustments.
Any potential liabilties or refunds owed by or to A vista Energy in the Californa Refud Proceeding were retaned by A vista Corp.
and/or its subsidiaries and have not been tranferred to Shell Energy and/or its affliates.
Because the resolution of the Californa refund proceeing remains uncertin, legal counel canot express an opinion on the extent of
the Company's liabilty, if any. However, based on informtion curently known to the Company's magement. the Company does
not expect that the Californa refud proceeding will have a material adverse effect on its fiancial condition, results of operations or
cash flows. This is primarly due to the fact that PERC orders have stated that any refunds wil be netted against unpaid amounts owed
to the respective parties and the Company does not believe that refuds would exceed unpaid amounts owed to the Company.
Pacif Northwest Refund Proceeding
In July 2001, the PERC initiated a preliminar evidentiar hearing to develop a factual record as to whether prices for spot maket
sales of wholesale energy in the Pacific Nortwest between December 25, 2000, and June 20, 2001, were just and reasonable. Durg
the hearng, Avista Corp. and Avista Energy vigorously opposed clai that rates for spot maket sales were unjust an uneasonable
and that the imposition of refuds would be appropriate. In June 2003, the PEC termnated the Pacific Nortwest refud
proceedings, aftr finding that the equities do not justify the imposition of refuds. These equitable factors included the fact that the
IFERC FORM NO.1 (ED. 12-88) Page 123.27
parcipants in the Pacific Northwest maket include not only utilities an other entities that are subject to FERC jursdiction, but also a
very substantial number of governental entities that are not subject to FERC jursdiction with respect to wholesale sales and thus
could not be ordered by the FERC to mae refuds based on existing law. Seven petitions for review were fied with the Ninth Circuit
challenging the merits of the FERC's decision not to order refunds and raising procedural issues.
On August 24, 2007, the Ninth Circuit issued its opinion on the consolidated petitions for review of the Pacific Nortwest refund
proceeding. The Ninth Circuit found that the FEC, in denying the request for refuds, had failed to tae into account new evidence
of market manipulation in the Californa energy maket and its potential ties to the Pacific Nortwest energy market and that such
failure was arbitrar and capricious and, accordingly, remaded the case to the FEC, stating that the FERC's findigs must be
reevaluated in light of the evidence. In addition, the Ninth Circuit concluded that the FERC abused its discretion in denying potential
relief for transactions involving energy that was purchaed in the Pacific Nortwest and ultimately consumed in Californa. The Ninth
Circuit expressly declined to diect the FERC to grant refuds. Requests for rehearng were fied on December 17, 2007.
Both A vista Corp. and Avista Energy were buyers and sellers of energy in the Pacific Nortwest energy market during the period
between December 25, 2000, and June 20, 2001, and, ifrefunds were ordered by the FERC, could be liable to mae payments, but also
could be entitled to receive refuds from other FERC-jursdictional entities. The opportty to mae claims against non-jursdctional
entities may be limited based on existing law. The Company canot predct the outcome of ths proceeing or the amount of any
refunds that A vista Corp. or Avista Energy could be ordered to mae or could be entitled to receive. Therefore. the Company cannot
predct the potential impact the outcome of ths mattr could ultitely have on the Company's results of operations. financial
condition or cash flows.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corpration (2) A Resubmission 041612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
California Attorney General Complaint
In May 2002, the FERC conditionally dismisse a complaint fied in March 200 by the Attorney General of the State of Californa
(California AG) that alleged violations of the Federal Power Act by the FERC and all sellers (including A vista Corp. and its
subsidiares) of electric power and energy into Californa. The complaint aleged that the FEC's adoption and implementation of
maket-based rate authority was flawed and, as a result, individua sellers should refud the difference between the rate charged and a
just and reasonable rate. In May 2002, the FEC issued an order dismissing the complaint but diecting sellers to re-fie certin
transaction sumes. It was not clear that Avista Corp. and its subsidiares were subject to this directive but the Company took the
conservative approach and re-fied certn transaction sumares in June and July of 2002. In July 2002, the Californa AG requested
a rehearing on the FERC order. which request was denied in September 2002. Subsequently, the California AG fied a Petition for
Review of the FERC's decision with the Ninth Circuit. In September 200, the Ninth Circuit upheld the FERC's maket-based rate
authority, but held that the FERC erred in ruing that it lacked authority to order refuds for violations of its reporting requiement.
The Cour remanded the case for fuer proceeings, but did not order any refuds leaving it to the FEC to consider appropriate
remedial options. Nonetheless, the Californa AG has interprete the decision as providing authority to the FEC to order refuds in
the Californa refud proceedng for an expaned refud period.
In March 2008, the FERC issued an order establishing a tral-tye heang to address "whether any individua public utility seller's
violation of the Commssion's market-based rate quarrly reportng requiement led to an unjust and uneasonable rate for tht
paricular seller in Californa durg the 200-2001 period." Puchasers in the California markets will be allowed to present evidence
that "any seller that violated the quaerly reportng requirement failed to disclose an increased market share suffcient to give it the
abilty to exercise market power and thus cause its market-based rates to be unjust and uneasonable." In parcular, the pares are
directed to address whether the seller at any point reached a 20 percent generation market share theshold, and if the seller did reach a
20 percent market share, whether other factors were present to indicate that the seller did not have the abilty to exercise maket power.
Based on information curently known to the Company's magement, the Company does not expect that this matter will have a
material adverse effect on its financial condition, results of operations or cash flows.
Stae of Montana Proceedings
The Attorney General of the State of Montaa (Montana AG) petitioned the Montaa Public Service Commssion (MPSC) to fine
public utilties $1.000 a day for each day it finds they engaged in alleged "decptive, fraudulent, anticompetitive or abusive practices"
and order refunds when consumers were forced to pay more than just and reaonable rates. In Febru 200, the MPSC issued an
order initiating investigation of the Montaa retal electrcity maket for the purse of determning whether there is evidence of
unawfl manpulation of that market. The Montana AG requeste specific information from A vista Energy and A vista Corp.
regarding their tranactions withn the state of Montaa durng the period from Januar 1,2000 though December 31, 2001. In
December 2008, the MPSC closed the Docket and termnated the investigation, subject to the recipt of a final report from the
MontanaAG.
IFERC FORM NO.1 (ED. 12-88) Page 123.28
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 0411612009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Colstrp Generatng Project Complains
In May 2003, various pares (all of which are residents or businesses of Colstrp, Montana) filed complaints against the owners of the
Colstrip Generating Project (Colstrip) in Monta Distrct Cour. Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrp.
The plaintiffs alleged damges to buildings as a result of foundation settement caused by seepage from Colstrp's freshwater surge
pond. Avista Corp.' s ownership interest in the freshwater surge pond is approxiately 11 percent. The plaintiffs also alleged
contamnation and trespass damges resulting from leakage from several of Colstrp's process ponds, most of which are for Units 1 &
2 ponds of which A vista Corp. has no ownership interest. In April 2008, the owners of Colstrip reached a settlement with the
plaintiffs. Under the settlement, Avista Corp.' s portion of the payment to the plaintiffs was $2.1 millon. A vista Corp. may be able to
recover a portion of ths payment though insurance. The Company fied petitions with the WUC and the IPUC to defer any
payments as a regulatory asset, in order to allow for potential futue recovery though futue rates. On September 12, 2008, the IPUC
issued its order approving the Company's petition. The WUC petition was subsequently withdrawn and the porton related to the
Washington jursdiction of $1.3 millon was expensed in 2008.
In March 2007, two famlies that own propert near the holding ponds from Units 3 & 4 of Colstrp filed a complaint againt the
owners of Colstrip and Hydrometrcs, Inc. in Montaa Distrct Cour. The plaintiffs allege that the holding ponds and remediation
activities have adversely impacted their propert. They allege contanation, decrease in water tables, reduced flow of strea on
their propert and other simiar impacts to their propert. They also seek puntive damges, attorney's fees and other relief similar to
that asserted in the litigation described above. No tral date has been set. Because the resolution of this complaint remai uncertn,
legal counel cannot express an opinion on the extent, if any, of the Company's liabilty. However, based on informtion curently
known to the Company's management, the Company does not expect this complaint wil have a material adverse effect on its finacial
condition, results of operations or cash flows.
Colstrp Royalt 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. own a 15 percent interest in Colstrp Units 3 & 4. The Minerals Management Servce
(MMS) of the Unite States Deparent of the Interior has issued orders, going back to 1991, to WECO to pay additional royalties
concernng coal delivered to Colstrp Units 3 & 4 via the conveyor belt. The owners of Colstrp Units 3 & 4 take deliver of the coal
at the beginng of the conveyor belt.
The orders assert that additional royalties are owed to 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 Tranportation Agreement durg the period October 1, 1991
though December 31, 2007.
The state of Montaa also fied claims assessing additional coal production taes on Coal Transporttion Agreement revenues
collected by WECO from the owners of Colstrip Units 3 & 4. Settlement of production ta clai has recently ocured between
WECO and the Montana Deparent of Revenue.
WECO and the owners of Colstrip Units 3 & 4 have agree to a cost sharng agreement for the payment of the settlements owed to the
Montana Deparent of Revenue for coal production taxes and for the MMS royalty clai as they are determned though litigation
or settement. Avista Corp. estimates that its share of the royalties, taxes and interest alleged would be $2.1 millon includig payment
for the calendar year 2008.
Based on information curently known to the Company's management, the Company does not expect that ths 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, though the ratemaking process, of any amounts paid.
Harbor Oil Inc. Site
Avista Corp. used Harbor Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB transformer oil in the late 1980s and early
1990s. In June 2005, the Environmenta Protetion Agency (EPA) Region 10 provided notification to Avista Corp. and several other
pares, as customers of Harbor Oil, that the EPA had determned that hazardous substances were release at the Habor Oil site in
Portand, Oregon and that Avista Corp. and several other pares may be liable for investigation and cleanup of the site under the
Comprehensive Environmental Response, Compensation, and Liabilty Act, commonly referred to as the federal "Superfnd" law,
which provides for joint and several liabilty. The initial indication from the EPA is that the site may be contanated with PCBs,
IFERC FORM NO.1 (ED. 12-SS) Page 123.29
The Company's Post Falls Hydroelectrc Generating Station (post Falls), a facilty constrcted in 1906 with anual generation of 10
average megawatts controls the water level in the La for portons of the yea (includig portons of the lakebed owned by the Tribe).
The Company has other hydroelectrc generating facilties on the Spokae River downstream of Post Falls.
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report.
(1) ~An Original (Mo, Da, Yr)
Avista Corpration (2)A Resubmission 0411612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
petroleum hydrocarbons, chlorinated solvents and heavy metas. Six potentially responsible pares, including Avista Corp., signed an
Administrative Order on Consent with the EPA on May 31, 2007 to conduct a remedal investigation and feasibilty stuy (RS).
The total cost of the RIS is estite to be $1.2 millon an will tae approxitely 2 1/2 yeas to complete. The actu cleaup, if
any, wil not occur until the RIS is complete. Based on the review of its reords related to Harbor Oil, th Company does not believe
it is a major contrbutor to ths potential environmenta contaation based on the de minimus xolume of waste oil it delivered to the
Harbor Oil site. However, there is curently not enough inormtion to allow the Company to assess the probabilty or amount of a
liabilty, if any, being incured. As such, it is not possible to mae an estite of any liabilty at ths time.
Lake Coeur d Alene
In July 1998, the United States Distrct Cour for the Distrct of Idaho issued its finding that the Tribe own, among other things,
portons of the bed and bank of Lae Coeur d' Alene (Lake) lying withn the curent boundaries of the Tribe's reservation lands. This
action had been brought by the United States on behalf of the Tribe against the state of Idaho. Avista Corp; was not a par to ths
action. The United States District Cour decision was affed by the United States Cour of Appeals for the Ninth Circuit. The
United States Supreme Cour affirmed ths decision in June 2001. This ownership decision resulted in, among other thngs, Avista
Corp. being liable to the Tribe for water storage on the Tribe's land and for Section 1O(e) payments.
In December 2008, Avista Corp., the Tribe and the Unite State DOl finalized an agreement regarding a range of issues related to
Post Falls and the Lake. The agreement establishes the amount of past and futue compensation A vista Corp. will pay for the us of
the Tribe's reservation lands under Section 1O(e) of the Federal Power Act (Section 1O(e) payments) and issues related to licensing of
th Company's hydroelectric generating facilties locate on the Spokae River (see Spokane River Relicensing below).
Avista Corp. agreed to compensate the Tribe a tota of $39 millon ($25 millon paid in 2008, $10 millon paid in 2009 and $4 milion
paid in 2010) for trespass and Section 1 O( e) payments for past storage of wate for the period from 1907 though 2007. A vista Corp.
agreed to compensate the Tribe for futue storage of wate though Section 10( e) payments of $0.4 millon per year beginng in 2008
and continuing though the first 20 years of a new licens and $0.7 millon per yea though the remaning term of the license.
In addition to Section 10(e) payments, Avista Corp. agree to mae annua payments over the life of a new PERC license to fud a
varety of protection, mitigation and enhancement measures on the Coeur d'Alene Reservation requied under Section 4( e) of the
Federal Power Act. These payments involve creation of a Coeur d Alene resource protection trt fund (the Trut Fund). Anual
payments from the Company to the Trut Fund for protection, mitigation and enhancement measurements would commence with the
issuance of a new PERC license and are expected to tota approxitely $100 millon over an assumed 5Q.yea license term.
In September 2008, as par of the settlement of the Company's general rate case the IPUC approved deferral of the Idaho jursdictional
allocation of amounts paid to the Tribe, the Trut Fund or relate to the licensing of its hydroelectrc generating facilties for later
recovery though rates in a subsequent general rate filing. Avista Corp. included these items in its general rate case filed in Janua
2009. In December 2008, the WUC approved a settlement of the Company's general rate case filing which provides simlar
treatment of the Washington jursdictional allocation of amounts paid to the Tribe, the Trust Fund or relate to the licensing of its
hydroelectrc generating facilties.
On Januar 27, 2009, the Public Counsel Section of the Washigtn Attrney General's Offce (public Counsel) filed a Petition for
Judicial Review of the WUC's recent order approving the settement of the Company's general rate case. Public Counsel raised a
number of issues that were previously argued before the WUC. These include whether settement costs associated with resolving the
dispute with the Tribe were pruent and whether recovery of such costs would constitute ilegal "retroactive ratemang." The appeals
process may tae several months and a decision is not expected until later in 200. The cour will either affir the decision of the
WUC in its entiety or reverse the decision, in whole or in par, and remad the matter back to the WUe for fuer consideration,
which could possibly result in refuds.
Spokane River Relicensing
The Company own and operates six hydroelectric plants on the Spokane River, and five of these (Lng Lake, Nine Mile, Upper Fals,
Monroe Street and Post Falls, which have a tota present capabilty of 144.1 MW) are under one PERC license and are referred to as
IFERC FORM NO.1 (ED. 12-88) Page 123.30
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)Avista Corpration (2)A Resubmission 0411612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
the Spokane River Project. The sixth, Litte Falls, is operate under separate Congressional authority and is not licensed by the PERC.
Since the PERC was unable to issue new license orders prior to the Augut 1,2007 (and subsequent Augut 1,2008) expiration of the
curent license, an annual license was issued for all five plants, in effect extending the curent license and its conditions until August 1,
2009. The Company has no reason to believe that Spokane River Project operations will be interpted in any maer relative to the
timing of the PERC's actions.
The Company fied a Notice of Intent to Relicense in July 200. The form consultation process involving planng and information
gathering with stakeholder groups lasted though July 2005, when the Company fied its new license applications with the PEC. The
Company initially requested the PERC to consider a license for Post Falls, which has a present capabilty of 18 MW, separately from
the other four hydroelectric plants due to the complexity of issues related to the Post Falls development. In the license applications, the
Company proposed a number of measures intended to address the impact of the Spokae River Project and enhance resources
associated with the Spokane River. PERC licenses are granted for term of 30 to 50 years.
Since the Company's July 2005 filing of applications to relicense the Spokane River Project, the PERC has continued varous stages
of processing the applications. In May 2006, the PERC issued a notice requestig other pares to provide terms and conditions
regarding the two license applications. In response to that notice, a number of pares including the Tribe, the state of Idaho,
Washington state agencies, and the United States DOl fied either recommended term and conditions, pursuant to Sections lO(a) and
lOG) of the Federal Power Act (F A), or mandatory conditions relate to the Post Falls application, pursuat to Section 4(e) of the
FP A. In Januar 2007, the PERC issued a draft Environmenta Impact Statement (EIS). Afer review of comments, the PEC issued
a final EIS in July 2007. This was the last admnistrative step for the PERC before the issuance of license orders; however, the PERC
was unable to move forward prior to Federal Clean Water Act 401 Water Quality Certfications (Certfications) being issued by the
states of Idaho and Washington.
The states ofIdaho and Washington issued Certfications for the Project on June 5, 2008 and June 10,2008, respectively. The Idaho
Certfication was based on a Settlement Agreement between Avista Corp., Idaho Deparent of Environmental Quaty an the Idaho
Deparent of Fish and Game, and is final. The Washington Certfication, which was issued by the Washigton Deparent of
Ecology (Eology); however, was appealed by Avista Corp., Inland Empire Paper and the Sierra Club/Center for Environmenta Law
and Policy. All issues, with the exception of one appealed by the Sierra Club/Center for Environmenta Law and Policy (aesthetic
spils at the Upper Falls plant) were resolved though a four-par Settlement Agreement. Avista Corp. is continuing negotiations on
the remaining issue. A hearing is scheduled before the Washington Pollution Control Hearing Board in August 200 to address the
remaining issue under appeaL.
On December 16,2008 Avista, the Unite States DOl, and the Tribe reached agreement resolving Federal Power Act Section 4(e)
conditions, as well as the payment of anual charges under Section 1 O( e) of the FP A regarding Post Falls, which stores water on a
porton of the Coeur d Alene Indian Reservation. The thee parties submitted a request to the PEC on Janua 29, 2009 to
incorporate the agreed-upon term and conditions in a new single 50-yea license for all five Spokane River hydroelectrc plants.
The United States Deparent ofFish and Wildlife concured, via a letter to FEC on July 31, 2008, that the Spokane River Project is
not likely to adversely affect any liste or theatened endangered species.
Avista Corp. can not determne exactly when the FEC wil complete action on the applications. Once granted, a new license wil
describe the final conditions A vista Corp. wil be responsible to implement, and the term for a new license.
The Company's estimate of the potential cost of the conditions proposed for the Spokane River Project, based on estites of what it
would cost to implement the recommendations and conditions included in the PERC's PElS and the numerous Settement Agreements,
tota approximtely $305 millon over a 50-year period.
In addition, the December 16,2008 settlement agreement between the Company and the Tribe resolved FPA Section 10(e), or storage
payments related to the Post Falls hydroelectric facilty. Under the Agreement, Avista Corp. will pay the Tribe $0.4 millon anualy
for the first 20 yea of a new PERC license and $0.7 millon anually for the remander of the license term for section 10(e) charges.
The WUC approved, for future recovery, costs incured in relicensing the Spokae River project, as well as the costs relate to
settement with the Tribe. The WUC approved deferred accounting treabnent, with a caring cost, until these costs are reflecte in
IFERC FORM NO.1 (ED. 12-88) Page 123.31
Page 123.32
............................................
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 0411612009 2008104
NOTES TO FINACIAL STATEMENTS (Continued)
futue retail rates. The IPUC approved simlar deferred accountig trabnent. Our general rate cases, filed in Janua 200, reflect
recovery of both the direct and deferred costs. The Company will continue to sek recvery, though the ratemag process, of all
operating and capitalized costs relate to the relicensing of the Spokae river plants.
Clak Fork Settlement Agreement
Dissolved abnospheric gas levels exceed state of Idaho and federal water quaity standards downtream of the Cabinet Gorge
Hydroelectrc Generating Project (Cabinet Gorge) durng periods when excess river flows must be divert over the spilway. Under
the term of the Clark Fork Settlement Agreement, the Company developed an abatement and mitigation strategy with the other
signatories to the agreement and developed the Gas Supersatuation Control Program (GSCP). The Idaho Deparent of
Environmental Quality and the USFWS approved the GSCP in Februar 2004 and the PEC issued an order approving the GSCP in
Janua 2005.
The GSCP provides for the opening and modification of one and, potentially, both of the two existing diversion tuels built when
Cabinet Gorge was originally constrte. When river flows excee the capacity of the powerhouse turbines, the excess flows would
be diverted to the tunnels rather than released over the spilway. The Company has underten physical and computer modeling
studies to confirm the feasibilty and likely effectiveness of the tul solution. Anysis of the predicted tota dissolved gas
performance indicates that the tunnels will not meet the performce criteria anticipate in the GSCP. In August 2007, the Gas
Supersaturation Subcommttee concluded that the tuel project does not meet the expectations of the GSCP and is not an acceptable
project. As a result, the Company has met and will continue meeting with key staeholders to review and amend the GSCP which
includes developing alternatives to the constrction of the tuels. The Company has expended $5.0 millon on the tuel project.
The WUC and IPUC have accepted the recovery of thes costs though rate.
The USFWS has listed bull trout as theatened under the Endangered Speies Act. The Clark Fork Settement Agreement describes
program intended to restore bull trout populations in the project ar. Using the concept of adaptive maagement and working closely
with the USFWS, the Company is evaluating the feasibilty of fish passage at Cabinet Gorge and Noxon Rapids. The results of these
studies will help the Company and other pares detene the best use of fuds toward continuing fish passage effort or other bull
trout population enhancement measures.
Air Qualit
The Company must be in compliance with requirements under the Clean Ai Act and Clea Ai Act Amendments for its therml
generating plants. The Company continues to monitor legislative developments at both the state and national level for the potential of
fuer restrictions on sulfu dioxide, nitrogen oxide and carbon dioxide, as well as other greenhouse gas and mercur emissions.
In 2006, the Montaa Deparent of Environmental Quality (Montana DEQ) adopted fial rules for the control of mercur emissions
from coal-fired plants. The new rues set strct mercur emission lits by 2010, and put in place a recuring ten-year review process
to ensure facilties are keeping pace with advancing technology in mercur emission control. The rues also provide for temporar
alternate emission limits provided cert provisions are met, and they allocate mercur emission credits in a maner that rewards the
cleanest facilties.
Compliance with new and proposed requiements and possible additional legislation or reguations will result in increases to capita
expenditues and operating expenses for expanded emission controls at the Company's therm generating facilties. The Company,
along with the other owners of Colstrp, complete the first phase of testing on two mercur control technologies. The joint owners of
Colstrip were encourged by prelimnar results and believe that we will be able to comply with the Montana law without utilizing the
temporar alternate emission limit provision. Preliminar estiates indicate that the Company's share of instalation capital costs will
be $1.5 millon and anua operating costs will increase by $2.9 millon (beginnng in late-2009). The Company will continue to seek
recovery, though the ratemakng process, of the costs to comply with varous ai quaity requiements.
Residentil Exchange Program
The residential exchange program is intended to provide access to the benefits of low-cost federal hydroelectricity to residential and
smal-far customers of the region's private (investor owned) and public (governental or customer owned) utilities. The Bonnevile
Power Admnistration (BPA) administers the residential exchange program under the Nortwest Power Act. Previously, Avista Corp.
and other private utilties in the Pacific Nortwest executed settlement agreements with BPA to resolve each par's rights and
obligations under the residential exchange program. Thes settements covered payment of benefits for the period October 1,2001,
though September 30, 2011. On May 3, 2007, the Ninth Circuit rued that the BPA exceeed its authority when it entered into the
settlement agreements with private utilties (including Avista Corp.) for the period from 2001 thugh 2011.
I FERC FORM NO. 1 (ED. 12-88)
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 041612009 208104
NOTES TO FINANCIAL STATEMENTS (Continued
In Febru 2008, the BPA initiated its WP-07 Supplemental rate case (WP-07S) to, among other thngs, determne the level of
benefits for customers served by private utilities (including Avista Corp.) for its fiscal year 2009. In addition to resolving residential
exchange issues for the long-term, the BPA also proposed an interim payout to private utilities for its fiscal year 2008, which included
$9.6 millon for customers of Avista Corp. Rate adjustments to pass though the interim payment to Avista Corp.'s customers were
approved by the WUC and IPUC in April 2008. In September 2008, the BPA issued its final Record of Decision in WP-07S. Avista
Corp. is evaluating the BPA's final Record of Decision, and may tae steps to challenge the BPA's final Record of Decision. Avista
Corp. has executed new Residential Exchange contracts with the BPA, for customer benefits in 2009. Rate adjustments to pass
though the payments in the amount of $2.4 millon for the period November 1,2008 though October 31, 2009 have been approved by
the WUC and IPUC.
Since the residential exchange settlement payments are passed though to A vista Corp. ' s customers as adjustments to electrc bils,
there is no effect on Avista Corp.' s net income or cash flows.
Other Contngencies
In the normal course of business, the Company has varous other legal claims and contingent matters outstanding. The Company
believes that any ultimate liabilty arsing 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 probabilty or amount of a
liabilty being incured. Such a change, should it occur, could be signficant.
The Company routinely assesses, based on in-depth studies, expert analyses and legal reviews, its contingencies, obligations and
commtments for remediation of contamnated sites, including assessments of ranges and probabilties of recoveries frm other
responsible pares who have and have not agree to a settlement and recoveries from insurance cariers. The Company's policy is to
accrue and charge to curent expense identified exposures related to environmenta remediation sites based on estites of
investigation, cleanup and monitoring costs to be incured.
The Company has potential liabilties under the Federal Endangered Species Act for species of fish that have either aleady ben added
to the endangered species list, been listed as "theatened" or been petitioned for listing. Thus far, measures adopted and implemented
have had minimal impact on the Company.
Under the federal licenses for its hydroelectrc projects, the Company is obligated to protect its propert rights, including water rights.
The state of Montaa is examning the statu of all water right claims within state boundares. Claims withn the Clark Fork River
basin could potentially adversely affect the energy production of the Company's Cabinet Gorge and Noxon Rapids hydroelectric
facilties. The Company is parcipating in this extensive adjudication process, which is unikely to be concluded in the foreseeable
future.
As of December 31, 2008, the Company's collective bargaining agrment with the International Brotherhood of Electrcal Workers
represente approximately 50 percent of all of A vista Corp.'s employees. The agreement with the local unon in Washington and
Idaho representing the majority (approximately 90 percent) of the bargaining unit employees expires in March 2010. Two local
agreements in Oregon, which cover approximately 50 employees, expire in April 2010.
NOTE 26. REGULATORY MATTERS
The following is a sumar of the Company's authorized rates of retu in each jursdiction:
Jursdiction and service
Washington electrc and natual gas
Idaho electrc and natural gas
Oregon natual gas
Implementation
Date
Januar 2009
October 2008
April 2008
Authorized
Overall Rate
of Retu
8.22%
8.45%
8.21%
Authoried
Retu on
Equity
10.2%
10.2%
10.0%
Authoried
Equity
Level
46%
48%
50%
Washington General Rate Cases
As approved by the WUC, on Januar 1,2008, electrc rates for the Company's Washingtn customers increased by an average of
9.4 percent, which was designed to increase annual revenues by $30.2 millon. As par of ths general rate increase, the base level of
power supply costs used in the ERM calculations was updated. Also, on Janua 1,2008, natual gas rates increased by an average of
IFERC FORM NO.1 (ED. 12-88)Page 123.33
In Januar 2009, the Company fied a general rate case with the !PUC requesting to increas base electrc rates for its Idaho customers.
In the general rate case filing, the Company requested a net electrc rate increase of 7.8 percent. The net electrc rate increase is based
on a requested 12.8 percent increase in biled rates with an offsettg 5.0 percent reduction in the curent PCA surcharge. The
Company also requested a 3.0 percent increase in natual gas rates. The filing is designed to increase anua base electrc service
revenues by $31.2 millon ($18.9 millon net after considering the reduction in the curnt PCA surcharge) and increase annual natual
gas service revenues by $2.7 millon. The Company's request is based on a proposed rate of retu on rate base of 8.8 percent, with a
common equity ratio of 50 percent and an 11.0 percent retur on equity. The !PUC generally has up to seven months to review a
general rate case fiing.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 0411612009 2008104
NOTES TO FINANCIAL STATEMENTS (Continued)
1.7 percent, which was designed to increae annual revenues by $3.3 millon.
In September 2008, the Company entered into a settement stipulation with respect to its general rate case that was filed with the
WUTC in March 2008. Other pares to the settement stipulation ar the staff of the WUC, Nortwest Industral Gas Users, and the
Energy Project. The Industral Customers of Nortwest Utities (ICND joined in portons of the settement and the Public Counel
Section of the Washington Attorney General's Offce (Pblic Counl) did not join in the settement stipulation. This settlement
stipulation was approved by the WUC in Deember 2008. The new electrc and natual gas rates beame effective on Januar 1,
200. As agreed to in the settlement, base electtc rates for the Company's Washigton customers increased by an average of9.1
percent, which is designed to increase annua revenues by $32.5 millon. Base natual gas rates for the Company's Washington
customers increased by an average of 2.4 percent, which is designed to increase anua revenues by $4.8 millon.
On Janua 27, 200, Public Counsel fied a Petition for Judicial Review of the WUC's recent order approvig the Company's
multipary settement. Public Counel raised a number of issues that were previously argued before the WUC. These include
whether settlement costs associated with resolving the dispute with the Coeur d Alene Tribe were prudent and whether recover of
such costs would constitute ilegal "retroactive ratemang." Public Counel also questioned whether the WUTC's decision to
entertin supplementa testiony by the Company to update its fiing for power supply costs durg the course of the proceeings was
appropriate. Finaly, Public Counsel argued that the settement imroperly included adversing costs, dues and donations, and certain
other expenses.
The appeal itself does not prevent the new rates from going into effect. The appes procss may tae several months and a decision is
not expecte until later in 2009. The cour will either aff the decision of the WUC in its entiety or reverse the decision, in whole
or in par, and remand the matter back to the WUC for fuer consideration, which could possibly result in refuds.
In Januar 2009, the Company fied a general rate cas with the WUC requesting to increase base electrc rates for the Company's
Washington customers. In the general rate case filing, the Company reuested a net electrc rate increase of 8.6 percent. The net
electric rate increase is based on a requested 16.0 percent increase in biled rates with an offsetting 7.4 percent reduction in the curent
ER surcharge. The Company also requested a 2.4 percent increase in natual gas rates. The fiing is designed to increase anual base
electrc service revenues by $69.8 millon ($37.5 millon net aftr considering the reduction in the curent ERM surcharge) and
increase annual natural gas service revenues by $4.9 millon. The Company's request is based on a propose rate of retur on rate base
of 8.68 percent, with a common equity ratio of 47.5 percent and an 11.0 percent retur on equity. The WUTC generally has up to 11
months to review a general rate case fiing.
As par of the general rate case settement agreement that was modified and approved by the WUTC in December 2005, the Company
agree to increase the utilty equity component to 35 pecent by the end of 2007 and 38 pecent by the end of 2008. The utility equity
component met ths taget as it was approxitely 47.6 percent as of Deember 31, 2008.
Idaho General Rate Cases
In August 2008, the Company entered into an all-par settement stipulation with respect to its general rate case that was filed with the
!PUC in April 2008. This settlement stipulation was approved by the !PUC in September 2008. The new electrc and natural gas rates
became effective on October 1,2008. As agreed to in the settement, base electrc rates for the Company's Idaho customers increased
by an average of 12.0 percent, which is designed to increase annual revenues by $23.2 millon. Base natual gas rates for the
Company's Idaho customers increased by an average of 4.7 percent, which is designed to increae anua revenues by $3.9 millon.
Oregon General Rate Case
As approved by the OPUC in March 2008, natural gas rates for the Company's Oregon customers increased 0.4 percent effective April
IFERC FORM NO.1 (ED. 12-88) Page 123.34
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
Avista Corpration (2)A Resubmission 041612009 2008/04
NOTES TO FINANCIAL STATEMENTS (Continued
1, 2008 (designed to increase anual revenues by $0.5 millon) and increased an additional 1. percent effective November 1,2008
(designed to increase annua revenues by an additional $1.4 millon).
NOTE 27. POTENTIAL HOLDING COMPANY FORMTION
At the Anua Meeting of Shareholders in May 200, the shareholders of Avista Corp. approved a proposal to proce with a statutory
share exchange, which would change the Company's organzation to a holding company strcture. The holding company, curently
named A V A Formtion Corp. (A V A), would become the parent of Avista Corp. Afer the contemplated dividend to A V A of the
capital stock of Avista Capital (Avista Capita Dividend) now held by Avista Corp., AVA would then also be the parent of Avista
CapitaL. The A vista Capita Dividend would effect the strctual separation of A vista Corp.' s non-utility businesses from its reguatedutility business. .
Avista Corp. received approval from the PERC in April 2006 (conditioned on approval by the state reguatory agencies), the !PUC in
June 2006 and the WUC in Februar 2007. Avista Corp. also fied for approval from the utilty reguators in Oregon and Montaa
and proceeings are pending in each of these jursdictions. The statutory share exchange is subject to the receipt of the remaning
regulatory approvals and the satisfaction of other conditions. The Company canot predict when the remaining regulatory approvals
will be obtained or if they will be on terms acceptable to the Company.
The !PUC accepted a stipulation entered into between Avista Corp. and the !PUC Staff that sets fort a variety of conditions, which
would serve to segregate the Company's utiity operations from the other businesses conducted by the holding company. The
stipulation among other thngs would require A vista Corp. to maintan certn common equity levels as par of its capita strctue.
Avista Corp. commtted to increase its actual utilty 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 imlemented on Janua 1,2006.
The calculation of the utility equity component is essentially the ratio of Avista Corp.'s tota common equity to tota capitaation
excluding, in each case, Avista Corp.'s investment in Avista Capita. The utilty equity component was approxitely 47.6 percent as
of December 31, 2008. In addition, !PUC approval would be requied for any dividend from Avista Corp. to the holding company tht
would reduce utility common equity below 25 percent of tota capitaization which, for ths purose, includes long and short-term debt,
capitalized lease obligations and preferred and common equity.
The WUTC accepted a similar stipulation entered into between A vista Corp. and the WUC staff. WUTC approval would be requied
for any dividend from Avista Corp. to the holding company that would reduce utility common equity below 30 percent of tota
capitalization.
Pursuat to the Plan of Share Exchange, a statutory share exchange would be effected whereby each outstading 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 beome holders of A VA common stock and Avista Corp. would become a subsidiar of A V A. The other outstag securties
of A vista Corp. would not be affected by the statutory shae exchange, with limite exceptions for stock options and other securties
outstading under equity compensation and employee benefit plan.
NOTE 28. INFORMATION SERVICES CONTRACTS
The Company has inormation services contracts that expire at varous times though 2013. Tota payments under these contracts were
$15.4 millon in 2008, $15.4 millon in 2007 and $12.5 millon in 2006. The majority of the costs are included in operation expenses
in the Statements ofIncome. Minium contractu obligations under the Company's informtion servces contracts are $15.1 millon
in 2009, $15.4 millon in 2010, $14.5 millon in 2011, $14.5 millon in 2012 and $14.9 millon in 2013. The largest of these contracts
provides for increases due to changes in the cost of living index and fuer provides flexibilty in the anual obligation from
year-to-year subject to a thee-year tre-up cycle.
NOTE 29. SUPPLEMENTAL CASH FLOW INFORMATION
(doll in thousands)
Cash paid for interest
Cash paid for income taxes
2007
$76,434
$8,116
2007
$78,705
$28,947
Other Cash Flows from Operating Activities:
Power and natual gas deferrals
IFERC FORM NO.1 (ED. 12-S8)
$(2,736)$(3,899)
Page 123.35
Change in special deposits
Change in other curent assets
Non-cash stock compensation
ESOP dividends
Gain on sale of assets
Reguatory disallowance of debt repurchase costs
$4,068
$(2,149)
$2,541
$-
$(1,123)
$-
$(1,626)
$(141)
$2,512
$1
$-
$3,850
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) XAn Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/1612009 2008104
NOTES TO FINANCIAL STATEMENTSCContinued)
IFERC FORM NO.1 (ED. 12-88) Page 123.36
............................................
This Page Intentionally Left Blank
FERC FORM NO.1 (NEW 06-02)Page 122a
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) n A Resubmission 04/16/2009
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, Af' D HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accmulated 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 accunted for as "fir value hedges", rep the accunts affeced and the related amounts in a footnote.
Line Item Unrealized Gains and Minimum Pension Foreign Currency Other
No.Losses on Available-Liabilty adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a)(b)(c)(d)(e)
1 Balance of Account 219 at Beginning of
Preceing Year (15,981,101)1,368,559
2 Preceding OtrlYr to Date Reclassifications
from Acct 219 to Net Income (2,379,000)
3 Preceding OuarterlYear to Date Changes in
Fair Value 3,199,837 1,010,441
4 Total (lines 2 and 3)3,199,837 (1,368,559)
5 Balance of Account 219 at End of
Preceding OuarterlY ear (12,781,264)
6 Balance of Account 219 at Beginning of
Current Year (12,781,264)
7 Current Otr/Yr to Date Reclassifications
from Acct 219 to Net Income
8 Current OuarterlYear to Date Changes in
Fair Value 6,688,946
9 Total (lines 7 and 8)6,688,946
10 Balance of Account 219 at End of Current
OuarterlYear (6,092,318)
............................................
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2008/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2009
STATEMENTS OF ACCUMULATED COMPREHENSIVE iNCOME, COMPREHENSIVE INCOME, A D HEDGING ACTIVITIES
Line
No.
Other Cash Flow
Hedges
Interest Rate Swaps
Other Cash Flow
Hedges
(Specify)
Totals for each
category of items
recorded in
Account 219
(h)
( 17,965.585)
( 1,770.000)
128,099
( 1,641.901)
( 19.607,486)
( 19,607,486)
10,656,750
2,858,418
13.515,168
6,092,318)
(f)
( 3,346,361)
(g)
1
2
3
4
5
6
7
8
9
10
6,682)
609,000
602,318)
6,682
3,479,861)
3,479,861)
6,826,222)
6,826,222)
10,656,750
3,830,528)
6,826,222
Net Income (Carred
Forwrd from
Page 117, Line 78)
Total
Comprehensive
Income
(i)ü)
FERC FORM NO.1 (NEW 06-02)Page 122b
1,631,351
75,568,224
22,211,433
3,415,636,422
1,142,578,137
2,273,058,285
1,457,302
61,824,355
............................................
aeo epo
(Mo, Da, Yr)
04/16/2009
SUMMA Y OF UTILITY PLANT AND ACCUM LATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electrc 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 YeadOuarter Ended
(b)
Line
No.
Classification
Utilty Plant
2 In Service
3 Plant in Service (Classified)
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7)
9 Leased to Others
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 Utiity Plant(13 less 14)
16 Detail of Accum Prov for Depr, Amort & Depl
17 In Service:
18 Depreciation
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utilly 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 Amortzation
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31,32)
3,313,806,232
2,419,182
2,534,598,235
3,316,225,414 2,534,598,235
2,597,879,892
862,999,350
1,734,880,542
19,379,703
1,142,578,137 862,999,349
FERC FORM NO.1 (ED. 12-89)Page 200
............................................
Name of Respondent
Avista Corporation
Gas
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2009
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Specify) Other (Specify) Other (Specify)
YearlPeriod of Report
End of 2008/04
Common Line
No.
656,008,542
1,619,845
123,199,455
799,337
657,628,387 123,998,792
174,049
6,080,717
22,211,433
686,094,586
248,348,881
437,745,705
7,663,152
19,379,703
248,348,881 31,229,907
FERC FORM NO.1 (ED. 12-89)Page 201
FERC FORM NO.1 (REV. 12-05)Page 204
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) FiA Resubmission 04/16/2009
ELECTRI PLANT IN SERVICE (Account 101,02, 103 and 106)
1.Report below the original cost of electric plant in service according to the prescribed accunts.
2. In addition to Account 101, Electric Plant in Servce (Classified), this page and the next include Account 102, Elecc Plant Purchased or Sold;
Accunt 103, Experimental Electric Plant Unclassified; and Accunt 106, Completed Construction Not Classified.Elecc.
3. Include in column (c) or (d), as appropriate. corrections of additions and retirements for the current or precing year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant accunt, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accunts.
6. Classify Accunt 106 according to prescribed accounts, on an estimated basis if necessary, and include the entres 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 accunt for accumulated depreciation provision. Include also in column (d)
ILlne Account ~No.Beginning of Year
(a)(b) (c
1 1. INTANGIBLE PLANT
2 (301) Organization
3 (302) Franchises and Consents 15,259,132 370,850
4 (303) Miscellaneous Intangible Plant 3,604,851 218,231
5 TOTAL Intangible Plant (Enter Total of lines 2,3, and 4)18,863,983 589,081
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights .2,232,907 -437
9 (311) Structures and Improvements 124,569,652 475,590
10 (312) Boiler Plant Equipment 161,631,319 1.639,795
11 (313) Engines and Engine-Driven Generators
12 (314) Turbogenerator Units 48,079,386 1,487,123
13 315) Accessory Electric Equipment 26,333,355 97,866
14 (316) Misc. Power Plant Equipment 15,275,332 199,604
15 (317) Asset Retirement Costs for Steam Production 585,276
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)378,707,227 3,899,541
17 B.. Nuclear Production Plant
18 (320) Land and Land Rights
19 (321) Structures and Improvements
20 (322) Reactor Plant Equipment
21 (323) Turbogenerator Units
22 (324) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights 56,000,957 216,470
28 (331) Structures and Improvements 39,391,080 542,283
29 (332) Reservoirs, Dams, and Waterwys 112,156,592 5,333,709
30 (333) Water Wheels, Turbines, and Generators 114,547,842 9,327,906
31 (334) Accessory Electric Equipment 28,948,787 2,736,614
32 (335) Misc. Power PLant Equipment 6,211,072 80,242
33 (336) Roads, Railroads, and Bridges 1,999,562
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)359,255,892 18,237,224
36 D. Other Production Plant
37 (340) Land and Land Rights 903,118
38 (341) Structures and Improvements 15,507,422 109,994
39 (342) Fuel Holders, Products, and Accessories 21,064,431 250
40 (343) Prime Movers 21.876,780
41 I (344) Generators 196,883,690 10,249.213
42 (345) Accessory Electric Equipment 15,105,891 1,181,420
43 (346) Misc. Power Plant Equipment 1,341,166 25,976
44 (347) Asset Retirement Costs for Other Production 351,682
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)273.034,180 11,566,853
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)1,010,997,299 33,703,618
............................................
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report
(1) ~An Original (Mo. Da, Yr)
(2) A Resubmission 04/16/2009
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 Accunts 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 utiily plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recrded 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 journai entries have been filed with the Commission as required by the Uniform System of Accunts, give also dateRetirements Adjustments Transfers Balance at LineEnd lg)Year No.
Year/Period of Report
End of 2008104
782 2,231,688
228,917 124,816,325
378,583 162.892,531
1.881.953 47,684,556
59,602 26,371,619
15,74,936
585,276
2,549,837 380,056,931
356,930
25,363
59
406
197,416
2,819
55,860,497
39,908,000
117,490,242
123,875,342
31,487,985
6,288,495
1,999,562
582,993 376,910,123
9,162,288
457,745
23,037
903,118
15,617,416
21,064,681
21,876,780
197,970,615
15,829,566
1,344,105
351,682
274,957,963
1,031,925,017
9,643,070
12,775,900
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
205FERC FORM NO.1 (REV. 12.05)Page
FERC FORM NO.1 (REV. 12-05)Page 206
............................................
Name of Respondent ThisWrtlS:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) CiA Resubmission 04/16/2009
ELECTRIC PLANT IN SERVICE (Accunt 101,102,11)3 and 106) (Continued)
ine Accunt ~No.Beginning of Year
(a)(b) (c)
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights 13,747,883 1,849,069
49 (352) Structures and Improvements 15,223,954 526,839
50 (353) Station Equipment 167,230,771 6,571,468
51 (354) Towers and Fixtures 17,079,954 18,360
52 (355) Poles and Fixtures 126,246,914 2,596,987
53 (356) Overhead Conductors and Devices 100,597,053 3,879,113
54 (357) Underground Conduit 561,148 2,044,340
55 (358) Underground Conductors and Devices 1,317,910 1,120,161
56 (359) Roads and Trails 1,826,844 45,402
57 (359.1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)443,832,431 18,651,739
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Rights 3,947,661 120,528
61 (361) Structures and Improvements 10,858,010 1,437,997
62 (362) Station Equipment 81,402,697 5,260,411
63 (363) Storage Battery Equipment
64 (364) Poles, Towers. and Fixtures 185,545,007 11,526,026
65 (365) Overhead Conductors and Devices 121,489,836 8,072,027
66 (366) Underground Conduit 65,856,250 5,529,402
67 (367) Underground Conductors and Devices 106,836,636 9,318,281
68 (368) Line Transformers 151,061,288 9,880,149
69 (369) Services 105,185,266 5,025,520
70 (370) Meters 23,347,930 21,414,178
71 (371) Installations on Customer Premises
72 (372) Leased Propert on Customer Premises
73 (373) Street Lighting and Signal Systems 26,262,991 1,587,887
74 (374) Asset Retirement Costs for Distribution Plant 129,707
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)881,923,279 79,172,406
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 Softre
81 (384) Communication Equipment
82 (385) Miscellaneous Regional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Regional Transmission and Market Oper
84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Rights 124,681
87 (390) Structures and Improvements 2,151,329 35,168
88 (391) Offce Furniture and Equipment 513,876 333,758
89 (392) Transportation Equipment 8,589,953 1,304,915
90 (393) Stores Equipment 300,788 77674
91 (394) Tools, Shop and Garage Equipment 3,293,560 106,855
92 (395) Laboratory Equipment 3,068,562 14,532
93 (396) Power Operated Equipment 20,056,431 2,851,928
94 (397) Communication Equipment 32,238,944 4,414,354
95 (398) Miscellaneous Equipment 3,888
96 SUBTOTAL (Enter Total of lines 86 thru 95)70,342.012 9,139,184
97 (399) Other Tangible Propert
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96,97 and 98)70,342,012 9,139,184
100 TOTAL (Accounts 101 and 106)2,425,959,004 141,256.028
101 (102) Electric Plant Purchased (See Instr. 8)
102 (Less) (102) Electric Plant Sold (See Instr. 8)
103 (103) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)2,425,959,004 141,256,028
...........................................
. FERC FORM NO.1 (REV. 12-05)
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 04/16/2009
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106)Continued)
Line~ ~f~No.e) (f)
471,452 15,595,500 48
424 15,750,369 49
872,748 172,929,491 50
17,098,314 51
558,008 128,285,893 52
545,662 103,930,504 53
2,605,88 54
108,000 2,330,071 55
1,872,246 56
57
2,086,294 460,397,876 58
59
4,068,189 60
33,925 12,262,082 61
459,093 86,204,015 62
63
294,588 196,716,445 64
293,841 129,268,022 65
36,218 71,349,434 66
589,161 115,565,756 67
1,395,473 159,545,964 68
101,423 110,109,363 69
489,066 44,273,042 70
71
72
89,849 27.761,029 73
129,707 74
3,782,637 957,313,048 75
76
71
78
79
80
81
82
83
84
85
124,681 86
11,753 2,174,744 87
128,981 718,653 88
413.030 9,481,838 89
50,668 327,794 90
47,307 3,353,108 91
1,693,720 1,389,374 92
1,175,820 21,732,539 93
189,272 36,464,026 94
1,107 2,781 95
3,711,658 75,769,538 96
97
98
3,711,658 75,769,538 99
22,705,562 2,544,509,470 100
101
102
103
22.705,562 2,544,509,470 104
Page 207
FERC FORM NO.1 (ED. 12-87)Page 216
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) CiA Resubmission 04/16/2009
CONSTRUCTION WORK IN PROGRESS - - ELEI 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" project 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 Rrogress -
No.Electric (Account 107)
(a)(b)
1 State of Washington
2 Electric Revenue 699,924
3 Wood Pole Management 953,560
4 Spokane-CDA 115kv line Relay Upgrades 345,674
5 Metro-Post St Reconductor Phase 1 157,872
6 Terre View 115-sub construct (WSU)983,627
7 System-Replace Obsolete Reclosers 141,705
8 NE Sub-Increase Capacity 381,808
9 Indian Trail 115-13kv sub-construct new sub 213,198
10 SE 12F2 Improve Tower Mtn Reliabilty 163,775
11 F&C 12F2 Strong Reconductor 121,725
12 Transportation Equipment 1,569,595
13 WSDOT Highway Franchise Consolidation 342,721
14 Minor Projects (73) Under $100,000 654,931
15
16 State of Idaho
17 Electric Revenue Blanket 170,418
18 Wood Pole Management 231,892
19 Holbrook-Upgrade Feeder 241,869
20 Appleway-Purchase Propert 188,986
21 Tribal Permits and Settements 134,593
22 Plummer-Increase CapacitylRebuild 417,619
23 Idaho Road Sub 353,360
24 NezPerce 115 sub-insta Capacitor Bank 158,36
25 Transportation Equipment 626,049
26 Productivity Initiative 246,891
27 Minor Projects (22) Under $100,000 289,067
28
29
30 Common-WA & ID
31 Noxon-Pinecreek 230kv: Ready Fiber Optic 184,559
32 System Rplc High Voltage OCBs 132,506
33 Spokane-CDA 115kv Line Relay upgrades 642,916
34 Terre View 115-sub Construct WSU 484,065
35 Beacon St yd-Oii Containment 204,495
36 Nez Perce 115sub-inst capacitor bank 371,220
37 Lolo 230-rebuild 230kv yard 469,993
38 Rathdrum 233- Construct Feeder 153,504
39 Cabinet Gorge Capital Projects 141,026
40 Kette Falls Capital Projects 369,908
41 Noxon Capital Projects 560,068
42 CS2 Capital Projects 429,913
43 TOTAL 61,824,355
...........................................
. FERC FORM NO.1 (ED. 12-87)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 04/16/2009
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 Demonstrting (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 (Accunt 107)
(a)(b)
1 Noxon Rapids Unit 1 Turbine 12,112,639
2 Noxon Rapids Unit 2 Turbine 451,700
3 Noxon Rapids Unit 3 Turbine 390,982
4 Nine Mile Redevelopment 317,777
5 TelephoneNideo Systems 227,405
6 Clark Fork Implement PME Agreement 3,497,641
7 Hydro Relicensing 27,209,920
8 Transporttion Equipment 490,620
9 Productivity Initiative 611, 186
10 Minor Projects (188) Under $100,000 2,580,917
11
12 Common -WAIID/OR
13 Minot Projects (0) Under $100,000
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43 TOTAL 61,824,355
Page 216.1
This '30rt Is:
(1) ~ An Original
(2) A Resubmission
ACCUMULATED PROVISION FOR DEPRECIATION OF ELE
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 propert.
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
andlor 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.
............................................
Name of Respondent
Avista Corporation
Date of Report
(Mo, Da, Yr)
04116/2009
TRIC UTILITY PLANT (Accunt 108)
Year/Period of Report
End of 2008/04
ine
No.
em
(a)
1 Balance Beginning of Year
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense
4 (403.1) Depreciation Expense for Asset
Retirement Costs
5 (413) Exp. of Elec. PIt. Leas. to Others
Transportation Expenses-Clearing
7 Other Clearing Accounts
8 Other Accounts (Specify, details in footnote):-269,532 -269,532
10 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
11 Net Charges for Plant Retired:
12 Book Cost of Plant Retired
13 Cost of Removal
14 Salvage (Credit)
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
oflines 12 thru 14)
16 Other Debit or Cr. Items (Describe. details in
footnote):
17
18 Book Cost or Asset Retirement Costs Retired
19 Balahce End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
63,582,382 63,582,382~~~
21,997,326
3,045,574
1,286,613
23,756,287
21,997,32
3,045,574
1,286,613
23,756,287
96,737 96,737
856,572,707 856,572,70
Section B. Balances at End of Year According to Functional Classification
20 Steam Production 237,857,615 237,857,615
21 Nuclear Production
22 Hydraulic Production-Conventional 90,948,956 90,948,95
23 Hydraulic Production-Pumped Storage
24 Other Production 45,632,205 45,632,205
25 Transmission 151,579,025 151,579,025
26 Distribution 287,538,257 287,538,257
27 Regional Transmission and Market Operation
28 General 43,016,649 43,016,64
FERC FORM NO.1 (REV. 12-05)Page 219
............................................
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2008/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) FiA Resubmission 04/16/2009
ACCUMULATED PROVI~ION 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 propert.
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.
ine
No.
Item
(a)
Section A. Balances and Changes During Year
( _1 qttl cleGlnc l;iam inc+a+e) ~ervce(b) (c)cTeCttj: tiant Heiafor Future Use
(d)
LJã~ggll9 '3fR~rs
(e)
29 TOTAL (Enter Total of lines 20 thru 28)856,572,707 856,572,707
FERC FORM NO.1 (REV. 12-05)Page 219
FERC FORM NO.1 (ED. 12-S9)Page 224
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) nA Resubmission 04/16/2009
i NVESTM NTS IN SUBSIDIARY COMPANIES Accunt 123.1)
1.Report below investments in Accunts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each securily owned. For bonds give also principal amount, date of issue, maturily and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open accunt. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary eamings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
ine uescnptJon ot Investment Date Acquired Date Of AmOUnt. or !nveatrnent at
No.Mal~riiY Beginning of Year
(a)(b)(d)
1
2 Avista Capital. Common Stock 1997 184,251,609
3 Avista Capital - Equity in Earnings -103,783.905
4 OCI Investment in Subs
5 Avista Capital - Other Changes in Net Investment -11,378,300
6 Avista Capital - Other Changes in Net Investment 2,281,868
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42 Total Cost of Account 123.1 $01 TOTAL 71,371,272
...........................................
. FERC FORM NO.1 (ED. 12-S9)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04(2) DA Resubmission 04/16/2009
iNVESTMENT IN SUBSIDIARY COMPANIES (Accunt 123.1) (Continued)
4. For any securities, notes, or accunts 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 securily 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 carred in the books of account if difference from cost) and the sellng price thereof, not including interest adjustment inciudible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.1
cqUlly in ~uDslolary Revenues tor Year Amount ot Investment at (jain or LOSS from investment LineEarnin~~)of Year
(f)
End lif Year DiSPl~rof No.g)
1
184.251,609 2
4,123,038 -99,660,867 3
4
3,629,762 -7,748,538 5
-1,636.110 645,758 6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
.39
40
41
4,123,038 1,993,652 77,487,962 42
Page 225
FERC FORM NO.1 (REV. 12-05)Page 227
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) DA Resubmission 04/16/2009
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 departents which use the class of materiaL.
2. Give an explanation of importnt inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accunts (operating expenses, clearing accounts, plant, etc.) affected debited Of 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)
1 Fuel Stock (Account 151)2,213,923 3,673,039 (1 )
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)10,710,048 10,461,384 (1 )
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)1,892,171 2,106,403 (1 )
8 Transmission Plant (Estimated)27,135 (1 )
9 Distribution Plant (Estimated)192,257 227,359 (1 )
10 Regionai Transmission and Market Operation Plant (1),(2)
(Estimated)I
11 Assigned to - Other (provide details in footnote)4,570,824 4,633,554 (1 ),(2)
12 TOTAL Account 154 (Enter Total of lines 5 thru 11)17,365,306 17,455,835
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Uti)
16 Stofes Expense Undistributed (Accunt 163)
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)19,579,229 21,128,874
............................................
This ~ort Is: Date of Report
(1)~ An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2009
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 accunt 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 accunt credited with the reimbursement received for performing the study.
ine
No.
Name of Respondent
Avista Corporation
Description
(a)
1 Transmission Studies
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
Costs Incurred During
Period
(b)
YearlPeriod of Report
End of 2008/04
Accunt Credited
With Reimbursement
(e)
Account Charged
(c)-~ ~ -- - -- --- - - - - - - - - - - - -
FERC FORM NO. 1/1.F/3-Q (NEW. 03-07)Page 231
PPL Energy Plus, LLC
PPL Energy Plus, LLC
10,309 186200
10,309 186200
10,309 186210
10,309 186210
---Generation Studies
RES America Developments Inc.
PPL Montana LLC
UPC Wind Prospects LLC (Palouse)
UPC Wind Prospects LLC (Latah)
Wilkins Wind Project
Horizon Wind Project
Avista - Reardan Project
Avista - Gambee Grangeville Projec
Avista - Garfeld County Project
BP Wind Interconnect
20,481 186200
6,770 186200
21,115 186200
23,084 186200
8,133 186200
21 ,432 186200
7,154 186200
7,408 186200
6,270 186200
4,749 186200
93 186200
4,578 186200
825 186200
20,481
6,770
7,826
186210
186210
186210
PPM Energy Wind
Avista - Grangevile Wind
Martnsdale Wind Intr
FERC FORM NO, 1/3-Q (REV. 02-04)Page 232
............................................
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) nA Resubmission 04/16/2009
o HER REGULATORY ASSETS (Accunt 182.3)
1. Report below the particulars (details) called for conc~ming 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 vvniien orr uunng vvniien orr uunng Current QuarterlYear
Currnt the QuarterlY ear the Peri
QurterlY ear Accunt Charged Amount
(a)(b)(c)(d)(e)(f)
1 Regulatory Asset FAS 106 2,36,760 9261107 472,752 1,891,008
2 Guaranteed Residual Value-Airplane 1.826,00 1.110,173 2,936,173
3 Reg Asset Post Ret Liab 51.00,123 . 121.271,624 172,277,747
4 Regulatory Asset FAS109 Utilit Plant 102,061,458 283 2,59.43 99,465,025
5 Regulatory Asset FAS109 DSIT Non Plant 3,05,79 256,09 3,30,888
6 Regulatory Asset FAS109 DFIT State Tax Cr 3,972,764 595,46 4,568,230
7 Regulatory Asst FAS109 WNP3 8,603,769 283 737,482 7,866,287
8 Reg Assets- Decouplings Surcharge 225.167 254,42 479,593
9
10 Regulatory Asset AMR 23,387,754 Various 23,64,523 -252,769
11 Regulatory Asset RTO Deposit- ID 283,2 Varius 70,806 212,417
12 Regulatory Asset BPA Residential Exchange 3,83,99 Various 3,587,767 249,229
13 Regulatory Asset BPA Residential Exch Interest 161,86 Various 161,862
14 Regulatory Asset ERM Approved for Recovery 41,95,84 Various 12,230,66 29,728,184
15
16 ID Wind Gen AFUDC 35,194 35,194
17
18 Regulatory Asset Wartila Units 3,34.865 Vaious 1,018,612 2,325,253
19 MTM St Regulatory Asst 7,17,42 53,057,55 60,228,970
20 MTM L T Regulatory Asst
21 Regulatory Asset FASl43 Asst Retirement Obligation 3,085,123 250,156 3,335.279
22
23 Reg Asset AN- CDA Lake SetUement 41,733,385 41,733,385
24
25 Regulatory Asset Workers Comp 2,851,024 246,144 3,097,168
26 CS2 Lev Ret 1,267,ns 174,56 1,442,33
27 Regulatory Asset ID PCA Deferral 1 7,516,287 Various 7,516,287
28 Regulatory Asset ID PCA Deferral 2 13,64,762 3,43,232 17,080,99
29 Regulatory Asset ID PCA Deferral 3 3,573,957 3,573,957
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 281,620,776 225,992,959_52,033,188 455,580,547
...................... This Page Intentionally Left Blank......................
FERC FORM NO.1 (ED. 12-94)Page 233
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 04/16/2009
M SCELLANEOUS DEFFERED DEBITS (Accunt 186)
1.Report below the particulars (details) called for conceming miscellaneous deferred debits.
2.For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $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 afiï~Amount End of Year
(a)(b)(c)(d (e)(f)
1
2 Colstrip Common Fac.1,110,99 1,110,999
3 Regulatory Asset-Decoupling def 594,442 4,505 589,937
4 WA Deferred Power Costs 16,564,895 9,341,072 7,223,823
5 WA ERM YTD Company Band 8,482,641 4,482,641 4,000,000
6 WA ERM YTD Contra Accunt -8,482,641 4,482,641 -4,000,000
7 Regulatory Asset ROT Deposit 553,747 158,213 395,534
8 Regulatory Asset-Mt lease pymt 1,366,800 1,428,501 2,795,301
9 Regulatory Asset-Mt lease pymt 2,633,200 2,779,808 5,413,008
10 Colstrip Common Fac.2,355,642 2,355,642
11 Regulatory Asset- COLS 738,101 738,101
12
13
14
15 Payroll Accual 14,022 14,022
16
17 Plant Allocation of clearing jr 1,038,165 1,133,85lJ 2,172,024
18
19 Misc Error Suspense -1,038 13,495 12,457
20
21
22 Misc susp acct-non w/o 200,000 171,673 28,327
23 Unamortized NR sale 8,103 17,664 25,767
24
25 Intangible Pension Asset
26
27 Nez Perce Settlement 186,809 5,212 181,597
28 Misc Deferred Debit Centralia 656,829 19,161 675,990
29
30
31
32 ID Panhandle Forest Use Permit 207,424 16,913 224,337
33 Metro-Sunset 115KV TE 351,506 351,506
34
35 UPRR Permit Conv 333,585 16,578 350,163
36 Insurance Recvy CDA Lake 161,991 161,991
37 Corp reorg stk iss. costs 118,086 118,086
38
39
40
41 Nez Perce Permit Conversion -964 964
42
43 PG & E Canada to N Cai trans 44,051 449,556 493,607
44 Misc Work Orders -:$50,000 83,795 31,935 115,730
45 Subsidiary Bilings 2,125,708 57,883 2,067,825
46 "Null" Projects directly to 186 4,458 350,163 -345,705
47 Misc. Work in Progress
48 ueterrea Keguiatory Comm.
Expenses (See pages 350 - 351)
49 TOTAL 40,642,265 32,008,980
...........................................
. FERC FORM NO.1 (ED. 12-94)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) riA Resubmission 04/16/2009
M SCELLANEOUS 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% ofthe Balance at End otYear 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 ~çcoum.Amount End of Year
Char~ed
(a)(b)(c)(d (e)(f)
1
2 Regulatory Assets Consv 2,564,057 1,280,292 1,283,765
3 Oregon Gas Comm Consvt 40,060 24,096 15,964
4
5 Oregon Common Gas Eff 414,778 272,477 142,301
6 WPNG HE Wtr Htrs-Oregon 260,525 258,779 1,746
7 WPNG HE Furnaces 2,121,880 2,081,157 40,723
8
9 WPNG OR Res Low 1 342,978 191,262 151,716
10
11 Oregon DSM Gen admin 9,073 9,073
12 Tankless Water Heater Rebate 7,194 7,194
13 Chimney Damper Rebate 594 594
14 Programmable Thermostat Rebate 8,843 8,843
15 High eff Space Heater Rebate 675 675
16
17 Oregon DSM Program Amort 2,536,269 2,536,269
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32 Energy Star Homes 275,659 275,563 96
33 Energy Star Manufactored Homes 16,225 16,205 20
34 HE Washing Machines 95,701 95,617 84
35 Regulatory Assets Consv 354,695 101,144 253,551
36 Regulatory Assets Consv 784,023 336,13 447,610
37
38
39 Regulatory Assets Conservation 154,919 154,919
40
41 Dry Creek Transport 364,432 1,774 366,206
42 Glendale Cust Premises Equip 183,654 183,654
43 Lake CDA Issues 1,950,624 1,950,624
44 Shareholder Lawsuit 2002 5,800 5,800
45
46
47 Misc. Work in Progress
48 ueterrea Keguiatory Comm.
Expenses (See pages 350 - 351)
49 TOTAL 40,642,265 32,008,980
Page 233.1
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) nA Resubmission 04/16/2009
ACCUMULATED DEFERRED INCOME TAX S (Accunt 190)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes.
2. At Other (Specify), include deferrls relating to other income and deductons.
ine uescnption ana Location ~No.of Year of Year
(a)(b) (c)
1 Electric
2 13,791,783 15,824,253
3
4
5
6
7 Other
8 TOTAL Electric (Enter Total of lines 2 thru 7)13,791,783 15,824,253
9 Gas
10 3,123,264 2,255,652
11
12
13
14
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15 3,123,264 2,255,652
17 Other 73.908,056 112,975,620
18 TOTAL (Acct 190) (Total of lines 8, 16 and 17)90,823,103 131,055,525
Notes
FERC FORM NO.1 (ED. 12-88)Page 234
............................................
...................... This Page Intentionally Left Blank......................
FERC FORM NO.1 (ED. 12-91)Page 250
............................................
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 04/16/2009
CAPITAL STOCKS (Account 201 and 2 4)
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (I.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line Class and Series of Stock and Number of shares Par or Stated Call Price at
No.Name of Stock Series Authrized by Charter Value per share End of Year
(a)(b)(c)(d)
1 Account 201 - Common Stock Issued
2 No Par Value 200,000,000
3 Restricted shares
4 TOTAL_COM 200,000,000
5
6
7 Account 204 - Preferred Stock Issued 10,000,000
8
9
10 Cumulative ~
11
12
13 TOTAL PRE 10,000.000
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
...........................................
. FERC FORM NO.1 (ED. 12.88)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) CiA Resubmission 04/16/2009
CAPITAL STOCKS (Account 201 and 2 4) (Continued)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT Line
(Total amount outstanding without reduction AS REACOUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS No.for amounts held by respondent)
~t1ares Amount ~t1ares t¿t)st ::n~res Amount
(e)(f)(g)(h)(i)ü)
1
54,487,574 755,903,119 2
55,939 1,121,577 3
54,487,574 755,903,119 55,939 1,121,577 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
Page 251
FERC FORM NO.1 (EO. 12-87)Page 254b
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 04/16/2009
CAPITAL STOCK EXPENSE (Accun 214)
1.Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
¡Line i;iass ana ~enes or ~toCk Balance at End or Year
No.(a)(b)
1 Common Stock - Public Issue 87,394
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22 TOTAL 87,394
....................
: This Page Intentionaly Left Blan......................
FERC FORM NO.1 (ED. 12-96)Page 256
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 04/16/2009
L )NG-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 number and dates)Of Debt issued Premium or Discount
(a)(b)(c)
1 Acct. 221 - Bonds:
2
3
4 Secured Medium Term Notes A 250,000,000 787,692
5 Discount 50,200
6 Secured Medium Term Notes B 161,000,000 788,947
7 Secured Medium Term Notes C 109,000,000 969,770
8 FMB's 6.125%45,000,000 825,301
9 Discount 204,750
10 FMB's 5.45%90,000,000 1,054,153
11 Discount 239,400
12 FMB's 6.25%150,000,000 1,812,935
13 (Premium)-266,500
14 Discount 63,000
15 FMB's5.70%150,000,000 4,702,304
16 Discount 222,000
17 FMB's 5.95%.250,000,000 2,246,19
18 835,000
19 FMB's 7.25%30,000,000 420,306
20 Pollution Control Revenue Bonds
21 6% Series due 2023 4,100,000 115,355
22 Colstrip 1999A due 2032 66,700,000 2,700,582
23 Discount 20,500
24 Colstrip 1999B due 2034 17,000,000 954,386
25
26 Acct. 222
27 Acct. 223 Advances from associated companies 1,200,000
28 LTD - AVA Trust ILL 61,856,000 1,658,634
29 LTD -AVA Trust II 51,547,000 3,633,783
30 Acct. 224 Other
31 Senior Notes 400,000,000 9,128,000
32 Discount 2,716,000
33 TOTAL 1,837,403,000 36,453,917
...........................................
. FERC FORM NO.1 (ED. 12-96)
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) nA Resubmission 04/16/2009
LONG-TERM DEBT (Account 221, 222, 22 and 224) (Continued)
10.Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to 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. Ifthe 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 u~isian!Jln~LineNominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)(g)
reSpYh\dent)
(i)
1
2
3
Var.Var.Var.Var.48,000,000 4,099,869 4
5
6-9-1995 7-1-2010 6-9-1995 7-1-2010 5,000,000 345,000 6
Var.Var.Var.Var.50,OOO,OOC 5,024,125 7
9-8-2003 9-1-2013 9-8-2003 9-1-2013 45,OOO,OOC 2,756,250 8
9
11-18-2004 12-1-2019 11-18-2004 12-1-2019 90,000,00(4,905,000 10
11
11-17-2005 12-1-2035 11-17-2005 12-1-2035 153,989,418 9,375,000 12
13
14
12-15-2006 7-1-2037 12-15-2006 7-1-2037 147,067,094 8,550,000 15
16
4-3-2008 6-1-2018 4-3-2008 6-1-2018 234,814,46(11,073,611 17
18
12-16-2008 12-16-2013 12-16-2008 12-16-2013 30,OOO,00C 90,625 19
20
12-18-1984 12-1-2023 12-18-1984 12-1-2032 4,100,000 246,000 21
9-1-1999 10-1-2032 9-1-1999 10-1-2032 66,700,000 3,345,934 22
23
9-1-1999 3-1-2034 9-1-1999 3-1-2034 17,000,000 872,388 24
25
26
1,200,000 27
4-5-2004 4-1-2034 4-30-2004 3-31-2034 61,856,000 4,020,640 28
6-3-1997 6-1-2037 6-30-1997 5-31-2037 51,547,000 2,120,149 29
30
4-3-2001 6-1-2008 5-1-2001 6-1-2008 11,084,938 31
32
1,006,273,979 67,909,529 33
Page 257
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 04/16/2009
RECONCILIATION OF REPl RTED NET INCOME WITH TAXBL INCOME FOR FEDERAL INCOME TAXES
1. Report the reconcilation of reported net income for the year with taxable income used in computing Federal income tax accals and show
computation of such tax accals. Include in the reconciliation, as far as practcable, the same detail as furnished on Schedule M.1 of the tax return for
the year. Submit a reconcilation even though there is no taxable income for the year. Indicate clearly the nature of each recnciling amount.
2. If the utilly is a member of a group which files a consolidated Federal tax return, recncile reported net income with taxable net income as if a
separate return were to be fieid, indicating, however, intercompany amounts to be eliminated in such a consolidated retum. 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 partcular need of a company, may be used as Long as the data is consistent and meets the requirements of
the above instructions. For electronic reportng purposes complete Line 27 and provide the substitute Page in the context of a footnote.
¡Line partiCUlars. (Details)Amount
No.(a)(b)
1 Net Income for the Year (Page 117)73,619,720
2
3
4 rraxable Income Not Reported on Books
5 9,501,848
6
7
8
9 Deductions Recorded on Books Not Deducted for Return
10 91,483,730
11 Federal Income Tax 5,376,170
12 Deferred Income Tax 35,858,558
13 Investment Tax Credit & State Income Tax 3,893
14 Income Recorded on Books Not Included in Retum
15 59,774,306
16 Equity in Sub Eamings (Income)/Loss -4,123,038
17 Corporate Overhead Unallocated Subs 823,208
18
19 Deductions on Return Not Charged Against Book Income
20 -262,942,348
21
22
23
24
25
26
27 Federal Tax Net Income 9,376,046
28 Show Computation of Tax:
29
30 Federal Tax Net Income 9,376,046
31 State Tax 171,437
32 Federal Tax Net Income including State Tax 9,547,483
33
34 Federal Tax (§35%3.341,619
35
36
37 Prior Years Tax Retum, Revenue Agent Report & Misc True Ups 3,865,437
38 Kettle Falls & Cabinet Gorge Tax Credits -1,830,887
39
40 otal Federal Tax Expense (agrees to line 11)5,376,169
41
42
43
44
FER( FORM NO.1 (ED. 12.96 Pa e 261g
............................................
...................... This Page Intentionally Left Blank.......................
FERC FORM NO.1 (ED. 12-96)Page 262
'............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) EiA Resubmission 04/16/2009
TAXES ACCRUED, PREPAID AND CHA GED DURING YEAR
1. Give particulars (details) of the combined prepaid and acced tax accounts and show the total taxes charged to operations and other accunts during
the year. Do not include gasoline and other sales taxes which have been charged to the 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 accunts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
ine Kind ofTax BALANCE AT BEGINNING OF YEAR c1~~~~ie~~Adjust-
No.(See instrction 5)'. axes Açc~~~repald_ Taxes ~i~~ring ments
(Accunt 236)(Inciude in Accunt 165)ear
(a)(b)(c)(d)(e)(f)
1 FEDERAL:
2 Income Tax 19,767,521 -6,011,211
3 Income Tax -23,161,363 5,020,161
4 Income Tax 1,535.388 -3,835,702
5 Income Tax (Current)3,195,302 14,227,203
6 Retained Earnings
7 Prior Retained Earnings -5,013,521
8 Prior Retained Earnings -2,127,838
9 Current Retained Earnings -2,374,114 -938,493
10 Total Federal -28,767,334 21,773,168 7,277,499
11
12 STATE OF WASHINGTON:
13 Property Tax (2006)-556 556
14 Property Tax (2007)10,692,000 -3,157,737 7,533,707 -556
15 Propert Tax (2008)7,771,834 660
16 Excise Tax (2005)91,452
17 Excise Tax (2006)-464
18 Excise Tax (2007)2,614,792 353,169 2,567,961
19 Excise Tax (2008)24,034,759 21,549,461
20 Natural Gas Use Tax 34,707 93,266 94,758
21 Municipal Occupation Tax 2,695,522 21,642,563 21,723,299
22 Sales & Use Tax (2005)-57,409 57,409
23 Sales & Use Tax (2006)49,466 -57,409
24 Sales & Use Tax (2007)60,189 46,546
25 Sales & Use Tax (2008)763,350 713,084 -1
26 Motor Vehicle Tax (2008)11,090 11,090
27 Total Washington 16,179,699 51,512,294 54,240,566 -1
28
29 STATE OF IDAHO:
30 Income Tax (2006)487,826
31 Income Tax (2007)-180,121 -100,628 -176,233
32 Income Tax (2008)41,224 485,000
33 Propert Tax (2007)2,121,077 -8,245 2,112,832
34 Property Tax (2008)3,737,222 1,225,086 -1
35 Motor Vehicle Tax (2008)10,098 10,098
36 Sales & Use Tax (2005)436
37 Sales & Use Tax (2007)5,173 5,186
38 Sales & Use Tax (2008)75,499 52,263
39 Irrigation Credits (2007)-470 -470
40 KWH Tax (2007)34,357 -9,496 24,862 1
41 TOTAL -4,717,808 94,915,994 84,092,608 -1
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) nA Resubmission 04/16/2009
TAXES ACCF UED, 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 otherwse pending
transmittl of such taxes to the taxing authorily.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accunts 408.1 and 409.1
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertining to other utilily departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utilty plant or other balance sheet accunts.
9. For any tax apportioned to more than one utilly department or accunt, state in a footnote the basis (necessily) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items AO¡Ustments to Ket.Other No.
ACCO~gJ 236)(Inc!. in Account 165)(Accunt 408.1, 409.1)(Account 409.3)Eamings (Accunt 439)
(h)(i)0)(k)(I)
1
25,778,732 3,742,962 16,024.559 2
-18,141,202 5,020,161 3
-2,300,314 213,585 -4,049,287 4
-11,031,901 -2,617,399 5,812,701 5
6
-5,013,521 7
-2,127,838 8
-1,435,621 -2,374,114 9
-14,271,665 1,339,148 20,434,020 10
11
12
13
-2,392,149 -765,588 14
7,771,174 6,258,500 1,513,334 15
91,452 16
-464 17
400,000 -48,417 401,586 18
2,485,298 15,767,570 8,267,189 19
33,215 93,266 20
2,614,786 13,959,888 7,682,675 21
22
-7,943 23
13,643 24
50,265 763,350 25
11,090 26
13,451,426 33,545,392 17,966,902 27
28
29
487,826 30
-104,516 -54,969 -45,659 31
-443,776 -49,822 91,046 32
10 -8,255 33
2,512,135 3,043,418 693,804 34
10,098 35
436 36
-13 37
23,236 75,499 38
-470 39
-9,495 -1 40
6,105,577 48,503,169 46,412,825 41
FERC FORM NO.1 (ED. 12-96)Page 263
FERC FORM NO, 1 (EO. 12-96)Page 262.1
............................................
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 04/16/2009
TAXES ACCRUED, PREPAID AND CHAI 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 accunts during
the year. Do not include gasoline and other sales taxes which have been charged to the accunts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnte and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accunts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accunts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to 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.
ii.ine Kind of Tax BALANCE AT BEGINNING OF YEAR c1~~~~le~lf Adjust-
No.(See instruction 5)T axes AccrueØ Prepaifl Taxes ~ta7g ~ring ments(Account 236)(include in Account 165)ear
(a)(b)(c)(d)(e)(f)
1 KWH Tax (2008)338,468 317,213
2 Franchise Tax (2006)-2,346 2,346
3 Franchise Tax (2007)1,619,792 6 1,617,452 -2,346
4 Franchise Tax (2008)4,107,494 2,433,731
5 Total Idaho 4,086,194 8,191,172 8,107,020
6
7 STATE OF MONTANA:
8 Income Tax (2005)
9 Income Tax (2006)516,192 -4,053
10 Income Tax (2007)-9,721 -181,898 -132,184
11 Income Tax (2008)27,219 375,000
12 Propert Tax (2006)5,672 -5,672
13 Property Tax (2007)3,084,105 -2,990 3,081,115
14 Propert Tax (2008)6,676,978 3,340,662
15 Colstrip Generation Tax 4,228 4,228
16 KWH Tax (2007)240,285 240,285
17 KWH Tax (2008)1,183,035 915,808
18 Motor Vehicle Tax (2008)3,287 3,287
19 Consumer Council Tax 4,865 46,489 26,904
20 Public Commission Tax 8 24 26
21 Total Montana 3,841,406 7,750,700 7,851,078
22
23 STATE OF OREGON:
24 Income Tax (2006)266,087
25 Income Tax (2007)-528,274 151,254 -377015
26 Income Tax (2008)-214,586 335,000
27 Propert Tax (2005)288,681 -1,467 -287,214
28 Propert Tax (2006)-285,790 -1,424 287,214
29 Propert Tax (2007)-759,157 759,157
30 Propert Tax (2008)900,406 1,910,406
31 Motor Vehicle Tax (2008)1,807 1,807
32 BETC Credit (2000)-387,653 387,653
33 BETC Credit (2001)163,940 -163,940
34 BETC Credit (2002)-46,118 46,118
35 BETC Credit (2003)25,292 -25,292
36 BETC Credit (2004)37,086 -37,086
37 BETC Credit (2005)-82,896 82,896
38 BETC Credit (2006 & Prior)-208,108 -290,349
39 BETC Credit (2007)17,786 191,873
40 BETC Credit (2008)-46,847
41 TOTAL -4,717,808 94,915,994 84,092,608 -1
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 04/16/2009
TAXES ACCI UED, 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 otherwse pending
transmittl of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utilty departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes chafged to utilly plant Of other balance sheet accounts.
9. For any tax apportioned to more than one utilty department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items .. Adjustments to Ret.Other No.
ACC~m236)(Inc!. in Account 165)(Account 408.1, 409.1)(Accunt 409.3)Eamings (Account 439)
(h)(i)0)(k)(I)
21,255 338,468 1
2
6 3
1,673,763 2,544,119 1,563,375 4
4,170,346 5,811,735 2,379,437 5
6
7
8
520,245 9
-59,435 -181,898 10
-347,781 27,219 11
-5,672 12
-2,990 13
3,336,316 6,676,978 14
4,228 15
16
267,227 1,183,035 17
3,287 18
24,450 46,489 19
6 24 20
3,741,028 7,747,413 3,287 21
22
23
266,087 24
-5 -70,944 222,198 25
-549,586 -53,647 -160,939 26
-1,467 27
-1,424 28
-76,843 836,000 29
-1,010,000 71,933 828,473 30
1,807 31
32
33
34
35
36
37
-498,457 38
209,659 191,873 39
-46,847 -46,847 40
6,105,577 48,503,169 46,412,825 41
FERC FORM NO.1 (ED. 12-96)Page 263.1
FERC FORM NO.1 (ED. 12-96)Page 262.2
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) 0 A Resubmission 04/16/2009
TAXES ACCRUED, PREPAID AND CHAI GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accred tax accunts and show the total taxes charged to operations and other accunts during
the year. Do not include gasoline and other sales taxes which have been charged to the accunts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accred taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affeced 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) accrals 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
i~~~Adjust-C argedNo.(See instruction 5)i. axes Accrue9 ~repalc:_ Taxes ~nng ~ring ments(Account 236)(Include in Account 165)ear ear
(a)(b)(c)(d)(e)(f)
1 Glendale Regulatory Tax Cr.-351,469
2 Franchise Tax (2004)-62,168 62,168
3 Franchise Tax (2005)60,185 -60.185
4 Franchise Tax (2006)37,494 -4,616
5 Franchise Tax (2007)1,413,741 1,416,374 2,633
6 Franchise Tax (2008)4,293,223 3,328,956
7 Total Oregon -49,872 5,681,927 6,615,528
8
9 STATE OF CALIFORNIA:
10 Income Tax (2005)-10,400 -8,531
11 Income Tax (2006)-800 -486
12 Income Tax (2007)-1,838 1,362
13 Total California -11,200 -1.838 -7,655
14
15 MISCELLANEOUS STATES:
16 Income Tax (2007)
17 Income Tax (2008)-1.125 -1.124
18 Total Misc States -1,125 -1.124
19
20 COUNTY & MUNICIPAL
21 WA Renewable Energy -9,614 -9,614
22 Misc.3,299 19,310 19,310
23 Total County 3,299 9,696 9,696
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL -4,717,808 94,915.994 84,092,608 -1
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) r=A Resubmission 04116/2009
TAXES ACCI UED, 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 accred and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwse pending
transmittal of such taxes to the taxing authority.
8. Report in COlumns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (i) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utilly departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utilty plant or other balance sheet accunts.
9. For any tax apportioned to more than one utilty department or account, state in a footnote the basis (necessity of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extordinary Items Aoiustmems to Ke!.Other No.ACCO~m236)(Inc!. in Account 165)(Accunt 408.1, 409.1)(Accunt 409.3)Earnings (Accunt 439)
(h)(i)0)(k)(I)
-351,469 -351,469 1
2
3
755 4
5
996,390 4,293,223 6
-983,473 59,481 5,622,446 7
8
9
-1,869 10
-314 11
-3,200 -1,838 12
-5,383 -1,838 13
14
15
16
-1 -1,125 17
-1 -1,125 18
19
20
-9,614 21
3,299 19,310 22
3,299 9,696 23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
6,105,577 48,503,169 46,12,825 41
FERC FORM NO.1 (ED. 12-96)Page 263.2
FERC FORM NO.1 (ED. 12-89)Page 266
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) ¡=A Resubmission 04/16/2009
ACCUMULA ED DEFERRED INVESTMENT TAX REDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utilty and
non utility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).lnclude in column (i)
the average period over which the tax credits are amortized.
i..ine Account Balance at Beginning AliocatlOnsTo
No.SUbdl~~sions of Year Deferred for Year Current Year's Income Adjustments~(c) (d) (e) (f)
1 Electric Utilty
23%
34%
47%
510%
E
7
8 TOTAL
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10 Gas Propertry (100%423,036 411400 49,3~
11
12 TOTAL PROPERTY 423.036 49,3Of
13
14
15
16
17
11:
19
20
21
22
23
24
25
26
27
21:
3C
31
32
33
34
35
36
37
38
39
40
41
42
43
4~
45
46
47
48
...........................................
. FERC FORM NO.1 (ED. 12-S9)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) ñ A Resubmission 04/16/2009
ACCUMULATED D FERRED INVESTMENT TAX CRED S (Accunt 255) (continuèd)
~ADJUSTMENT EXPLANATION Lineof Year of AI ocabon No.to Incomeh i -
1
2
3
4
5
6
7
8
9
373,728 10
11
373,728 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
Page 267
FERC FORM NO.1 (ED. 12-94)Page 269
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) fjA Resubmission 04/16/2009
o HER DEFFERED CREDITS (Accun 253)
1. Report below the partculars (details) called for conceming C?ther deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts les than $10,000, whichever is greater) may be groupe by classes.
Line Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
(b)
Accunt
(e)(f)(a)(c)(d)
1 CCS Install (253000)164 41900 164
2 Pacificorp Capacitor (253080)14,058 456100 9,372 4,686
3
4 Centralia Environmental (253110)965,260 232650 1,374 963,886
5 Rathdrum Refund (253120)408,686 550000 33,822 374,864
6 NE Tank Spil (253130)135,540 186200 36,933 98,607
7 Bils Pole Rentals (253140)202,867 8,753 211,620
8 CR-CS2 GE LTSA (253150)4,739,221 4,739,221
9 IR Swaps (254170)568,713 568,713
10 Sale/Leaseback on Bldg (253850)1,045,824 931000 261,456 784,368
11 Clark Fork Relicensing (253890)-949,317 184999 274,403 -1,223,720
12 Defer Comp Retired Execs (253900)236,392 431100 55,944 180,48
13 Defer Comp Active Execs (253910)12,114,655 128250 3,306,934 8,807,721
14 Executive Incent Plan (253920)140,000 140,000
15 Unbiled Revenue (253990)3,758,203 1,577,265 5,335,468
16 Regulatory Accruals (253650)4,000,000 4,000,000
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL 18,072,332 3,980,402 10,893,952 24,985,882
.....................
. This Page Intentionally Left Blank........... ............
This ~rt Is: Date of Report
(1) ~An Original (Mo, Da. Yr)
(2) A Resubmission 04/16/2009
ACCUMULATE DEFFERED INCOME TAXES - OT ER PROPERTY (Account 82)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to propert not
subject to accelerated amortization
2. For other (Specify,include deferrls relating to other income and deductions.
............................................
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2008104
CHANGES DURING YEAR
Line
No.
Account Balance at
Beginning of Year Amounts Debited
to Accunt 410.1
(c)
Amounts Credited
to Account 411.1
(d)(a)(b)
1 Account 282
2 Electric
3 Gas
4 Other
5 TOTAL (Enter Total of lines 2 thru 4)
6
7
8
9 TOTAL Account 282 (Enter Total of lines 5 thru
10 Classification of TOTAL
11 Federal Income Tax
12 State Income Tax
13 Local Income Tax
243,603,622
65,325,660
11,120.041
320,049,323
20,991,257
9,585,595
1,257,180
31,834,032
320,049,323 31,834,032
309,404,482
10,64,841
31,412,550
421,482
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
.. Name of Respondent
. Avista Corporation
ACCUMULATED DEFERRED INCO
. 3. Use footnotes as required........................................
. FERC FORM NO.1 (ED. 12-96)
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2009
E TAXES - OTHER PROPERTY (Account 282) (Continued)
Year/Period of Report
End of 2008104
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.2 to Account 411.2
ADJUSTMENTS
Debits Balance at Line
End of Year No.
NOTES (Continued)
Page 275
3,246,029 -9,824,248 -285,262
............................................
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/1612009
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 2008/04
1 Accunt 283
2 Electric
3 Electric
4
5
6
7
8
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
11 Gas
12
13
14
15
16
(a)
Balance at
Beginning of Year
(b)
Line
No.
Account
47,772,530 842,539 1,068,560
47,772,530 842,539 1,068,560
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 of TOTAL
21 Federal Income Tax
22 State Income Tax
23 Local Income Tax
3,246,029 -9,824,248 -285,262
188,255,955 4,301,642 -3,620
239,274,514 -4,680,067 779,678
236,223,718 -4,680,067 779,678
3,050,796
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
...........................................
. FERC FORM NO.1 (ED. 12-96)
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2008/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04116/2009
ACCUMULATED EFERRED INCOME TAXES - OTHE (Account 283) (Continue
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.2 to Account 411.2
ADJUSTMENTS
Line
No.
480,536 182
407
737,483 190
46,569191
236
729,555
78,414
402,332
48,019,117
31,845
402,332
480,536 784,052 1,210,301 48,453,294
-60,649 16,366 182 69,457 -6,439,429
-60,649 69,457
1,745,275 190/283
2,598,784
419,887 3,374,248 2,598,784 53,868,087
6,613,716
279,078,915
9,664,572
NOTES (Continued)
Page 277
FERC FORM NO. 1/3-Q (REV 02-04)Page 278
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) flA Resubmission 04/16/2009
o HER REGULATORY LIABILITIES (Accunt 254)
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $50,000 which ever is less),may be grouped
by classes.
3. For Regulatory Liabilties being amortized, show period of amortization.
Balance at Begining DEBITS Balance at End
Line Descrption and Purpose of of Current of Current
No.Other Regulatory Liabilties OuarterlY ear Accunt Amount Credits OuarterlYearCredited
(a)(b)(c)(d)(e)(f)
1 Idaho Investment Tax Credit (254005)7,120,00 1,234,857 8,35,865
2 Oregon BETC Credit (25410)257,98 190 128,99 128,992
3 Oeffered Gas Exchange (254028)49528 49,565 -494,565
4 FAS 109 Invest Tax Credit (254180)227,79 190180 6,639 221,157
5 Nez Perce (254220)79,404 various 5,50 786,902
6 Oregon Senate Bil (254250)3,63,488 407431 1,118,862 2,519,626
7 Reg liabilty CCX CR 10 (254300)754,484 754,484
8 BPA Res Exch Regulatory Liab (25435)407450 1,62.92 -1,629,929
9 Unrealized Currency Exchange (25499)30,876 49,757 80,633
10 Mark to Market FAS133 (254750)53,413,78 8,706,426 44,707,357
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 65,481,339 12,09,915 2,039,098 55,429,522
...................... This Page Intentionally Left Blank........... ............
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da. Yr)End of 2008/04
(2) DA Resubmission 04/16/2009
E ECTRIC OPERATING REVENUES (Accunt 400)
1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (t), and (g). Unbiled revenues and MWH
related to unbiled 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 (t) and (g), on the basis of meters, in addition to the number of flat rate accounts; except tht whre separate meter readings are added
for biling purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twlve figures at the close of
each month.
4. If increases or decreases from previous period (columns (c),(e). and (g)), are not derived fro previously reported figures, explain any inconsstencies in a footnote.
Line Title of Accunt Oprating Revenues Year Operating Revenues
No.to Date Quarterll Annual Previous year (no Quarterl)
(a)(b)(c)
1 Sales of Electricily
2 (440) Residential Sales 279,640,876 251,356,668
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)247,713,799 224.179,531
5 Large (or Ind.) (See Instr. 4)101,785,110 95,206,943
6 (444) Public Street and Highway Lighting 5,961,756 5.516,824
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales 980,339 856,061
10 TOTAL Sales to Ultimate Consumers 636,081,880 577,116.027
11 (447) Sales for Resale 224,672,881 138,609,644
12 TOTAL Sales of Electricity 860,754,761 715.725.671
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provo for Refunds 860,754,761 715,725.671
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues 570.818 558,237
18 (453) Sales of Water and Water Power 306,684 309,017
19 (454) Rent from Electric Propert 2,774,767 2,792,411
20 (455) Interdepartmental Rents
21 (456) Other Electrc Revenues 47,550,273 14,275,491
22 (456.1) Revenues from Transmission of Electricily of Others 9,428,833 10,470,726
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 60,631,375 28,405,882
27 TOTAL Electric Operating Revenues 921,386,136 744,131,553
FERC FORM NO. 1/3-Q (REV. 12-05)Page 300
............................................
............................................
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2008104
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da. Yr)
(2) A Resubmission 04116/2009
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) reularly us 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 classifcation
in a footnote.)
6. See pages 108-109, Important Changes During Period, for importnt new terriory added and important rate increase or decreases.
7. For Lines 2,4.5.and 6, see Page 304 for amounts relating to unbiled revenue by accounts.
8. Include unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD
Year to Date Ouarterly/Annual Amount Previous year (no Ouarterly)(d) (e)
AVG.NO. CUSTOMERS PER MONTH Line
Current Year (no Ouarterly) Previous Year (no Ouarterly) No.(f) (g)
5
6
7
8
13,507 12,842 74 9
9,029,319 8,924,726 352,352 10
3,566,073 2.536,103 11
12,595.392 11,460,829 352,352 12
13
12,595,392 11,460,829 352.352 347,097 14
Line 12. column (b) includes $
Line 12, column (d) includes
10,497,151 of un biled revenues.
90,630 MWH relating to unbiled revenues
FERC FORM NO. 1/3.0 (REV. 12-05)Page 301
Page 304
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Ei A Resubmission 04/16/2009
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electcity sold, revenue, average number of customer, averge Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue accunt in the sequence followed in "Electrc Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue accunt, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entres in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billng periods during the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue biled pursuant thereto.
6. Report amount of un biled revenue as of end of year for each applicable revenue accunt subheading.
¡Line l'lumUer ana IllIe Or t\aie scneauie Mvvn :)010 t\evenue l\verage NumDer ~vvn_or ?aies ~~~folderNo.(a)(b)(c)of c~~\omers Per ?~stomer
(f)
1 RESIDENTIAL SALES (440)
2 1 Residential Service 3,551,301 253,762,316 297,608 11,933 0.0715
3 2 Residential Service
4 3 Residential Service
5 12 Res. & Farm Gen. Service 65,311 6,748,600 12,017 5,435 0.1033
6 15 MOPS II Residential
7 22 Res. & Farm Lg. Gen. Service 49,946 3,490,509 97 514,907 0.0699
a 30 Pumping-Special
9 32 Res. & Farm Pumping Service 14,027 1,042,119 1,659 8,455 0.0743
10 48 Res. & Farm Area Lighting 4,847 994,119 0.2051
11 49 Area Lighting-High-Press.295 67,180 0.2277
12 56 Centralia Refund
13 95 Wind Power 172,291
14 72 Residential Service
15 73 Residential Service
16 74 Residential Service
17 76 Residential Service
18 77 Residential Service
19 58A Tax Adjustment -43,258
20 58 Tax Adjustment 7,253,316
21 SubTotal 3,685,733 273,487,192 311,381 11,837 0.0742
22 Residential-Unbilled 57,963 6,153,68 0.1062
23 Total Residential Sales 3,743,696 279,640,876 311,381 12,023 0.0747
24
25 COMMERCIAL SALES (442)
2€2 General Service
27 3 General Service
28 11 General Service 665,829 61,687,997 33,594 19,820 0.0926
29 12 Res. & Farm Gen. Service
30 16 MOPS II Commercial
31 19 Contract-General Service
32 21 Large General Service 2,032,057 147,948,358 4,460 455,618 0.0728
33 25 Extra Lg. Gen. Service 353,026 17,764,630 13 27,155,846 0.0503
34 28 Contract-Extra Large Serv
35 31 Pumping Service 92,007 6,132,191 1,008 91,277 0.0666
36 47 Area Lighting-Sod. Vap 6,897 1,251,174 0.1814
37 49 Area Lighting-High-Press.2,346 424,214 0.1808
38 56 Centralia Refune
39 95 Wind Power 63,679
40 74 Large General Service
41 TOTAL Biled 12,504,76 850,257,610 352,35 35,89 0.068C
42 Total Unbiled Rev.(See Instr. 6)90,63C 10,497,151 C C 0.1158
43 TOTAL 12,595,39L 860,754,761 352,35~35,741 0.068~
FERC FORM NO.1 (ED. 12-95)
...........................................
. FERC FORM NO.1 (ED. 12-95)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 04/16/2009
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 bils rendered during the year divided by the number of billng periods during the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue account subheading.
I Line Numoer ana I me OT Kate scneouie IVlvvn ;:010 Kevenue Average Numoer ~vvn_oT ?aies ~6'S'blderNo.(a)(b)(c)of c~~\omers Per r~stomer
(f)
1 75 Large General Service
2 76 Large General Service
3 77 General Service
4 58A Tax Adjustment -44,210
558 Tax Adjustment 8,513,743
.6 SubTotal 3,152,162 243,741,782 39,075 80,670 0.0773
7 Commercial-Unbiled 35,670 3,972,017 0.1114
8 Total Commercial 3,187,832 247,713,799 39,075 81,582 0.0777
9
10 INDUSTRIAL SALES (442)
11 2 General Service
12 3 General Service
13 8 Lg Gen Time of Use
14 11 General Service 6,833 645,180 234 29,201 0.0944
15 12 Res. & Farm Gen. Service
16 21 Large General Service 183,873 12,684,216 190 967,753 0.0690
17 25 Extra Lg. Gen. Service 1,783,289 81,528,110 22 81,058,591 0.0457
18 28 Contract - Extra Large Service 862 309,781 1 862,000 0.3594
19 29 Contract Lg. Gen. Service
20 30 Pumping Service - Special 26,900 1,589,966 38 707,895 0.0591
21 31 Pumping Service 54,910 3,766,164 750 73,213 0.0686
22 32 Pumping Svc Res & Firm 4,59£292,863 153 30,039 0.0637
23 47 Area Lighting-Sod. Vap.218 35,37 0.1607
24 49 Area Lighting - High-Press 49 8,095 0.1652
25 95 Wind Power 1,728
2€72 General Service
27 73 General Service
28 74 Large General Service
2~75 Large General Service
30 76 Pumping Service
31 77 General Service
32 58A Tax Adjustment -872
3358 Tax Adjustment 553,392
34 SubTotal 2,061,530 101,413,660 1,388 1,485,252 0.0492
3E Industrial-Unbilled -3,003 371,450 -0.1237
36 Total Industrial 2,058,527 101,785,110 1,388 1,483,089 0.0494
37
38 STREET AND HWY LIGHTING (444)
39 6 Mercury Vapor St. Ltg.
40 7 HP Sodium Vap. St. Ltg
41 TOTAL Biled 12,504,76 850,257,610 352,35_35,481 0.068C
42 Total Unbiled Rev.(See Instr. 6)90,63 10,497,151 (0.115~
43 TOTAL 12,595,39 860,754,761 352,35;¿35,747 0.068:3
Page 304.1
Page 304.2
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 04116/2009
SALES OF ELECTRICITY BY RATE Sl HEDULES
1. Report below for each rate schedule in effect during the year the MWH of eleccily sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale whch is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue accunt in the sequence followed in "Electc Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue accunt, List the rate schedule and sales data under eacti
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue accunt classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the specal schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bils rendered during the year divided by the number of billing periods during the year (12
if all billngs are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue biled pursuant thereto.
6. Report amount of unbiled revenue as of end of year for each applicable revenue accunt subheading.
¡Line Numoer ana Ilte or Kate scneouie Mvvn ~oia Kevenue Average NumDer lwvaor ::aies ~~~folderNo.(a)(b)(c)of C~~\omers Per r~stomer
(f)
1 11 General Service
2 41 Co-Owned St. Lt. Service 221 35,295 16 13,813 0.1597
3 42 Co-Owned St. Lt. Service 20,037 5,261,801 353 56,762 0.2626
4 High-Press. Sod. Vap.
5 43 Cust-Owned St. Lt. Energy 25 2,036 1 25,000 0.0816
6 and Maint. Service
7 44 Cust-Owned St. Lt. Energy 84~101,925 29 29,069 0.1209
a and Maint. Svce - High-Pres
9 Sodium Vapor
10 45 Cust. Owned St. Lt. Energy Svc 1,340 81,650 6 223,333 0.0609
11 46 Cust. Owned St. Lt. Energy Svc 3,291 265,891 29 113,483 0.0808
12 58A Tax Adjustment -970
13 58 Tax Adjustment 214,125
14 SubTotal 25,757 5,961,756 434 59,348 0.2315
15 Street & Hwy Lighting-Unbiled
16 Total Street & Hwy Lighting 25,757 5,961,756 434 59,348 0.2315
17
18 OTHER SALES TO PUBLIC
19 (445)
20 None
21
22 INTERDEPARTMENTAL SALES 13,507 980,006 74 182,527 0.0726
23 58 Tax Adjustment 333
24 Total Interdepartental 13,507 980,339 74 182,527 0.0726
25
2€SALES FOR RESALE (447)
27 61 Sales to Other Utiities (NDA)3,566,073 224,672,881 0.0630
28
29
30 Total Sales for Resale 3,566,073 224,672,881 0.0630
31
32
33
34
35
36
37
3~
3~
40
41 TOTAL Biled 12,504,76 850,257,610 352,35 35,48~0.068C
42 Total Unbiled Rev.(See Instr. 6)90,63(10,497,151 C (0.1158
43 TOTAL 12,595,39"860,754,761 352,35~35,74 0.068~
FERC FORM NO.1 (ED. 12-95)
...................... This Page Intentionally Left Blank........... ............
fERC FORM NO.1 (ED. 12-90)Page 310
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008104
(2) OA Resubmission 04/16/2009
SALES FOR RESALE (Account 4-7)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electrcity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or trncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain 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-termR means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing l\vera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Arizona Public Service SF WSPP-C
2 BC Transmission Corp.SF Tariff 12
3 Barclays Bank PLC SF WSPP-C
4 Barclays Bank PLC SF ISDA
5 Bear Energy LP SF WSPP-C
6 Benton County Public Utility District SF WSPP-C
7 Black Hils Power, Inc.SF WSPP-C
8 BP Energy Company SF WSPP-C
9 Bonnevile Power Administrtion LF Tariff 8
10 Bonnevile Power Administration LF BPAOATI
11 Bonnevile Power Administration SF WSPP-C
12 Bonnevile Power Administration SF Tariff 12
13 Cargill Power Markets, LLC SF WSPP-C
14 Chelan Counly PUD NO.1 SF WSPP-C
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) OA Resubmission 04/16/2009
Si LES FOR RESALE (Accunt 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)(j)(k)
2 130 130 1
15 1,014 1,014 2
159,403 8.649,804 8,649.804 3,
359,686 359,68€4
141,963 9,217,990 9,217,99C 5
210 13,970 13,970 6
400 7,600 7,60C 7
172,395 9,306,920 9,306,920 8
32,854 2.067,677 2,067,677 9
2,142 128,816 128,816 10
45,991 3,047,875 3,047,875 11
23 647 647 12
59,42 2,643,254 2,643,254 13
2,000 104,300 104,300 14
0 0 0 0 0
3,566.073 6,272,815 202,188.645 16,211,421 224,672,881
3,566,073 6,272,815 202,188,645 16,211,421 224,672,881
Page 311
FERC FORM NO.1 (ED. 12-90)Page 310.1
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008104
(2) riA Resubmission 04/16/2009
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 affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions ofthe 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 suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing Avera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Clatskanie Peoples PUD SF WSPP-C
2 Conoco Phillps SF WSPP-C
3 Conoco Philips SF Tariff 9
4 Constellation Energy Commodities Group SF WSPP-C
5 Coral Power, LLC SF WSPP-C
6 Coral Power, LLC SF Tariff 9
7 Credit Suisse Energy LLC SF WSPP-C
8 Douglas Counly PUD No. 1 SF WSPP-C
9 EPCOR Merchant & Capital US SF WSPP-C
10 Eugene Water & Electric Board SF WSPP-C
11 Fortis Energy Marketing & Trading GP SF WSPP-C
12 Franklin County PUD NO.1 SF WSPP-C
13 Grant Counly PUD NO.2 SF WSpp-C
14 Grant County PUD NO.2 SF Tariff 12
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This~rtIS:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04'
(2) A Resubmission 04/16/2009
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariff 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled 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)0)(k)
1,238 71.930 71,93C 1
25 1,943 1,943 2
122,976 122,97E 3
276,615 17.766,319 17,766.3H 4
103,172 6,060,874 6,060.874 5
1,350 1,350 6
3,600 200.100 200,100 7
6 8
600 43,200 43,200 9
2,602 136,520 136,520 10
53,099 2,571,208 2,571,208 11
65 4,375 4,375 12
25.669 1,468,375 1,468.375 13
6 469 469 14
0 0 0 0 0
3.566,073 6,272,815 202,188,645 16.211,421 224.672,881
3,566,073 6,272,815 202,188,64 16,211,421 224,672,881
Page 311.1
FERC FORM NO.1 (ED. 12-90)Page 310.2
............................................
Name of Respondent This
Wrt
Is: Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ri A Resubmission 04/16/2009
SALES FOR RESALE (Account 4 7)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions ofthe service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authorily Statistical FERC Rate Avera~e Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing .Avera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Grant County PUD NO.2 SF Tariff 10
2 Grays Harbor Counly PUD NO.1 SF WSPP-C
3 Highland Energy SF WSPP-C
4 Highland Energy SF Tariff 9
5 Hinson Power Company, LLC SF WSPP-C
6 Iberdrola Renewables, Inc.SF WSPP-C
7 Idaho Power Company SF WSPP-C
8 Idaho Power Company SF Tariff 10
9 Idaho Power Company SF Tariff 12
10 Integry's Energy Service, Inc.SF WSPP-C
11 J. Aron & Company SF WSPP-C
12 JP Morgan Ventures Energy SF WSPP-C
13 Lehman Brothers Commodily Services, Inc SF WSPP-C
14 Modesto Irrigation Distrct SF WSPP-C
Subtotal RO (0 0
Subtotal non-RO 0 0 0
Total 0 0 0
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ñA Resubmission 04/16/2009
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (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 bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (9) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQn 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 ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(9)(h)(i)0)(k)
3,105 3,105 1
115 7,620 7,620 2
10,001 546,938 546,93S 3
889 889 4
512 16,912 16,912 5
121,654 6,432,100 6,432,100 6
71,054 3,839,428 3,839,428 7
100 100 8
58 3,006 3,006 9
3,400 168,700 168,700 10
23,758 831,530 831.530 11
21,630 1,094,890 1,094,890 12
54,000 4,899,200 4,899,200 13
10,484 552.579 552.579 14
0 0 0 0 0
3,566,073 6,272,815 202,188,645 16,211,421 224,672,881
3,566,073 6,272,815 202,188,645 16,211,421 224,672,881
Page 311.2
FERC FORM NO.1 (ED. 12-90)Page 310.3
............................................
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo. Da, Yr)End of 2008104
(2) riA Resubmission 04/16/2009
SALES FOR RESALE (Account 447)
1. Report all sales for resale (I.e.. sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( I.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (I.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
lF - for tong-term service. "long-term" means five years or longer and "firm" means that service cannot be interrpted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of lF service). This category should not be used for long-term firm service which meets the
definition of RQ service. For all transactions identified as lF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as lF service except that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
lU . for long-term service from a designated generating unit. "long-term" means five years or longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availabilty 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 Authorily Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly IIling Avera~e Avera~
cation Tariff Number Demand (MW) Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Morgan Stanley SF WSPP-C
2 NaturEner Glacier Wind Energy 1, LLC SF Tariff 9
3 NaturEner Glacier Wind Energy 1, LLC SF Tariff 9
4 NaturEner Glacier Wind Energy 1, LLC SF Tariff 9
5 NortWestern Energy LLC SF WSPP-C
6 NorthWestern Energy LLC SF Tariff 10
7 NorthWestern Energy LLC LF Tariff 9
8 NorthWestern Energy LLC IF Tariff 10
9 NorthWestern Energy LLC IF Tariff 10
10 NorthWestern Energy LLC IF Tariff 9
11 NorthWestern Energy LLC SF Tariff 12
12 Okanogan County PUD SF WSPP-C
13 PNGC Power SF WSPP-C
14 PacifiCorp SF WSPP-C
Subtotal RO 0 0 0
Subtotal non-RO C 0 0
Total 0 0 0
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) nA Resubmission 04/16/2009
SALES FOR RESALE (Accunt 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (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 (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.($)($)($)
(g)(h)(i)0)(k)
207,399 13,074,311 13,074,311 1
844 46.370 46,37C 2
50,400 50,400 3
12,203 12,203 4
44,921 3,137,828 3,137.828 5
559,29E 559,299 6
8,250 481,749 481,74E 7
2,716,645 2,716,645 8
310,152 310,152 9
38,837 2,476,831 2,476,831 10
90 5,949 5,948 11
9,895 541,390 541,30 12
5,290 340,610 340,610 13
33,783 1,520,386 1,520,386 14
0 0 0 0 0
3,566,073 6,272,815 202.188,645 16,211,421 224,672,881
3,566,073 6,272,815 202,188,645 16,211,421 224,672,881
Page 311.3
FERC FORM NO.1 (ED. 12-90)Page 310.4
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 04/16/2009
SALES FOR RESALE (Account 4 7)
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (I.e., the
supplier includes projected load for this service in its system resourc planning). In addition, the reliabilty of requirements service must
be the same as, or second only to, the supplier's servce to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrpted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing Avera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 PacifiCorp SF Tariff 12
2 PacifiCorp SF Tariff 10
3 PacifiCorp LF Tariff 9
4 Peaker LLC LF Tariff 9
5 Pend Oreile Public Utilty District IF Tari 10
6 Pend Oreile Public Utility Distrct IF Tariff 9
7 Pend Oreile Public Utilty District SF Tariff 10
8 Pend Oreile Public Utilty District SF Tariff 9
9 Portland General Electric Company SF WSPP-C
10 Portland General Electrc Company SF Tariff 12
11 Portland General Electric Company SF Tariff 10
12 Powerex SF WSPP-C
13 Powerex SF Tariff 9
14 Powerex SF Tariff 9
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) OA Resubmission 04/16/2009
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariff 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 (t). For all other types of service, enter NA in columns (d), (e) and (t)' Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on 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 bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)ü)(k)
265 15,569 15,56~1
875 875 2
5,250 306,568 306,6~3
1,749,091 1,749,091 4
407,23~407,23~5
2,352 37,056 37,05t 6
68,90£68,90t 7
36,603 1,961,139 1,961,138 8
68,104 3,561,873 3,561,873 9
81 5,092 5,092 10
6,420 6,420 11
269,594 13,998,960 13,998,960 12
103,521 103,521 13
13,092 13,092 14
0 0 0 0 0
3,566,073 6,272,815 202,188,645 16,211,421 224,672,881
3,566,073 6,272,815 202,188,645 16,211,421 224,672,881
Page 311.4
FERC FORM NO.1 (ED. 12-90)Page 310.5
............................................
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) nA Resubmission 04/16/2009
SALES FOR RESALE (Account 447)
1. Report all sales for resale (I.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electrcity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (I.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly illng Avera~e Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 PPL EnergyPlus, LLC SF Tariff 10
2 PPL EnergyPlus, LLC SF WSPP-C
3 PPL EnergyPlus, LLC LF Tariff 9
4 Public Service of Colorado SF WSPP-C
5 Puget Sound Energy SF WSPP-C
6 Puget Sound Energy SF Tariff 12
7 Puget Sound Energy LF Tariff 9
8 Puget Sound Energy SF Tariff 10
9 Rainbow Energy Marketing SF WSPP-C
10 Redding, City of SF WSPP-C
11 Sacramento Municipal Utilily Distrct SF WSPP-C
12 Sacramento Municipal Utilly District LF WSPP-C
13 Seattle City Light SF WSPP-C
14 Seattle City Light SF Tariff 12
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo. Da, Yr)End of 2008/04
(2) Õ A Resubmission 04/16/2009
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 reportng
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 tariff under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bils rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils r~ndered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
366,683 366,8:1
18,851 1,054,865 1,054,86 2
18,748 1,094,885 1,094,885 3
8,000 415,660 415,660 4
204,849 13,924,578 13,924,578 5
37 2,447 2,447 6
23,997 1,401,453 1,401,453 7
25C 25C 8
102,645 5,692,068 5,692.0as 9
3.645 195,254 195,254 10
55,098 3,647,642 3,647,642 11
643,459 47,832.272 47,832.272 12
13,517 807,729 807,729 13
1 64 64 14
0 0 0 0 0
3,566,073 6,272,815 202,188,645 16,211,421 224.672,881
3,566,073 6,272,815 202,188,645 16,211,421 224,672,881
Page 311.5
FERC FORM NO.1 (ED. 12-90)Page 310.6
............................................
Name of Respondent ThiS~IOrt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo. Da, Yr)End of 2008104
(2)A Resubmission 04/16/2009
SALES FOR RESALE (Account 4 7)
1. Report all sales for resale (I.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( I.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (I.e., the
supplier includes projected load for this service in its system resourc planning). In addition, the reliabilty of requirements servce must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain 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 ofthe contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing Averape Avera~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Sempra Energy Trading SF WSPP-C
2 Shell Energy N.A SF WSPP-C
3 Sierra Pacific Power Company SF WSPP-C
4 Sierra Pacific Power Company SF Tariff 12
5 Snohomish County PUD SF WSPP-C
6 Sovereign Power LF Tariff 9
7 Sovereign Power LF Tariff 10
8 Suez Energy Marketing NA, Inc SF WSPP-C
9 Tacoma Power SF WSPP-C
10 Tacoma Power SF Tariff 10
11 The Energy Authorily SF WSPP-C
12 TransAlta Energy Marketing SF WSPP-C
13 Turlock Irrgation District SF WSPP-C
14 IntraCompany Wheeling LF
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total C 0 0
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da. Yr)End of 2008104
(2) OA Resubmission 04/16/2009
S LES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on 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 bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
165,641 8,970,735 8,970,735 1
48,354 2,556,744 2,556,744 2
4,908 348,808 348,808 3
103 5,990 5,990 4
2,370 134,150 134,150 5
7,750 445,357 445,357 6
114,622 114,622 7
2,000 165,200 165,200 8
8,287 538,566 538,566 9
450 450 10
3,280 162,301 162,301 11
94,905 3,925,770 3,925,770 12
3,558 264,110 264,110 13
-14,817,897 14,817,897 14
0 0 0 0 0
3,566,073 6,272,815 202.188,645 16,211,421 224,672.881
3,566,073 6,272,815 202,188,645 16,211,421 224,672,881
Page 311.6
FERC FORM NO.1 (ED. 12-90)Page 310.7
............................................
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) OA Resubmission 04116/2009
SALES FOR RESALE (Account 447)
1. Report all sales for resale (I.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( I.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (I.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrpted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availability and reliabilty of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate.term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averaße Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly iIing Avera~e Aver~
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 IntraCompany Generation LF
2 Revenue Adjustment AD
3
4
5
6
7
8
9
10
11
12
13
14
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008104
(2) ¡= A Resubmission 04/16/2009
S,LES 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 adjustent. 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 tariff 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 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bils rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(g)(h)(i)0)(k)
679,786 679,786 1
309 18.605 18,605 2
3
4
5
6
7
8
9
10
11
12
13
14
0 0 0 0 0
3,566,073 6,272,815 202,188,645 16,211,421 224,672,881
3,566,073 6,272,815 202,188,645 16,211,421 224,672,881
Page 311.7
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2009
ELE TRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount forNo ~~. W ~
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering
5 501) Fuel
6 (502) Steam Expenses
7 (503) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr.
9 (505) Electric Expenses
10 (506) Miscellaneous Steam Power Expenses
11 (507) Rents
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12)
14 Maintenance
15 (510) Maintenance Supervision and En ineering
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. H draulic 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 Waterw s
56 (544) Maintenance of Electric Plant
57 (545) Maintenance of Miscellaneous Hydraulic Plant
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)
Year/Period of Report
End of 2008/04
Name of Respondent
Avista Corporation
Am,ount.forPrevious Year
(c)
353,838 271,720
28,776,474 26,719,429
1,880,633 1,840,213
814,258 835.130
3,455,151 2,068,116
38,367 29,922
35,318,721 31,764.530
461,747 514,698
526.317 496,664
4,876,984 5.724,096
544,537 1,031,164
637,092 723,773
7,046,677 8,490,395
42,365,398 40,254,925
1,642,209
744,841
3.209,339
4,724,140
984,206
802,071
12,106,806
1,657,569
735,341
2,744,019
4.515,089
718,330
755,035
11,125,383
302,771
312,861
662,450
2,164,716
294,574
3,737.372
15,844,178
309,538
336,239
1,368,818
2,114,811
150,450
4,279,856
15,405,239
FERC FORM NO.1 (ED. 12-93)Page 320
............................................
...........................................
. FERC FORM NO.1 (ED. 12-93)
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) DA Resubmission 04/16/2009
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 ear
(a)(b) (c)
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering 1,650,998 1,202,574
63 (547) Fuel 107,175,030 99,775,888
64 (548) Generation Expenses 1,666,082 1,331,508
65 (549) Miscellaneous Other Power Generation Expenses 455,207 444,348
66 (550) Rents 33,433 21,779
67 TOTAL Operation (Enter Total of lines 62 thru 66)110,980,750 102,776,097
68 Maintenance
69 (551) Maintenance Supervision and Engineering 423,483 942,204
70 (552) Maintenance of Structures 4,186 4,998
71 (553) Maintenance of Generating and Electric Plant 4,920,956 1,749,571
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 114,800 160,317
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)5,463,25 2,857,090
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)116,444,175 105,633,187
75 E. Other Power Supply Expenses
76 (555) Purchased Power 276,853,230 191,126.248
77 (556) System Control and Load Dispatching 500,980 480,570
78 (557) Other Expenses 78,800,960 26,956,543
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)356,155,170 218,563,361
80 TOTAL Power Production Expenses (Total of lines 21. 41, 59, 74 & 79)530,808,921 379,856.712
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering 2,227,450 2,406,849
84 (561) Load Dispatching 1,981,275 -26,009
85 (561.1) Load Dispatch-Reliabilly 16,212
86 (561.2) Load Dispatch-Monitor and Operate Transmission System 1,165,928
87 (561.3) Load Dispatch-Transmission Service and Scheduling 770,853
88 (561.4) Scheduling, System Control and Dispatch Services
89 (561.5) Reliabilty, Planning and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation Interconnection Studies
92 1(561.8) Reliabilly. Planning and Standards Development Services
93 (562) Station Expenses 252,115 166,599
94 (563) Overhead Lines Expenses 505,160 160,177
95 (564) Underground Lines Expenses
96 (565) Transmission of Eiectricity by Others 13,632,001 13,853,279
97 (566) Miscellaneous Transmission Expenses 1,312,796 878,319
98 (567) Rents 100,620 77,306
99 TOTAL Operation (Enter Total of lines 83 thru 98)20,011,417 19,469,513
100 Maintenance
101 (568) Maintenance Supervision and Engineering 591,365 480,094
102 (569) Maintenance of Structures 279,425 324,247
103 (569.1) Maintenance of Computer Hardware
104 (569.2) Maintenance of Computer Softare
105 (569.3) Maintenance of Communication Equipment
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment 1,237,393 990,440
108 (571) Maintenance of Overhead Lines 1,226,863 940,925
109 (572) Maintenance of Underground Lines 1,311 11,075
110 (573) Maintenance of Miscellaneous Transmission Plant 7,209 99,918
111 TOTAL Maintenance (Total oflines 101 thru 110)3,343,566 2,846,699
112 TOTAL Transmission Expenses (Total of lines 99 and 111)23,354,983 22,316,212
Page 321
FERC FORM NO.1 (ED. 12-93)Page 322
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 04/16/2009
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Accunt ~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 Faciltation
117 (575.3) Transmission Rights Market Faciltation
118 575.4) Capacity Market Faciltation
119 (575.5) Ancilary Services Market Faciltation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Faciltation, Monitoring and Compliance Service
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 Softre
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering 1,391,231 1,086,493
135 (581) Load Dispatching
136 (582) Station Expenses 621,675 456,006
137 (583) Overhead Line Expenses 1,975,815 872,105
138 (584) Underground Line Expenses 896,606 1,400,038
139 (585) Street Lighting and Signal System Expenses 194,939 209,843
140 (586) Meter Expenses 1,308,218 908,418
141 (587) Customer Installations Expenses 825,366 886,924
142 (588) Miscellaneous Expenses 5,097,414 4,614,263
143 (589) Rents 191,442 152,361
144 TOTAL Operation (Enter Total of lines 134 thru 143)12,502,706 10,586,451
145 Maintenance
146 (590) Maintenance Supervision and Engineering 1,371,668 1,334,695
147 (591) Maintenance of Strctures 294,513 269,664
148 (592) Maintenance of Station Equipment 750,947 872,990
149 (593) Maintenance of Overhead Lines 7,983,419 6,718,499
150 (594) Maintenance of Underground Lines 1,059,209 1,064,426
151 (595) Maintenance of Line Transformers 678,925 550,762
152 (596) Maintenance of Street Lighting and Signal Systems 610,966 559,751
153 I (597) Maintenance of Meters 145,069 176,847
154 (598) Maintenance of Miscellaneous Distribution Plant 503,563 352,619
155 TOTAL Maintenance (Total of lines 146 thru 154)13,398,279 11,900,253
156 TOTAL Distribution Expenses (Total of lines 144 and 155)25,900,985 22,486,704
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 490,861 533,668
160 (902) Meter Reading Expenses 2,313,137 2,138,197
161 (903) Customer Records and Collection Expenses 7,490,538 7,992,442
162 (904) Uncollectible Accounts 1,927,667 1,635,521
163 (905) Miscellaneous Customer Accounts Expenses 147,464 190,078
164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163)12,369,667 12,489,906
.
.. Name of Respondent This RWrt Is: Date of Report
(1) An Original (Mo, Da, Yr)Avista Corporation. (2) A Resubmission 04/1612009
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Continued)
. If the amount for previous year is not derived from previously reported figures, explain in footnote.. Line Account Amount forNo Current Year. W ~
. 165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
. 166 Operation
167 (907) Supervision
. 168 (908) Customer Assistance Expenses
. 169 (909) Informational and Instructional Expenses
170 (910) Miscellaneous Customer Service and Informational Expenses
. 171 TOTAL Customer Service and Information Expenses (Total 167 thru 170)
. 172 7. SALES EXPENSES
173 Operation
. 174 (911) Supervision
. 175 (912) Demonstrating and Sellng Expenses
176 (913) Advertisin Expenses
. 177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177)
. 179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
. 181 (920) Administrative and General Salaries
. 182 (921) Offce Supplies and Expenses
. 183 (Less) (922) Administrative Expenses Transferred-Credit
184 (923) Outside Services Emplo ed
. 185 (924) Propert Insurance
186 (925) Injuries and Damages
. 187 (926) Employee Pensions and Benefits
. 188 (927) Franchise Requirements
189 (928) Regulato Commission Expenses
. 190 (929) (Less Duplicate Charges-Cr.
191 (930.1) General Advertising Expenses
. 192 (930.2) Miscellaneous General Expenses
. 193 (931) Rents
194 TOTAL Operation (Enter Total of lines 181 thru 193)
. 195 Maintenance
. 196 (935) Maintenance of General Plant
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196)
. 198 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197)................
. FERC FORM NO.1 (ED. 12-93)
Year/Period of Report
End of 2008/04
Am,ountJørPrevious Year
(c)
16,553,310
112,666
145,297
16,811,273
11,181,123
65,646
117,124
11,363,893
424,827
128,150
213,550
766,27
501,591
258,828
189,311
949,730
19,181,918
3,782,093
38,836
10,997,229
1,015,509
2,968,505
1,186,191
5,950
4,783,704
19,387,201
3,633,500
34,969
11,687,401
1,128,497
3,289,641
991,605
6,327
4,315,148
4,017
3,198,612
590,566
47,675,458
9,097
3,092,795
698,836
48,205,079
7,319,496
54,994,954
665,007,310
7,127,608
55,332,687
504,795,844
Page 323
FERC FORM NO.1 (ED. 12-90)Page 326
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) OA Resubmission 04/16/2009
PU~CHAdrED POWER hAccu9t 5 5)
(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 part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is servce which the supplier plans to provide on an ongoing basis (I.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as U= service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electncity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the length of the contract and service from designated units of less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW) Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 BP Energy Comp IF WSPP
2 BP Energy Comp SF WSPP
3 BP Energy Comp SF ISOA
4 Barclays Bank PLC SF WSPP
5 Barclays Bank PLC SF ISDA
6 Bear Energy SF WSPP
7 Benton Counly PUD NO.1 SF WSPP
8 Black Creek Hydro LU FERC#1
9 Black Hils Power SF WSPP
10 Bonnevile Power Administrtion LF WNP#3Agr.
11 Bonnevile Power Administration SF WSPP
12 Bonnevile Power Administration EX PNCA
13 Bonnevile Power Administration SF Tariff #8
14 Bonnevile Power Administration OS BPAOATI
Total
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo. Da, Yr)End of 2008/04
(2) n A Resubmission 04/16/2009
ccouRtl~8gS) (GOntinUeO)(Including pòwer exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reportng
years. Provide an explanation in a footnote for each adjustment.
4. In column (c). identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (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 bils rendered to the respondent. Report in columns (h) and (i) the megawattours
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 U+k+l)No.Received Delivered
~l ~i~~fl
of Settement ($)
(g)(h)(i)(m)
219,59 7,576,20C 7,576,200 1
23,76f 1,448,15S 1,448,15S 2
1,706,752 1,706,752 3
212,231 16,063,99;¿16,063,992 4
1,065,876 1,065,876 5
101,02.7,782,74A 7,782,744 6
2.30C 177,18~177,185 7
311 12,991 12,997 8
40C 35,60C 35,600 9
374,99~13,283.091 13,283,097 10
128,001 6,201,35f 6,201,35f 11
16.965 17,250 87,78f -12,435 75,353 12
33,501 1,916,661 1,916,667 13
13,528 13,52f 14
5,686,485 718,926 720,744 4,292,113 269,923,183 2,637,934 276,853,23C
Page 327
FERC FORM NO.1 (ED. 12-90)Page 326.1
............................................
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008104
(2)A Resubmission 04/16/2009
PU~CHAJlED POWER hAccou~t 5 5)nclu 109 power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (I.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is servce which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW) Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Bonnevile Power Administration SF BPAOATT
2 Cargil Power Markets, LLC SF WSPP
3 Chelan Counly PUD NO.1 LU Rocky Reach
4 Chelan County PUD NO.1 SF WSPP
5 City of Spokane LU PURPA
6 Clatskanie Peoples PUD SF WSPP
7 Constellation Energy Commodities Group SF WSPP
8 Douglas County PUD NO.1 LU Wells
9 Douglas County PUD NO.1 LU Wells Settement
10 Douglas Counly PUD NO.1 IF Wells
11 Douglas Counly PUD NO.1 SF WSPP
12 Douglas Counly PUD NO.1 EX 305
13 EPCOR Merchant & Capital US SF WSPP
14 Eugene Water & Electric Board SF WSPP
Total
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent ThisR,!lOrt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) =A Resubmission 04/16/2009
~ .,,' ~(
ccouRtl~8gl~ (L;ontlnUeo¡
nc udmg 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 biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliets system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components ofthe amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered
~l \t~\fl
of Settlement ($)
(g)(h)(i)(m)
10,04C 737,40S -167,821 569,587 1
55,18€3,414,33€3,414,336 2
165,OOC 2,115,51S 2,115,518 3
2,OO~76,76"76,765 4
45,91~1,776,46~1,776,464 5
1,35~80,67~80,675 6
132,95~8,495,57A 8,495,574 7
148,06€1,315,05~1,315,059 8
26,60.475,87A 475,874 9
2,800,503 2,800,503 10
61,30 4,138,63 4,138,637 11
114,525 114,479 1,576,25C 1,590 1,577,840 12
2,40C 220,09 220,092 13
7,813 360,339 360,339 14
5,686,485 718,926 720,744 4,292,113 269,923,183 2,637,934 276,853,23C
Page 327.1
FERC FORM NO.1 (ED. 12-90)Page 326.2
............................................
Name of Respondent ThiS~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 04/16/2009
PU~C~A~ED POWER hAccou9t 5 5)
n u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange trnsaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the 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 reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm servces, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling -Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Fortis Energy Mkt SF WSPP
2 Ford Hydro Limited Partnership LU PURPA
3 Franklin County PUP NO.1 SF WSPP
4 Grant County PUP NO.2 LU Wanapum
5 Grant County PUP NO.2 LU Priest Rapids
6 Grant County PUD NO.2 LU PR Displacement
7 Grant Counly PUD NO.2 SF WSPP
8 Grays Harbor County PUD NO.1 SF WSPP
9 Highland Energy IU WSPP
10 Hydro Technology Systems LU PURPA
11 Idaho Power Company SF WSPP
12 Inland Power & Light Company RO 208
13 J P Morgan Ventures Energy SF WSPP
14 Jim White LU PURPA
Total
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This Re ort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ==A Resubmission 04/16/2009
.. .,. -(
ccou~~~8gS) (ContinueClJnc udiñ pòwer 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 biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered ($)($~($)of Settlement ($)
(g)(h)(i)0)(k (I)(m)
36,18~2,715,5H 2,715,516 1
3,65"1 188,38f 188,388 2
661 47,66~47,669 3
326,28C 5,715,40"5,715,404 4
138,34~5,253,03C 5,253,030 5
194,571 4,625,161 4,625,161 6
25,32C 1,341.64f 1,341,646 7
65~44,44"44,445 8
36,581 2,231,74 2,231,742 9
8,501 396,361 396,361 10
14,52"1 834,07f 834,078 11
13"1 7,05¿7,054 12
35,12"1 2,417,84.2,417,842 13
95E 85.211 85,211 14
5,686,485 718,926 720,744 4,292,113 269.923,183 2,637,934 276,853,23C
Page 327.2
FERC FORM NO.1 (ED. 12-90)Page 326.3
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da. Yr)End of 2008/04
(2) nA Resubmission 04/16/2009
PU~C~AciED POWER hAccou~t 5 5)nc u ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions ofthe service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX -For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authorily Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 John Day Hydro LU PURPA
2 Kalich, Clint LU PURPA
3 Lehman Bothers SF WSPP
4 Mirant Energy Trading SF WSPP
5 Morgan Stanley Capital Group IF WSPP
6 Morgan Stanley Capital Group SF WSPP
7 Morgan Stanley Capital Group SF ISDA
8 NorthWestern Energy LLC SF WSPP
9 Okanogan County PUD NO.1 SF WSPP
10 PPL Energy Plus SF WSPP
11 PPM Energy LU PPM Energy
12 PPM Energy SF WSPP
13 PacifiCorp SF WSPP
14 Pacific NW Gen Corp SF WSPP
Total
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr).End of 2008/04
(2) CJ A Resubmission 04/16/2009
,ccouR~~8gs~ (ContinUed),-, .. 'nnëíuding pòwer 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 suppliets system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (i). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settement
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 ofthe 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 COSTISETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered ~l \t~\fl
of Settlement ($)
(g)(h)(I)(m)
2,09~90,18€90,186 1
1 171 171 2
12,92~954,03€954,036 3
6,80(564,OOf 564,008 4
658.74~20,245,97f 20,245,978 5
149,12 8,906,311 8,906,317 6
129,392 129.392 7
50,51€2,866,17~2,866,172 8
62,402 3,951,331 3,951,331 9
634,96(35,086,45~35,086,455 10
84,71 (3,344,62 3,34,621 11
145,541 9,883,8H 9,883.819 12
60,93C 3,645,85f 3,645,858 13
4,53"276,13t 276,13€14
5,686,485 718,926 720,744 4,292,113 269,923,183 2,637,934 276,853,23C
Page 327.3
FERC FORM NO.1 (ED. 12-90)Page 326.4
.........................................."..
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) DA Resubmission 04/16/2009
PU~C~~ED POWER ~Accou9t 5 5)
n ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le.. transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions'of the service as follows:
RQ - for requirements service. Requirements service is servce which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longerthan one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy. capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined 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 Authrily Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Pend Oreile County PUD NO.1 SF Pend 0'
2 Pend Oreile County PUD No. 1 SF Pend 0'
3 Philips Ranch LU PURPA
4 Portland General Electric Company EX 304
5 Portland General Electric Company EX 178
6 Portland General Electric Company SF WSPP
7 Potlatch Corporation LU PURPA
8 Powerex Corp SF WSPP
9 Powerex Corp SF WSPP
10 Puget Sound Energy SF WSPP
11 Rainbow Energy Marketing Corp SF WSPP
12 Seattle City Light SF WSPP
13 Seattle City Light EX WSPP
14 Sempra Energy Trading SF WSPP
Total
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This Re ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ==A Resubmission 04/16/2009v."" (nc uding pòwe~~ã~3g~) ((;ontinueo)
AD - for out-of-penod adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
~?æ \f?
of Settement ($)
(g)(h)(i)(m)
3,225 385,02€385,02€1
69,964 19,652 20,829 4,451,47€-86,974 4,364,502 2
31 2,274 2,274 3
10,533 10,496 4
447,067 447,690 ...~11,974 -11,974 5
11,829 871,01~871,15 6
418,23:J 17,950,56C 17,950,560 7
47,39E 3,735,90,3,735,903 8
1,491,360 1,491,360 9
41,91S 2,928,83.2,928,832 10
193,624 9,992,995 9,992,999 11
53,42:J 3,911,42¿3,911,424 12
110,000 110,000 1,705,OOC 1,705,000 13
126,081 10,094,421 10,094,421 14
5,686,485 718,926 720,744 4,292,113 269,923,183 2,637,934 276,853,23C
Page 327.4
FERC FORM NO.1 (ED. 12-90)Page 326.5
............................................
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) nA Resubmission 04/16/2009
PU~CHAJlED POWER hAccou~t 5 5)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 part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the 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 reliabilty of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
IF - for long-term firm service. "long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of IF 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 IF, 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 IF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services. where the duration of each period of commitment for service is one
year or less.
lU - for long-term service from a designated generating unit. "long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliabilty of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the length of the contract and service from designated units of less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Biling Average Average
cation Tariff Number Demand (MW) Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(1)
1 Sheep Creek Hydro LU PURPA
2 Shell Energy SF WSPP
3 Shell Energy SF WSPP
4 Sierra Pacific Power Company SF WSPP
5 Silicon Valley Power SF WSPP
6 Snohomish Counly PUD NO.1 SF WSPP
7 Sovereign Power IF Sovereign
8 Stimson Lumber IU PURPA
9 Suez Energy Mkt SF WSPP
10 Tacoma Power SF WSPP
11 The Energy Authorily SF WSPP
12 TransAlta Energy Marketing SF WSPP
13 Tucson Electric SF WSPP
14 IntraCompany Generation Services OS OATT
Total
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) riA Resubmission 04/16/2009
ccouR~~ggS) (ContinUed)(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 biling demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the 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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (i). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered ($)
~~~\~l
of Settement ($)
(g)(h)(i)ij (m)
5,43 323,25~323,254 1
159,02~12,595,471 12,595,471 2
250 250 3
3,85..208.14~208,142 4
6C 1,62C 1,620 5
5,75€241,24C 241.240 6
2,78 157,49~157,494 7
37,36 1,999,55 1,999,557 8
1,20C 85,98C 85,980 9
20,20~737,15€737,158 10
9,75C 406,96 406,967 11
25,67~1,365,99f 1,365,998 12
4~4,16~4,165 13
679,78.679,78'l 14
5,686,485 718,926 720,744 4,292,113 269,923,183 2,637,934 276,853,23C
Page 327.5
FERC FORM NO.1 (ED. 12-90)Page 326.6
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008104
(2) ri A Resubmission 04/16/2009
PU~CHAdlED POWER hAccou~t 5 5)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 part in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions ofthe service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliabilty of requirement service must
be the same as, or second only to, the suppliets service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availabilty and reliabilty of
service, aside from transmission constraints, must match the availabilty and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affliations)Classifi-Schedule or Monthly Billng Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Other - Inadvertent Interchange EX
2
3
4
5
6
7
8
9
10
11
12
13
14
Total
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This Report Is:Date of Report YearlPeriod of Report
Avista Corporation (1) 'X An Original (Mo, Da, Yr)End of 2008/04
(2) F A Resubmission 04/16/2009
ccouR~~ggS) \ ~ominueoi-i1ncludíng 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 billng demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (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 bils rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components ofthe amount shown in column (I). Report in column (m)
the total charge shown on bils received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (i)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETILEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total Q+k+l)No.Received Delivered ~l ~i~\~l
of Settlement ($)
(g)(h)(i)(m)
184 1
2
3
4
5
6
7
8
9
10
11
12
13
14
5,686,485 718,926 720,744 4,292,113 269,923,183 2,637,93~276,853,23C
Page 327.6
FERC FORM NO.1 (ED. 12-90)Page 328
............................................
Name of Respondent This I ~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1 )~An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 04/16/2009
.., t:YKv.1 .'~ '.,:.~,ccoUm40i:.1J(Including trnsactions referred to as 'wheeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilties, 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 affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions ofthe 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 Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Vaagen Bros Lumber Vaagen Bros Lumber Idaho Power Company LFP
2 PacifiCorp PacifiCorp PacifiCorp LFP
3 Seattle City Light Seattle City Light Bonnevile Power Administration LFP
4 Tacoma City Light Tacoma City Light Bonnevile Power Administration LFP
5 Grant County PUD Grant County PUD Grant Counly PUD LFP
6 Spokane Indian Tribes Bonneville Power Administrtion Spokane Indian Tribes LFP
7 USBR Bonneville Power Administration East Greenacres LFP
8 Consolidated Irrigation District Bonnevile Power Administrtion Consolidated Irrigation District LFP
9 Bonneville Power Administration Bonnevile Power Administrtion Bonnevile Power Administration FNO
10 City of Spokane Cily of Spokane Puget Sound Energy LFP
11 Bonnevile Power Administration Bonneville Power Administration Idaho Power Company NF
12 Bonnevile Power Administration Bonneville Power Administration Avista Corporation NF
13 Bonnevile Power Administration NorthWestem Montana Bonnevile Power Administrtion NF
14 Bonnevile Power Administration Bonnevile Power Administrtion Idaho Power Company SFP
15 Idaho Power Company Portland General Electric Idaho Power Company NF
16 Idaho Power Company Avista Corporation Idaho Power Company NF
17 Idaho Power Company Grant County Public Utilty Dist Idaho Power Company NF
18 Idaho Power Company PacifiCorp Idaho Power Company NF
19 Idaho Power Company Douglas County PUD Idaho Power Company NF
20 Idaho Power Company Puget Sound Energy Idaho Power Company NF
21 Idaho Power Company Chelan Public Utility District Idaho Power Company NF
22 Idaho Power Company Avista Corporation Bonnevile Power Administration NF
23 Idaho Power Company Idaho Power Company Bonnevile Power Administration NF
24 Idaho Power Company Idaho Power Company Avista Corporation NF
25 Idaho Power Company Bonneville Power Administrtion Idaho Power Company NF
26 Idaho Power Company Idaho Power Company PacifiCorp NF
27 Idaho Power Company Idaho Power Company Puget Sound Energy NF
28 Idaho Power Company NorthWestern Montana Idaho Power Company NF
29 Idaho Power Company Idaho Power Company Grant County Public Utiity Dist NF
30 Idaho Power Company Chelan Public Utilily District Idaho Power Company NF
31 Idaho Power Company Bonnevile Power Administration Idaho Power Company SFP
32 Idaho Power Company Bonnevile Power Administration NorthWestern Montana SFP
33 Idaho Power Company Avista Corporation Bonnevile Power Administration SFP
34
TOTAL
............................................
Name of Respondent ThIS~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 04/16/2009
y r-YK I. ccount 4ot))((;ontlnUeO)
(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 biling demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (I) and U) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billng TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand Megawan HOUrs MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
FERC No. 228 Colvile Substation Lolo-Oxbow 230 kv ~24,334 24,33'1
FERC No. 182 Lolo-Oxbow 230 kv Dry Gulch 20 58,790 58,79(2
FERC Trf NO.8 Chelan-Stratford 115 Stratford 115kV SS 191,707 191,70 3
FERC Trf NO.8 Chelan-Stratford 115 Stratford 115kV SS 191,706 191,70E 4
FERC No. 104 Larson Substation Round Lake/Coulee Cy 25 83,375 83,37~5
FERC Trf NO.8 Sunset Westside 2 3,233 3,23.6
FERC No. 80.2 Bell Substation East Greenacres 3 3,162 3,16~7
FERC Trf NO.8 Bell Substation Consolidated 4 5,706 5,701 8
FERC Trf NO.8 1,845,468 1,845,61 9
No 155 Sunset-Westside 115k Westside 23 128,135 128,13~10
FERC Trf NO.8 23,248 23,241 11
FERC Trf NO.8 12
FERC Trf NO.8 100 10(13
FERC Trf NO.8 20,393 20,39 14
FERC Trf NO.8 200 20(15
FERC Trf NO.8 2,400 2,40(16
FERC Trf NO.8 1,448 1,44 17
FERC Trf NO.8 650 65(18
FERC Trf NO.8 1,064 1,06'19
FERC Trf NO.8 200 20(20
FERC Trf NO.8 1,420 1,42(21
FERC Trf No. 8 1,600 1,60(22
FERC Trf NO.8 21,054 21,05'23
FERC Trf NO.8 2,168 2,16~24
FERC Trf NO.8 74,222 74,222 25
FERC Trf NO.8 600 60C 26
FERC Trf NO.8 1,998 1,99€27
FERC Trf NO.8 214 21~28
FERC Trf NO.8 400 40C 29
FERC Trf NO.8 4,914 4,91~30
FERC Trf NO.8 233,762 233,76~31
FERC Trf NO.8 1,477 1,471 32
FERC Trf NO.8 7,800 7,80(33
34
81 3,293,560 3,293,56(
FERC FORM NO.1 (ED. 12-90)Page 329
FERC FORM NO.1 (ED. 12-90)Page 330
............................................
Name of Respondent This oo0rt Is:Date of Repo YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) Õ A Resubmission 04/16/2009
T i-gK '- '. ccu~t 4ÒÖ) (I,onunuoo)
(Including transactons reftered to as 'weeling')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on 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 bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and u) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote 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)
67,488 24,334 28,281 120,103 1
261,516 261,516 2
120,524 120,524 3
120,524 120,524 4
27.711 27,711 5
14.582 14,582 6
16,588 16,588 7
35,448 35,448 8
5,431,948 5,431,948 9
127,506 32.088 159,594 10
87,236 87,236 11
11,468 11,468 12
204 204 13
71,771 71,771 14
800 800 15
9,019 9,019 16
5,634 5,634 17
2,600 2,600 18
3,551 3,551 19
747 747 20
5,284 5,284 21
4,654 4,654 22
98,081 98,081 23
8,672 8,672 24
302,222 302,222 25
2,400 2,400 26
7,992 7,992 27
719 719 28
1,600 1,600 29
18,713 18,713 30
853,617 853,617 31
5,654 5,654 32
30,744 30,744 33
34
7,914,641 1,453,822 60,369 9,428,832
............................................
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ri A Resubmission 04116/2009
IOF t:(,K U.I ..'" ccount 456.1 )
(Including transactions referred to as 'weelingo)
1. Report all transmission of electricity, I.e., wheeling, provided for other electric utilties, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-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 Authorily)(Company of Public Authority (Company of Public Authorily)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Idaho Power Company Grant Counly Public Utilty Dist Idaho Power Company SFP
2 Idaho Power Company Idaho Power Company Bonnevile Power Administration SFP
3 NorthWestern Energy NortWestern Montana Bonneville Power Administration NF
4 NorthWestern Energy NorthWestern Montana Puget Sound Energy NF
5 NorthWestern Energy NorthWestern Montana Chelan Public Utilly District NF
6 NorthWestern Energy NorthWestem Montana Portland General Electric NF
7 NorthWestern Energy NorthWestem Montana Idaho Power Company SFP
8 PacifiCorp PacifiCorp Bonnevile Power Administration NF
9 PacifiCorp NorthWestern Montana PacifiCorp NF
10 PacifiCorp PacifiCorp NorthWestern Montana NF
11 PacifiCorp PacifiCorp Idaho Power Company NF
12 PacifiCorp PacifiCorp Bonnevile Power Administration SFP
13 PacifiCorp Avista Corporation Bonneville Power Administration NF
14 PacifiCorp PacifiCorp Bonnevile Power Administration NF
15 Powerex NortWestern Montana Bonnevile Power Administration NF
16 Powerex Idaho Power Company Bonnevile Power Administration NF
17 Powerex Bonneville Power Administration Idaho Power Company NF
18 Powerex Avista Corporation Bonnevile Power Administration NF
19 Powerex Bonnevile Power Administration Idaho Power Company SFP
20 Powerex NorthWestern Montana Bonnevile Power Administration SFP
21 Puget Sound Energy Puget Sound Energy Idaho Power Company NF
22 Puget Sound Energy NorthWestern Montana Puget Sound Energy NF .
23 Puget Sound Energy NorthWestern Montana Bonnevile Power Administration NF
24 Puget Sound Energy Idaho Power Company Puget Sound Energy NF
25 Constellation Energy Commodities Group Avista Corporation NorthWestern Montana NF
26 Portland General Electric NorthWestern Montana Portland General Electric NF
27 Portland General Electric Idaho Power Company Portland General Electric NF
28 Portland General Electric NortWestern Montana Bonnevile Power Administrtion NF
29 Portland General Electric NorthWestern Montana Bonnevile Power Administration SFP
30 Morgan Stanley Capital Group Bonnevile Power Administration NortWestern Montana NF
31 Morgan Stanley Capital Group Bonnevile Power Administration Idaho Power Company NF
32 Morgan Stanley Capital Group NorthWestem Montana Bonnevile Power Administration NF
33 Morgan Stanley Capital Group Bonnevile Power Administration NorthWestern Montana SFP
34
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.1
FERC FORM NO.1 (ED. 12-90)Page 329.1
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) OA Resubmission 04/16/2009
l.!" i-YK '-! ni:l'~ J/'. ccun. ....vl\"'onnnueö)(Including transactions reffered to as 'wIeeling')
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 biling 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 megawattours received and delivered.
FERC Rate Point of Receipt Point of Delivery Biling TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt HOUrs MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
FERC Trf NO.8 400 40C 1
FERC Trf NO.8 7,811 7,811 2
FERC Trf NO.8 4,794 4,79A 3
FERC Trf NO.8 626 62€4
FERC Trf NO.8 309 30~5
FERC Trf NO.8 539 53~6
FERC Trf NO.8 7
FERC Trf No. 8 1,430 1,43C 8
FERC Trf NO.8 6,376 6,37€9
FERC Trf NO.8 264 26A 10
FERC Trf NO.8 961 961 11
FERC Trf NO.8 1,139 1,13~12
FERC Trf No.8 13
FERC Trf NO.8 1,247 1,241 14
FERC Trf NO.8 22,835 22,83E 15
FERC Trf NO.8 4,578 4,57~16
FERC Trf NO.8 21,055 21,05E 17
FERC Trf NO.8 1,523 1,52~18
FERC Trf No. a 8,390 8,39C 19
FERC Trf NO.8 9,901 9,901 20
FERC Trf NO.8 67 61 21
FERC Trf NO.8 97 9 22
FERC Trf NO.8 725 72E 23
FERC Trf NO.8 710 71C 24
FERC Trf NO.8 56 5€25
FERC Trf NO.8 16,763 16,76~26
FERC Trf NO.8 125 12E 27
FERC Trf NO.8 1,876 1,87E 28
FERC Trf NO.8 688 68~29
FERC Trf NO.8 400 40C 30
FERC Trf NO.8 434 43¿31
FERC Trf NO.8 2,201 2,201 32
FERC Trf NO.8 11,047 11,0 33
34
81 3,293,560 3,293,56(
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This F~ort Is:Date of Report Year/Period of Report
Avista Corpration (1 )~An Original (Mo, Da. Yr)End of 2008/04
(2)A Resubmission 04/16/2009
u.r .. .' FQR q i, .... ":w ccouat 40Ö) ii;ontlnUea)
(Including transactions reffered to as ' eeling')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the biling demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
1,102 1,102 1
23,254 23,254 2
20,408 20,408 3
3,111 3,111 4
1,589 1,589 5
2,860 2,860 6
29,400 29,400 7
43,171 43,171 8
37,720 37,720 9
1,168 1,168 10
9,245 9,245 11
11,499 11,499 12
400 400 13
7,616 7,616 14
100,696 100,696 15
19,484 19,484 16
76,197 76,197 17
5,211 5,211 18
75,130 75,130 19
33,980 33,980 20
298 298 21
776 776 22
4,6138 4,688 23
4,591 4,591 24
224 224 25
72,362 72,362 26
552 552 27
8,702 8,702 28
2,778 2,778 29
1,600 1,600 30
2,960 2,960 31
9,524 9,524 32
57,624 57,624 33
34
7,914,641 1,453,822 60,369 9,428,8321
Page 330.1
FERC FORM NO.1 (ED. 12-90)Page 328.2
............................................
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) nA Resubmission 04/16/2009
......'" i KIl.l i T FOR U.I ccunn6:-t)
(Including transactions referred to as 'wheeling')
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying faciliies, non-traditional utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public 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 affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions ofthe 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 Authorily)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 Sierra Pacific Power Company Bonneville Power Administrtion Idaho Power Company NF
2 Sierra Pacific Power Company Bonneville Power Administration NorthWestern Montana NF
3 Sierra Pacific Power Company Avista Corporation Bonnevile Power Administration NF
4 Sierra Pacific Power Company Bonnevile Power Administration Idaho Power Company SFP
5 Cargil Power Markets NorthWestem Montana Bonnevile Power Administration NF
6 Cargil Power Markets NorthWestem Montana Idaho Power Company NF
7 Cargil Power Markets Idaho Power Company Bonneville Power Administration NF
8 Cargill Power Markets Idaho Power Company PacifiCorp NF
9 Cargil Power Markets Bonnevile Power Administration Idaho Power Company NF
10 Cargil Power Markets Bonneville Power Administration NorthWestem Montana NF
11 Cargil Power Markets NortWestern Montana Chelan Public Utilly District NF
12 Cargil Power Markets NorthWestern Montana Grant County PUD NF
13 Cargil Power Markets Chelan Public Utilty District Idaho Power Company NF
14 Cargil Power Markets Bonnevile Power Administration Idaho Power Company SFP
15 Cargil Power Markets Bonnevile Power Administration Idaho Power Company SFP
16 Cargil Power Markets NortWestern Montana Bonnevile Power Administration SFP
17 Rainbow Energy Marketing Corp Bonnevile Power Administration Idaho Power Company NF
18 Rainbow Energy Marketing Corp Bonneville Power Administration NorthWestern Montana NF
19 Rainbow Energy Marketing Corp Bonnevile Power Administration Idaho Power Company SFP
20 Coral Power NorthWestern Montana Chelan Public Utility Distrct NF
21 Coral Power NorthWestern Montana Puget Sound Energy NF
22 Coral Power Chelan Public Utilily Distrct Idaho Power Company NF
23 Coral Power Chelan Public Utilty District NorthWestern Montana NF
24 Coral Power Bonnevile Power Administration NorthWestem Montana NF
25 Coral Power Bonnevile Power Administration Idaho Power Company NF
26 Coral Power NorthWestern Montana Bonnevile Power Administration NF
27 Coral Power NorthWestern Montana Grant County PUD NF
28 Coral Power Idaho Power Company Chelan Public Utilty District NF
29 Coral Power Idaho Power Company Bonnevile Power Administration NF
30 PPL Energy Plus NorthWestern Montana Grant County PUD NF
31 PPL Energy Plus NortWestern Montana Bonnevile Power Administration NF
32 PPL Energy Pius NorthWestem Montana Chelan Public Utility District NF
33 PPL Energy Plus Idaho Power Company Bonnevile Power Administration NF
34
TOTAL
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo. Da, Yr)End of 2008/04
(2) Õ A Resubmission 04/16/2009
,........ I KI~II Y i-YK (. I H~K.:: .(1 ccount 456)(Continued)
(Including transactions reffered to as 'wIeeling')
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 ü) 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 lIegawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)(g)(h)(i)0)
FERC Trf NO.8 51,417 51,41 1
FERC Trf NO.8 400 40C 2
FERC Trf NO.8 1,800 1.80C 3
FERC Trf NO.8 33,541 33,541 4
FERC Trf NO.8 309 3m 5
FERC Trf NO.8 520 52(6
FERC Trf NO.8 342 34.7
FERC Trf NO.8 24 2'8
FERC Trf NO.8 4.704 4,704 9
FERC Trf NO.8 12,781 12.781 10
FERC Trf NO.8 16 1E 11
FERC Trf NO.8 350 35C 12
FERC Trf NO.8 680 68C 13
FERC Trf NO.8 8,413 8,41~14
FERC Trf NO.8 26,721 26,721 15
FERC Trf NO.8 42 4,16
FERC Trf NO.8 1.041 1,041 17
FERC Trf NO.8 210 21C 18
FERC Trf NO.8 20,095 20,09'19
FERC Trf NO.8 21,523 21,52,20
FERC Trf NO.8 125 12!21
FERC Trf NO.8 95 9'22
FERC Trf NO.8 158 151 23
FERC Trf NO.8 43 4 24
FERC Trf NO.8 532 53~25
FERC Trf NO.8 390 39C 26
FERC Trf NO.8 50 5C 27
FERC Trf NO.8 40 4(28
FERC Trf NO.8 675 6n 29
FERC Trf NO.8 8,164 8,16'30
FERC Trf NO.8 3.822 3,82.31
FERC Trf NO.8 595 59~32
FERC Trf NO.8 609 60!33
34
81 3,293,560 3,293,56~
Page 329.2
FERC FORM NO.1 (ED. 12-90)Page 330.2
............................................
Name of Respondent ThiS~ort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 04/16/2009
i i o.F ELE ; i KIL;l I Y ~~ ccunt ntinued
(Including transactions reffered to as eeling')
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bils rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and ü) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)(k+l+m)No.
(k)(I)(m)(n)
175,036 175,036 1
1,665 1,665 2
6,487 6,487 3
106,395 106,395 4
1,272 1,272 5
2,161 2,161 6
1,439 1,439 7
96 96 8
15,508 15,508 9
38,544 38,544 10
66 66 11
1,529 1,529 12
3,340 3,340 13
44,600 44,600 14
100,621 100,621 15
1,615 1,615 16
3,416 3,416 17
552 552 18
49,000 49,000 19
92,103 92,103 20
530 530 21
526 526 22
672 672 23
177 177 24
2,370 2,370 25
1,655 1,655 26
211 211 27
194 194 28
2,890 2,890 29
34,005 34,005 30
16,250 16,250 31
2,594 2,594 32
2,551 2,551 33
34
7,914,641 1,453,822 60,369 9,428,832
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) Õ A Resubmission 04/16/2009
i I.Ut- t:Lt(. I KIl¿l I Y '."" ~ ~&~ccount 456.1)
(Including transactions referred to as 'wheelin '
1. Report all transmission of electricity, I.e., wheeling, provided for other electric utilties, cooperatives, other public authorities,
qualifying facilties, non-traditional utilty suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public 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 affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions ofthe 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 Authorily)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affliation)(Footnote Affliation)(Footnote Affliation)cation
(a)(b)(c)(d)
1 PPL Energy Plus NorthWestern Montana Puget Sound Energy NF
2 Highland Energy NorthWestern Montana Grant Counly PUD NF
3 Highland Energy NorthWestern Montana Bonnevile Power Administration NF
4 TransAlta Energy Marketing US Bonnevile Power Administration NorthWestem Montana NF
5 TransAlta Energy Marketing US NortWestem Montana Bonnevile Power Administration NF
6 TransAlta Energy Marketing US Bonneville Power Administration Idaho Power Company NF
7 TransAlta Energy Marketing US Bonnevile Power Administration NorthWestem Montana SFP
8 NaturEner USA Bonnevile Power Administration NorthWestern Montana SFP
9 NaturEner USA NorthWestern Montana Bonneville Power Administration SFP
10 The Energy Authority NorthWestern Montana MIDC NF
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.3
FERC FORM NO.1 (ED. 12-90)Page 329.3
............................................
Name of Respondent ThiS~ort Is:Date of Report Vear/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 04/16/2009
-: i-YK '-! ,_, '._ ~'. ccun, "vvli""ntinUeå)
(Including transactions reffered to as 'wteeling')
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billng demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and ü) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery 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)ü)
FERC Trf NO.8 512 51~1
FERC Trf NO.8 120 12C 2
FERC Trf NO.8 239 23~3
FERC Trf NO.8 85 8~4
FERC Trf NO.8 2,225 2,22~5
FERC Trf NO.8 150 15C 6
FERC Trf NO.8 11,127 11,12 7
FERC Trf NO.8 2,975 2,9n 8
FERC Trf NO.8 9,585 9,58~9
FERC Trf NO.8 10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
81 3,293,560 3,293,56~
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent ThiS~ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 04/16/2009
. CLC oJ I KI.yll Y i-YK l. ccoun~ llO:R\ IC ontinued)
(Including transactions reffered to as''Weeling1)' -,
9. In column (k) through (n), report the revenue amounts as shown on bils or vouchers. In column (k), provide revenues from demand
charges related to the billng demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bils or vouchers rendered, including
out of 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 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)! Line
($)($)($)(k+l+m)No.
(k)(I)(m)(0)
2,100 2,100 1
480 480 2
956 956 3
340 340 4
10,118 10,118 5
682 682 6
33,166 33,166 7
56,892 56,892 8
101,964 101,964 9
224 224 10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
7,914,641 1,453,822 60,369 9,428,832
Page 330.3
FERC FORM NO. 1/3.Q (REV. 02-04)Page 332
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 04/16/2009
TRANS~ ISSION OF ELECTRICITY BY OTHE S (Account 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, Le. wheeling or electricity prövided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilties, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non.Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider ofthe transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERG\EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawan-Ilemana l:nergy _LJtner Total Cost of
IiUTS Iiours Charles Charles Charles Trans~ssionAuthority (Footnote Affilations)Classification Received Delivered ($($($
(a)(b)(c)(d)(e)(f)(g)
1 Bonnevile Power Admin lFP 1,172,808 1,172,808
2 Bonnevile Power Admin lFP 7,846,008 583,608 8,429,616
3 Bonnevile Power Admin lFP 788,745 788,745
4 Bonevile Power Admin FNS 1,075,396 318,13 1,393,809
5 Bonnevile Power Admin OS 24,360 24,36
6 Bonnevile Power Admin SFP 3,404 3,404
7 Bonnevile Power Admin NF 28,815 28,815 125,015 125,015
8 GrantPUD lFP 20,257 20,257
9 Kootenai Electric Coop lFP 41,94 41,94
10 Northern lights lFP 135,820 135,820
11 NorthWestern Energy NF 37,389 37,38 243,772 -61,549 182,223
12 Northwestern Energy SFP 278,670 278,670
13 Portland General Elec lFP 642,588 642,588
14 Portland General Elec NF 616 616 924 924
15 Puget Sound Energy NF 456 456 2,316 2,316
16 Rainbow Energy Mkt NF 6,996 6,996 24,486 24,486
TOTAL 211,20:211,202 12,005,640 761,528 864,832 13,632,00
...........................................
. FERC FORM NO. 1/3-Q (REV. 02-04)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) EiA Resubmission 04/16/2009
TRANSI\ iSS ION OF ELECTRICITY BY OTHE S (Account 565)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity pråvided by other electric utilties, 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 affliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bils or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bils rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERG'i EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawau-.\.emana F.nergy .!JlIer Total Cost ofnoursnoursChar¡ies Ch(f¡ies Ch($Jles Trans~ssionAuthorily (Footnote Affliations)Classification Received Delivered ($(a)(b)(c)(d)(e)(f)(g)
1 Seattle City Light NF 74,179 74,179 238,528 238,528
2 Snohomish PUD NF 59,846 59,846 116,347 116,347
3 Tacoma Power NF 2,905 2,905 10,140 10,140
4 TOTAL 211,202 211,202 12,005,640 761.528 864,832 13,632,00
5
6
7
8
9
10
11
12
13
14
15
16
TOTAL 211,20~211,202 12,005,640 761,528 864,832 13,632,00
Page 332.1
FERC FORM NO.1 (ED. 12-94)Page 335
............................................
Name of Respondent This ~ort Is:Date of Rep'ort YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) Fi A Resubmission 04/16/2009
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line DescriltiOn Amount
No.(a (b)
1 Industry Association Dues 433,447
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 102,459
5 Oth Expn ::-5,000 show purpose, recipient, amount. Group if c: $5,000 1,433,583
6 Communily Relations 453,236
7 Education and Informational 19,691
8 Other Miscellaneous General Expenses 272,917
9 Directors Fees and Expense 469,967
10 Consulting Fees 13,312
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42 .
43
44
45
46 TOTAL 3,198,612
....................
: This Page Intentionally Left Blank........... ............
FERC FORM NO.1 (REV. 12-03)Page 336
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo. Da, Yr)End of 2008/04
(2) 0 A Resubmission 04/16/2009
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403.404.4 5)
(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 Amortzation Charges
Depreciation Amortization of
Line Dygrecation Expense for Asset Limited Term Amortization of
No.Functional Classification xpense Retirement Costs Electric Plant Other Electric Total
(Account 403)(Account 403.1)(Account 404)Plant (Acc 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 3,276,481 3,276,481
2 Steam Production Plant 10,309,774 10,309,774
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 7,341,157 7,341,157
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 8,772,317 2,450,031 11,222,348
7 Transmission Plant 9,266,249 9,266,249
8 Distribution Plant 24,527,250 24,527,250
9 Regional Transmission and Market Operation
10 General Plant 2,615,229 2,615,229
11 Common Plant-Electric 4,889,212 721,491 5,610,703
12 TOTAL 67,721,188 6,448,003 74,169,191
B. Basis for Amortization Charges
...........................................
. FERC FORM NO.1 (REV. 12-03)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) FiA Resubmission 04/16/2009
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreClaole t:stimatea Net Appriea Mortality Mverage
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)(In Th?~fandS)7~l (pergrnt)(pef;rnt)TYKe 7~l
12 STEAM PLANT
13 Colstrip No. 3
14 311 50,447 65.00 -5.00 2.28 S1.5 17.88
15 312 75,39S 60.00 -10.00 2.70 R1 18.57
16 314 19,854 50.00 -10.00 3.39 01 28.07
17 315 9,381 55.00 -5.00 2.49 S1.5 20.78
18 316 8,81S 50.00 2.26 R2 15.88
19 Subtotal 163,900
20
21 Colstrip NO.4
22 311 49,59S 65.00 -5.00 2.35 S1.5 21.32
23 312 47,069 60.00 -10.00 2.83 R1 23.84
24 314 14,550 50.00 -10.00 3.50 01 28.31
25 315 6,685 55.00 -5.00 2.59 S1.5 25.11
26 316 4,193 50.00 2.46 R3 19.98
27 Subtotal 122,096
28
29 Kettle Falls
30 310 148 35.00 2.19 50
31 311 24,771 65.00 -5.00 2.34 51.5 20.59
32 312 40,425 60.00 -10.00 3.31 R1 22.43
33 314 13,279 50.00 -10.00 3.18 01 16.35
34 315 10,306 55.00 -5.00 2.74 51.5 17.61
35 316 2,463 50.00 2.68 R2 21.44
36 Subtotal 91,392
37
38 HYDRO PLANT
39 Cabinet Gorge
40 330 7,725 75.00 2.75 R3 67.57
41 331 10,090 110.00 -5.00 1.62 RO.5 56.19
42 332 30,911 100.00 1.79 R1.5 7796
43 333 37,427 60.00 -5.00 2.59 R1.5 52.14
44 334 5,471 45.00 1.43 R2.5 16.54
45 335 2,38€65.00 0.13 R1 1.20
46 336 1,09S 60.00 2.05 S2.5 17.49
47 Subtotal 95,10S
48
49 Noxon Rapids
50 330 29,974 75.00 2.83 R3 69.37
Page 337
FERC FORM NO.1 (REV. 12-03)Page 337.1
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 04/16/2009
DEPRECiATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie t:stimatea Net Appiieo MOrtliy Average
No.Account No.Plant Base Avg. Service Salvage D~r. rates Curve Remaining
(a)(In Th?~fandS)7~r (pergrnt)( er;rnt)Tr8e 7~l
12 331 12,8a.110.00 -5.00 1.77 RO.5 81.53
13 332 31,871 100.00 1.79 R1.5 75.35
14 333 49,803 60.00 -5.00 2.89 R1.5 56.01
15 334 14,150 45.00 2.53 R2.5 43.88
16 335 2,672 65.00 0.97 R1 19.90
17 336 225 60.00 2.12 R2.5 39.60
18 Subtotal 141,579
19
20 Post Falls
21 330 2,732 75.00 3.79 R3 56.46
22 331 1,274 110.00 -5.00 0.36 RO.5 56.29
23 332 6,044 100.00 2.72 R1.5 92.62
24 333 2,234 60.00 -5.00 0.16 R1.5
25 334 685 45.00 0.14 R2.5 0.01
26 335 223 65.00 2.68 R1 53.83
27 Subtotal 13,192
28
29 Long Lake
30 330 418 75.0C 5.68 R3 45.63
31 331 1,845 110.0C -5.00 0.12 RO.5 15.32
32 332 16,638 100.0C 1.10 R1.5 24.34
33 333 8,824 60.00 -5.00 1.29 R1.5 13.91
34 334 2,822 45.00 0.82 R2.5 30.46
35 335 433 65.00 1.58 R1 30.46
36 Subtotal 30,980
37
38 Little Falls
39 330 4,217 75.00 7.03 R3 56.31
40 331 92 110.00 -5.00 0.12 RO.5 2.00
41 332 5,025 100.00 1.51 R1.5 51.95
42 333 3,969 60.00 -5.00 0.51 R1.5
43 334 1,975 45.00 0.93 R2.5 12.81
44 335 145 65.00 1.18 R1 19.46
45 Subtotal 16,259
46
47 Upper Falls
48 330 64 75.00 2.48 R4 37.64
49 331 538 110.00 -5.00 0.12 RO.5 9.42
50 332 7,126 100.00 1.20 R1.5 76.61
...........................................
. FERC FORM NO.1 (REV. 12-03)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) FiA Resubmission 04/16/2009
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle . Esiimaieo Net . Appiieci MOn:allty Mverage
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)(In Th?~~andS)7~l (pergrnt)(per;rnt)Tr8e 7~l
12 333 1,136 60.00 -5.00 0.90 R1.5 6.67
13 334 2,094 45.00 1.85 R2.5 37.00
14 335 107 65.00 2.30 R1 51.46
15 Subtotal 11,065
16
17 Nine Mile
18 330 11 75.00 4.59 R3 34.35
19 331 3.943 110.00 -5.00 2.35 RO.5 80.39
20 332 11,840 100.00 2.16 R1.5 72.53
21 333 9,465 60.00 -5.00 3.03 R1.5 56.34
22 334 2.637 45.00 2.57 R2.5 31.52
23 335 290 65.00 2.31 R1 45.87
24 336 625 60.00 2.64 S2.5 56.50
25 Subtotal 28,811
26
27 Monroe Street
28 331 8,405 110.00 -5.00 1.82 RO.5 109.02
29 332 8,045 100.00 1.72 R1.5 99.22
30 333 11,018 60.00 -5.00 2.28 R1.5 60.23
31 334 1,653 45.00 2.97 R2.5 45.13
32 335 34 65.00 2.04 R1 64.37
33 336 50 60.00 2.17 S2.5 59.42
34 Subtotal 29,205
35
36 OTHER PRODUCTION
37 Northeast Turbine
38 341 365 0.98 SO
39 342 32 55.00 1.31 R3
40 343 9,090 50.00 7.83 S2.5 8.42
41 344 2,605 45.00 0.72 R3
42 345 424 40.00 8.54 S1.5 11.83
43 346 300 1.24 SO
44 Subtotal 12,816
45
46 Rathdrum Turbine
47 341 3,187 3.95 SO
48 342 1,700 55.00 4.10 R2.5 44.14
49 343 3,659 50.00 3.61 S2.5 33.50
50 344 48,858 45.00 3.37 R3 35.49
Page 337.2
FERC FORM NO.1 (REV. 12-03)Page 337.3
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) nA Resubmission 04/16/2009
DEPRECiATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie i:siimateo Net Appiieo MOrlllY lwerage
No.Account No.Plant Base Avg. Service Salvage D~r. rates Curve Remaining
(In Th?~fandS)
7~fe
(per3rnt)( er~nt)Tr8e 7~f(al cl
12 345 2,540 40.00 3.56 S1.5
13 Subtotal 59,944
14
15 Kettle Falls CT
16 342 89 55.00 4.74 R3 39.59
17 343 9,071 50.00 4.71 52.5 35.98
18 344 4 45.00 4.98 R3 36.77
19 345 5 40.00 4.48 51.5 28.83
20 Subtotal 9,169
21
22 Boulder Park
23 341 725 2.63 SO
24 342 11 55.00 2.71 R3 37.93
25 343 57 50.00 3.01 S2.5 40.21
26 344 30,094 45.00 2.84 R3 32.97
27 345 271 40.00 2.97 S1.5 31.24
28 346 7 2.69 SO
29 Subtotal 31,270
30
31 Coyote Springs 2
32 341 11,341 2.76 SO
33 342 19,12 55.00 2.85 R3 44.23
34 344 116,410 45.00 2.92 R3 41.58
35 345 12,589 40.00 3.10 51.5 32.07
36 346 1,03 2.76 SO
37 Subtotal 160,505
38
39 TRANSMISSION PLANT
40 350 11,362 75.00 1.28 R4 53,27
41 352 15,750 60.00 -5.00 1.61 R4 44.73
42 353 172,930 47.00 -15.00 2.39 R3 31.13
43 354 17,098 70.00 -20.00 1.87 53 43.89
44 355 128,395 60.00 -30.00 1.84 R3 37.27
45 356 103,821 60.00 -10.00 1.93 R3 43.30
46 357 2,60 60.00 1.58 R4 52.84
47 358 2,330 55.00 1.73 S3 41.27
48 359 1,872 65.00 1.65 R4 45.05
49 Subtotal 456,164
50
...........................................
. FERC FORM NO.1 (REV. 12-03)
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) EjA Resubmission 04/16/2009
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreciaoie t:stimatea Net APpliea MOrtaliy Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)(In Th?~fandS)7~l (pergrnt)(per;rnt)TYKe 7~l
12 DISTRIBUTION PLANT
13 361 12,262 55.00 -10.00 1.80 R3 35.51
14 362 86.204 42.00 .10.00 2.60 R1.5 28.26
15 364 196,777 50.00 -25.00 2.66 R2.5 34.66
16 365 129,268 50.00 -15.00 2.46 R2.5 35.35
17 366 71,349 45.00 -10.00 2.71 R3 36.09
18 367 115,566 28.00 -15.00 6.38 L4 23.05
19 368 159,54 44.00 -5.00 2.00 R2 27.21
20 369 110,109 60.00 -15.00 1.63 R3 38.01
21 370 44,273 38.00 2.39 51 33.72
22 373 14,446 32.00 -15.00 1.08 R2.5 8.68
23 373.4 13,315 32.00 -5.00 2.82 R2.5 18.79
24 Subtotal 953,115
25
26 GENERAL PLANT
27 390.1 2,175 55.00 -5.00 1.85 S2 20.91
28 391.1 718 5.00 17.67 SO 3.80
29 393 32 25.00 2.25 SO 22.97
30 394 3,353 20.00 4.22 SO 10.35
31 395 1,389 15.00 7.72 SO 7.82
32 397 36,464 15.00 5.40 SO 5.17
33 398 3 10.00 2.37 SO 7.80
34 Subtotal 44,430
35
36 MISCPOWER
37 392 1,518 11.00 10.00 3.70 S3
38 396 2,506 15.00 10.00 5.40 L2
39 Subtotal 4,024
40
41 TOTAL COMPANY 2,475,025
42
43
44
45
46
47
48
49
50
Page 337.4
FERC FORM NO.1 (ED. 12-96)Page 350
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) 0 A Resubmission 04/16/2009
R..GULATORY COMMISSION EXPEN ES
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a part.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current yeats amortization of amounts
deferred in previous years.
Line Description Assessed by Expenses Total Deferrea.
No.(Furnish name of regulatory commission or body the Regulatory of Expense for in Account
Commission Current Year .18~.3 aldocket or case number and a description of the case)Utilily (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.1,886,187 344,169 2,230,356
5
6
7
8
9 Washington Utilties and Transportation
10 Commission: includes annual fee and various
11 other electric dockets 746,339 333,218 1,079,557
12
13 Includes annual fee and various other natural
14 gas dockets 438,327 226,012 664,339
15
16 Idaho Public Utilties Commission
17 Includes annual fee and various other electric
18 dockets 509,718 240,302 750,020
19
20 Includes annual fee and various other natural
21 gas dockets 218,450 114,501 332,951
22
23 Public Utilty Commission of Oregon
24 Includes annual fees and various other natural
25 gas dockets 544,741 180,05€724,797
26
27 Not directly assigned electric 723,772 723,772
28 Not directly assigned natural gas 282,026 282,026
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 4,343,762 2,444,056 6,787,818
...........................................
. FERC FORM NO.1 (ED. 12-96)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da. Yr)End of 2008/04
(2) ri A Resubmission 04/16/2009
REGULATORY COMMISSION EXPENSE~ (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 Line
Department AmOUnt Accunt 182.3 Account Account 182.3 No.No.End of Year
(f)(g)(h)(i)0)(k)(I)
1
2
3
Electric 928 2,230,356 4
5
6
7
8
9
10
Electric 928 1,079,557 11
12
13
Gas 928 664,339 14
15
16
17
Electric 928 750,020 18
19
20
Gas 928 332,951 21
22
23
24
Gas 724,797 25
26
Electric 928 723.772 27
Gas 928 282,026 28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
6,787,818 46
Page 351
(a)
Direc PayrollDistrbution
(b)
Total
............................................
Name of Respondent
Avista Corporation
Year/Period of Report
End of 2008104
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2009
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
Utilty Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Line
No.
Classification
1 Electric
2 Operation
3 Production
4 Transmission
5 Regional Market
6 Distribution
7 Customer Accounts
8 Customer Service and Informational
9 Sales
10 Administrative and General
11 TOTAL Operation (Enter Total of lines 3 thru 10)
12 Maintenance
13 Production
14 Transmission
15 Regional Market
16 Distribution
17 Administrative and General
18 TOTAL Maintenance (Totai 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 OpeL and Maint. (Total of lines 20 thru 27)
29 Gas
30 Operation
31 Production-Manufactured Gas
32 Production-Nat. Gas (Including Expl. and Dev.)
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42 Maintenance
43 Production-Manufactured Gas
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
4,626,264
5,449,349
339,599
389,128
12,012,969
34,285,840
8,867,403
5,449,349
339,599
389,128
12,012,969
41,740,897
3,864,070
2,411,740
162,03
151,966
4,649,383
12,000,114
FERC FORM NO.1 (ED. 12-88)Page 354
............................................
Name of Respondent
Avista Corporation
This ~ort Is:
(1) ~An Original
(2) A Resubmission
IBUTION OF SALARIES AND WAG
Date of Report
(Mo, Da, Yr)
04/16/2009
S (Continued)
YearlPeriod of Report
End of 2008/04
DIST
Line Classification Direct Payroll Total
No.Distribution
(a)(b)
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)752,515
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru 8,397
56 Transmission (Lines 35 and 47)499,826
57 Distribution (Lines 36 and 48)5,932,248
58 Customer Accounts (Line 37)2,411,740
59 Customer Service and Informational (Line 38)162,043
60 Sales (Line 39)151,966
61 Administrative and General (Lines 40 and 49)4,649,383
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)14,568,118
63 Other Utilty Departments
64 Operation and Maintenance
65 TOTAL All Utilty Dept. (Total of lines 28,62, and 64)
66 Utilty Plant
67 Construction (By Utilty Departments)
68 Electric Plant
69 Gas Plant
70 Other (provide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70)
72 Plant Removal (By Utilty Departments)
73 Electric Plant 908,961 171,862 1,080,823
74 Gas Plant 83,692 15,824 99,516
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)992,653 187,686 1,180,339
77 Other Accounts (SpeCify, provide details in footnote):
78 Stores Expense 1,594,474 -1,594,474
79 Regulatory Assets 214,454 214,454
80 Preliminary Survey and Investigation -3,566 -3,566
81 Small Tool Expense 2,424,013 -2,424,013
82 Miscellaneous Deferred Debits 23,023,863 23,023,863
83 Non-operating Expenses 396,265 396,265
84
85 Expenditures of Certin Civic, Political and Related 238,729 238,729
86 Employee Incentive 3.015,100 -3.015,100
87 DSM Tarrif Rider and Payroll Equilzation Liability 15,086,274 -13,720,024 1,366,250
88 Incentivel Stock Compensations 42,804 42,804
89
90
91
92
93
94
95 TOTAL Other Accounts 46,032,410 -20.753,611 25,278,799
96 TOTAL SALARIES AND WAGES 134,543,229 -3,731,231 130,811,998
FERC FORM NO.1 (ED. 12-88)Page 355
............................................
Name of Respondent
Avista Corporation
This Report Is:
(1) IX An Original
(2) 0 A Resubmission
Date of Report
(Mo,Da, Yr)
04116/2009
Year/Period of Report
End of 2008/04
COMMON UTILITY PLANT AND EXPENSES
1. Describe the property carried in the utilly's accounts as common utilly plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utilty Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to
the respective departments using the common utilly plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortzation at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utilly 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 utilly plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utiily plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
1 & 2. Common Plant in service and accumulated provision for depreciation
Acct. No.
303
389
390
391
392
393
394
395
396
397
398
399
Description
Intangible
Land and Land Rights
Structures and Improvements
Office Furniture and Equipment
Transportation Equipment
Stores Equipment
Tools, Shop & Garage Equipment
Laboratory Equipment
Power Operated Equipment
Communications Equipment
Miscellaneous Equipment
Asset Retirement Cost
25,135,774
3,568,315
42,073,255
25,951,182
2,061,676
930,305
1,995,656
600,828
1,926,054
18,903,065
501,002
351,680
Total Common Plant
Const. Work in Progress
123,998,792
7,663,152
Total Utility Plant
Acc. Prov. for Dep. & Amort.
131,661,944
31,229,906
Net Utility Plant 100,432,038
3. Common Expense allocated to Electric and Gas departments:
Allocation to Allocated to
Acct. No.Description Total Electric Dept Gas Dept
901 Cust acct/collect 924,600 490,861 433,739
supervision
902 Meter reading expenses 3,519,743 2,182,840 1,336,903
903 Cust rec & collection 11,474,317 6,265,758 5,208,559
expenses
903.90-99 A/R Misc.fees 1,112,596 904,674 207,922
904 Uncollectible accounts 3,631,011 1,927,667 1,703,343
905 Misc cust acct expenses 277,767 147,464 130,303
907 Cust srvc & info exp 0 0 0
supervision
908 Cust assistance exp 819,933 508,495 311,438
909 Info & instruct advert 88,132 47,299 40,833
expenses
910 Misc cust srvc & info 234,286 145,297 88,989
FERC FORM NO.1 (ED. 12-87) Page 356
Basis of
Allocation
#cust 19 yr.end
#cust 19 yr.end
#cust 19 yr.end
net direct plant
#cust 19 yr.end
#cust 19 yr.end
#cust 19 yr.end
#eust 19 yr.end
#cust 19 yr.end
#cust 19 yr.end
............................................
Name of Respondent
Avista Corporation
This Report Is:
(1) 00 An Original
(2) 0 A Resubmission
Year/Period of ReportDate of Report
(Mo, Da, Yr)
04/16/2009 2008104End of
COMMON UTILITY PLANT AND EXPENSES
1. Describe the propert carried in the utilty's accunts as common utiily plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utilly 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 utilily departments using the Common utilly 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 amortzation for common utilly plant classified by accunts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departents using the common utilly 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 utilly plant classification and reference to order of the Commission or other
authorization.
expenses
911 Sales expense sprvsn 0 0 0 #cust & yr.end
912 Demo and selling exp 685,017 424,827 260,190 #cust & yr.end
913 Advertising expenses 206,637 128,150 78,487 #cust & yr.end
916 Misc sales expense 344,340 213,550 130,791 #cust & yr.end
920 Admin & gen salaries 25,038,044 18,072,846 6,965,197 four factor
921 Office supplies &0 0 0 four factor
expenses
922 Admin expenses tranf-5,089,802 3,664,899 1,424,903 four factor
cred
923 Outside srvcs employed 15,007,852 10,799,795 4,208,058 four factor
924 Property insurance 1,138,330 819,142 319,188 four factor
925 Injuries & damages 5,750,714 4,281,058 1,469,656 four factor
926 Employee pensions &35,981,195 25,983,616 9,997,579 four factor
benefits
927 Franchise requirement 0 0 0 four factor
928 Regulatory commission 1,005,797 723,772 282,026 four factor
expenses
929 Duplicate charges -0 0 0 four factor
credit
930.1 General advertising exp 5,077 4,017 1,060 four factor
930.2 Misc general expenses 4,202,376 3,078,544 1,123,832 four factor
931 Rents 787,601 557,706 229,894 four factor
935 Maint of general plant 7,752,899 5,649,014 2,103,885 four factor
403 Depreciation 6,704,799 4,889,213 1,815,587 four factor
404 Amort of LTD term plant 4,552,272 3,276,482 1,275,790 four factor
Note 1: The four factor allocator is made up of 25 percent each of customer counts ,direct labor, direct
O&M, and net direct plant.
4. Letters of approval received from staffs of State Regulatory Commissions in 1993
FERC FORM NO.1 (ED. 12-87)Page 356.1
FERC FORM NO.1 (New 2-04)Page 398
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) EiA Resubmission 04116/2009
PURCHASES AND SALES OF ANCILLAR SERVICES
Report the amounts for each type of ancilary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billng determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancilary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e). (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d). (e), (f). and (g) report the amount of energy imbalance services purchased and sold 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 ancilary services purchased or sold during
the year. Include in a footnote and specify the amount for each type of other ancilary service provided.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Biling Determinant Usage - Related Biling Determinant
Unit of Unit of
linE Type of Ancilary Service Number of Units Measure Dollars Number of Units Measure Dollars
No.(a)(b)(c)(d)(e)(f)(g)
1 Scheduling, System Control and Dispatch 33 MW 134,770
2 Reacte Supply and Voltge 33 MW 408
3 Regulation and Frequency Response 141,561 MWh 80,785 72,155 MW 645,06
4 Energy Imbalance 840 MW 3,00,328
5 Operating Reserve. Spinning 77,358 MWh 1,498,374 46,190 MWh 608,723
6 Operating Reserve. Supplement 853 MWh 6,764 58,179 MWh 710,031
7 Oter 1,357,884 MW 12,139,479 1.357,884 MW 12,139,479
8 Total (Lines 1 thru 7)1,578,322 13,860,580 1,535,248 17,109,629
............................................
Name of Respondent
Avista Corporation
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 04/16/2009
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, fumish 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 ü) by month the system' monthly maximum megawatt load by statistical classifications. See General Instrction for
the definition of each statistical classification.
YearlPeriod of Report
End of 2008104
NAME OF SYSTEM:
Line
No.Month
(a)
1 January
2 February
3 March
4 Totalfor Quarter 1
5 Aprl
May
7 June
Total for Quarter 2
9 July
1 August
11 September
12 Total for Quarter 3
13 Ocober
14 November
15 Deember
16 Total for Quarter 4
17 Total Year to
DateJear
Monthly Peak
MW - Total
Day of Hour of
Monthly Monthly
Peak Peak
(d)
800
1900
800
Firm Network Firm Network Long-Term Firm Other Long- Short-Term Firm Other
Service for Self Service for Point-to-point Term Firm Point-to-point Servic
Others Reservations Service Reservation
(e)(f)(g)(h)(i)ü)
1,646 168 94 332
1,460 168 8 13
1,35 168 12
4,459 5 114 34
1,301 168 n
1,232 169 276 375
1,533 17 525 49
4,066 508 878 424
1,462 17 383 75
1,567 170 165
1,202 170 66 128
4,231 511 614 203
1,271 169 38
1,339 16 43
1,770 16 77
4,380 501 158
17,136 3,333 2,024 468 1,764 972
(b)
2,03
1,78
1,65
5,47
1,58
1,49
1,86
4,94
1,79
1,90
1,45
5,15
1,5
1,62
2,191
5,361
~=
900
1400
1600-
i ~;
1600
1600
1700~~, "
~=
""
20,93
FERC FORM NO. 1/3-Q (NEW. 07-04)Page 400
FERC FORM NO.1 (ED. 12-90)Page 401a
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) Fi A Resubmission 04/16/2009
ELECTRIC ENERGY ACCOU~ T
Report below the information called for concerning the disposition of electric energy generated. purchased, exchanged and wheeled during the year.
Line Item MegaWatt Hours Line Item MegaWatt Hours
No.No.
(a)(b)(a)(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to Ultimate Consumers (Including 9,029,319
3 Steam 1,958,082 Interdepartmental Sales)
4 Nuclear 23 Requirements Sales for Resale (See
5 Hydro-Conventional 3,851,251 instrction 4. page 311.)
6 Hydro-Pumped Storage 24 Non-Requirements Sales for Resale (See 3,566,073
7 Other 1.734,908 instrcton 4, page 311.)
8 Less Energy for Pumping 25 Energy Fumished Without Charge
9 Net Generation (Enter Total of lines 3 7,544,241 26 Energy Used by the Company (Electric 9,705
through 8)Dept Only, Excluding Station Use)
10 Purchases 5,686,48~27 Total Energy Losses 623,811
11 Power Exchanges:28 TOTAL (Enter Total of Lines 22 Through 13,228,908
12 Received 718,926 27) (MUST EOUAL LINE 20)
13 Delivered 720.744
14 Net Exchanges (Line 12 minus line 13)-1,818
15 Transmission For Other (Wheeling)
16 Received 3,293,560
17 Delivered 3,293,560
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9, 10, 14, 18 13,228,908
and 19)
...........................................
. FERC FORM NO.1 (ED. 12-90)
Name of Respondent This oo0rt IS:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) Õ A Resubmission 04/16/2009
MONTHLY PEAKS AND OUTPUT
(1) Report the monthly peak load and energy output. If the respondent has tw 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 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 1,105,963 134,731 1,705 23 800
30 February 1,000,743 163,745 1,509 5 1900
31 March 1,244,292 407,272 1,397 25 800
32 April 1,000,410 235,222 1,345 1 900
33 May 1.125,257 398,014 1,255 19 1400
34 June 1,122,422 410,743 1,568 30 1600
35 July 1,302,391 502,218 1,492 2 1600
36 August 1,012,735 230,104 1,602 18 1600
37 September 885,426 184,688 1,224 19 1700
38 October 1,009,099 248,685 1,303 29 800
3ll November 1,101,927 316,093 1,373 24 1800
40 December 1,318,243 334,558 1,821 16 1900
41 TOTAL 13,228,908 3,566,073
Page 401b
FERC FORM NO.1 (REV. 12-03)Page 402
............................................
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2008/04
(2) DA Resubmission 04/16/2009 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only.2. Large plants are steam plants with installed 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 facilty.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 quantily of fuel burned converted to Mct.7. Ouantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accunts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name: Coyote Springs 2 Name: Spokane N.E
(a)(b)(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine Gas Turbine
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Not Applicable Not Applicable
3 Year Originally Constructed 2003 1978
4 Year Last Unit was Installed 2003 1978
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)287.00 61.80
6 Net Peak Demand on Plant - MW (60 minutes)307 30
7 Plant Hours Connected to Load 6675 82
8 Net Continuous Plant Capabilly (Megawatts)279 61
9 When Not Limited by Condenser Water 279 0
10 When Limited by Condenser Water 279 0
11 Average Number of Employees 22 1
12 Net Generation, Exclusive of Plant Use - KWh 1696319000 2154000
13 Cost of Plant: Land and Land Rights 0 129664
14 Structures and Improvements 11340586 365280
15 Equipment Costs 149164262 13182384
16 Asset Retirement Costs 351682 0
17 Total Cost 160856530 13677328
18 Cost per KW of Installed Capacily (line 17/5) Including 560.4757 221.3160
19 Prouction Expenses: Oper, Supv, & Engr 1339059 9496
20 Fuel 103444188 267937
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 1257794 50469
26 Misc Steam (or Nuclear) Power Expenses 889 4288
27 Rents 67255 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 263092 22359
30 Maintenance of Structures 0 1673
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 4492709 82586
33 Maintenance of Misc Steam (or Nuclear) Plant 200 14315
34 Total Production Expenses 110873146 453123
35 Expenses per Net KWh 0.0654 0.2104
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas Gas
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)MCF MCF
38 Ouantity (Units) of Fuel Burned 11609569 0 0 27740 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)1020000 0 0 1020000 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 8.910 0.00 0.000 9.659 0.000 0.000
41 Average Cost of Fuel per Unit Burned 8.910 0.000 0.000 9.659 0.00 0.000
42 Average Cost of Fuel Burned per Milion BTU 8.736 0.00 0.000 9.469 0.00 0.00
43 Average Cost of Fuel Burned per KWh Net Gen 0.061 0.000 0.000 0.124 0.000 0.000
44 Average BTU per KWh Net Generation 6981.000 0.000 0.000 13136.000 0.000 0.000
...........................................
. FERC FORM NO.1 (REV. 12-03)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2008/04(2) D A Resubmission 04/16/2009 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accunts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants. report Operating Expenses, Accunt Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attbuted to research and development; (b) Iypes of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment Iype and quantily for the
report period and other physical and operating characteristics of plant.
Plant Plant Plant Line
Name: Kette Falls Name:Colstrip Name:Rathdrum No.
(d)(e)(f)
Steam Steam Gas Turbine 1
Conventional Conventional Not Applicable 2
1983 1984 1995 3
1983 1985 1995 4
50.70 233.40 166.50 5
50 226 176 6
5064 8780 126 7
.50 222 149 8
50 222 0 9
49 222 0 10
30 210 2 11
200423000 1757659000 13067000 12
941300 1290825 621682 13
24770695 100045629 3186951 14
66472954 185950687 56756800 15
450687 134589 0 16
92635636 287421730 60565433 17
1827.1329 1231.4556 363.7564 18
176760 177078 134188 19
7522699 21253774 1332065 20
0 0 1332065 21
557765 1322868 0 22
0 0 0 23
0 0 0 24
769802 44456 143933 25
427189 2945137 86483 26
0 38367 0 27
0 0 0 28
108780 345391 37632 29
90985 435332 1492 30
1124664 3752319 0 31
222484 322054 139334 32
165897 471195 57891 33
11167025 31107971 3265083 34
0.0557 0.0177 0.2499 35
WOOD GAS Coal Oil GAS 36
TONS MCF Tons Bbls MCF 37
302536 2386 0 1124845 954 0 158815 0 0 38
8500000 1020000 0 16781000 140000 0 1020000 0 0 39
24.790 9.556 0.000 18.771 145.989 0.000 8.388 0.000 0.000 40
24.790 9.556 0.000 18.771 145.989 0.000 8.388 0.000 0.000 41
2.920 9.369 0.000 1.120 24.650 0.000 8.223 0.00 0.000 42
0.038 0.112 0.000 0.012 0.000 0.000 0.102 0.000 0.000 43
12844.000 0.000 0.000 10747.000 0.000 0.000 12397.000 0.000 0.000 44
Page 403
FERC FORM NO.1 (REV. 12-03)Page 402.1
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2008/04
(2) OA Resubmission 04/16/2009 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 nudear plants.3. Indicate by a footnote any plant leased or operated
as a joint facilty.4. If net peak demand for 60 minutes is not available, give data which is available, 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 bumed converted to Mct.7. Ouantities of fuel bumed (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: Bou/der Park Name:
(a)(b)(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Internal Comb
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Conventional
3 Year Originally Constructed 2002
4 Year Last Unit was Installed 2002
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)24.60 0.00
6 Net Peak Demand on Plant - MW (60 minutes)25 0
7 Plant Hours Connected to Load 1109 0
8 Net Continuous Plant Capabilty (Megawatts)25 0
9 When Not Limited by Condenser Water 0 0
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 1 0
12 Net Generation, Exclusive of Plant Use - KWh 2066000 0
13 Cost of Plant: Land and Land Rights 144733 0
14 Structures and Improvements 724602 0
15 Equipment Costs 30545079 0
16 Asset Retirement Costs 0 0
17 Total Cost 31414414 0
18 Cost per KW of Installed Capacity (line 17/5) Including 12770087 0.0000
19 Production Expenses: Oper, Supv, & Engr 10669 0
20 Fuel 1838037 0
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 95084 0
26 Misc Steam (or Nuclear) Power Expenses 5437 0
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 45239 0
30 Maintenance of Structures 233 0
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 193808 0
33 Maintenance of Misc Steam (or Nuclear) Plant 37338 0
34 Total Production Expenses 2225845 0
35 Expenses per Net KWh 0.1080 0.0000
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)GAS
37 Unit (Coal-tons/Oil-barreI/Gas-mcf/Nuclear-indicate)MCF
38 Ouantily (Units) of Fuel Burned 194238 0 0 0 0 0
39 Avg Heat Cont - Fuel Bumed (btu/indicate if nudear)1020000 0 0 0 0 0
40 Avg Cost of Fuel/unit, as Oelvd f.o.b. during year 9.463 0.000 0.000 0.000 0.000 0.000
41 Average Cost of Fuel per Unit Burned 9.463 0.000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 9.277 0.000 0.000 0.000 0.00 0.00
43 Average Cost of Fuel Burned per KWh Net Gen 0.089 0.000 0.000 0.000 0.000 0.000
44 Average BTU per KWh Net Generation 9615.000 0.000 0.000 0.000 0.000 0.000
...........................................
. FERC FORM NO.1 (REV. 12-03)
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2008/04(2)D A Resubmission 04/16/2009 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Accunt Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electrc Plant." indicate plants
deSigned for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accunting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment Iype 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)
1
2
3
4
0.00 0.00 0.00 5
0 0 0 6
0 0 0 7
0 0 0 8
0 0 0 9
0 0 0 10
0 0 0 11
0 0 0 12
0 0 0 13
0 0 0 14
0 0 0 15
0 0 0 16
0 0 0 17
0.0000 0.0000 0.0000 18
0 0 0 19
0 0 0 20
0 0 0 21
0 0 0 22
0 0 0 23
0 0 0 24
0 0 0 25
0 0 0 26
0 0 0 27
0 0 0 28
0 0 0 29
0 0 0 30
0 0 0 31
0 0 0 32
0 0 0 33
0 0 0 34
0.0000 0.0000 0.0000 35
36
37
0 0 0 0 0 0 0 0 0 38
0 0 0 0 0 0 0 0 0 39
0.000 0.000 0.000 0.000 0.000 0.000 0.00 0.00 0.00 40
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.00 41
0.000 0.000 0.00 0.000 0.00 0.000 0.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44
Page 403.1
FERC FORM NO.1 (REV. 12-03)Page 406
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)2008/04
(2) DA Resubmission 04/16/2009 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacily (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facilty, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, reprt 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)14.80 10.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)16 11
7 Plant Hours Connect to Load 8.386 8,692
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions 16 11
10 (b) Under the Most Adverse Oper Conditions 14 9
11 Average Number of Employees 1 1
12 Net Generation, Exclusive of Plant Use - Kwh 104,210,000 77,977000
13 Cost of Plant
14 Land and Land Rights 0 1,081,854
15 Structures and Improvements 8,405,476 538,257
16 Reservoirs. Dams, and Waterwys 8,04,079 7,126,169
17 Equipment Costs 12,704,055 3,337.508
18 Roads, Railroads, and Bridges 50,448 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)29,205,058 12,083,788
21 Cost per KW of Installed Capacily (line 20 I 5)1,973.3147 1,208.3788
22 Production Expenses
23 Operation Supervision and Engineering 36,448 35,792
24 Water for Power 43 0
25 Hydraulic Expenses 2,278 14,602
26 Electric Expenses 403,049 396,978
27 Misc Hydraulic Power Generation Expenses 64,033 78,076
28 Rents 0 0
29 Maintenance Supervision and Engineering 2,228 279
30 Maintenance of Structures 7,190 -3,613
31 Maintenance of Reservoirs, Dams, and Waterwys 169,958 28,089
32 Maintenance of Electric Plant 37,419 42,731
33 Maintenance of Misc Hydraulic Plant 2,472 367
34 Total Production Expenses (total 23 thru 33)725,118 593,301
35 Expenses per net KWh 0.0070 0.0076
.. Name of Respondent This RW0rt Is:
(1) An OriginalAvista Corporation. (2) DA Resubmission 04/16/2009
. 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 FORM NO.1 (REV. 12-03)
Date of Report
(Mo, Da, Yr)
YearlPeriod of Report
2008/04
FERC licensed Project No. 2058
Plant Name: Cabinet Gorge
(d)
End of
line
No.
FERC Licensed Project No. 2058
Plant Name: Noxon Rapids
(e)
FERC Licensed Project No.
Plant Name: Long Lake
2545
Storage
Outdoor
Storage
Conventional
1952
1953
265.00
261
8,780
Storage
Outdoor
1959
1977
480.60
530
6,775
9,913,802 35,831,528 1,597,959
10,089,656 12,883,459 1,845.328
30,910,987 31,859,561 16,637,951
45,284,673 66,624,841 12,079,416
1,098,564 225,369 0
0 0 0
97,297,682 147,424,758 32,160,654
367.1611 306.7515 459.4379
108,175 89,326 1,034
0 0 0
2,185 50,496 7,403
973,287 981,924 570,425
206,013 162,303 63,681
0 0 0
33,490 37,341 5,756
90,909 99,777 75,999
32,852 33,132 20,243
205,707 883,830 161,43
64,929 37,437 2,140
1,717,547 2,375,566 908,124
0.0016 0.0014 0.0018
1915
1924
70.00
90
7,033
Page 407
FERC FORM NO.1 (REV. 12-03)Page 406.1
............................................
Name of Respondent This~rtIS:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) DA Resubmission 04/16/2009
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: Nine Mile Falls Plant Name: Post Falls
(a)(b)(c)
1 Kind of Plant (Run-of-River or Storage)Run-of-River Storage
2 Plant Construction type (Conventional or Outdoor)Conventionai Conventional
3 Year Originally Constructed 1908 1906
4 Year Last Unit was Installed 1994 1980
5 Total installed cap (Gen name plate Rating in MW)26.40 14.80
6 Net Peak Demand on Plant-Megawatts (60 minutes)20 18
7 Plant Hours Connect to Load 8,752 8,780
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions 20 18
10 (b) Under the Most Adverse Oper Conditions 9 12
11 Average Number of Employees 1 2
12 Net Generation, Exclusive of Plant Use - Kwh 104,892,000 85,518,000
13 Cost of Plant
14 Land and Land Rights 33,429 3,076,554
15 Structures and Improvements 3,943,110 1,274,575
16 Reservoirs, Dams, and Waterwys 11,840,543 6,044,594
17 Equipment Costs 12,391,557 3,141,665
18 Roads, Railroads, and Bridges 625,181 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)28,833,820 13,537,388
21 Cost per KW of Installed Capacily (line 20 I 5)1,092.1902 914.6884
22 Production Expenses
23 Operation Supervision and Engineering 44,863 28,138
24 Water for Power 0 0
25 Hydraulic Expenses 1,018 103
26 Electric Expenses 427,685 386,919
27 Misc Hydraulic Power Generation Expenses 145,046 130,430
28 Rents 0 0
29 Maintenance Supervision and Engineering 52,891 458
30 Maintenance of Structures 10,156 1,000
31 Maintenance of Reservoirs, Dams, and Waterwys 117,149 45,374
32 Maintenance of Electric Plant 314,998 123,702
33 Maintenance of Misc Hydraulic Plant 6,014 419
34 Total Production Expenses (total 23 thru 33)1,119,820 716,543
35 Expenses per net KWh 0.0107 0.0084
............................................
Name of Respondent
Avista Corporation
YearlPeriod of Report
End of 2008/04
This ~ort Is: Date of Report
(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 04/16/2009
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accunts prescribed by the Uniform System of 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.
Plant Name: Little Falls
(d)
o FERC Licensed Project No.
Plant Name:
o FERC Licensed Project No.
Plant Name:
o Line
No.
(e)
Run-of-River
Conventional
1910
1911
32.00
37
7,032
0.00
o
o
0.00
o
o
4,325,371 0 0
928,141 0 0
5,025,360 0 0
6,088,106 0 0
0 0 0
0 0 0
16,366,978 0 0
511.4681 0.000 0.0000
401 0 0
0 0 0
13.388 0 0
523,079 0 0
37,311 0 0
640,574 0 0
57,640 0 0
28,700 0 0
106,845 0 0
132,014 0 0
4,688 0 0
1,544,640 0 0
0.0076 0.0000 0.0000
FERC FORM NO.1 (REV. 12-03)Page 407.1
FERC FORM NO.1 (REV. 12-03)Page 406.2
............................................
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo. Da, Yr)2008/04
(2) DA Resubmission 04/16/2009 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro piants of 10,000 Kw or more of installed capacily (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 specfying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.0 FERC Licensed Project No.0
No.Plant Name:Plant Name:
(a)(b)(c)
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)0.00 0.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)0 0
7 Plant Hours Connect to Load 0 0
8 Net Plant Capabilty (in megawatts)
9 (a) Under Most Favorable Oper Conditions 0 0
10 (b) Under the Most Adverse Oper Conditions 0 0
11 Average Number of Employees 0 0
12 Net Generation, Exclusive of Plant Use - Kwh 0 0
13 Cost of Plant
14 Land and Land Rights 0 0
15 Structures and Improvements 0 0
16 Reservoirs, Dams, and Waterwys 0 0
17 Equipment Costs 0 0
18 Roads, Railroads, and Bridges 0 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)0 0
21 Cost per KW of Installed Capacity (line 20 / 5)0.0000 0.0000
22 Production Expenses
23 Operation Supervision and Engineering 0 0
24 Water for Power 0 0
25 Hydraulic Expenses 0 0
26 Electric Expenses 0 0
27 Misc Hydraulic Power Generation Expenses 0 0
28 Rents 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 0 0
31 Maintenance of Reservoirs, Dams, and Waterwys 0 0
32 Maintenance of Electric Plant 0 0
33 Maintenance of Misc Hydraulic Plant 0 0
34 Total Production Expenses (total 23 thru 33)0 0
35 Expenses per net KWh 0.000 0.0000
,
.. Name of Respondent
. Avista Corporation.
. 5. The items under Cost of Plant represent accounts or combinations of accunts prescribed by the Uniform System of Accunts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
. 6. Report as a separate plant any plant equipped with combinations of steam, hydro, intemal combustion engine. or gas turbine equipment...
. FERC Licensed Project No.
. Plant Name:.................................
This ~rt Is: Date of Report
(1) ~An Original (Mo. Da, Yr)
(2) DA Resubmission 04/16/2009
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Year/Period of Report
2008104End of
o FERC Licensed Project No.
Plant Name:
o FERC Licensed Project No.
Plant Name:
o Line
No.
(d)(e
0.00
o
o
0.00
o
o
0.00
o
o
o
o
o
o
o
o
o
0.000
o
o
o
o
o
o
o
0.0000
o
o
o
o
o
o
o
0.0000
o
o
o
o
o
o
o
o
o
o
o
o
0.0000
o
o
o
o
o
o
o
o
o
o
o
o
0.0000
o
o
o
o
o
o
o
o
o
o
o
o
0.000
. FERC FORM NO.1 (REV. 12-03)Page 407.2
FERC FORM NO.1 (REV. 12-03)Page 410
............................................
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) OA Resubmission 04/16/2009
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 facilly, and give a concise statement of the facts in a footnote. If licensed project,
give project number in footnote.
Line Year .installe. ça~acily ~etPeaK Net GenerationName of Plant Orig.Name Plate atini Demand Excluding Cost of Plant
No.Const.(In MW)(~tWn.)Plant Use
(a)(b)(c)(e)(f)
1 Kettle Falls CT 2002 7.20 8.0 2,762.000 9,169,338
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25 ,
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
...........................................
. FERC FORM NO.1 (REV. 12-03)
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (MO, Da, Yr)End of 2008/04
(2) OA Resubmission 04/16/2009
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 utilzed in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset Operation ProOuctlon Expenses Fuel Costs (in cents LineRetire. Costs) Per MW Exc'l. Fuel Fuei Maimenance Kind of Fuel (per Millon Btu)
(g)(h)(i)0)(k)(I)
No.
1,273,519 132,955 292,805 21,896 Nat Gas 909 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
Page 411
FERC FORM NO.1 (ED. 12-S7)Page 422
............................................
Name of Respondent This
Wrt
is: Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) nA Resubmisslon 04/16/2009
TRANSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of Iines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accunts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Accunt 121, Nonutilty Propert.
5. Indicate whether the type of supporting strcture 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 Iype of supportng structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portons of a transmission line of a different tye 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 trnsmission 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 strctures 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 footnte, explain the basis of such occupancy and state whether expenses with
respect to such strctures are included in the expenses reported for the line designated.
LE~GthH ~oie WileS)Line
(Indicate Ji~;'Type of Iri e 5dP NumberNo.other than u dergroun lines Of60 cvcle 30hase)Supporting report circuit miles)
From vn ~(flc(ure vnf'lii:~~wes CircuitsToOperatingDesignedStructureof Lin~o 1.1)0 er
Desilla ed ine(a)(b)(c)(d)(e)(g)(h)
1 Group Sum 6O.OC 60.00 1.00
2
3 Group Sum 115.OC 115.00 . 1,548.00
4
5 Beacon Sub #4 BPABell Sub 23O.OC 230.00 Steel Tower 1.00 1
6 Beacon Sub BPABell Sub 23O.OC 230.00 HTyp 5.00 1
7 Beacon Sub #5 BPA Bell Sub 230.0(230.00 Steel Pole 4.00 1
8 Beacon Sub #5 BPA Bell Sub 230.0(230.00 HType 2.00 1
9 Beacon Cabinet Gorge Plant 230.0(230.00 Steel Tower 1.00 1
10 Beacon Cabinet Gorge Plant 230.0(230.00 SleelPole 26.00 2
11 Beacon Cabinet Gorge Plant 230.0C 230.00 HType 53.00 1
12 Beacon Sub Lolo Sub 230.0(230.00 SleelTower 1.00 1
13 Beacon Sub Lolo Sub 23O.OC 230.00 HType 108.00 1
14 Benewah Shawnee 230.0(230.00 Steel Pole 60.00 1
15 Noxon Plant Pine Creek Sub 230.0(230.00 HType 43.00 1
16 Cabinet Gorge Plant Noxon 230.0(230.00 HType 19.00 1
17 Benewah Sw. Station Pine Creek Sub 230.0(230.00 SleelTower 1
18 Benewah Sw. Station Pine Creek Sub 230.0(230.00 HType 43.00 1
19 Divide Creek Lolo Sub 230.0(230.00 Steel Tower 1
20 Divide Creek Lolo Sub 230.0C 230.00 HType 43.00 1
21 N. Lewiston Walla Walla 230.0C 230.00 Steel Tower 4.00 1
22 N. Lewiston Walla Walla 23O.0C 230.00 HType 43.00 1
23 N. Lewiston Shawnee 23O.0C 230.00 Steel Tower 7.00 1
24 N. Lewiston Shawnee 23.0(230.00 HTyp 27.00 1
25 Walla Walla Wanapum 230.0(23.00 Alum.1
26 Walla Walla Wanapum 230.0(230.00 HType 78.00 1
27 BPA (Libby)Noxon Plant 23O.0C 230.00 Steel Tower 1.00 1
28 BPA/Hot Springs #1 Noxon Plant 230.0(230.00 Steel Tower 1.00 1
29 BPA/Hot Springs #2 Noxon Plant (dead)230.0(230.00 Steel Tower 2.00 1
30 BPA/Hot Springs #2 Noxon Plant 230.0(230.00 HType 68.00 1
31 BPA Line West Side Sub 230.0(230.00 Steel Pole 2.00 2
32 Hatwi N. Lewiston Sub 230.0(230.00 HType 7.00 1
33 Divide Creek Imnaha 230.0C 230.00 HType 20.00 1
34 Colstrip Plant Broadview 500.0C 500.00
35
36 TOTAL 2,215.00 3.00 31
...........................................
. FERC FORM NO.1 (ED. 12-87)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) n A Resubmission 04/16/2009
RANSMISSION LINE STATISTICS ((ontinued)
7. Do not report the same transmission line structure twce. 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 tw or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or porton 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 accunted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (I) on the book cost at end of year.
I"v~ i VI' LINE (Include in Column (j 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)0)(k)(i)(m)(n)(p)
136,03S 70,092 20,130 1
2
8,434,651 88,411,161 96,845,812 468,900 663,579 584 1,133,06~3
4
95 McMACSR 17,91.:1,334,573 1,352,486 6,276 6,27E 5
1272 McMACSR 6
1272 ACSS 7
1272 ACSS 30,32~3,280,805 3,311,128 1,025 7,852 8,871 8
95 McMACSR 9
1590 ACSS 10
95 McMACSR 324,32 36,013,172 36,337,499 26,329 26,32S 11
95 McMACSR 12
1272 McMAL 456,16.6,758,36E 7,214,528 30,161 10,635 40,796 13
1590 ACSS 570,20 47,025,m 47,595,386 1,981 3,175 5,156 14
954 McMAL 105,64 17,385,07E 17,490,72 9,502 57,27S 66,78C 15
954 McMAL 49,04!1,066,610 1,115,655 4,588 4,58S 16
954 McMAL 17
954 McMAL 157,19 2,600,653 2,757,84 7,071 20,580 27,651 18
1272 McMAL 19
1272 McMAL 86,221 3,660,550 3,746,778 423 16,000 16,42~20
1272 McMAL 21
1272 McMAL 623,98;6,153,355 6,777,339 13,625 5,806 19,431 22
1272 McMAL 23
1272 McMAL 872,151 8,065,713 8,937,864 4,639 4,63~24
1272 McMAL 25
1272 McMAL 70,781 2,552,486 2,623,267 22,497 40,460 -62,95 26
1272 McMAL 27
1272 McMAL 19,521 19,521 5,832 5,83.i 28
1272 McMAL 29
1272 McMAL 144,63 3,287,45.:3,432,091 2,150 61,183 63,33~30
1272 McMAL 36,461 594,~631,00 -2,667 2,66 31
1272 McMACSR 106,581 2,517,780 2,624,361 32
1272 McMAL 60,30~1,297,448 l,357,75C 33
595,78!28,743,579 29,33,368 44,275 461,390 68,206 573,871 34
35
12,878,425 26,838,115 273,716,540 60,249 1,393,630 68,7lK 2,06,e&36
Page 423
FERC FORM NO.1 (REV. 12-03)Page 424
............................................
Name of Respondent This
Wrt
Is: Date of Repor Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008/04
(2) riA Resubmission 04/16/2009
RANSMISSION LINES ADDED DUR NG YEAR
1. Report below the information called for concerning Transmission lines added or altered during the year.It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (I) to (0), it is permissible to report in these columns the
Line LINe L~gth IN\:,I"t:K rUR
No.From To in Type Numberper Present Ultimate
Miles Miles
(a)(b)(c)(d)(e)(f)(g)
1 Benewah Shawnee 45.00 Steel Pole 8.aC 1 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 45.00 8.00 1 1
..........................................
. FERC FORM NO.1 (REV. 12-03).
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) An Original (Mo, Da, Yr)End of 2008104
(2) Fi A Resubmission 04/16/2009
TRAN MISSION LINES ADDED DURING Y AR (Continued)
costs. Designate, however, if estimated amounts are r~ported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (i) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
Voltage LINE COSt Line
Size Specification COnf~uration KV Land and Poles, Towers Conductors Asset Total No.
and pacing (Operating)Land Rights and Fixtures and Devices Retire. Costs
(D)(h)(i)0)(k)(I)(m)(n)(0)
1590 ACSS SDC.20.79 23C 468 .1,59~409,732 408,608 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
468 -1,59:409,732 408,608 44
Page 425
FERC FORM NO.1 (ED. 12-96)Page 426
............................................
Name of Respondent ThiS~IOrt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008104
(2)A Resubmission 04/16/2009
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 STATE OF WASHINGTON
2
3 Airwy Heights Distr. Unattended 115.00 13.80
4 Barker Road Distr. Unattended 110.00 13.80
5 Beacon Tmsm. Unattended 230.00 115.00 13.80
6 Boulder Tmsm. Unattended 230.00 115.00 13.80
7 Chester Distr. Unattended 115.00 13.80
8 Chewelah 115Kv Distr. Unattended 115.00 13.80
9 Colbert Distr. Unattended 115.00 13.80
10 College & Walnut Distr. Unattended 115.00 13.80
11 Colvile 115Kv Distr. Unattended 115.00 13.80
12 Critchfield Distr. Unattended 115.00 13.80
13 Dry Gulch Distr. Unattended 115.00 13.80
14 East Colfax Distr. Unattended 115.00 13.80
15 East Farms Distr. Unattended 115.00 13.80
16 Fort Wright Distr. Unattended 115.00 13.80
17 Francis and Cedar Distr. Unattended 115.00 13.80
18 Gifford Distr. Unattended 115.00 34.00
19 Glenrose Distr. Unattended 115.00 13.80
20 Greenwood Distr. Unattended 115.00 13.80
21 Hallett & White 115-13kv Distr. Unattended 115.00 13.80
22 Indian Trail Dist. Unattended 115.00 13.80
23 Industrial Park Distr. Unattended 115.00 13.80
24 Kettle Falls Distr. Unattended 115.00 13.80
25 Lee & Reynolds Distr. Unattended 115.00 13.80
26 Liberty Lake Distr. Unattended 115.00 13.80
27 Little Falls 115/34Kv Distr. Unattended 115.00 34.00
28 Lyons & Standard Distr. Unattended 115.00 13.80
29 Mead Distr. Unattended 115.00 13.80
30 Metro Distr. Unattended 115.00 13.80
31 Milan Distr. Unattended 115.00 13.80
32 Milwood Tmsm & Dist Unattd 115.00 60.00 13.80
33 Ninth & Central Distr. Unattended 115.00 13.80
34 Northeast Distr. Unattended 115.00 13.80
35 Northwest Distr. Unattended 115.00 13.80
36 Opportunity Dist. Unattended 115.00 13.80
37 Othello Distr. Unattended 115.00 13.80
38 Post Street Distr. Unattended 115.00 13.80
39 Pound Lane Distr. Unattended 115.00 13.80
40 Pullman Dist Unattended 115.00 13.80
...........................................
. FERC FORM NO.1 (ED. 12-96)
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) OA Resubmission 04/16/2009
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwse 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 part, 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 part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(Q)(h)(i)Ci (k)
1
2
24 2 Fred Oil & Air Fan 2 40 3
12 1 Two Stage Fan 1 20 4
536 4 Fred Oil & Air Fan 4 560 5
300 2 Two Stage Fan 2 50C 6
24 2 Fred Oil & Air Fan 2 40 7
15 3 Fred Ai 3 15 8
12 1 Fred Oil & Air Fan 1 20 9
36 2 Two Stage Fan 2 60 10
31 3 Frcd Oil & Air Fan 3 45 11
12 1 Two Stage Fan 1 20 12
24 2 Fred Oil & Air Fan 2 40 13
12 1 FrOil/Air Fan 1 20 14
12 1 Two Stage Fan 1 20 15
24 2 Fr OillAir/2StgFan 2 40 16
60 2 Fred Air Fan 2 36 17
12 1 18
12 1 Fred Oil & Air Fan 1 2C 19
13 4 1 FrOillAirlTwo Stage 4 22 20
12 1 Two Stg Fan 1 20 21
12 1 Two Stage Fan 1 20 22
28 3 Two StglPtlFred Oil 40 40 23
12 1 Fred Oil & Air Fan 1 20 24
12 1 Two Stage Fan 1 2C 25
24 2 Two Stage Fan 2 40 26
12 1 27
36 2 Two Stage Fan 2 6C 28
18 1 Two Stage Fan 1 30 29
24 2 Two Stage Fan 2 40 30
24 2 Frcd Oil & Air Fan 2 40 31
44 3 1 FrcAir/FrcOillAirFan 3 61 32
24 2 1 Fred & Two Stage Fan 2 4C 33
24 2 Two Stage Fan 2 40 34
24 2 Two Stage Fan 2 40 35
12 1 Two Stage Fan 1 20 36
24 2 FrOil/AirFan 2 40 37
95 4 Fred Oil & Wt Fan 4 9~38
24 2 Two Stage Fan 2 40 39
24 2 Fred Oil & Air Fan 2 40 40
Page 427
FERC FORM NO.1 (ED. 12-96)Page 426.1
............................................
Name of Respondent This oo0rt Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ri A Resubmission 04/16/2009
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Ross Park Distr. Unattended 115.00 13.80
2 Roxboro Distr. Unattended 115.00 24.00
3 Shawnee Trans. Unattended 230.00 115.00
4 Silver Lake Distr. Unattended 115.00 13.80
5 Southeast Distr. Unattended 115.00 13.80
6 South Othello Distr. Unattended 115.00 13.80
7 South Pullman Distr. Unattended 115.00 13.80
8 Sunset Distr. Unattended 115.00 13.80
9 Third & Hatch Distr. Unattended 115.00 13.80
10 Waikiki Distr. Unattended 115.00 13.80
11 Washington State University-East Campus Distr. Unattended 13.80 4.16
12 WestSide Trans. Unattended 230.00 115.00 13.80
13 Other: 72substa less than 10MVA Distr. Unattended
14
15 STATE OF IDAHO
16 Appleway Dist & Trf Unattnd 115.00 13.80
17 Avondale Dist. Unattended 115.00 13.80
18 Benewah Trans. Unattended 230.00 115.00 13.80
19 Big Creek Distr. Unattended 115.00 .13.80
20 Blue Creek Distr. Unattended 115.00 13.80
21 Bunker Hil Distr. Unattended 115.00 13.80
22 Clark Fork Distr. Unattended 115.00 21.80
23 Coeur d'Alene 15th Ave Distr. Unattended 115.00 13.80
24 Cottonwood Distr. Unattended 115.00 24.90
25 Daiton Distr. Unattended 115.00 13.80
26 Grangevile Dist & Trf Unattnd 115.00 13.80
27 Holbrook Distr. Unattended 115.00 13.80
28 Huetter Distr. Unattended 115.00 13.80
29 Juliaetta Distr. Unattended 115.00 13.80
30 Kamiah Dist & Trfr Unattnd 115.00 13.80
31 Kooskia Distr. Unattended 115.00 13.80
32 Lolo Tran & Dist Unattnd 230.00 115.00 13.80
33 Moscow Distr. Unattended 115.00 13.80
34 Moscow 230Kv Tran & Dist Unattnd 230.00 115.00 13.80
35 North Moscow Distr. Unattended 115.00 13.80
36 North Lewiston Trans Unattended 230.00 115.00 13.80
37 North Lewiston Distr. Unattended 115.00 13.80
38 Oden Distr. Unattended 115.00 21.80
39 Oldtown Distr. Unattended 115.00 21.80
40 Orofino Distr. Unattended 115.00 13.80
...........................................
. FERC FORM NO.1 (ED. 12-96)
Name of Respondent This wort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) riA Resubmission 04/16/2009
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other 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 part is an associated company.
Capacily of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacily No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
30 2 'Two Stage Fan 2 60 1
24 2 Two Stage Fan 2 40 2
250 1 3
12 1 Fred Oil & Air Fan 1 20 4
30 2 Two Stage Fan 2 50 5
12 1 Two Stage Fan 1 20 6
30 2 Two Stage Fan 240 50 7
35 4 1 Pt. & Two Stage Fan 4 50 8
54 3 Two Slg Fan & Cap 103 90 9
24 2 Two Stage Fan 2 40 10
15 2 Two Stage Fan 2 19 11
250 2 12
193 137 13
14
15
30 2 Two Stage Fan 2 50 16
12 1 Fred Oil & Air Fan 1 20 17
75 1 Two Stage Fan 1 125 18
17 2 Portable Fan 2 22 19
20 3 1 20
12 1 Frcd Air Fan 1 2E 21
10 1 Frcd Air Fan 1 13 22
36 2 Two Stage Fan 2 60 23
12 1 Two Stage Fan 1 20 24
24 2 FrcOilfAir2StgFan 2 40 25
25 4 FredOillAirlPt Fan 2 34 26
12 1 Two Stage Fan 1 20 27
12 1 Two Stage Fan 1 20 28
12 1 Fred Oil & Air Fan 1 20 29
12 1 Two Stage Fan 1 20 30
15 3 Fred Air Fan 2 20 31
270 3 Fred OilfAirlTwo Stg 1 262 32
24 2 FrOilfAir/2Stg Fan 2 40 33
137 2 1 Capacitors 80 182 34
12 1 Two Stage Fan 1 20 35
250 1 1 Fred Oil/Air&Cptrs 81 295 36
10 3 37
10 1 Frcd Air Fan 13 38
10 1 Fred Air Fan 1 13 39
20 2 Frcd Oil & Air Fan 1 21:40
Page 427.1
FERC FORM NO.1 (ED. 12-96)Page 426.2
............................................
Name of Respondent ThiS!ort Is:Date of Report YearlPeriod of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2)A Resubmission 04/16/2009
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 Osbum Distr. Unattended 115.00 13.80
2 Pine Creek Tran & Dist Unattd 230.00 110.00 13.80
3 Pleasant View Distr. Unattended 115.00 13.80
4 Post Falls Distr. Unattended 115.00 13.80
5 Potlatch Dist & Trfr Unatt 115.00 13.80
6 Prarie Distr. Unattended 115.00 13.80
7 Priest River Distr. Unattended 115.00 20.80
8 Sagle Dist. Unattended 115.00 20.80
9 Sandpoint Distr. Unattended 115.00 20.80
10 South Lewiston Distr. Unattended 115.00 13.80
11 Sweetwater Distr. Unattended 115.00 24.00
12 St. Maries Distr. Unattended 115.00 24.00
13 Tenth & Stewrt Distr. Unattended 115.00 13.80
14 Wallace Dist & Whse Unattd 115.00 13.80
15 Rathdrum Tran & Dist Unattd 230.00 115.00 13.80
16 Other: 29 substa less than 10 MVA Distr. Unattended
17
18 STATE OF MONTANA
19 1 substation less than 10 MVA Distr. Unattended
20
21 SUBSTA. ~ GENERATING PLANTS
22 STATE OF WASHINGTON
23 Boulder Park Trans Step-Up 115.00 13.80
24 Kette Falls Trans Step-Up 115.00 13.80
25 Long Lake Trans.115.00 4.00 4.00
26 Nine Mile Trns Step-Up & Dist 115.00 60.00 2.30
27 Little Falls Trans.115.00 4.00
28 Northeast Trans. Step-Up 115.00 13.80
29
30 STATE OF IDAHO
31 Cabinet Gorge (Switchyard)230.00 115.00 13.80
32 Cabinet Gorge (HED)Trans. Step-Up 230.00 13.80
33 Post Falls Trans. Step-Up 115.00 2.30
34 Rathdrum Trans. Step-Up 115.00 13.80
35 STATE OF MONTANA
36 Noxon Trans. Step-Up 230.00 13.80
37
38 STATE OF OREGON
39 Coyote Springs II Trans. Step -Up 500.00 13.80 18.00
40
...........................................
. FERC FORM NO.1 (ED. 12-96)
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) ri A Resubmission 04/16/2009
SUBSTATIONS (Continued)
5. Show in columns (1),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 part, 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 part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT 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)(j (k)
12 1 Portable Fan 1 15 1
262 3 Capacitors 80 307 2
12 1 Two Stage Fan 1 20 3
18 1 Two Stage Fan 1 30 4
15 2 Portable Fan 2 19 5
12 1 Frcd Oil & Air Fan 1 20 6
10 1 1 Frcd Air Fan 1 13 7
12 1 Two Stage Fan 1 20 8
30 3 Fred Air Fan 3 38 9
27 4 Port Fan/FredOil/Ai 4 3~10
12 1 Frcd Oil & Air Fan 1 20 11
24 2 Two Stage Fan 2 40 12
30 2 Fred OillAirlTwo Stg 2 50 13
10 3 14
462 3 FredOil/AirFan/Cptr 243 470 15
82 47 1 16
17
18
5 1 19
20
21
22
36 1 Two Stage Fan 1 60 23
30 1 1 Two Stage Fan 1 62 24
80 4 1 25
18 2 Frcd Oil & Air Fan 1 40 26
24 2 Fred Oil & Air Fan 2 40 27
36 1 Two Stage Fan 1 60 28
29
30
125 1 2 stage fan 1 13 31
30 6 1 Fred Oil and Air Fan 2 30 32
16 2 Fred Air/Oil/Air Fan 2 21 33
114 2 3 Two Stage Fan 2 19C 34
35
532 9 1 Fred Oil Air e 555 36
37
38
213 1 1 Two Stage fan 2 355 39
40
Page 427.2
FERC FORM NO.1 (ED. 12-96)Page 426.3
............................................
Name of Respondent This oo0rt Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo. Da. Yr)End of 2008/04
(2) nA Resubmission 04/16/2009
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 SUMMARY:
2 Washington:
3 10 subs Trans. Unattended
4 116 subs Distr. Unattended
5 3 subs Tran & Dist Unatt
6 Idaho:
7 6 subs Trans. Unattended
8 58 subs Distr. Unattended
9 9 subs Tran & Dist Unattnd
10 Montana:1 sub Trans. Unattended
11 1 sub Distr. Unattended
12 Oregon:1 sub Trans. Unattended
13 System: 205 subs
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
...........................................
. FERC FORM NO.1 (ED. 12-96)
Name of Respondent This wort Is:Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr)End of 2008/04
(2) r= A Resubmission 04116/2009
SUBSTATIONS (Continued)
5. Show in columns (1),0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, 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.
Capacily of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacily No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(g)(h)(i)(j (k)
1
2
1189 3
1221 4
604 5
6
660 7
511 8
1222 9
533 10
5 11
213 12
6158 13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
Page 427.3
Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
!Schedule Page: 219 Line No.: 8 Column: c
Includes Accum Provision of non-recoverable plant of ~$29i, 550~
and PAS 143 depreciation of $22,019
¡Schedule Page: 219 Line No.: 16 Column: c
Includes change in Removal Work in Process of $96,737
IFERC FORM NO.1 (ED. 12-87)
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04116/2009 2008/04
FOOTNOTE DATA
!Schedule Page: 224 Line No.: 5 Column: f
Line 5 - Avista Capital - Other changes in Net Investment:
Represents the liability to non-controlling interest at Advantage IQ
I$chedule Page: 224 Line No.: 6 Column: f
Line 6 - Avista Capital - Other changes in Net Investment:
Represents the change in controlling ownership of Advantage IQ
I FERC FORM NO.1 (ED. 12-87)Page 450.1
Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation /2) A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
!Schedule Page: 227 Line No.: 1 Column:d
(1)Electric
(2)Gas
¡Schedule Page: 227 Line No.: 5 Column:dFootnote Linked.See note on 227,Row:1,col/item:
ISchedule Page: 227 Line No.: 7 Column:dFootnote Linked.See note on 227,Row:1,col/item:
ISchedule Page: 227 Line No.: 8 Column:d
Footnote Linked.See note on 227,Row:1,col/item:
ISchedule Page: 227 Line No.: 9 Column:dFootnote Linked.See note on 227,Row:1,col/item:
¡Schedule Page: 227 Line No.: 10 Column:dFootnote Linked.See note on 227,Row:1,col/item:
¡Schedule Page: 227 Line No.: 11 Column:dFootnote Linked.See note on 227,Row:1,col/item:
IFERC FORM NO.1 (ED. 12-87)
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2) A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
!Schedule Page: 231 Line No.: 2 Column: b
Total Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 2 Column: d
Total Reimbursements Received Life to Date.
¡Schedule Page: 231 Line No.: 3 Column: b
Total Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 3 Column: d
Total Reimbursements Received Life to Date.
¡Schedule Page: 231 Line No.: 22 Column: b
Total Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 22 Column: d
Total Reimbursements Received Life to Date.
!Schedule Page: 231 Line No.: 23 Column: b
Total Charges Incurred Life to Date.
!Schedule Page: 231 Line No.: 23 Column: d
Total Reimbursements Received Life to Date.
~chedule Page: 231 Line No.: 24 Column: b
Total Charges Incurred Life to Date.
!Schedule Page: 231 Line No.: 24 Column: d
Total Reimbursements Received Life to Date.
¡Schedule Page: 231 Line No.: 25 Column: b
Total Charges Incurred Life to Date.
~ciiëciu"ë-p;igë:231 Line No.: 26 Column: b
Total Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 27 Column: b
Total Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 28 Column: b
Total Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 29 Column: b
Total Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 30 Column: b
Total Charges Incurred Life to Date.
~chedule Page: 231 Line No.: 31 Column: b
Total Charges Incurred Life to Date.
!Schedule Page: 231 Line No.: 32 Column: b
Total Charges Incurred Life to Date.
rsdule Page: 231 Line No.: 33 Column: b
Total Charges Incurred Life to Date.
¡Schedule Page: 231 Line No.: 34 Column: b
Total Charges Incurred Life to Date.
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
¡Schedule Page: 256 Line No.: 22 Column: h
Background
On December 31, 2008, the City of Forsyt, Montana Pollution Control Revenue Refunding Bonds, Seres
1999A (Avista Corporation Colstrip Project) due 2034 were remarketed on behalf of A vista Corp. in the amount
of $66.7 milion. A vista Corp. purchased the Bonds and expects that at a later date, subject to market
conditions, the bonds wil be refunded or remarketed to unaffliated investors.
The trust Indenture indicates the following:
THE BONDS SHALL NOT BE DEEMED TO CONSTITUTE A DEBT, LIABILITY OR GENERA
OBLIGATION OF THE ISSUER, THE STATE OR OF AN POLITICAL SUBDIVISION THEREOF,
OR A PLEDGE OF THE FAITH AND CREDIT OF THE ISSUER, THE STATE OR OF AN SUCH
POLITICAL SUBDIVISION, BUT SHALL BE PAYABLE SOLELY FROM THE REVENUES AND
PROCEEDS PROVIDED THEREFOR. THE ISSUER SHAL NOT BE OBLIGATED TO PAY THE SAM
NOR INTEREST THEREON EXCEPT FROM THE REVENUES AND PROCEEDS PLEDGED THEREFOR,
AND NEITHER THE FAITH AND CREDIT NOR THE TAXING POWER OF THE ISSUER, THE STATE
OR OF AN POLITICAL SUBDIVISION THEREOF IS PLEDGED TO THE PAYMNT OF THE
PRINCIPAL OF OR THE INTEREST ON THE BONDS.
Accounting Guidance
SFAS 140 paragraph 16 indicates that there are specific criteria that must be met in order to remove a liabilty
from the financial statements.
Paragraph 16 - A debtor shall derecognize a liabilty if and only if it has been extinguished. A liabilty
has been extinguished if either of the following conditions is met:
a. The debtor pays the creditor and is relieved of its obligation for the liabilty. Paying the
creditor includes delivery of cash, other financial assets, goods, or servces or reacquisition by the
debtor of its outstanding debt securties whether the securties are canceled or held as so-called
treasur bonds.
b. The debtor is legally released from being the primary obligor under the liabilty, either
judicially or by the creditor.
Conclusion
The $66.7 millon of pollution control bonds should be excluded from Avista Corp's balance sheet based upon
the following:
A vista Corp. has effectively paid the creditors by purchasing the outstanding Bonds, which meets the
requirements of paragraph 16a.
IFERC FORM NO.1 (ED. 12-87)
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008/04
FOOTNOTE DATA
Although the Bonds are not in Avista Corp's name, the trust indentue indicates that the Bonds shall not
be deemed to be an obligation of the issuer (the City of Forsyth). The bonds are effectively a "conduit
bond" which indicates they are the obligation of A vista Corp. Therefore, the reacquisition of bonds that
A vista Corp is the primar obligor would meet the requirements of paragraph 16a to extinguish the
bonds.
¡Schedule Page: 256 Line No.: 31 Column: h
The $272,860,000 Senior Notes matued June 1, 2008.
IFERC FORM NO.1 (ED. 12-S7) Page 450.2
Contrbutions in Aid of Constrtion - Electrc 6,259,362
............................................
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 04/16/2009 2008104
FOOTNOTE DATA
!Schedule Page: 261 Line No.: 8 Column: a
Schedule Page: 261 Line No: 5 Column: b
Taxable Income Not Reported on Books
Tax NOT Book Income BPA C&RD Receipts
Tax NOT Book Income
Tax NOT Book Income
Tax NOT Book Income
Tax NOT Book Income
Tax NOT Book Income
Tax NOT Book Income
Tax NOT Book Income
Tax NOT Book Income
Tax NOT Book Income
Tax NOT Book Income
Tax NOT Book Income
CSS Temp Servce Fees - ID 54,920
CSS Temp Servce Fees - W A 73,800
Customer Uncollectibles - Sales for Resale - ED AN 2,705,100
Contributions In Aid of Constrction - Gas Nort 304,971
BETC - Oregon Purchased Tax Credits (l! 87%)
Contrbutions in Aid of Constrction - OR
(96,870)
32,762
Customer Uncollectibles (excluding ED AN)125,086
Customer Uncollectibles (excluding ED AN)33,340
Customer Uncollectibles (excluding ED AN)15,401
BETC Interest - Perm Diff
(6,023)
9,501,848
Schedule Page: 261 Line No:10 Column: b
Deductions Recorded on Books Not deducted for Return
Book NOT Tax Expense Book Depreciation - Electrc
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
71,818,207
DSM - Old Electrc Progr Amort 1,280,293
F AS 106 - Deferred Amort Postretire Benefits - ED ID 88,782
F AS 106 - Deferred Amort Postretire Benefits - ED W A 250,574
Montana Settlement - ED ID
(1,428,501)
Monta Settement - ED W A
Non-monetary Purchased Power
(2,779,808)
(277,615)
Rathdr Turbine Sales Tax Refud
Redemption Expense Amort - PCBs
(33,828)
194,949
WN3 - Investment Exchange Power 2,450,031
Book Depreciation - Gas Nort 11,614,556
IFERC FORM NO.1 (ED. 12-87)Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
Book NOT Tax Expense
DSM - Old Gas Program Amort 437,557
F AS 106 - Deferred Amort Postretire Benefits - GD W A 55,561
Book Depreciation - Gas South 4,510,915
Transportation Book Depreciation 113,228
Airplane Lease Payments 215,186
FAS 106 (68.6% O&M)
Meal Disallowances
(955,212)
272,755
Paid Time Off Equalization 427,699
Redemption Expense Amort 2,394,894
Transportation Book Depreciation 999,769
Airplane Lease Payments 57,355
FAS 106 (68.6% O&M)
Meal Disallowances
(254,599)
72,699
Paid Time Off Equalization 113,998
Redemption Expense Amort 638,328
Transportation Book Depreciation 263,810
Airplane Lease Payments 26,495
FAS 106 (68.6% O&M)
Meal Disallowances
(117,609)
33,583
Paid Time Off Equalization 52,660
Redemption Expense Amort 294,869
401(k) ESOP Dividend Deduction
A V A Holding Co - Corporate Restrcture
(I ,044,570)
7,921
Impairment on LM 2500
Political Contrbutions
(2,289,978)
1,211,098
Preferred Dividend Requirement
SERP - Supplemental Executive Retirement Plan 629,528
Page 450.2IFERC FORM NO.1 (ED. 12-87)
Book NOT Tax Expense Penalties 138,152
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
91,483,730
Schedule Page:261 Line No:15 Column b
Income Recorded on Books Not Included in Return
Book NOT Tax Income AFUDC - Electrc
(1,934,908)
Book NOT Tax Income Boulder Park Disallow - IPUC Order 10/2004
(103,530)
Book NOT Tax Income Clark Fork PMEs - ED ID
(274,403)
Book NOT Tax Income CS2 Retention - ED ID
(174,560)
Book NOT Tax Income Gain General Offce Building - ED
(196,092)
Book NOT Tax Income Grid West/TO Funding - ED.ID 70,806
Book NOT Tax Income Grid West/TO Funding - ED.WA 158,213
Book NOT Tax Income IdaoPCA 1,660,797
Book NOT Tax Income Injur & Damages - Electrc 135,500
Book NOT Tax Income Kettle Falls Disallowance - ED W A
(134,954)
Book NOT Tax Income NE Tan Spil
(36,933)
Book NOT Tax Income Nez Perce Settement - ED ID 5,212
Book NOT Tax Income Nez Perce Settlement - ED W A
(22,008)
Book NOT Tax Income Unbiled Revenue Add-ons - ED ID 598,226
Book NOT Tax Income Unbiled Revenue Add-ons - ED W A 747,631
Book NOT Tax Income W A Deferred Power Costs 23,802,834
Book NOT Tax Income Warila Units 233,428
Book NOT Tax Income Warsila Units 785,184
Book NOT Tax Income AFUDC - Gas Nort
(295,526)
Book NOT Tax Income Decoupling Mechansm - W A Gas
(249,921)
Book NOT Tax Income Deferred Gas - GD ID 3,217,554
Book NOT Tax Income Deferred Gas - GD W A 8,749,580
Book NOT Tax Income Deferred Gas - GD AN 1,597,806
Book NOT Tax Income Gain General Offce Building - GD
IFERC FORM NO.1 (ED. 12-87)Page 450.3
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Book NOT Tax Income
Injur & Damages - Gas Nort
(65,364)
1,100,321
Unbiled Revenue Add-ons - GD ID 48,717
Unbiled Revenue Add-ons - GD W A 182,690
AFUDC - Gas South
Deferred Gas - OR
(119,981)
8,148,345
DSM OR - Additions - 186700 - GD OR 2,628,336
DSM OR - Amortzation - 495600
DSM OR - Amortization - 908250
(38,608)
1,263,423
DSM OR - Amortization Accrual - 908250 (OJ 235)50,056
Injury & Damages - Oregon
Deferred Gas - ID - Interest 201,846
Deferred Gas - W A - Interest 540,412
DFIT on Equity Stock Comp 2,411,528
DFIT on Liability Stock Comp 284,319
Idaho PCA - Interest
Kettle Falls Nonoperatig - ED ID
(1,152,699)
(53,066)
(960,878)
(11,007)
9,593,949
Offcers Life Insurance (Cash Surender)
Offcer Life Insurance Benefit Accrual
PGE Monetization (Spokane Energy)
W A Deferred Power Costs - Interest
Tax-Exempt Interest Income
(2,231,098)
(317,272)
162,390OR Deferred Gas - Interest
OR DSM Deferred - Interest
Wind Generation AFUDC
(213,177)
(35,194)
(738,101)
Colstrp Settlement - ED ID
Colstrip Settement - ED W A
I FERC FORM NO.1 (ED. 12-87)Page 450.4
Chicago Climate Exchange - ED il 754,484
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
Book NOT Tax Income
Book NOT Tax Income Chicago Climate Exchange - ED W A
59,774,306
Schedule Page:261 Line No: 20 Column b
Deductions on Return Not Charged Against Book Income
Tax NOT Book Expense BPA Residential Exchange - ED il
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
Tax NOT Book Expense
609,223
BP A Residential Exchange - ED W A 3,140,406
Cost of Removal / Salvage - Electrc
DSM Tarff Rider - ED il
(1,760;187)
(1,768:,539)
(1,587,898)
320,000
DSM Tarff Rider - ED WA
DSM Tarff Rider - ED AN
Tax Depreciation - Electrc
Tax Depreciation - Rathdrm Turbine
(132,192,708)
(3,836,432)
(117,163)
(627,887)
(1,273,972)
o
Cost of Removal / Salvage - Gas Nort
DSM Tarff Rider - GD il
DSM Tarff Rider - GD W A
DSM Tarff Rider - GD AN
Tax Depreciation - Gas Nort
Cost of Removal / Salvage - Oregon
(29,658,937)
(359,686)
(15,594,413)
(12,785)
(458,114)
1,110,571
Tax Depreciation - OR Gas
Tax Depreciation - Basic American Foods Non-Utility
Tax Depreciation - Sandpoint Acquisition Adjustment
WPNG Acquisition OR - Book
Tax Amortization WPNG Acquisition - OR
Section 199 Manufactuing Deduction
(631,039)
(2,830,350)
(1,186,711)
Oregon Senate Bil 408 (SB 408)
Deferred Compensation Accrual
(4,856,348)Tax NOT Book Expense FASB 87 & Retirement Pay Accrual (68.6% O&M)
IFERC FORM NO.1 (ED. 12-87) Page 450.5
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
Tax NOT Book Expense Interest Rate Swaps - Amortization
(17,760,785)
(10,838,756)
(1,294,396)
(4,733,906)
(2,888,929)
(597,933)
(2,186,778)
(1,334,511)
Tax NOT Book Expense Interest Rate Swaps - Amortization
Tax NOT Book Expense Deferred Compensation Accrual
Tax NOT Book Expense FASB 87 & Retirement Pay Accrual (68.6% O&M)
Tax NOT Book Expense Deferred Compensation Accrual
Tax NOT Book Expense FASB 87 & Retirement Pay Accrul (68.6% O&M)
Tax NOT Book Expense Interest Rate Swaps - Amortization
Tax NOT Book Expense CDA Lake Settement ED ID
Tax NOT Book Expense CDA Lake Settement ED W A
Tax NOT Book Expense CDA Lake Settlement ED AN
(27,733,385)
(262,942,348)
IFERC FORM NO.1 (ED. 12-S7) Page 450.6
rsdule Page: 310.4 Line No.: 4
Peaker i LLC capaci ty contract
¡Schedule Page: 310.4 Line No.: 14Bundled Transmission
¡Schedule Page: 310.5 Line No.: 3 Column: b
PPL sale terminates October 31, 2013.
!SchedulePage: 310.5 Line No.: 7 Column: bPuget Sound Energy sale terminates October 31, 2013.
¡Schedule Page: 310.5 Line No.: 12 Column: b
Contract expires 2014.
¡Schedule Page: 310.6 Line No.: 6 Column: b
Sovereign Power contract terminates 1-31-2010
¡Schedule Page: 310.6 Line No.: 7 Column: b
Sovereign Contract terminates 1-31-2010
¡Schedule Page: 310.6 Line No.: 14 Column: aIntracompany Wheeling
¡Schedule Page: 310.6 Line No.: 14 Column: bIntraCompany Wheeling terminates 09/30/2023.
Column: b
terminates Decemer 31, 2016.
Column: b
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2Ç An Original (Mo, Da, Yr)
Avista Corporation 1(2). A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
¡Schedule Page: 310 Line No.: 4 Column: b
SWAP
¡Schedule Page: 310 Line No.: 9 Column: bBPA Contract Terminates Septemer 30, 2011.
¡Schedule Page: 310 Line No.: 10 Column: b
BPA Contract Terminates January 1, 2036.
¡Schedule Page: 310.3 Line No.: 4 Column: bBundled Transmission
¡Schedule Page: 310.3 Line No.: 7NorthWestern Energy LLC sale
¡Schedule Page: 310.3 Line No.: 9
Bundled Transmission
¡Schedule Page: 310.4 Line No.: 3 Column: b
PacifiCorp sale terminates October 31, 2013.
Column:b
expires October 31, 2013.
Column: b
¡Schedule Page: 310.7 Line No.: 1 Column: a
Intracompany generation - sale of ancillary services
¡Schedule Page: 310.7 Line No.: 1 Column: bIntraCompany Generation - Sale of Ancillary Services terminates 12/31/2009.
¡Schedule Page: 310.7 Line No.: 2 Column: bEstimated revenues - true up in later periods.
I FERC FORM NO.1 (ED. 12-87)Page 450.1
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008/04
FOOTNOTE DATA
-~
I
I
I .
I
I
I
\Schedule Page: 326 Line No.: 3 Column: i
Financial Swap
¡Schedule Page: 326 Line No.: 10 Column: b
Terminates 2019
!Schedule Page: 326 Line No.: 12 Column: i
Non Monetary
¡Schedule Page: 326 Line No.: 14 Column: i
Ancillary services - Spin & Supplemental
¡Schedule Page: 326.1 Line No.: 1 Column: i
Non Monetary
¡Schedule Page: 326.1 Line No.: 12 Column: i
Non Monetary
!Schedule Page: 326.2 Line No.: 12 Column: bFootnote Linked. See note on 326, Row: 10, col/item:
¡Schedule Page: 326.3 Line No.: 7 Column: i
Financial Swap
!Schedule Page: 326.4 Line No.: 2 Column: iNon Monetary
ISchedule Page: 326.4 Line No.: 5 Column: i
Non Monetary
IFERC FORM NO.1 (ED. 12-87)Page 450.1
I
I
I
=:
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Oa, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
!Schedule Page: 332 Line No.: 2 Column: 9
Ancilliary Services
ISchedule Page: 332 Line No.: 4 Column: g
Use of Facilities
¡Schedule Page: 332 Line No.: 5 Column: g
Use of Facilities Charge
¡Schedule page: 332 Line No.: 11 Column: g
OATT Rate Case Refund
IFERC FORM NO.1 (ED. 12-87)Page 450.1
............................................
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1 ) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
Column: b
Directors 2008
Vendor Name
HEIDI B STANLEY
BRIAN W DUNHAM
ERIK J ANDERSON
KRISTIANNE BLAKE
JOHN F KELLY
MICHAEL L NOEL
R JOHN TAYLOR
JACK W GUSTAVEL
LURA J POWELL
ROYEIGUREN
Expenses
$23,118
$41,166
$70,247
$66,403
$77,051
$53,789
$26,105
$22,850
$22,267
$66,965
ISChedule Page: 335 LineNo.: 5
Vendor
VENDORS LESS THAN $5,000
ADVENTURS IN ADVERTISING
AZAR'S FOOD SERVICES
BOARDV ANTAGE INC
BOWNE OF LOS ANGELES INC
BROADRIDGE
CITIANKNA
CITY OF SPOKANE
COPYRIGHT CLEARACE CENR INC
CORP CREDIT CAR
DEWEY & LEBOEUF LLP
EDITPOOR
EXECUTIVE MBA PROGRAM
FITCH RATINGS
FOUNDATION FOR WATER & ENERGY EDUCATION
KOLBE CORP
KORN FERRY INTERNATIONAL
MA YN K MALQUIST
MAIAN MCMAHON DURN
MELLON INVESTOR SERVICES LLC
MICHAL G ANDREA
MOODYS INVESTORS SERVICE
NATIONAL HYDROPOWER ASSOCIATION
NORTHWEST GAS ASSOCIATION
NYSE MARKET INC
PAT NEWMAN
IFERC FORM NO.1 (ED. 12-87) Page 450.1
Purpose Amount
Pay Stations
Misællaneous
Subscriptions
Professional Services
Treasury Fe
Miscellaneous
Misællaneous
Misællaneous
Subscriptions
General services
Professional Services
Employee Misc Expenses
Miscellaneous
Donations
Professional services
Miscellaneous
Offce Supplies
Employee Misc Expenses
Miscellaneous
Employee Misc Expenses
Miscellaneous
Donations
Professional Services
General Services
Professional Services
129.036
15383
7735
20661.46
19874.52
36154
35142.55
13748
5106.91
60614.44
31888
10479.25
17990
30583
6190
5971.14
128210.41
6615
5169.28
103843.85
11503.43
67642.4
20520
8995
35423.03
26528
PATRICIA J SHEA
ROGER D WOODWORTH
SKlLLSOFT CORPORATION
THE BANK OF NEW
YORK
THE BANK OF NEW YORK MELLON
THE COEUR D ALENE
THE COEUR D ALENE RESORT
THE DAVENPORT HOTEL
THE LAURL HILL ADVISORY GROUP LLC
THE TRUSTEES OF THE UNIVERSITY
UNION BANK OF CALIFORNA
WASHINGTON ROUNTABLE
WOLFF SERVICES
Materials & Equipment
Rating Agency Fees
Miscellaneous
Miscellaneous
5356
6020
6271
20525
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
Miscellaneous
Miscellaneous
Employee Lodging
Miscellaneous
General Services
Conference Fees
Miscellaneous
Miscellaneous
Employee Relocation
7094
15201
27067
11930
15907
6620
6203
7196
6699
I FERC FORM NO.1 (ED. 12~87)Page 450.2
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
¡Schedule Page: 398 Line No.: 7 Column: b
Interdepartmental spinning reserve service for Native Load.
!Schedule Page: 398 Line No.: 7 Column: d
Interdepartmental spinning reserve service for Native Load.
¡Schedule Page: 398 Line No.: 7 Column: e
Interdepartmental spinning reserve service for Native Load.
¡Schedule Page: 398 Line No.: 7 Column: g
Interdepartmental spinning reserve service for Native Load.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
IFERC FORM NO.1 (ED. 12-87) Page 450.1
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Moi Da, Yr)
Avista Corporation (2)A Resubmission 04116/2009 2008/04
FOOTNOTE DATA
¡Schedule Page: 402 Line No.: -1 Column: b
Operated by Portland General Electric.
¡Schedule Page: 402 Line No.: -1 Column: e
Joint proj ect operated by PPL Montana LLC.
............................................
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/16/2009 2008104
FOOTNOTE DATA
¡Schedule Page: 406 Line No.: -2 Column: b
License period from August 1, 1972 to July 31, 2007. Extended one year 07-09.
!Schedule Page: 406 Line No.: -2 Column: c
License period from August 1, 1972 to July 31, 2007. Extended one year 07-09.
!Schedule Page: 406 Line No.: -2 Column: d
License period from March 1, 2001 to February 28, 2046
¡Schedule Page: 406 Line No.: -2 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. Extended one year 07-09.
¡Schedule Page: 406.1 Line No.: -2 Column: b
License period from August 1, 1972 to July 31, 2007. Extended one year 07-09.
¡Schedule Page: 406.1 Line No.: -2 Column: c
Licensed period from August 1, 1972 to July 31, 2007. Extended one year 07-09.
¡Schedule Page: 406.1 Line No.: -2 Column: dNot a licensed project.
IFERC FORM NO.1 (ED. 12-87) Page 450.1
This Page Intentionally Left Blank
............................................
A vista Corp.
2008 Form 1
State Supplements
r? .r:. c~f "'~ ';'...,. L.T
2Dag Mt\ y 13 AM 9= 16
IDAHO
Name of Respondent This Report Is:Date of Report Yea of Report
(l)~An Originl (Mo, Da, Yr)
A vista Corporation (2)DA Resubmission April 17, 2009 December 3 i, 2008
SUMMARY OF UTILITY PLANT AND ACCUMATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Line Item Total Electric
No.
(a)(b)(c)
1 UTILITY PLANT
2 In Service
3 Plant in Service (Classified)796,823,282 670,684,893
4 Property Under Capital Leases 1,633,474
5 Plant Puchased or Sold
6 Completed Constrction not Classified
7 Investment in Kettle Falls
8 TOTAL (Enter Total of lines 3 thru 7)798,456,756 670,684,893
9 Leased to Others
io Held for Future Use 39,828
11 Constrction Work in Progress 3,583,492 3,037,585
12 Acquisition Adjustments 0 0
13 TOTAL Utility Plant (Enter Total of lines 8 th 12)802,080,076 673,722,478
14 Accum. Prov. for Depr., Amort., & Depl.0 0
15 Net Utilty Plant (Enter total of line 13 less 14)802,080,076 673,722,478
DETAIL OF ACCUMULATED PROVISIONS FOR
16 DEPRECIATION, AMORTIZATION AN DEPLETION
17 In Service:
18 Depreciation
19 Amort. and Depl. of Producing Nat. Gas Land and Land Rights
20 Accumulated Depreciation - Kettle Falls
21 Amort. of Other Utility Plant
22 TOTAL in Service (Enter Total of lines 18 thu 21)
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 TOTAL Leased to Others (Enter Total of lines 24 and 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 TOTAL Held for Future Use (Ent. Tot. of lines 28 and 29)
31 Abandonment of Leases (Natural Gas)
32 Amort. of Plant Acquisition Adjustment 0 0
TOTAL Accumulated Provisions (Should agree with line 14 above)
33 (Enter Total of lines 22,26,30,31, and 32)0 0
State of Idao
FERC FORM NO.1 (ED. 12-89)Page 200
A vista Corporation
This R~ort Is:
(1) (2 An Original
(2) D A Resubmission April 17, 2009
Date of Report
State of Idaho
Year of ReportName of Respondent
December 31, 2008
SUMMAY OF UTILITY PLANT AND ACCUMUATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION (Contiued)
Gas Other (Specify)Other (Specify)Other (Specify). Common Line
No.
1
2
120,785,323 3
403,189 4
5
6
7
121,188,512 6,583,351 8
9
39,828 io
495,965 49,942 11
12
121,724,305 6,633,293 13
0 14
121,724,305 6,633,293 15
o o 33
FERC FORM NO.1 (ED. 12-89)Page 201
State of Ido
Name of Respondent Ths R~rt Is:Date of Report Yea of Report
2 (1) X An Origi (Mo, Da, Yr)
Avista Corp.(2)0 A Resubmission Febru 16, 200 Decber 31, 2008
ELECTRIC PLANT IN SERVICE (Accunts 101, 102, 103, 106)
1. Repo below the orgial cost of elec plat in see ac-estte basi if neces, and include the en1rs in colu
cording to the presced accowts.(c). Al to be included in colu (c) ar entres for revesals
2. In additon to AccountlOl, Elec Plat in Serce (Clas-of tetative diutis of pror yea repor in co (b).
sied), th page and the next include Accounts 102 Ele Plat Likwi if the respondent bas a signifcant amount of plat
Purchase or Sold; Account 103, Experienta Elecic Plat Un-retimets \Wicb have not been classied to pr accounts
Classifed; and Account 106, Completd Constction Not Clas-at the end of the yea, include in column (d) a tentative disib-
sifed - Electic.uti of such retiemets on an estte basis. wi approp
3. Include in column (c) or (d), as approprite. corons of add-rite contra entr to the account for accumulate depreciation
itions and retiements for the cuent or precedùig year.proviio. luclude also in column (d) reversals of tetative dis-
4. Enclose in parentheses cred adjustments of plat accounts to tributions of prio yea of unclassifed retiements. Attch sup-
indicate the negative effec of such accounts.plemental sttement showùg the account disibutions of these
5. Classif AccowtlO6 according to prescried accowts, on an tentatie classcatis in colus (c) and (d), includig the
Balance at
Line Acunt Begig of Yea Additions
No.(a)(b)(c)
1 1. INANGIBLE PLAN
2 (301)Or,ganzation 0
3 (302)Franchises and Consents 9,036,684
4 (303)Miscellaneous Inta,gble Plant 0
5 TOTAL Inta,gble Plant (Enter Tota of lines 2,3, and 4) .9,036,684 -
6 2. PRODUCTION PLAN
7 A Stea Production Plant
8 (310)Lad and Land Rights 0
9 (311)Structures and Improvements 0
10 (312)Boiler Plant Equipment 0
11 (313)Engies and Engie Driven Generators 0
12 (314)Tubo,generator Units 0
13 (315)Acessory Electrc Equipment 0
14 (316)Misc. Power Plant Equipment 0
15 (317)Asset Retiement Costs for Stea Production 0
16 TOTAL Steam Production Plant (Eter Tota of lines 8 th 15)--
17 B. Nuclear Production Plant
18 (320)Lad and Land Rights 0
19 (321)Structures and Improvements 0
20 (322)Reactor Plant Equipment 0
21 (323)Turbogenerator Units 0
22 (324)Accessory Electrc Equipment 0
23 (325)Misc. Power Plant Equipment 0
24 (326)Asset Retiement Costs for Nuclea Production 0
25 TOTAL Nuclea Production Plant (Enter Total of lines 18 th 24)--
26 C. Hydraulic Production Plant
27 (330)Lad and Lad Rights 6,310,260 206
28 (331)Strctures and Improvements 10,586,852 310,643
29 (332)Reservoirs, Dams, and Waterways 30,301,484 5,333,709
30 (333)Water Wheels, Turbines, and Generators 39,585,859 74,936
31 (334)Accessory Electrc Equipment 6,086,159 240,486
32 (335)Misc. Power Plant Equipment 2,575,531 12,692
33 (336)Roads, Railroads, and Brid,ges 1,098,564
34 (337)Asset Retirement Costs for Hydraulic Production 0
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)96,544,709 5,972,672
36 D. Other Production Plant
37 (340)Lad and Lad Rights 621,682
38 (341)Structures and Improvements 3,186,951
39 (342)Fuel Holders, Products and Accssories 1,700,144
40 (343)Pre Movers 3,658,328
41 (344)Generators 48,632,967 225,140
42 (345)Accessorv Electrc Equipment 1,870,665 1,081,821
FERC FORM NO.1 (ED. 12-91)Page 204
State of Idaho
Name of Respondent This Rim0rt Is:Date of Report Year of Report
(1) X An Origial (Mo, Da, Yr)
Avista Corp.(2)0 A Resubmission ##Decber 31, 2008
ELECTRIC PLANT IN SERVICE (Accunts 101, 102, 103, and 106) (Continued)
revesals of the prior yeas tentative accowt disutions of um (f) only the offt to the debit QI crit diute in
these amounts. Careful obserce of the above instctons column (f) to pri account clasiicatis.
and the text of Accounts 101 and 106 wi avoid seus omi 7. For Account 399. stte the natu and us of plat inchided
sios of the repord amount of respondent's plat actuall in the accowt and if substtil in amount submi a suple
in servce at end of year.meta sttement showig subaccount classification of sucb
6.Show in colunm (f) relassifcations or transfers wiin plat conorming to the requiements of these pages.
utity plat accounts. Include al in colu (f) the additons 8. For each amount compriing the reord balace and
or reductons of pri account classifcations arg from changes in Account 102, stte the propert purchase or sold.
disibution of amounts initll recorded in Account 102 In name of vendor or purhase. and date of transacton. If pro-
showig the clearance of Accowt 102, inchide in column (e)pose joul entries have bee f"iI wi the Comnion
the amounts wi respect to accunnlate provision for as requied by the Unifor Systm of Accowts,give also
depreiation, acquist adjustnts, etc., and show in col-date of sucb fIlig.
Balance at
Retiements Adjustments Tranfers End of Yea Line
(d)(e)(f (~)No.
1
0 (301)2
9,036,684 (302)3
0 (303)4
0 0 0 9,036,684 5
6
7
0 (310)8
0 (311)9
0 (312)10
0 (313)11
0 (314)12
0 (315)13
0 (316)14
0 (317)15
0 0 0 0 16
17
0 (320)18
0 (321)19
0 (322)20
0 (323)21
0 (324)22
0 (325)23
0 (326)24
0 0 0 0 25
26
356,930 5,953,536 (330)27
8,100 10,889,395 (331)28
0 35,635,193 (332)29
0 39,660,795 (333)30
170,436 6,156,209 (334)31
0 2,588,223 (335)32
1,098,564 (336)33
0 (337)34
535,466 0 0 101,981,915 35
36
621,682 (340)37
3,186,951 (341)38
1,700,144 (342)39
3,658,328 (343)40
48,858,107 (344)41
412,265 2,540,221 (345)42
FERC FORM NO.1 (ED. 12-87)Page 205
Name of Respondent Th R~rt Is:Date of Report Yea of Report
(1) X An Origil (Mo, Da, Yr)
Avista Corp.(2)D A Resubmission Februy 16,2009 Decmber 31, 2008
ELCTRIC PLANT IN SERVICE (Accounts 101, 102, 103, 106)
Balance atlieAccuntBegig of Yea Additions
No.(a)(b)(c)
43 (346)Misc. Power Plant Equipment 0
44 (347)Asset Retirement Costs for Other Production 0
45 TOTAL Other Production Plant (Eter Total of lines 37 th 45)59,670,737 1,306,961
46 TOTAL Production Plant (Eter Total of lines 16, 25, 35, and 45)156,215,446 7,279,633
47 3. TRANSMISSION PLAN
48 (350)Lad and Lad Rights 4,493,755 231,554
49 (352)Structures and hnprovements 7,461,853 416,665
50 (353)Station Equipment 69,716,294 2,608,460
51 (354)Towers and Fixtures 556,655 0
52 (355)Poles and Fixtures 44,422,551 742,633
53 (356)Overhead Conductors and Devices 27,296,137 566,399
54 (357)Undercround Conduit 0 0
55 (358)Undercround Conductors and Devices 0 0
56 (359)Roads and Trails 1,374,00
57 (359.1)Asset Retiement Costs for Tranmission Plant 0
58 TOTAL Transmission Plant (Eter Tota of lines 48 th 57)155,321,247 4,565,711
59 4. DISTRffUTION PLAN
60 (360)Lad and Lad Rights 971,116 (7,087)
61 (361)Structures and hnprovements 3,191,163 36,828
62 (362)Station Equipment 29,570,485 266,254
63 (363)Storage Battery Equipment 0 -
64 (364)Poles, Towers, and .Fixtures 72,922,931 4,665,929
65 (365)Overhead Conductors and Devices 49,814,264 3,207,439
66 (366)Undercround Conduit 26,382,155 1,137,368
67 (367)Undercround Conductors and Devices 39,311,479 2,705,947
68 (368)Line Transformers 54,364,259 2,953,859
69 (369)Services 40,614,375 1,704,658
70 (370)Meters 8,375,595 19,730,759
71 (371)Installations on Customer Premises 0 -
72 (372)Lesed Prperty on Customer Premises 0 -
73 (373)Street Lighting and Signal Systems 11,757,917 671,328
74 (374)Asset Retiement Costs for Distrbution Plant 0
75 TOTAL Distrbution Plant (Enter Total of lines 60 th 74)337,275,739 37,073,282
76 5. GENERA PLANT
77 (389)Lad and Land Rights 101,907
78 (390)Structures and hnprovements 1,125,918 11,699
79 (391)Office Furture and Equipment 0 0
80 (392)Transportation Equipment 1,396,703 77,156
81 (393)Stores Equipment 30,140 0
82 (394)Tools, Shop and Garage Equipment 433,560 6,351
83 (395)Laboratory Equipment 314,087 0
84 (396)Power Operated Equipment 5,373,039 640,808
85 (397)Communcation Equipment 3,793,581 139,114
86 (398)Miscellaneous Equipment 2,785 0
87 SUBTOTAL (Enter Total of lines 77 th 86)12,571,720 875,128
88 (399)Other Tangible Property I 0
89 (399.1)Asset Retirement Costs for General Plant 0
90 TOTAL General Plant (Enter Total of lines 87 and 90)12,571,720 875,128
91 TOTAL (Accounts 101 and 106)670,420,836 49,793,754
92 (102)Electrc Plant Purchased 0
93 (Lss)(102) Electrc Plant Sold 0
94 (103)Experimental Plant Unclassified 0
95 TOTAL Electrc Plant in Service 670,420,836 49,793,754
FERC FORM NO.1 (ED. 12-87)
State of Idao
Page 206
State of Idao
Name of Respondent Ths wort Is:Date of Report Yea of Report
(1) X An Origial (Mo, Da, Yr)
Avista Corp.(2)0 A Resubmission ##Decber 31,2008
ELECTRIC PLAN IN SERVICE (Accounts 101, 102, 103, and 106) (Continued)
Balance at
Retiements Adjustments Transfers End of Yea lie
(d)(e)(f (g)No.
0 (346)43
0 (347)44
412,265 --60,565,433 45
947,731 --162,547,348 46
47
1,452 4,723,857 (350)48
7,878,518 (352)49
660,769 0 71,663,985 (353)50
556,655 (354)51
57,435 0 45,107,749 (355)52
4,429 0 27,858,io7 (356)53
0 (357)54
0 (358)55
1,374,002 (359)56
0 (359.1)57
724,085 0 0 159,162,873 58
59
964,029 (360)60
7,375 3,220,616 (361)61
125,915 (350,575)29,360,249 (362)62
0 0 (363)63
189,403 77,399,457 (364)64
89,940 0 52,931,763 (365)65
18,526 0 27,500,997 (366)66
170,347 89 41,847,168 (367)67
32,122 57,285,996 (368)68
45,524 661 42,274,170 (369)69
28,106,354 (370)70
0 (371)71
0 (372)72
35,304 0 12,393,941 (373)73
0 (374)74
714,456 0 (349,825)373,284,740 75
76
101,907 (389)77
11,753 1,125,864 (390)78
0 0 (391)79
128,728 1,345,131 (392)80
15,395 14,745 (393)81
7,046 432,865 (394)82
183,554 130,533 (395)83
260,718 5,753,129 (396)84
0 0 3,932,695 (397)85
486 2,299 (398)86
607,680 0 0 12,839,168 87
0 (399)88
0 (399.1)89
607,680 0 0 12,839,168 90
2,993,952 0 (349,825)716,870,813 91
0 (102)92
0 93
0 (103)94
2,993,952 0 (349,825)716,870,813 95
FERC FORM NO.1 (ED. 12w87)Page 207
Name of Respondent Ths R~rt Is:Date of Report Year of Report
(1) X An Orginal (Mo, Da, Yr)
A vista Corpration (2)D A Resubmission Apri 18, 2009 Dec. 31,2008
ELECTRIC OPERATING REVENUS (Account 400)
1. Report below operating revenues for each prescribed for each group of meters added. The average number of
account, and manufactured gas revenues in tota.customers meas the average of twelve figures at the close
2. Report number of customers, columns (t) and (g), on of each month.
the basis of meters, in addition to the number of flat rate 3. If previous yea (columns (c), (e), and (g), are not
accounts; except that where separte meter readings are derived from previously reported figures, explain any incon-
added for billing purposes, one customer should be counted sistencies in a footnote.
OPERATING REVENUS
Line Title of Account Amount for Amount for
No.Year Previous Year
(a)(b)
1 Sales of Electrcitv
2 (440) Residential Sales 88,806,974 82,202,981
3 (442) Commercial and Industral Sales (3)
4 Small (or Commercial)71,994,661 66,597,380
5 Large (or Industral)56,575,008 53,023,256
6 (44) Public Street and Highway Lightig 1,821,535 1,766,926
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Raiwavs
9 (448) Interdeparental Sales 142,079 109,758
10 TOTAL Sales to Ultiate Consumers 219,340,257 (1)203,700,301
11 (447) Sales for Resale 5,676,695 665,530
12 TOTAL Sales of Electrcity 225,016,952 204,365,831
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provision for Refunds 225,016,952 204,365,831
15 Other Operatig Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues 214,804 195,158
18 (453) Sales of Water and Water Power
19 (454) Rent from Electrc Propert 845,345 766,116
20 (455) Interdeparental Rents
21 (456) Other Electrc Revenues 392,497 265,133
22 (456.1) Revenues from Transmission of Electrcty of Others 5,004,067 5,183,591
23
24
25
26 TOTAL Other Operating Revenues 6,456,713 6,409,998
27 TOTAL Electrc Operatin~ Revenues $231,473,665 $210,775,829
State of Idaho
FERC FORM NO.1 (ED. 12-90)Page 300
Name of Respondent This R~rt Is:
(1) l2 An Orginal
Date of Report
(Mo, Da, Yr)
State of Idaho
Year of Report
A vista Corporation (2) D A Resubmission Apri 18, 2008 Dec. 31, 2008
ELECTRIC OPERATING REVENUS (Account 400) (Continued)
4. Commercial and Industral Sales, Account 442, may
be classified according to the basis of classification (Small
or Commercial, and Large or Industral) 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.)
5. See page 108, Importt Changes During Year, for
importt new terrtory added and important rate increases
or decreases.
6. For lines 2, 4, 5, and 6, see page 304 for amounts
relating to unbiled revenue by accounts.
7. Include unmetered sales. Provide details of such sales
in a foonote.
Amount for Year
Amount for
Previous Year
A VG. NO. OF CUSTOMERS PER MONT
Number for
Number for Year Previous Year Line( ( ) No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
MEGAWATT HOURS SOLD
1,020,533 996,001 16,356 16,027
1,242,247 1,249,326 482 477
8,716 8,600 124 126
2,020 1,631 23 19
3,502,520 (2)3,445,281 120,780 118,320
125,471 20,002
3,627,991 3,465,283 120,780 118,320
3,627,991 3,465,283 120,780 118,320
(1) Includes $3,943,917 of un biled revenues.
(2) Includes 29,478 MWH relating to unbiled revenues.
(3) Segregation of Commerical and Industral made on basis of utilization of energy and not on size of account.
FERC FORM NO.1 (ED. 12-89)Page 301
Name of Respondent Ths Report Is:
I2An Origial
A vista Corpration DA Resubmission
Date of Report Yea of Report
(Mo, Da, Yr)
April 18,200 Dec. 31, 2008
State of Idaho
SALES OF ELECTRCITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect durng the
year the m Wh of electrcity sold, revenue, average number of
customers, average kWh per customer, and average revenue
per kWh, excluding data for Sales for Resale which is report
on pages 310-311.
2. Provide a subheading and tota for each prescribed
operating revenue account in the sequence followed in "Elec-
trc Operating Revenues," page 301. If the sales under any rate
schedule are classified in more than one revenue account, list
the rate schedule and sales data under each applicable revenue
account subheading.
3. Where the same customers are served under more than
one rate schedule in the same revenue account classification
Lim
No.
Number and Title of Rate Schedule MWHSold
(a)
1 RESIDENTIAL SALES (440)
2 1 Residential Service
3 2 Residential Service
4 3 Residential Service
5 12 Res. & Far Gen. Service
6. 22 Res. & Far Lg. Gen. Service
7 30 Pumping-Special
8 32 Res. & Far Pumping Service
9 48 Res. & Far Area Lighting
10 49 Ara Lighting-High-Press.
11 56 Centrala Credt
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 Tota
20 Residential-Unbiled
21 COMMERCIA SALES (442)
22 2 General Service
23 3 General Service
24 11 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 Ar Lighting-High-Press.
32 56 Centralia Creit
33 95 Wind Power
34 73 General Service
35 74 Large General Service
36 75 Large General Service
37 76 Large Genera Service
38 77 Genera Service
39 79 Area Light-High Press.
40 58 Tax Adjustment41 Tota
42 Commercial-Unbiled
43 Total Biled
44 Total Unbiled Rev. (See Instr. 6)
45 TOTAL
FERC FORM NO.1 (ED 12-90)
(b)
1,170,311
19,789
11,701
3,596
1,246
295
1,206,938
22,066
(such as a genera residential schedule and an off pe water
heating schedule), the entres in colum (d) for the special
schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number
of bils rendered durng the year divided by t1e number of
billng periods durng the year (12 if al bilings are made
monthly).
5. For any rate schedule having a fuel adjustment clause
state in a footnote the estiated additional revenue biled pur-
suant thereto.
6. Report amount of unbiled revenue as of end of year for
each applicable revenue account subheadin,g.
Average KW of
Number of Sales per
Customers Customer(d) (e)
Revenue
Revenue
(cents) per
KWH Sold
(f(c)
82,023,028 98,896 11,834 7.01
1,836,64 4,290 4,613 9.28
714,503 23 508,739 6.11
271,463 586 6,137 7.55
219,860 17.65
67,180 22.77
48,64
1,128,167
86,309,487
2,497,487
11,628 7.23103,795
298,591 24,473,912 14,568 20,496 8.20
605,808 39,020,399 1,336 453,449 6.44
72,432 3,285,500 3 24,144,00 4.54
29,209 1,931,767 449 65,053 6.61
1,071 132,983 12.42
2,346 424,214 18.08
10,292
1,322,219
1,009,457 70,601,286 16,356 61,718 7.05
11,076 1,393,375
2,216,395 156,910,773 120,151 7.08
33,142 3,890,862 0 11.74
2,249,537 160,801,635 120,151 7.15
Page 304
Name of Respondent This Report Is:
I! An Orginal
Date of Report Year of Report
(Mo, Da, Yr)
A vista Corporation DA Resubmission i\pril 18,2009 Dec. 31, 2008
State of Idaho
SALES OF ELECTRCITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect durng the
year the m Wh of electrcity sold, revenue, average number of
customers, average kWh per customer, and average revenue
per kWh, excluding data for Sales for Resale which is report
on pages 310-311.
2. Provide a subheadng and tota for each prescribed
operating revenue account in the sequence followed in "Elec-
trc Operating Revenues," page 301. If the sales under any rate
schedule are classified in more than one revenue account, list
the rate schedule and sales data under each applicable revenue
account subheading.
3. Where the same customers are served under more than
one rate schedule in the same revenue account classifcation
Lin~
No.
Number and Title of Rate Schedule MWHSold
(a)INDUSTRIL Si\ES (442)
2 General Service
3 General Service
8 Lg Gen Time of Use
11 General Service
21 Lage 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 & Frm
47 Area Lighting-Sod. Yap.
49 Area Lighting-High-Press.
56 Centralia Credit
72 Genera Service
73 Genera 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
Industral-Unbiled
(b)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27 STREET i\ HWY LIGHTING (44)
28 11 Genera 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. Energy
33 and Maint. Service
34 44 Cust.-Owned St. Lt. Energy
35 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 Total
43 Street and Hwy Lighting-Unbiled
44 Total Biled
45 Total Unbiled Rev. (See Instr. 6)
46 TOTAL
3,767
82,753
1,133,551
22,799
2,936
56
49
1,245,911
(3,664)
281
1,023
8,716
3,471,022
29,478
3,500,500
FERC FORM NO.1 (ED 12-90)
(such as a general residential schedule and an off peak water
heating schedule), the entres in column (d) for the special
schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number
of bils rendered durg the year divided by the number of
billng periods durng the year (12 if all bilings are made
monthly).
5. For any rate schedule having a fuel adjustment clause
state in a footnote the estimated additional revenue biled pur-
suant thereto.
6. Report amount of unbiled revenue as of end of year for
each aoolicable revenue account subheading.Average KW of
Number of Sales per
Customers Customer(d) (e)
Revenue
Revenue
(cents) per
KWH Sold
(f)(c)
329,715
5,156,773
49,275,926
129
83
10
29,202
997,024
113,355,100
8.75
6.23
4.35
1,500,808
175,336
6,726
8,095
220
40
103,632
73,400
6.58
5.97
12.01
16.52
68,574
56,521,953
53,055
482
o
2,584,878 4.55
116
6683
15,246
1,609,348
2,039
74,920
5 23,200 13.14
88 75,943 24.08
1 25,00 8.16
16 36,750 12.74
3 93,667 5.58
11 93,00 7.36
25
588
15,669
75,249
29,064
1,821,535
215,254,261
3,943,917
219,198,178
124 70,290 6.24
120,757
o
120,757
6.20
13.38
6.26
Page 304.1
Name of Respondent Ths Report Is:
~An Orginal
A vista Corpration DA Resubmission
Date of Report Year of Report
(Mo, Da, Yr)
Apri 18,200 Dec. 31, 2008
State of Idao
SALES OF ELECTRCIT BY RATE SCHEDULES
1. Report below for each rate schedule in effect durng the
year the m Wh of electrcity sold, revenue, average number of
customers, average kWh per customer, and average revenue
per kWh, excluding data for Sales for Resale which is reported
on pages 310-311.
2. Provide a subheading and tota for eah prescribed
operating revenue account in the sequence followed in "Elec-
trc Operating Revenues," page 301. If the sales under any rate
schedule 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
Line
No.
MWSoldNumber and Title of Rate Schedule
(a)
OTHER SALES TO PUBLIC
AUTORITIES (445)
None
(b)
1
2
3
4
5
6
7
8
9
10 SALES FOR RESALE (447) (1)
11 61 Sales to Other Utilities - ID
12
13
14
14
15
16
17 Note: Sch. 61 is a state assigned rate schedule for Saleslesale
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39 Tota Biled
40 Tota Unbiled Rev.
41 TOTAL
INTRDEPARTMNTAL
SALES(44)
58 Tax Adjustment
Total 2,020
125,471
2,020
(such as a general residential schedule and an off peak water
heating schedule), the entres in colum (d) for the special
schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number
of bils rendered durg the year divided by the number of
billing periods durng the year (12 if all billngs are made
monthly).
5. For any rate schedule having a fuel adjustment clause
state in a footnote the estiated additional revenue biled pur-
suant thereto.
6. Report amount of unbiled revenue as of end of yea for
each applicable revenue account subheadinl!.
Average KWH of
Number of Sales per
Customers Customer(d) (e)
Revenue
(c)
142,050
29
142,079
23 87,826
87,826
Revenue
(cents) per
KWH Sold
(f
7.03
7.03
Tota 125,4711
3,598,513
29,478
3,627,991
FERC FORM NO.1 (ED 12-90)
23
5,676,695
5,676,695
221,073,035
3,943,917
225,016,952
Page 304.2
120,780
o
120,780
29,794
30,038
6.14
13.38
6.20
Idao
Avista Corp.
This Report Is:(1) ~AnOnginai
(2) c:A Resubmission
Date 01 Report Year of ReportNam of Respodent
April 17, 200 Deembr 31, 200
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the arunt for previou ye is not denved from previously reported figures, explain In footnes.
UnaNo. Accountlal
1 11 \ POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Ooeration
4 500 Ooeration Sun.wision and Ennineennn
5 501 Fuel
6 50 Steam Exnnses
7 503 Steam from Oter Sources
8 Less, (504\ Steam Tranferred-Cr.
9 505 Elecri EXnAnses
10 506 Miscellanou Steam Power Exoenses
11 5071 Rents
12 509 Alloces
13 TOTAlOriration Enter Total of Unes 4thru 11
14 Maintenane
15 510 Maintenane Suriivision and Enoineenno
16 511 Maintenane of Strures
17 512 Maintenance of Boiler Plant
18 513 Maintenan of Electri Plant
19 514 Maintenance of Miscellanous Steam Plant
20 TOTAL Maintenance Enter Total of Unes 14 thru 18
21 TOTAl Powr Prodction Exnnses-Steam Plant Enter Tot of lines 12 and 19\
22 B. Nuclear Power Generation
23 Ooeration
24 51 Oriration Suriivision and Enoineennii~
25 518 Fuel
26 519 Coolants and Water
27 520 Steam Exoenses
28 521 Steam Irom Other Sources
29 Less 522 Steam Translerred-r.
30 523 Electri Exoenses
31 524 Miscellaneous Nuclear Powr Exr;ses
32 525 Rents
33 TOTAL Ooration Enter Tota of liens 23 thru 31
34 Maintenane
35 528 Maintenan Suoeivision and Ennineennn
36 529 Maintenance of Strutures
37 530 Maintenance of Reactor Plant Enuinmet
36 531 Maintenance of Elecnc Plant
39 532 Maintenace of Miscellaneous Nuclear Plant
40 TOTAl Maintenane Enter Total of lines 34thru 36
41 TOTAL Power Prouction Exoenses-Nuclear PoweriEntertota 01 lines 32 and 39
42 C. Hvdralic Powr Generation
43 Ooeration
44 535 Ooeraon Suriivision and Enaineennn
45 536 Water for Power
46 53 Hvdraulic Exnses
47 538 Elecnc ExnAnses
46 539 Miscellaneous Hvdraulic Powr Generation Exoenses
49 540 Rents
50 TOTAL Ooeration (Enter Tota of lines 43 thru 48
Amnt for CUrrnt YearfbJ
Amunt for Pnor YearIe
29,469 26,809
29469 26,809
2.695
2,695
32,165 2680
576,38
264,999
966,417
1,361,772
369,894
115,56
3,675,024
717,192
260,38
773,463
1,298,931
313,22
24,490
3,367,68
FERC FORM NO.1 (12-9)Page 320
Idaho
Nam of Repodent This Repo Is:
(1) irAn Original
(2) i:A Reubsio
ELECTRIC OPERATION AND MAINTENAE EXPENSES
Date of Report Year Of Repo
April 17, 20 Deembr 31, 20Avista Co.
Une
No.Acount(a)
C. Hvdralic Powr Generation Cotinued
Amnt for Current Year Amnt for Previou Year(b) (c)
59208 74,597
9288 104,297
104,072 48904
407,029 698,707
128,007 4O,nO
791,201 1,407,419
4,46,225 4,795,101
187,627 59,922
1,33,06 1,774,127
143,951 131,564
20864 30 12012,03 11,976
1,86,251 2,258757
54201 27,113
1,492 984
139,33 113.087
59,690 103,451
25,717 244,63
2,114,968 250,393
98,50,379 67,677,804
178,249 170,170
21,00,194 (2,598,752
1 19,691,82 65,249,22
126,305,180 72,574,525
790,512 83,681
69,403 673726
--
.
--
--
--
--
--
--
80,512 69524
201791 53,8n
-
4,850268 4905,44
466,56 312,386
11325 3,200
7,095,265 6,861839
155,286 107,540
132,710 152665
385,30 216,557
483,36 40653
--
4,693 35.2741,16155 918,68
8256821 7,780,528
454,876 38,998
50
51
52
53
54
55
56
57
58
59
80
61
62
63
84
65
68
67
68
69
70
71
72
73
74
75
76n
78
79
80
81
82
83
84
85
86
87
86
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
109
110
Maintenane
541 Maintenance Supervision and Enaineerina
542 Maintenane Of Struures
54 Maintene Of Reservoirs, Dam, and Waterwys
54 Maintenan Of Electrc Plant
54 Mainteane Of Miscellaneous Hvdraullc Plant
TOTAL Maintenan Enter Total of lines 52 thru 56
TOTAL Power Production Exoonses-Hvdrallc Power Enter tot Of lines 49 and 57)
D. Other Powr Generation
Operatio
54 Oooration Suoorvisio and Enaineerina
54 Fuel
54 Generaon Exonses
549 Miscellaneou Other Powr Generation Exiinses
55 Rents
TOTAL Oooration Enter Tot Of lines 61 thru 65
Maintenane
551 Maintenan Suiirvision an Enoineerina
552 Maintenane Of Strctures
553 Maintenane Of Generatina and Eleri Plant
554 Maintenance of Miscellaneous Other Powr Generation Plant
TOTAL Maintenane Enter Tota Of lines 68 thru 71
TOTAL Powr Production Exiinses-other Powr Enter Total Of lines 86 and 721
E. Other Power suiiv Exiinses
5551 Purchased Power
5561 SYStem Cotrol and Load Disoalchina
557) Oter Exiinses
TOTAL Oter Power SUOOlV Exoonses (Enter Tota Of lines 75 thru n
TOTAL Powr Production Exiinses (Enter Total of lines 20, 40, 58, 73 an 781
2. TRANSMISSION EXPENSES
Oiiration
5601 Oiiration Suiirvision and Erineerino
5611 Lod DisoaIChino
561.1 Load Dis aIChina Relialit
561.2 Load Dis !Cino Monitor an Ooora Trasrrion SYStem
561.3 Load Dis tchina Tramision Service and SChed
561.4 SChedulin Svseml Cotrol and Dioach Serv561.5 Reliablitv, Planin and Standard Devetot
561. Trasmission Service Studes
561. Generation Interconnec Studies
:.~ina and Stdard Developmnt Services
56 Overhead Une Exoonses
564 Underaround Una Exiinses
565 Transmission of Electrlcltv bv Others
586 Miscellaneous Trasmission Exnses
567 Rents
TOTAL Oooration Enter Tota Of lines 82 thru 89
Maintenane
568 Maintenae Suoorvision and En ineerino
569 Maintenae of Struures
570 Maintenan of Station Eouiomt
571 Maintenance Of Overhead Unes
572 Maintenance Of Undraround Une
573 Maintenance Of Miscellaneos Trasmission Plant
TOTAL Maintenan EnterTatai Of lines 92 thru 971
TOTAL Tramision Exoenses (Enter Tota 01 lines 90 and 98
3. DISTRIBUTION EXPENSES
Ooeraon
5801 Oiiration Suiirvision and Enoineerino
FERC FORM NO.1 (12-96)Page 321
Idaho
Nam of Respodent This Report Is:Date of Repo Year of Report
(1) iKAn Onginal
Avista Corp.(2)i:A Resubmssicx Apnl17, 200 Decemr 31, 2008
ELECTRIC OPERATION AND MAIf.ENANCE EXPENSES
Une
No.Acunt Amunt for Current Year Amunt for Pnor Year
fa)fb fcl
103 3. DISTRIBUTION EXPENSES (Continued\
104 581 Lod DiStehim -
105 582 Staticx """"nses 244,290 191,631
106 583 Overhd Une Exnnses 657028 205,66
107 584 Undemround Une Exnønses 288,975 539,789
108 585 Street Uohtno and Sienal SyStem Exoenses 153,83 139,nO
109 586 Mete Eises 6,637 (163,269
110 58 Custor Installations Exnses 44,342 410,704
111 58 Miscellaneous Dlstnbution Expenses 1,54,106 154,678
112 58 Rents 82,715 5263
113 TOTAL Ooeration Enter Tota 01 lines 102thru 112 3,859,00 3,307,599
114 Maintenan
115 590 Maintenance Sunørvision and Enoineenno 447,419 48,118
116 591 Maintenance of Structre 61,48 88,938
117 592 Maintenane 01 Station Enuioment 158.00 172,321
118 593 Maintenance 01 Overhead Unes 3,123891 3,134,265
119 594 Maintenane of Undemround Unes 311,46 271,102
120 595 Maintenance 01 Une Trasformrs 108,40 58,235
121 596 Maintenance of Street Unhting and Signal Systems 142,400 147,910
122 59 Maintenane 01 Meters 4554 82,788
123 598 Maintenane 01 Misellans Distribuon Plant 210123 85,922
124 TOTAL Maintenae IEnterTota 01 lines 115 thru 123 4608,726 4,527,595
125 TOTAL Distnbution Exoenses Enter Total of lines 113 and 124\8,467,734 7,835194
126 4. CUSTOMER ACCOUNTS EXPENSES
127 Ooeration
128 901 Suoervision 168,32 181,949
129 90 Meter Readinn Exnønses 292217 36,704
130 90 Customr Rec and Collection Exoenses 2,513,513 2,651442
131 904 Unclectible Acounts 66103 557,614
132 905 Miscellaneous Customer Acnts Exoenses 50,58 84805
133 TOTAL Custor Acnts Exoenses IEnter Tota 01 lines 128thru 132 368,659 3,816,514
134 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
135 Ooeration
136 90 Sunervision -
137 908 Customr Assistane Ex nses 3,881,823 3,83,782
138 909 Informtional and Instructicxal Expenses 32,428 17,111
139 910 Miscellaneous Customr Service and Informtional Exnses 49,825 39.932
140 TOTAL Cust. Service and Infortional ExnFnses IEnter Tot of lines 136 thru 139T 3,98,076 3,891,826
141 6. SALES EXPENSES
142 Oneraticx
143 911 Su""rvisicx --
144 912 Demostratino and Sellnc Exoenses 155,244 181,813
145 913 Adertsinn Exrvses 40,56 85,997
146 916 Miscellans Sales nsas 21 9
147 TOTAL Sales EXnFnses (Enter Tot 01 lines 143 thru 146 195,829 267,819
148 7. ADMINISTRATIVE AND GENERAL EXPENSES
149 Ooeration
150 920\ Administrative and General Salanes 6574.227 6.761,163
151 9211 Offce Suoolies and Exoenses 1,297,351 1,268,126
152 Les\ 1922\ Administratve ex""ses Traferredredit 13,32 12205
FERC FORM NO.1 (12-96)Page 322
Idaho
Nam of Respont This Report Is:Dal 01 Report Year 01 Repo(1) ~An Original
AvistaCo.(2)c:A Reubision April 17, 200 Decembr 31, 200
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Une
No.Acount Amnt for CUrrnt Year Amunt for Prior Year
(a)fb c
153 7. ADMINISTRATIVE AND GENERA EXPENSES (Continue'
154 923 Outside Services Emoved 3,772,598 4079254
155 924 Prort Insurace 3436 393,879
156 92 In'uri and Damll_o 1,023,02 1146,285
157 926, Emovee Pension an Benefit 37720 316,075
158 92 Franhise Reauirements 5,950 6,327
159 928 ReoulOl Cossion ExnAnses 1,763,40 1496,154
160 Less 929 Duolicate Chara-Cr.
161 930.1 i Genera Adertisina Exiins 960183
162 930.2) Miscellaous Genera Exoenses 1,03,973 -
163 931 Rents 174,907 243,46
164 TOTALOoeraon IEnterTota 01 lines 150thru 163)16,35,678 16678704
165 Maintenan
166 935 Maintenane 01 Genera Plant 1,896,567 1,86,751
167 TOTAL Administratie and General Exiinses Enter Total of line 164 and 166\18,251244 18,53,45
168 TOTAL Elecri Oneratian an Maintenane Exnnses Ener Total 01 lines 169,126,543 114705,862
79,99,125,l33,l40,147,and 16n
NUMBER OF ELECTRIC DEPARMENT EMPLOYEES IT
1. The data on numbr 01 empoy should be reported cotrtion empoyee in a footnote.I
far the payroll period ending nearest to October 31, or any 3. Th numbr 01 empoyes assigne to the eleri
payroll period ending 60 days before or aler Ocober 31.depantlrom joint functio 01 comnation ulrities mav
2. n the respont's payroll for th reportng peri in-be determed by estimate, on the bais 01 empoye F!a-
cludes any speial contruon personnel, include such Ients. Show the estimate numbr of equivalent emoo"".
employe on line 3, and show the numbr of such speial attributed to the elecri departnt from jointlunction.
1 Pavrol Peri Ended Datel Deemr 31, 2007
2 Tot Realar Ful~ TIme Emovees 87 86
3 Tata Part-TIme an Temoorarv Emoloves 4 5
4 Allocaton 01 Genera Emovees 122 119
5 Tot Empovees See Nate 1 213 210
FERC FORM NO.1 (12-96)Page 323