2012Annual Report.pdf

AvW o ti THIS FILING IS
Item 1: J An Initial (Original) OR M Resubmission No._
Submission
Form 2 Approved
OMB No.1902-0028
(Expires 10/31/2014)
Form 3-Q Approved
OMB No.1902-0205
(Expires 05/31/2014)
¼ c: it
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Ui
FERC FINANCIAL REPORT
FERC FORM No. 2: Annual Report of
Major Natural Gas Companies and
Supplemental Form 3-Q: Quarterly
Financial Report
These reports are mandatory under the Natural Gas Act, Sections 10(a), and 16 and 18
CFR Parts 260.1 and 260.300. 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 a confidential nature.
Exact Legal Name of Respondent (Company) Year/Period of Report
Avista Corporation End of 2012/Q4
FERC FORM No. 2/3Q (02-04)
QUARTERLY/ANNUAL REPORT OF MAJOR NATURAL GAS COMPANIES
IDENTIFICATION
01 Exact Legal Name of Respondent Year/Period of Report
Avista Corporation End of 2012/Q4
03 Previous Name and Date of Change (If name changed during year)
04 Address of Principal Office at End of Year (Street, City, State, Zip Code)
1411 East Mission Avenue, Spokane, WA 99207
05 Name of Contact Person 06 Title of Contact Person
Christy Burmeister-Smith VP, Controller, Prin. Acctg Officer
07 Address of Contact Person (Street, City, State, Zip Code)
1411 East Mission Avenue, Spokane, WA 99207
08 Telephone of Contact Person, Including Area Code This Report Is: 10 Date of Report
(1)[]An Original (Mb, Da, Yr)
509-495-4256 (2)[]A Resubmission 04/12/2013
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct
statements of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all
material respects to the Uniform System of Accounts.
11 Name 12 Title
Christy Burmei%er-Smith VP, Controller, Prin. Acctg Officer
13 Signature W-1-- 4-- 14 Date Signed
Christy BurmeistW-Smith 04/12/2013
Title 18, U.S.C. 1001, makes it a crime for any person knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM NO. 2/3Q (02-04) Page
Name of Respondent This Re ort Is:
(1)X An original
(2)JA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
List of Schedules (Natural Gas Company)
Enter in column (d) the terms "none," "not applicable," or 'NA" as appropriate, where no information or amounts have been reported
for certain pages. Omit pages where the responses are "none," "not applicable," or "NA."
-
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Date Revised
(c)
Remarks
(d)
- GENERAL CORPORATE INFORMATION AND FINANCIAL STATEMENTS
1 General Information 101
2 Control Over Respondent 102 N/A
3 Corporations Controlled by Respondent 103
4 Security Holders and Voting Powers 107
5 Important Changes During the Year 108
6 Comparative Balance Sheet 110-113
7 Statement of Income for the Year 114-116
8 Statement of Accumulated Comprehensive Income and Hedging Activities 117
9 Statement of Retained Earnings for the Year 118-119
10 Statements of Cash Flows 120-121
11 Notes to Financial Statements 122
BALANCE SHEET SUPPORTING SCHEDULES (Assets and Other Debits)
12 Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization, and Depletion 200-201
13 Gas Plant in Service 0 204-209
14 Gas Property and Capacity Leased from Others 212 N/A
15 Gas Property and Capacity Leased to Others 213 N/A
16 Gas Plant Held for Future Use 214
17 Construction Work in Progress-Gas 216
18 Non-Traditional Rate Treatment Afforded New Projects 217 N/A
19 General Description of Construction Overhead Procedure 218
20 Accumulated Provision for Depreciation of Gas Utility Plant 219
21 Gas Stored 220
22 Investments 222-223
23 Investments in Subsidiary Companies 224-225
i Prepayments 230
25 Extraordinary Property Losses 230 N/A
26 Unrecovered Plant and Regulatory Study Costs 230 N/A
27 Other Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accumulated Deferred Income Taxes 234-235
BALANCE SHEET SUPPORTING SCHEDULES (Liabilities and Other Credits)
30 Capital Stock 250-251
31
-
Capital Stock Subscribed, Capital Stock Liability for Conversion, Premium on Capital Stock, and
Installments Received on Capital Stock 252 N/A
32 Other Paid-in Capital 253
33 Discount on Capital Stock 254 N/A
34 Capital Stock Expense 254
35 Securities issued or Assumed and Securities Refunded or Retired During the Year 255
36 Long-Term Debt 256-257
37 Unamortized Debt Expense, Premium, and Discount on Long-Term Debt 258-259
FERC FORM NO. 2 (REV 42-07) Page 2
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
List of Schedules (Natural Gas Company) (continued)
Enter in column (d) the terms "none," "not applicable," or "NA" as appropriate, where no information or amounts have been reported
for certain pages. Omit pages where the responses are "none," "not applicable," or "NA."
-
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Date Revised
(c)
Remarks
(d)
38 Unamortized Loss and Gain on Reacquired Debt 260
39 Reconciliation of Reported Net Income with Taxable Income for Federal Income Taxes 261
40 Taxes Accrued, Prepaid, and Charged During Year 262-263
41 Miscellaneous Current and Accrued Liabilities 268
42 Other Deferred Credits 269
43 Accumulated Deferred Income Taxes-Other Property 274-275
44 Accumulated Deferred Income Taxes-Other 276-277
45 Other Regulatory Liabilities 278
- INCOME ACCOUNT SUPPORTING SCHEDULES
46 Monthly Quantity & Revenue Data by Rate Schedule 299 N/A
47 Gas Operating Revenues 300-301
48 Revenues from Transportation of Gas of Others Through Gathering Facilities 302-303 N/A
49 Revenues from Transportation of Gas of Others Through Transmission Facilities 304-305 N/A
50 Revenues from Storage Gas of Others 306-307 N/A
51 Other Gas Revenues 308
52 Discounted Rate Services and Negotiated Rate Services 313 N/A
53 Gas Operation and Maintenance Expenses 317-325
54 Exchange and Imbalance Transactions 328 N/A
55 Gas Used in Utility Operations 331
56 Transmission and Compression of Gas by Others 332 N/A
57 Other Gas Supply Expenses 334
58 Miscellaneous General Expenses-Gas 335
59 Depreciation, Depletion, and Amortization of Gas Plant 336-338
60 Particulars Concerning Certain Income Deduction and Interest Charges Accounts 340
COMMON SECTION
61 Regulatory Commission Expenses 350-351
62 Employee Pensions and Benefits (Account 926) 352
63 Distribution of Salaries and Wages 354355
64 Charges for Outside Professional and Other Consultative Services 357
65 Transactions with Associated (Affiliated) Companies 358
GAS PLANT STATISTICAL DATA
66 Compressor Stations 508-509 N/A
67 Gas Storage Projects 512-513
68 Transmission Lines 514 N/A
69 Transmission System Peak Deliveries 518 N/A
70 Auxiliary Peaking Facilities 519
71 Gas Account-Natural Gas 520
72 Shipper Supplied Gas for the Current Quarter 521 N/A
73 System Map 522 N/A
74 Footnote Reference 551
75 Footnote Text 552
76 Stockholder's Reports (check appropriate box)
[] Four copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO. 2 (REV 12-07) Page 3
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)flA Resubmission 04/1212013 End of 2012/04
General Information
1.Provide name and title of officer having custody of the general corporate books of account and address of office where the general corporate books are kept and address of office
where any other corporate books of account are kept, it different from that where the general corporate books are kept.
Christy Burmeister-Smith, Vice President and Controller
1411 E Mission Avenue
Spokane, WA 99207
2.Provide the name of the State under the laws of which respondent is incorporated and date of incorporation. If incorporated under a special law, give reference to such law. If not
incorporated, state that fact and give the type of organization and the date organized.
State of Washington, Incorporated March 15, 1889
3.If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of receiver or trustee, (b) date such receiver or trustee took possession, (c)
the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not Applicable
4, State the classes of utility and other services furnished by respondent during the year in each State in which the respondent operated.
Electric service in the states of Washington, Idaho and Montana
Natural gas service in the states of Washington, Idaho and Oregon
5. Have you engaged as the princiRal accountant to audit your financial statements an accountant who is not the principal accountant for your previous years certified financial
statements?
(1)Yes... Enter the date when such independent accountant was initially engaged:
(2)No
EERC FORM NO. 2 (12-96) Page 101
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
Corporations Controlled by Respondent
1.Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by
respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2.If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held,
naming any intermediaries involved.
3.If control was held jointly with one or more other interests, state the fact in a footnote and name the other -interests.
4.In column (b) designate type of control of the respondent as "D" for direct, an "I" for indirect, or a "J" for joint control.
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 that exercises direct control.
4.Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual
agreement or understanding between two or more parties who together have control within the meaning of the definition of control in
the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line
No.
Name of Company Controlled
(a)
Type of Control
(b)
Kind of Business
(C)
Percent Voting
Stock Owned
(d)
Footnote
Reference
(e)
I Avista Capital, Inc. D Parent company to the Company's
subsidiaries.
100 Not used
2 Ecova, Inc. I Provides utility bill processing services 79 Not used
3
4 Avista Development, Inc. I Maintains investment portfolio md. real
estate
100 Not used
5 Avista Energy, Inc. I Inactive 100 Not used
6 Penlzer Corporation I Parent of Bay Area Mfg and Pentzer
Venture Hldngs
100 Not used
7 Pentzer Venture Holdings I Inactive 100 Not used
8 Bay Area Manufacturing I Holding Co. of AM&D dba MetaIFX 100 Not used
9 Advanced Manufacturing & Development I Custom mfg of electronic enclosures 83 Not used
10 dba MetaIFX I Not used
11 1 Spokane Energy, LLC D Owns an electric capacity contract. 100 Not used
12 Avista Capital II D Affiliated business trust issued pref
trust sec.
100 Not used
13 Avista Northwest Resources, LLC I Owns an interest in a venture fund
investment
100 Not used
14 Steam Plant Square, LLC I Commercial office and retail leasing 85 Not used
15 Courtyard Office Center, LLC I Commercial office and retail leasing 100 Not used
16 Steam Plant Brew Pub, LLC I Restaurant operations 85 Not used
17
20
21
22
23
24
25
26
27
28
29
30
FERC FORM NO. 2 (12-96) Page 103
Name of Respondent This Re ort Is: Date of Report Yea Period of Report
(1)X An Original (Mo, Da, Yr)
(2)flA Resubmission 04/12/2013 End of 2012/Q4
Security Holders and Voting Powers
1.Give the names and addresses of the 10 security holders of the respondent who, at the date of the latest closing of the stock book
or compilation of list of stockholders of the respondent, prior to the end of the year, had the highest voting powers in the respondent,
and state the number of votes that each could cast on that date if a meeting were held. If any such holder held in trust, give in a
footnote the known particulars of the trust (whether voting trust, etc.), duration of trust, and principal holders of beneficiary interests in
the trust. If the company did not close the stock book or did not compile a list of stockholders within one year prior to the end of the
year, or if since it compiled the previous list of stockholders, some other class of security has become vested with voting rights, then
show such 10 security holders as of the close of the year. Arrange the names of the security holders in the order of voting power,
commencing with the highest. Show in column (a) the titles of officers and directors included in such list of 10 security holders.
2.If any security other than stock carries voting rights, explain in a supplemental statement how such security became vested with
voting rights and give other important details concerning the voting rights of such security. State whether voting rights are actual or
contingent; if contingent, describe the contingency.
3.If any class or issue of security has any special privileges in the election of directors, trustees or managers, or in the determination
of corporate action by any method, explain briefly in a footnote.
4.Furnish details concerning any options, warrants, or rights outstanding at the end of the year for others to purchase securities of
the respondent or any securities or other assets owned by the respondent, including prices, expiration dates, and other material
information relating to exercise of the options, warrants, or rights. Specify the amount of such securities or assets any officer, director,
associated company, or any of the 10 largest security holders is entitled to purchase. This instruction is inapplicable to convertible
securities or to any securities substantially all of which are outstanding in the hands of the general public where the options, warrants,
1. Give date of the latest closing of the stock 2. State the total number of votes cast at the latest general 3. Give the date and place of
book prior to end of year, and, in a footnote, state meeting prior to the end of year for election of directors of the such meeting:
the purpose of such closing: respondent and number of such votes cast by proxy.
May 10, 2012
Total: 52774389 Spokane, WA
By Proxy: 52774389
- VOTING SECURITIES
4. Number of votes as of (date): 11/29/2012
Total Votes Common Stock Preferred Stock Other Line Name (Title) and Address of
No Security Holder
(a) (b) (c) (d) (e)
5 TOTAL votes of all voting securities 58,627,915 58,627,915
6 TOTAL number of security holders 10,629 10,629
7 TOTAL votes of security holders listed below
8 GARY ELY, LIBERTY LAKE, WA 141,984 141,984
9 DBH PROPERTIES LP, COEUR D'ALENE, ID 77,646 77,646
10 GARY GAIL ELY, LIBERTY LAKE, WA 65,218 65,218
11 JACK W GUSTAVEL, COEUR DALENE, ID 40,740 40,740
12 MARK TTHIES, SPOKANE, WA 24,163 24,163
13 MARIAN M DURKIN, SPOKANE, WA 23,986 23,986
14 KAREN S FELTES, SPOKANE, WA 20,345 20,345
15 FREDERICK W SCHO1T TR, SANTA MONICA, CA 19,498 19,498
16 JOHN F KELLY, CORAL GABLES, FL 19,342 19,342
17 THOMAS A LOWE & KATHLEEN B LOWE, TR UA, SATELLITE BEACH,
FL 17,360 17,360
18
19
20
FERC FORM NO. 2 (12-96) Page 107
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
FOOTNOTE DATA
Schedule Page: 107 Line No.: I Column: I
To pay the December 14, 2012, dividend.
FERC FORM NO. 2 (12-96) Page 552.1 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
(2)_A Resubmission 04/12/2013 20121Q4
Important Changes During the Quarter/Year
Give details concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the -
inquiries. Answer each inquiry. Enter "none" or "not applicable" where applicable. If the answer is given elsewhere in the report, refer to the
schedule in which it appears.
1.Changes in and important additions to franchise rights: Describe the actual consideration and state from whom the franchise rights were
acquired. If the franchise rights were 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: Briefly describe the property, and the related transactions, and cite Commission
authorization, if any was required. Give date journal entries called for by Uniform System of Accounts were submitted to the Commission.
4.Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give effective
dates, lengths of terms, names of parties, rents, and other conditions. 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 cite 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 or assumed by respondent as guarantor for the performance by another of any agreement or obligation, including
ordinary commercial paper maturing on demand or not later than one year after date of issue: State on behalf of whom the obligation was
assumed and amount of the obligation. Cite Commission authorization if any was required.
7.Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8.State the estimated annual effect and nature of any important wage scale changes during the year.
9.State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such proceedings
culminated during the year.
10.Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer, director,
security holder, 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.Estimated increase or decrease in annual revenues caused by important rate changes: State effective date and approximate amount of
increase or decrease for each revenue classification. State the number of customers affected.
12.Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during
the reporting period.
13.In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30 percent
please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the
respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s).
Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
1.None
2.None
3.None
4.None
5.None
6.Avista Corp. has a committed line of credit with various financial institutions in the total amount of
$400.0 million with an expiration date of February 2017. The committed line of credit is secured by
non-transferable First Mortgage Bonds of the Company issued to the agent bank that would only become due
and payable in the event, and then only to the extent, that the Company defaults on its obligations under the
com.ixuit1ed line of credit.
Balances outstanding under the Company's revolving committed line of credit were as follows as of December
31, 2012 and December 31, 2011 (dollars in thousands):
December 31, December 31,

2012 2011
Balance outstanding at end of period $52,000 $61,000
Letters of credit outstanding at end of period $35,885 $29,030
I FERC FORM NO. 2 (12-96) 108.1 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Important Changes During the Quarter/Year
In June 2012, Avista Corp. entered into a bond purchase agreement with certain institutional investors in the
private placement market for the purpose of issuing $80.0 million of 4.23 percent First Mortgage Bonds due in
2047. The new First Mortgage Bonds were issued under and in accordance with the Mortgage and Deed of
Trust, dated as of June 1, 1939, from the Company to Citibank, N.A., trustee, as amended and supplemented by
various supplemental indentures and other instruments. The issuance of the bonds occurred at closing in
November 2012. The total net proceeds from the sale of the new bonds were used to repay a portion of the
borrowings outstanding under the Company's $400.0 million committed line of credit and for general corporate
purposes. The debt issuance was approved by regulatory commissions as follows:WUTC (Docket No.
U-i 11176 Order 02) IPUC (Case No. AVU-U-1 1-01 Order No. 32338) and the OPUC (Docket UF 4269 Order
No. 11-334).
7.On May 10, 2012, the shareholders of Avista Corp. approved an amendment of the Company's Restated
Articles of Incorporation and Bylaws to reduce certain shareholder approval requirements to reduce the approval
standards for shareholder voting to a "Majority of Votes Cast", where permissible under Washington law, and
otherwise to be the lowest threshold permitted by Washington law.
8.Average annual wage increases were 2.4% for non-exempt employees effective February 27, 2012. Average
annual wage increases were 2.7% for exempt employees effective February 27, 2012. Officers received average
increases of 3.5% effective February 27, 2012. Certain bargaining unit employees received increases of 3.0%
effective March 26, 2012.
9.Reference is made to Note 18 of the Notes to Financial Statements.
10.None
11.Reference is made to Note 20 of the Notes to Financial Statements.
12.Effective June 1, 2012, Avista Corp. appointed Don Kopczynski as Vice President of Operations and Jason
Thackston as Vice President of Customer Solutions. Mr. Kopczynski was previously Vice President of
Customer Solutions and Mr. Thackston was previously Vice President of Energy Delivery.
13.Proprietary capital is not less than 30 percent.
FERC FORM NO. 2 (12-96) 108.2 1
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 201 2/Q4
Comparative Balance Sheet (Assets and Other Debits) -
Line
No.
-
Title of Account
(a)
Reference
Page Number
(b)
Current Year End of
Quarter/Year Balance
(C)
Prior Year
End Balance
12/31
(d)
1 UTILITY PLANT
4,044,184,930 3,876,924,839 2 Utility Plant (101-106, 114) 200-201
3 Construction Work in Progress (107) 200-201 139,513,892 78,182,230
4 TOTAL Utility Plant (Total of lines 2 and 3) 200-201 4,183,698,822 3,955,107,069
5 (Less) Accum. Provision for Depr., Amort., DepI. (108, 111, 115) 1,408,153,972 1,333,212,160
6 Net Utility Plant (Total of line 4 less 5) 2,775,544,850 2,621,894,909
7 Nuclear Fuel (120.1 thru 120.4, and 120.6) 0 0
8 (Less) Accum. Provision for Amort., of Nuclear Fuel Assemblies (120.5) 0 0
9 Nuclear Fuel (Total of line 7 less 8) 0 0
10 Net Utility Plant (Total of lines 6 and 9) 2,775,544,850 2,621,894,909
11 Utility Plant Adjustments (116) 122 0 0
12 Gas Stored-Base Gas (117.1) 220 6,992,076 6,992,076
13 System Balancing Gas (117.2) 220 0 0
14 Gas Stored in Reservoirs and Pipelines-Noncurrent (117.3) 220 01 0
15 Gas Owed to System Gas (117.4) 220 0 0
16 OTHER PROPERTY AND INVESTMENTS
5,536,702 6,021,869 17 Nonutility Property (121)
18 (Less) Accum. Provision for Depreciation and Amortization (122) 921,820 915,043
19 Investments in Associated Companies (123) 222-223 12,047,000 12,047,000
20 Investments in Subsidiary Companies (123.1) 224-225 118,714,423 71,971,368
21 (For Cost of Account 123.1 See Footnote Page 224, line 40)
0 0 22 Noncurrent Portion of Allowances
23 Other Investments (124) 222-223 16,439,055 18,889,385
24 Sinking Funds (125) 0 0
25 Depreciation Fund (126) 0 0
26 Amortization Fund - Federal (127) 0 0
27 Other Special Funds (128) 9,154,874 13,288,292
28 Long-Term Portion of Derivative Assets (175) 1,092,593 184,929
29 Long-Term Portion of Derivative Assets - Hedges (176) 01 0
30 TOTAL Other Property and Investments (Total of lines 17-20, 22-29) 162,062,827 121,487,800
31 CURRENT AND ACCRUED ASSETS
2,624,516 945,496 32 Cash (131)
33 Special Deposits (132-134) 2,716,333 22,215,906
34 Working Funds (135) 799,065 861,010
35 Temporary Cash Investments (136) 222-223 251,390 60,913
36 Notes Receivable (141) 234,901 283,666
37 Customer Accounts Receivable (142) 159,703,153 173,557,636
38 Other Accounts Receivable (143) 5,188,679 7,943,467
39 (Less) Accum. Provision for Uncollectible Accounts - Credit (144) 4,653,167 4,498,489
40 Notes Receivable from Associated Companies (145) 314,682 0
41 Accounts Receivable from Associated Companies (146) 700,835 29,252
42 Fuel Stock (151) 4,120,767 4,248,389
43 Fuel Stock Expenses Undistributed (152) 0 0
FERC FORM NO. 2 (REV 06-04) Page 110
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Yea Period of Report
End of 2012/04
Comparative Balance Sheet (Assets and Other Debits)(continued)
Line
No.
-
Title of Account
(a)
Reference
Page Number
(b)
Current Year End of
Quarter/Year Balance
(C)
Prior Year
End Balance
12/31
(d)
44 Residuals (Elec) and Extracted Products (Gas) (153) 0 0
45 Plant Materials and Operating Supplies (154) 23,875,397 21,746,205
46 Merchandise (155) 0 0
47 Other Materials and Supplies (156) 0 0
48 Nuclear Materials Held for Sale (157) 0 0
49 Allowances (158.1 and 158.2) 0 0
50 (Less) Noncurrent Portion of Allowances 0 0
51 Stores Expense Undistributed (163) 0 0
52 Gas Stored Underground-Current (164.1) 220 17,276,287 23,609,470
53 Liquefied Natural Gas Stored and Held for Processing (164.2 thru 164.3) 220 0 0
54 Prepayments (165) 230 16,090,480 16,554,560
55 Advances for Gas (166 thru 167) 0 0
56 Interest and Dividends Receivable (171) 31,981 85,059
57 Rents Receivable (172) 830,718 1,568,627
58 Accrued Utility Revenues (173) 0 0
59 Miscellaneous Current and Accrued Assets (174) 429,169 254,324
60 Derivative Instrument Assets (175) 5,231,375 1,323,663
61 (Less) Long-Term Portion of Derivative Instrument Assets (175) 1,092,593 184,929
62 Derivative Instrument Assets - Hedges (176) 7,265,426 32,408
63 (Less) Long-Term Portion of Derivative Instrument Assests - Hedges (176) 0 0
64 TOTAL Current and Accrued Assets (Total of lines 32 thru 63) 241,939,394 270,636,633
65 DEFERRED DEBITS
66 Unamortized Debt Expense (181) 13,532,890 14,332,877
67 Extraordinary Property Losses (182.1) 230 0 0
68 Unrecovered Plant and Regulatory Study Costs (182.2) 230 0 0
69 Other Regulatory Assets (182.3) 232 559,831,454 524,250,326
70 Preliminary Survey and Investigation Charges (Electric)(183) 3,894,551 4,180,937
71 Preliminary Survey and Investigation Charges (Gas)(183.1 and 183.2) 0 0
72 Clearing Accounts (184) 0 0
73 Temporary Facilities (185) 0 0
74 Miscellaneous Deferred Debits (186) 233 15,701,369 34,001,379
75 Deferred Losses from Disposition of Utility Plant (187) 0 0
76 Research, Development, and Demonstration Expend. (188) 0 0
77 Unamortized Loss on Reacquired Debt (189) 21,635,414 23,830,734
78 Accumulated Deferred Income Taxes (190) 234-235 148,425,469 153,408,420
79 Unrecovered Purchased Gas Costs (191) ( 6,916,577) ( 12,140283)
80 TOTAL Deferred Debits (Total of lines 66 thru 79) 756,104,570 741,864,390
81 TOTAL Assets and Other Debits (Total of lines 10-15,30,64,and 80) 3,942,643,717 3,762,875,808
FERC FORM NO. 2 (REV 06-04) Page 111
Name of Respondent This Re ort Is:
(1)X An Original
(2)[]A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Comparative Balance Sheet (Liabilities and Other Credits)
Line
No.
-
Title of Account
(a)
Reference
Page Number
(b)
Current Year
End of
Quarter/Year
Balance
Prior Year
End Balance
12/31
(d)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201) 250-251 863,316,222 832,413,930
3 Preferred Stock Issued (204) 250-251 0 0
4 Capital Stock Subscribed (202, 205) 252 0 0
5 Stock Liability for Conversion (203, 206) 252 0 0
6 Premium on Capital Stock (207) 252 0 0
7 Other Paid-In Capital (208-211) 253 10,942,942 11,686,949
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 ( 14,977,565) ( 11,086,811)
11 Retained Earnings (215, 215.1, 216) 118-119 377,687,824 364,536,285
12 Unappropriated Undistributed Subsidiary Earnings (216.1) 118-119 ( 747,337) ( 28,386,302)
13 (Less) Reacquired Capital Stock (217) 250-251 01 0
14 Accumulated Other Comprehensive Income (219) 117 ( 6,700,160) ( 5,636,826)
15 TOTAL Proprietary Capital (Total of lines 2 thru 14) 1,259,477,056 1,185,700,847
16 LONG TERM DEBT
1,336,700,000 1,257,171,208 17 Bonds (221) 256-257
18 (Less) Reacquired Bonds (222) 256-257 83,700,000 83,700,000
19 Advances from Associated Companies (223) 256-257 51,547,000 51,547,000
20 Other Long-Term Debt (224) 256-257 0 0
21 Unamortized Premium on Long-Term Debt (225) 258-259 204,316 213,200
22 (Less) Unamortized Discount on Long-Term Debt-Dr (226) 258-259 1,656,685 1,838,814
23 (Less) Current Portion of Long-Term Debt 0 0
24 TOTAL Long-Term Debt (Total of lines 17 thru 23) 1,303,094,631 1223,392,594
25 OTHER NONCURRENT LIABILITIES
4,491,191 4,749,777 26 Obligations Under Capital Leases-Noncurrent (227)
27 Accumulated Provision for Property Insurance (228.1) 0 0
28 Accumulated Provision for Injuries and Damages (228.2) 700,447 3,235,000
29 Accumulated Provision for Pensions and Benefits (228.3) 283,984,764 246,176,609
30 Accumulated Miscellaneous Operating Provisions (228.4) 0 0
31 Accumulated Provision for Rate Refunds (229) 0 0
FERC FORM NO. 2 (REV 06-04) Page 112
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
- Comparative Balance Sheet (Liabilities and Other Credits)(continued)
Line
No.
Title of Account
(a)
Reference
Page Number
(b)
Current Year
End of
Quarter/Year
Balance
Prior Year
End Balance
12/31
(d)
32 Long-Term Portion of Derivative Instrument Liabilities 26,310,290 40,530,269
33 Long-Term Portion of Derivative Instrument Liabilities - Hedges 0 2,641,867
34 Asset Retirement Obligations (230) 3,167,936 3,512,818
35 TOTAL Other Noncurrent Liabilities (Total of lines 26 thru 34) 318,654,628 300,846,340
36 CURRENT AND ACCRUED LIABILITIES
37 Current Portion of Long-Term Debt 0 0
38 Notes Payable (231) 52,000,000 61,000,000
39 Accounts Payable (232) 116,147,642 98,160,779
40 Notes Payable to Associated Companies (233) 598 1,866,383
41 Accounts Payable to Associated Companies (234) 709,623 709,883
42 Customer Deposits (235) 3,323,152 8,868,640
43 Taxes Accrued (236) 262-263 22,309,642 8,292,344
44 Interest Accrued (237) 12,038,698 11,797,709
45 Dividends Declared (238) 0 0
46 Matured Long-Term Debt (239) 0 0
47 Matured Interest (240) 0 0
48 Tax Collections Payable (241) 120,427 104,100
49 Miscellaneous Current and Accrued Liabilities (242) 268 61,331,657 55,333,088
50 Obligations Under Capital Leases-Current (243) 258,586 224,884
51 Derivative Instrument Liabilities (244) 55,825,491 111,353,644
52 (Less) Long-Term Portion of Derivative Instrument Liabilities 26,310,290 40,530,269
53 Derivative Instrument Liabilities - Hedges (245) 1,433,1601 18,895,143
54 (Less) Long-Term Portion of Derivative Instrument Liabilities - Hedges 0 2,641,867
55 TOTAL Current and Accrued Liabilities (Total of lines 37 thru 54) 299,188,386 333,434,461
56 DEFERRED CREDITS
57 Customer Advances for Construction (252) 947,342 947,213
58 Accumulated Deferred Investment Tax Credits (255) 12,613,058 10,400,886
59 Deferred Gains from Disposition of Utility Plant (256) 0 0
60 Other Deferred Credits (253) 269 26,169,966 26,584,147
61 Other Regulatory Liabilities (254) 278 55,244,962 20,939,852
62 Unamortized Gain on Reacquired Debt (257) 260 2,355,118 2,484,655
63 Accumulated Deferred Income Taxes - Accelerated Amortization (281) 0 0
64 Accumulated Deferred Income Taxes - Other Property (282) 419,216,613 398,500,293
65 Accumulated Deferred Income Taxes - Other (283) 245,681,957 259,644,520
66 TOTAL Deferred Credits (Total of lines 57 thru 65) 762,229,016 719,501,566
67 TOTAL Liabilities and Other Credits (Total of lines 15,24,35,55,and 66) 3,942,643,717 3,762,875,808
FERC FORM NO. 2 (REV 06-04) Page 113
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)OA Resubmission 04/12/2013 End of 2012/Q4
Statement of Income
Quarterly
1.Enter in column (d) the balance for the reporting quarter and in column (e) the balance for the same three month period for the prior year.
2.Report in column (f) the quarter to date amounts for electric utility function; in column (h) the quarter to date amounts for gas utility, and in (J) the quarter to date amounts for
other utility function for the current year quarter.
3.Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in (k) the quarter to date amounts for
other utility function for the prior year quarter.
4.If additional columns are needed place them in a footnote.
Annual or Quarterly, if applicable
5.Do not report fourth quarter data in columns (e) and (
6.Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to a utility department
Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7.Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
8.Report data for lines 8, 10 and 11 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 407.1 and 407.2.
9.Use page 122 for important notes regarding the statement of income for any account thereof.
10.Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's
customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the
contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with
respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues
received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income, and expense accounts.
12.If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13.Enter on page 122 a concise explanation of only those changes in accounting mehods made during the year which had an effect on net income, including the basis of
allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14.Explain in a footnote if the previous years/quarters figures are different from that reported in prior reports.
15.If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.
Title of Account Reference Total Total Current Three Prior Three
Page Current Year to Prior Year to Date Months Ended Months Ended
Number Date Balance Balance Quarterly Only Quarterly Only
for Quarter/Year for Quarter/Year No Fourth Quarter No Fourth Quarter
Line (a) (b) (c) (d) (e) (I)
1 UTILITY OPERATING INCOME
300-301 1,494227,540 1,617,162,384 0 0 2 Gas Operating Revenues (400)
3 Operating Expenses
4 Operation Expenses (401) 317-325 1051,630,004 1,169,781,694 0 0
5 Maintenance Expenses (402) 317-325 61377,568 57411,515 0 0
6 Depreciation Expense (403) 336-338 102188,312 96,771,421 0 0
7 Depreciation Expense for Asset Retirement Costs (403.1) 336-338 0 0 0 0
8 Amortization and Depletion of Utility Plant (404-405) 336-338 12,353382 11,307,561 0 0
9 Amortization of Utility Plant Acu. Adjustment (406) 336-338 99,047 99,047 0 0
10 Amort. of Prop. Losses, Unrecovered Plant and Reg. Study Costs (407.1) 0 0 0 0
11 Amortization of Conversion Expenses (407.2) 0 0 0 0
12 Regulatory Debits (407.3) 5,612,331 3,529,991 0 0
13 (Less) Regulatory Credits (407.4) 24,170,474 19,872,716 0 0
14 Taxes Other than Income Taxes (408.1) 262-263 83,263,801 83,348,911 0 0
15 Income Taxes-Federal (409.1) 262-263 14,435,558 23,554,951 0 0
16 Income Taxes-Other (409.1) 262-263 379,911 1,264,963 0 0
17 Provision of Deferred Income Taxes (410.1) 234-235 35,782,461 29,793,186 0 0
18 (Less) Provision for Deferred Income Taxes-Credit (411.1) 234-235 4,224,555 2,475,028 0 0
19 Investment Tax Credit Adjustment-Net (411.4) 2,073,106 2,458,952 0 0
20 (Less) Gains from Disposition of Utility Plant (411.6) 0 0 0 0
21 Losses from Disposition of Utility Plant (411.7) 0 0 0 0
22 (Less) Gains from Disposition of Allowances (411.8) 0 0 0 0
23 Losses from Disposition of Allowances (411.9) 0 0 0 0
24 Accretion Expense (411.10) 0 0 0 0
25 TOTAL Utility Operating Expenses (Total of lines 4 thru 24) 1,340,800,457 1,456,974,448 0 0
26 Net Utility Operating Income (Total of lines 2 less 25) (Carry forward to page 116,
- line 27) 153,427,0831 160,187,936 0 0
FERC FORM NO. 2 (REV 06-04) Page 114
Name of Respondent This Re ort Is:
(1)X An Original
(2)JA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Statement of Income
Line
No.
Elec. Utility
Current
Year to Date
(in dollars)
(g)
Elec. Utility
Previous
Year to Date
(in dollars)
(h)
Gas Utility
Current
Year to Date
(in dollars)
(i)
Gas Utility
Previous
Year to Date
(in dollars)
(j)
Other Utility
Current
Year to Date
(in dollars)
(k)
Other Utility
Previous
Year to Date
(in dollars)
(I)
2 1,017,916,105 1053,850,680 ,311,435 563311,704 0 0
3
4 664,363,922 702,686,156 t387,266,082 467,095,538 0 0
5 50481,432 47,524,279 ,896,136 9887,236 0
6 83,017204 78,744,936 ,171,108 18,026,485 0
0 0 0 0 0
8 9,725,903 9,015,875 2,627,479 2,291,686 0
9 99,047 99,047 0 0 0
0 0 0 0 0
0 0 0 0 0
12 4,618,160 3,366,279 994,171 163,712 0
13 22,537,730 17,238,278 1,632,744 2,634,438 0
14 62,217,029 61,363,417 21,046,772 21,985,494 0
15 16,824,429 23,647,758 ( 2,388,871) ( 92,807) 0
16 432,992 922,947 ( 53,081) 342,016 0
17 24,012,637 17,702,120 11,769,829 12,091,066 0
18 4,120,508 2,793,831 104,047 ( 318,803) 0
19 2,115,166 2,502,656 ( 42,060) ( 43,704) 0
20 0 0 0 0 0
0 0 0 0
22 0 0 0 0 0 0
23 0 0 0 0 0
24 0 0 0 0 0
25 891,249,683 927,543,361 449,550,774 529,431,087 0
26 126,666,422 126,307,319 26,760,661 33,880,617 0 0
FERC FORM NO. 2 (REV 06-04) Page 115
Name of Respondent This Re ort Is:
(1)X An Original
(2)EJA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/014
Statement of Income(continued) -
Line
Title of Account Reference
Page
Number
(a) (b)
Total Total
Current Year to Prior Year to Date
Date Balance Balance
for QuarterlYear for Quarter/Year
(c) (d)
Current Three
Months Ended
Quarterly Only
No Fourth Quarter
(e)
Nor Three
Months Ended
Quarterly Only
No Fourth Quarter
(f)
27 Net Utility Operating Income (Carried forward from page 114) 153,427,0831 160,187,936 0 0
28 OTHER INCOME AND DEDUCTIONS
29 Other Income
30 Nonutility Operating Income
0 0 0 31 Revenues form Merchandising, Jobbing and Contract Work (415)
32 (Less) Costs and Expense of Merchandising, Job & Contract Work (416) 0 0 0 0
33 Revenues from NonutilityOperations(417) ( 236) ( 21,355) 0 0
34 (Less) Expenses of Nonutility Operations (417.1) 8,415,859 6,836,563 0 0
35 Nonoperating Rental Income (418) ( 2,749) ( 2,731) 0 0
36 Equity in Earnings of Subsidiary Companies (418.1) 119 ( 1,206861) 9971,326 0 0
37 Interest and Dividend Income (419) 1,864,293 1,293,357 0 0
38 Allowance for Other Funds Used During Construction (419.1) 4,054,947 2,224,987 0 0
39 Miscellaneous Nonoperating Income (421) 0 0 0 0
40 Gain on Disposition of Property (421.1) 0 31,120 0 0
41 TOTAL Other Income (Total of lines 31 thru 40) ( 3,706,465) 6,660,1411 0 0
42 Other Income Deductions
0 0 43 Loss on Disposition of Property (421.2) 0 0
44 Miscellaneous Amortization (425) 0 304,717 0 0
45 Donations (426,1) 340 2,272,123 2,143,177 0 0
46 Life Insurance (426.2) 2,533,552 2,253,671 0 0
47 Penalties (426.3) 15,251 281,762 0 0
48 Expenditures for Certain Civic, Political and Related Activities (426.4) 1,414,338 1,186,0221 0 0
49 Other Deductions (426.5) 1,815,326 407,2231 0 0
50 TOTAL Other Income Deductions (Total of lines 43 thru 49) 340 8,050,5901 6,576,5721 01 0
51 Faxes Applic. to Other Income and Deductions
52 Taxes Other than Income Taxes (408.2) 262-263 145,213 ( 2.275) 0 0
53 Income Taxes-Federal (409.2) 262-263 106,965 ( 962,923) 0 0
54 Income Taxes-Other (409.2) 262-263 ( 1,231,456) ( 349,700) 0 0
55 Provision for Deferred Income Taxes (410.2) 234-235 ( 520,718) 40,666 0 0
56 (Less) Provision for Deferred Income Taxes-Credit (411.2) 234-235 5,190,742 4,710,550 0 0
57 Investment Tax Credit Adjustments-Net (411.5) 0 0 0 0
58 (Less) Investment Tax Credits (420) 0 0 0 0
59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) ( 6,690,738) ( 5,984,782) 0 0
60 Net Other Income and Deductions (Total of lines 41, 50,59) ( 5,066,317) 6,068,351 0 0
61 INTEREST CHARGES
61,400,721 0 0 62 Interest on Long-Term Debt (427) 65,281,624
63 Amortization of Debt Disc. and Expense (428) 258-259 447,351 604,805 0 0
64 Amortization of Loss on Reacquired Debt (428.1) 3,364,150 4,021,281 0 0
65 (Less) Amortization of Premium on Debt-Credit (429) 258-259 8,883 8,883 0 0
66 (Less) Amortization of Gain on Reacquired Debt-Credit (429.1) 0 0 0 0
67 Interest on Debt to Associated Companies (430) 340 885,123 ( 26,307) 0 0
68 Other Interest Expense (431) 340 2,582,407 2,983,099 0 0
69 (Less) Allowance for Borrowed Funds Used During Construction-Credit (432) 2,401,072 2,942,302 0 0
70 Net Interest Charges (Total of lines 62 thru 69) 70,150,700 66,032,414 0 0
71 Income Before Extraordinary Items (Total of lines 27,60 and 70) 78,210,0661 100,223,873 0 0
72 EXTRAORDINARY ITEMS
0 0 0 0 73 Extraordinary Income (434)
74 (Less) Extraordinary Deductions (435) 0 0 0 0
75 Net Extraordinary Items (Total of tine 73 less line 74) 0 0 0 0
76 Income Taxes-Federal and Other (409.3) 262-263 0 0 0 0
77 Extraordinary Items after Taxes (Total of line 75 less line 76) 01 01 0 0
78 Net Income (Total of lines 71 and 77) 78,210,0661 100,223,873
01 0
FERC FORM NO. 2 (REV 06-04) Page 116
This Page Intentionally Left Blank
Name of Respondent This Report Is: Date of Report Yea Period of Report
(1)An Original (Mo, Da, Yr) End of 2012/Q4
(2)EA Resubmission 04/12/2013
Statement of Accumulated Comprehensive Income and Hedging Activities
1.Report in columns (b) (C) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2.Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3.For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
Unrealized Gains Minimum Pension Foreign Currency Other
Line and Losses on Iiabililty Adjustment Hedges Adjustments
No. Item available-for-sale (net amount)
securities
- (a) (b) (c) (d) (e)
1 Balance of Account 219 at Beginning of Preceding
- Year ( 4,325,953)
2 Preceding Quarter/Year to Date Reclassifications
from Account 219 to Net Income
3 Preceding Quarter/Year to Date Changes in Fair
- Value 134,046 ( 1,444,919)
4 Total (lines 2 and 3) 134,046 ( 1,444,919)
5 Balance of Account 219 at End of Preceding
- Quarter/Year 134,046 ( 5,770,872)
6 Balance of Account 219 at Beginning of Current Year 134,046 ( 5,770,872)
7 Current Quarter/Year to Date Reclassifications from
Account 2l9to Net Income - ( 290,263)
8 Current Quarter/Year to Date Changes in Fair Value 323,478 ( 1,096,549)
9 Total (lines 7 and 8) 33,215 ( 1,096,549)
10 Balance of Account 219 at End of Current
- Quarter/Year 167,261 ( 6,867,421)
FERC FORM NO. 2 (NEW 06-02) Page 117
Name of Respondent This Report Is:
(1)An Original
(2)EjA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
Statement of Accumulated Comprehensive Income and Hedging Activities(continued)
Line
No.
Other Cash Flow Hedges
Interest Rate Swaps
(f)
Other Cash Flow Hedges
(Insert Category)
(g)
Totals for each
category of
items recorded in
Account 219
(h)
Net Income
(Carried Forward
from Page 116,
Line 78)
(I)
Total
Comprehensive
Income
(j)
4,325,953)
2
3 ( 1,310,873)
4 ( 1,310,873) j 100,223,872 1 98,912,999
( 5,636,826)
6 ( 5,636,826)
7 ( 290,263)
8 ( 773,071)
9 ( 1,063,334) 78,21 0,0661 77,146,732
10 ( 6,700,160)
FERO FORM NO. 2 (NEW 06-02) Page 117a
This Page Intentionally Left Blank
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Statement of Retained Earnings
1.Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year.
2.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).
3.State the purpose and amount for each reservation or appropriation of retained earnings.
4.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.
5.Show dividends for each class and series of capital stock.
Line
No.
-
Contra Primary
Item AccountAffected
(a) (b
Current Quarter
Year to Date
Balance
(c)
Previous Quarter
Year to Date
Balance
(d)
— UNAPPROPRIATED RETAINED EARNINGS
1 Balance-Beginning of Period 362,988164 325,313,182 I
2 Changes (Identify by prescribed retained earnings accounts)
3 Adjustments to Retained Earnings (Account 439)
4 TOTAL Credits to Retained Earnings (Account 439) (footnote details) I I 10,509,950
5 TOTAL Debits to Retained Earnings (Account 439) (footnote details)
6 Balance Transferred from Income (Acct 433 less Acct 418.1) 79,416,927 90,252,547
7 Appropriations of Retained Earnings (Account 436)
8 TOTAL Appropriations of Retained Earnings (Account 436) (footnote details)
9 Dividends Declared-Preferred Stock (Account 437)
10 TOTAL Dividends Declared-Preferred Stock (Account 437) (footnote details)
11 Dividends Declared-Common Stock (Account 438)
12 TOTAL Dividends Declared-Common Stock (Account 438) (footnote details) 68,552,375 63,736,956
13 Transfers from Account 216.1, Unappropriated Undistributed Subsidiary Earnings 2,286,987 649,441
14 Balance-End of Period (Total of lines 1, 4, 5, 6, 8, 10, 12, and 13) 376,139,703 362,988,164
15 APPROPRIATED RETAINED EARNINGS (Account 215)
16 TOTAL Appropriated Retained Earnings (Account 215) (footnote details) 1,548,121 I 1,548,121 I
17 APPROPRIATED RETAINED EARNINGS-AMORTIZATION RESERVE, FEDERAL (Account
- NONE
18 TOTAL Appropriated Retained Earnings-Amortization Reserve, Federal (Account
19 TOTAL Appropriated Retained Earnings (Accounts 215, 215.1) (Total of lines 1548,121 1548,121
20 TOTAL Retained Earnings (Accounts 215, 215.1, 216) (Total of lines 14 and 1 377,687,824 364,536,285
21 UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account 216.1)
- Report only on an Annual Basis no Quarterly
22 Balance-Beginning of Year (Debit or Credit) ( 28,386,302) ( 24,343,433)
23 Equity in Earnings for Year (Credit) (Account 418.1) ( 1,206,861) 9,971,326
24 (Less) Dividends Received (Debit)
25 Other Changes (Explain) 28,845,826 ( 14,014,195)
26 Balance-End of Year ( 747,337) ( 28,386,302)
FERC FORM NO. 2 (REV 06-04) Page 118-119
Name of Respondent This Re ort Is:
(1)X An Original
(2)JA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Statement of Cash Flows
(1)Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify
separately such items as investments, fixed assets, intangibles, etc.
(2)Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation
between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
(3)Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing
activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income
taxes paid.
(4)Investing Activities: Include at Other (line 25) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities
assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General
Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost.
Line Description (See Instructions for explanation of codes) Current Year Previous Year
No. to Date to Date
(a) Quarter/Year Quarter/Year -
1 Net Cash Flow from Operating Activities
2 Net Income (Line 78(c) on page 116) 78,210,066 100,223,872
3 Noncash Charges (Credits) to Income:
112,091,663 105,727,999 4 Depreciation and Depletion
5 Amortization of deferred power and gas costs, debt expense and exchange power 12,954,915 28,936,761
6 Deferred Income Taxes (Net) 19,589,845 21,115,803
7 Investment Tax Credit Adjustments (Net) 2,212,172 2,558,524
8 Net (Increase) Decrease in Receivables 12,838,942 3,428,347
9 Net (Increase) Decrease in Inventory 4,331,613 ( 2,737,133)
10 Net (Increase) Decrease in Allowances Inventory
11 Net Increase (Decrease) in Payables and Accrued Expenses 31,767,362 ( 1,250,437)
12 Net (Increase) Decrease in Other Regulatory Assets ( 4,674,400) 10,565,705
13 Net Increase (Decrease) in Other Regulatory Liabilities ( 4,241041) ( 11,754,169)
14 (Less) Allowance for Other Funds Used During Construction 4,054,947 2,224,987
15 (Less) Undistributed Earnings from Subsidiary Companies ( 1,206,861) 9,971,326
16 Other (footnote details):
17 Net Cash Provided by (Used in) Operating Activities
18 (Total of Lines 2 thru 16) I 275,980,953 228,764,858
19
20 Cash Flows from Investment Activities:
21 Construction and Acquisition of Plant (including land):
268,743,138) ' ( 240,025,802) 22 Gross Additions to Utility Plant (less nuclear fuel) I
23 Gross Additions to Nuclear Fuel
24 Gross Additions to Common Utility Plant
25 Gross Additions to Nonutility Plant
26 (Less) Allowance for Other Funds Used During Construction
27 Other (footnote details):
28 Cash Outflows for Plant (Total of lines 22 thru 27) ( 268,743,138) ( 240,025,802)
29
30 Acquisition of Other Noncurrent Assets (d)
31 Proceeds from Disposal of Noncurrent Assets (d)
32 Federal grant payments received 8,277,036 16,927,752
33 Investments in and Advances to Assoc. and Subsidiary Companies ( 19,138,510) ( 5,482,493)
34 Contributions and Advances from Assoc. and Subsidiary Companies
35 Disposition of Investments in (and Advances to)
36 Associated and Subsidiary Companies
37
38 Purchase of Investment Securities (a)
39 Proceeds from Sales of Investment Securities (a)
FERC FORM NO. 2 (REV 06-04) Page 120
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012104
- Statement of Cash Flows (continued)
Line
No.
Description (See Instructions for explanation of codes)
(a)
Current Year
to Date
Quarter/Year
Previous Year
to Date
Quarter/Year
40 Loans Made or Purchased
41 Collections on Loans
42
43 Net (Increase) Decrease in Receivables
44 Net (Increase) Decrease in Inventory
45 Net (Increase) Decrease in Allowances Held for Speculation
46 Net Increase (Decrease) in Payables and Accrued Expenses
47 Changes in other property and investments 4,540,198 ( 1,754,160)
48 Net Cash Provided by (Used in) Investing Activities
49 (Total of lines 28 thru 47) I 275,064,414)1 ( 230,334703)
50
51 Cash Flows from Financing Activities:
52 Proceeds from Issuance of:
53 Long-Term Debt (b) I 80,000,000 I 85,000,000'
54 Preferred Stock
55 Common Stock 29,078,745 26,462,920
56 Other (footnote details):
57 Net Increase in Short-term Debt (c)
58 Cash received for settlement of interest rate swap agreements
59 Cash Provided by Outside Sources (Total of lines 53 thru 58) I 109,078,745 i 111,462,920
60
61 Payments for Retirement of:
62 Long-Term Debt (b) ( 11,324,884) I 195,575) I
63 Preferred Stock
64 Common Stock
65 Other
66 Net Decrease in Short-Term Debt (c) ( 9,000,000) ( 49,000,000)
67 Premium paid to repurchase long-term debt
68 Dividends on Preferred Stock
69 Dividends on Common Stock ( 68,552,375) ( 63,736,957)
70 Net Cash Provided by (Used in) Financing Activities
71 (Total of lines 59 thru 69) 891,013 ( 16503,709)
72
73 Net Increase (Decrease) in Cash and Cash Equivalents
74 (Total of line 18, 49 and 71) I 1,807,552 ( 18,073,554)
75 ________________________ _________________________
76 Cash and Cash Equivalents at Beginning of Period 1,867,419 19,940,973
77
78 Cash and Cash Equivalents at End of Period 3,674,971 1,867,419
FERC FORM NO. 2 (REV 06-04) Page 120a
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 20121Q4
FOOTNOTE DATA
çhedule Page: 120 Line No.: 65 Column: b
Settlement of interest rate swap agreement (18,546,870)
Long-term debt and short-term borrowing issuance costs (763,603)
$chedule Page: 120 Line No.: 65 Column: c
Settlement of interest rate swap agreement (10,557,000)
Long-term debt and short-term borrowing issuance costs (4,477,097)
Schedule Page: 120 Line No.: 16 Column: c
Power and natural gas deferrals 193,076
Change in special deposits (14,234,011)
Change in other current assets (5,795,951)
Non-cash stock compensation 4,147,207
Changes in other non-current assets/liabilities (816,072)
Net change in receivables allowance 651,650
Schedule Page: 120 Line No.: 16 Column: b
Power and natural gas deferrals 1,704,991
Change in special deposits 9,792,264
Change in other current assets 1,080,222
Non-cash stock compensation 4,549,448
Changes in other non-current assets/liabilities (7,388,676)
Net change in receivables allowance 3,973,772
Cash paid for foreign currency hedges 35,881
I FERC FORM NO. 2 (12-96) Page 552.1 I
This Page Intentionally Left Blank
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/04
Notes to Financial Statements
1.Provide important disclosures regarding the Balance Sheet, Statement of Income for the Year, Statement of Retained Earnings for the Year,
and Statement of Cash Flow, or any account thereof. Classify the disclosures according to each financial statement, providing a subheading for
each statement except where a disclosure is applicable to more than one statement. The disclosures must be on the same subject matters and
in the same level of detail that would be required if the respondent issued general purpose financial statements to the public or shareholders.
2.Furnish details as to any significant contingent assets or liabilities existing at year end, and briefly explain any action initiated by the Internal
Revenue Service involving possible assessment of additional income taxes of material amount, or a claim for refund of income taxes of a
material amount initiated by the utility. Also, briefly explain any dividends in arrears on cumulative preferred stock.
3.Furnish details on the respondent's pension plans, post-retirement benefits other than pensions (PBOP) plans, and post-employment benefit
plans as required by instruction no. 1 and, in addition, disclose for each individual plan the current year's cash contributions. Furnish details on
the accounting for the plans and any changes in the method of accounting for them. Include details on the accounting for transition obligations or
assets, gains or losses, the amounts deferred and the expected recovery periods. Also, disclose any current year's plan or trust curtailments,
terminations, transfers, or reversions of assets. Entities that participate in multiemployer postretirement benefit plans (e.g. parent company
sponsored pension plans) disclose in addition to the required disclosures for the consolidated plan, (1) the amount of cost recognized in the
respondent's financial statements for each plan for the period presented, and (2) the basis for determining the respondent's share of the total
plan costs.
4.Furnish details on the respondent's asset retirement obligations (ARO) as required by instruction no. 1 and, in addition, disclose the amounts
recovered through rates to settle such obligations. Identify any mechanism or account in which recovered funds are being placed (i.e. trust funds,
insurance policies, surety bonds). Furnish details on the accounting for the asset retirement obligations and any changes in the measurement or
method of accounting for the obligations. Include details on the accounting for settlement of the obligations and any gains or losses expected or
incurred on the settlement.
5.Provide a list of all environmental credits received during the reporting period.
6.Provide a summary of revenues and expenses for each tracked cost and special surcharge.
7.Where Account 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 item. See General Instruction 17 of the Uniform System of Accounts.
8.Explain concisely any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
9.Disclose details on any significant financial changes during the reporting year to the respondent or the respondent's consolidated group that
directly affect the respondent's gas pipeline operations, including: sales, transfers or mergers of affiliates, investments in new partnerships, sales
of gas pipeline facilities or the sale of ownership interests in the gas pipeline to limited partnerships, investments in related industries (i.e.,
production, gathering), major pipeline investments, acquisitions by the parent corporation(s), and distributions of capital.
10.Explain concisely unsettled rate proceedings where a contingency exists such that the company may need to refund a material amount to
the utility's customers or that the utility may receive a material refund with respect to power or gas purchases. State for each year affected the
gross revenues or costs to which the contingency relates and the tax effects and explain the major factors that affect the rights of the utility to
retain such revenues or to recover amounts paid with respect to power and gas purchases.
11.Explain concisely significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding
affecting revenues received or costs incurred for power or gas purchases, and summarize the adjustments made to balance sheet, income, and
expense accounts.
12.Explain concisely only those significant changes in accounting methods made during the year which had an effect on net income, including
the basis of allocations and apportionments from those used in the preceding year. Also give the approximate dollar effect of such changes.
13.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.
14.For the 30 disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which
have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in
such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term
contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from
business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though
a significant change since year end may not have occurred.
15.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.
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
Avista Corporation (Avista Corp. or the Company) is an energy company engaged in the generation, transmission and distribution of
energy, as well as other energy-related businesses. Avista Corp. generates, transmits and distributes electricity in parts of eastern
Washington and northern Idaho. In addition, Avista Corp. has electric generating facilities in Montana and northern Oregon. Avista
Corp. also provides natural gas distribution service in parts of eastern Washington and northern Idaho, as well as parts of northeastern
and southwestern Oregon. Avista Capital, Inc. (Avista Capital), a wholly owned subsidiary of Avista Corp., is the parent company of
all of the subsidiary companies, except Spokane Energy, LLC (Spokane Energy). Avista Capital's subsidiaries include Ecova, Inc.
(Ecva), a 79.() percent owned subsidiary as of December 31, 2012. Ecova is a provider of energy efficiency and other facility
information and cost management programs and services for multi-site customers and utilities throughout North America.
I FERC FORM NO. 213-Q (REV 12-07) 122.1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
Basis of Reporting
The financial statements include the assets, liabilities, revenues and expenses of the Company and have been prepared in accordance
with the accounting requirements of the Federal Energy Regulatory Commission (FERC) as set forth in its applicable Uniform System
of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles
generally accepted in the United States of America (U.S. GAAP). As required by the FERC, the Company accounts for its investment
in majority-owned subsidiaries on the equity method rather than consolidating the assets, liabilities, revenues, and expenses of these
subsidiaries, as required by U.S. GAAP. The accompanying financial statements include the Company's proportionate share of utility
plant and related operations resulting from its interests in jointly owned plants. In addition, under the requirements of the FERC, there
are differences from U.S. GAAP in the presentation of (1) current portion of long-term debt (2) assets and liabilities for cost of
removal of assets, (3) assets held for sale, (4) regulatory assets and liabilities, (5) deferred income taxes and (6) comprehensive
income.
Use of Estimates
The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of
America (U.S. GAAP) requires management to make estimates and assumptions that affect amounts reported in the financial
statements. Significant estimates include:
determining the market value of energy commodity derivative assets and liabilities,
• pension and other postretirement benefit plan obligations,
• contingent liabilities,
recoverability of regulatory assets, and
. unbilled revenues.
Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the financial
statements and thus actual results could differ from the amounts reported and disclosed herein.
System of Accounts
The accounting records of the Company's utility operations are maintained in accordance with the uniform system of accounts
prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the state regulatory commissions in Washington,
Idaho, Montana and Oregon.
Regulation
The Company is subject to state regulation in Washington, Idaho, Montana and Oregon. The Company is also subject to federal
regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its
operations.
Operating Revenues
Revenues related to the sale of energy are recorded when service is rendered or encrgy is delivered to customers. The determination of
the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the
month. At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter reading is
estimated and the corresponding unbilled revenue is estimated and recorded.
Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands):
2012 2011
Unbilled accounts receivable $ 77,298 $ 82,950
Advertising Expenses
The Company expenses advertising costs as incurred. Advertising expenses were not a material portion of the Company's operating
expenses in 2012 and 2011.
I FERC FORM FlO. 213-Q (REV 12-07) 1222
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/04
Notes to Financial Statements
Depreciation
For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing composite rates for utility
plant. Such rates are designed to provide for retirements of properties at the expiration of their service lives. For utility operations, the
ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31:

2012 2011
Ratio of depreciation to average depreciable property 2.92% 2.92%
The average service lives for the following broad categories of utility plant in service are:
• electric thermal production - 33 years,
• hydroelectric production - 73 years,
• electric transmission - 51 years,
• electric distribution - 38 years, and
• natural gas distribution property -49 years.
Taxes Other Than Income Taxes
Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and
certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes
collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled
the following amounts for the years ended December 31 (dollars in thousands):

2012 2011
Utility taxes $ 53,716 $ 55,739
Allowance for Funds Used During Construction
The Allowance for Funds Used During Construction (AFUDC) represents the cost of both the debt and equity funds used to finance
utility plant additions during the construction period. As prescribed by regulatory authorities, AFUDC is capitalized as a part of the
cost of utility plant and the debt related portion is credited against total interest expense in the Statements of Income. The Company is
permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a reasonable return thereon, through its
inclusion in rate base and the provision for depreciation after the related utility plant is placed in service. Cash inflow related to
AFUDC does not occur until the related utility plant is placed in service and included in rate base. The effective AFUDC rate was the
following for the years ended December 31:
2012 2011
Effective AFUDC rate 762% 7.91%
Income Taxes
A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the differences between
the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company's
consolidated income tax returns. The deferred income tax expense for the period is equal to the net change in the deferred income tax
asset and liability accounts from the beginning to the end of the period. The effect on deferred income taxes from a change in tax rates
is recognized in income in the period that includes the enactment date. Deferred income tax liabilities and regulatory assets are
established for income tax benefits flowed through to customers as prescribed by the respective regulatory commissions.
Stock-Based Compensation
Compensation cost relating to share-based payment transactions is recognized in the Company's financial statements based on the fair
value of the equity or liability instruments issued and recorded over the requisite service period. See Note 17 for further information.
FERC FORM NO 2/3-Q (REV 12-07) 1223 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)XAn Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
Cash and Cash Equivalents
For the purposes of the Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months or
less when purchased to be cash equivalents.
Allowance for Doubtful Accounts
The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The
Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to
accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual accounts.
Utility Plant in Service
The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of
property and improvements, is capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is
charged to accumulated depreciation.
Derivative Assets and Liabilities
Derivatives are recorded as either assets or liabilities on the Balance Sheets measured at estimated fair value. In certain defined
conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for derivatives depends on
the intended use of the derivatives and the resulting designation.
The Washington Utilities and Transportation Commission (UTC) and the Idaho Public Utilities Commission (IPUC) issued accounting
orders authorizing Avista Corp. to offset commodity derivative assets or liabilities with a regulatory asset or liability. This accounting
treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of
settlement. The orders provide for Avista Corp. to not recognize the unrealized gain or loss on utility derivative commodity
instruments in the Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for
recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through
purchased gas cost adjustments, the Energy Recovery Mechanism (ERM) in Washington, the Power Cost Adjustment (PCA)
mechanism in Idaho, and periodic general rates cases. Regulatory assets are assessed regularly and are probable for recovery through
future rates.
Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated
fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual
basis until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other than
temporary.
Fair Value Measurements
Fair value represents the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly
transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred
compensation assets, as well as derivatives related to interest rate swap agreements and foreign currency exchange contracts, are
reported at estimated fair value on the Balance Sheets. See Note 15 for the Company's fair value disclosures.
Regulatory Deferred Charges and Credits
The Company prepares its financial statements in accordance with regulatory accounting practices because:
• rates for regulated services are established by or subject to approval by independent third-party regulators,
• the regulated rates are designed to recover the cost of providing the regulated services, and
• in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be
charged to and collected from customers at levels that will recover costs.
Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not
currently included in rates, but expected to be recovered or refunded in the future) are reflected as deferred charges or credits on the
FERC FORM NO. 213-0 (REV 12-07) 122.4
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)XAn Original (Mo, Da, Yr)
(2)_A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
Balance Sheets. These costs and/or obligations are not reflected in the Statements of Income until the period during which matching
revenues are recognized. If at some point in the future the Company determines that it no longer meets the criteria for continued
application of regulatory accounting practices for all or a portion of its regulated operations, the Company could be:
required to write off its regulatory assets, and
precluded from the future deferral of costs not recovered through rates at the time such costs are incurred, even if the
Company expected to recover such costs in the future.
See Note 20 for further details of regulatory assets and liabilities.
Investment in Exchange Power-Net
The investment in exchange power represents the Company's previous investment in Washington Public Power Supply System Project
3 (WNP-3), a nuclear project that was terminated prior to completion. Under a settlement agreement with the Bonneville Power
Administration in 1985, Avista Corp. began receiving power in 1987, for a 32.5-year period, related to its investment in WNP-3.
Through a settlement agreement with the UTC in the Washington jurisdiction, Avista Corp. is amortizing the recoverable portion of its
investment in WNP-3 (recorded as investment in exchange power) over a 32.5-year period that began in 1987. For the Idaho
jurisdiction, Avista Corp. fully amortized the recoverable portion of its investment in exchange power.
Unamortized Debt Expense
Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt.
Unamortized Loss on Reacquired Debt
For the Company's Washington regulatory jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums
paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued-in
connection with the repurchase, these costs are amortized over the life of the new debt. In the Company's other regulatory
jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding
debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a
component of interest expense.
Contingencies
The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss
contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated.
The Company also discloses losses that do not meet these conditions for accrual, if there is a reasonable possibility that a loss may be
incurred.
NOTE 2. NEW ACCOUNTING STANDARDS
Effective January 1, 2012, the Company adopted Accounting Standards Update (ASU) No. 2011-04, "Fair Value Measurement (Topic
820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs." This ASU
requires enhanced disclosures for fair value measurements, including quantitative analysis of unobservable inputs used in Level 3 fair
value measurements. The ASU also clarifies the FASB's intent about the application of existing fair value measurement requirements.
The adoption of this ASU did not have any impact on the Company's financial condition, results of operations and cash flows. See
Note 15 for the Company's fair value disclosures.
In February 2013, the FASB issued ASU No. 2013-02, "Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out
of Accumulated Other Comprehensive Income." This ASU does not change current requirements for reporting net income or other
comprehensive income in financial statements; however, it will require entities to disclose the effect on the line items of net income for
reclassifications out of accumulated other comprehensive income if the item being reclassified is required to be reclassified in its
entirety to net income under U.S. GAAP. For other items that are not required to be reclassified in their entirety to net income under
U.S. GAAP, an entity is required to cross-reference other disclosures required under U.S. GAAP to provide additional detail about
those items. This ASU is effective for fiscal years beginning after December 15, 2012. The Company does not expect that this ASU
will have any material impact on its financial condition, results of operations and cash flows.
I FERC FORM NO 2/3-Q (REV 12-07) 122.5 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/04
Notes to Financial Statements
In December 2011, the FASB issued ASU No. 2011-11, "Balance Sheet (Topic 210): Disclosures about Offsetting Assets and
Liabilities." This ASU enhances disclosure requirements about the nature of an entity's right to offset and related arrangements
associated with its financial instruments and derivative instruments. ASU No. 2011-11 requires the disclosure of the gross amounts
subject to rights of set-off, amounts offset in accordance with the accounting standards followed, and the related net exposure. The
Company will be required to adopt this ASU effective January 1, 2013. Adoption of this ASU will require additional disclosures in the
Company's financial statements; however, the Company does not expect that this ASU will have any material impact on its financial
condition, results of operations and cash flows.
In January 2013, the FASB issued ASU No. 2013-01, "Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about
Offsetting Assets and Liabilities." This ASU clarifies which instruments and transactions are subject to the enhanced disclosure
requirements of ASU 2011-11 regarding the offsetting of financial assets and liabilities. ASU No. 2013-01 limits the scope of ASU
No. 2011-11 to only recognized derivative instruments, repurchase agreements and reverse repurchase agreements, and borrowing and
lending securities transactions that are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The Company will be
required to adopt this ASU effective January 1, 2013. The Company does not expect that this ASU will have a material impact on its
financial condition, results of operations and cash flows.
NOTE 3. VOLUNTARY SEVERANCE INCENTIVE PROGRAM
On October 22, 2012, Avista Corp. announced a voluntary severance incentive program to reduce the total utility workforce
and achieve necessary long-term, sustainable, Company-wide savings, in addition to other cost saving measures.
In general, most regular full and part-time employees of Avista Corp. (not including any of its subsidiaries) who were not
covered by a collective bargaining agreement were eligible to participate in the program. Based on the response to the
program by interested employees and the approvals by Company management, the program resulted in the termination of 55,
or approximately 6 percent, of the eligible 919 non-union employees, and the total severance costs under the program were
$7.3 million (pre-tax). The total severance costs are made up of the severance payments and the related payroll taxes and
employee benefit costs. Approximately 50 percent of the applicants to the program were approved for termination by
Company management. The long-term operating and maintenance cost savings under the program are expected to exceed the
severance costs of the program and the expected payback period for the severance costs will be approximately 1.4 years.
Each participant in the program was entitled to receive severance pay in an amount calculated by reference to the
participant's years of service and base pay as of December 31, 2012. In no event did the amount of severance pay exceed 78
weeks of a participant's base pay.
All terminations under the voluntary severance incentive program were completed by December 31, 2012. The cost of the
program was recognized as expense during the fourth quarter of 2012 and severance pay was distributed in a single lump sum
cash payment to each participant during January 2013.
NOTE-4. ECOVA ACQUISITIONS
The acquisition of Cadence Network in July 2008 was funded by issuing additional Ecova common stock. Under the transaction
agreement, the previous owners of Cadence Network had a right to have their shares of Ecova common stock redeemed by Ecova
during July 2011 or July 2012 if their investment in Ecova was not liquidated through either an initial public offering or sale of the
business to a third party. These redemption rights were not exercised and expired effective July 31, 2012. As such, this redeemable
noncontrolling interest was reclassified to equity effective July 31, 2012. Additionally, certain minority shareholders and option
holders of Ecova have the right to put their shares back to Ecova at their discretion during an annual put window. Stock options and
other outstanding redeemable stock are valued at their maximum redemption amount which is equal to their intrinsic value (fair value
less exercise price).
In January 2011, Ecova acquired substantially all of the assets and liabilities of Building Knowledge Networks, LLC (BKN), a
Seattle-based real-time building energy management services provider.
On November 30, 2011, Ecova acquired all of the capital stock of Prenova, Inc. (Prenova), an Atlanta-based energy management
company.
I FERC FORM NO. 213-Q (REV 12-07) 122.6 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
On January 31, 2012, Ecova acquired all of the capital stock of LPB Energy Management (LPB), a Dallas, Texas-based energy
management company.
NOTE 5. DERIVATIVES AND RISK MANAGEMENT
Energy Commodity Derivatives
Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices.
Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by
supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista
Corp. utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these
commodity price exposures. The Company has an energy resources risk policy and control procedures to manage these risks. The
Company's Risk Management Committee establishes the Company's energy resources risk policy and monitors compliance. The Risk
Management Committee is comprised of certain Company officers and other members of management. The Audit Committee of the
Company's Board of Directors periodically reviews and discusses enterprise risk management processes, and it focuses on the
Company's material financial and accounting risk exposures and the steps management has undertaken to control them.
As part of the its resource procurement and management operations in the electric business, Avista Corp. engages in an ongoing
process of resource optimization, which involves the economic selection from available energy resources to serve Avista Corp.'s load
obligations and the use of these resources to capture available economic value. Avista Corp. transacts in wholesale markets by selling
and purchasing electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel.
Such transactions are part of the process of matching resources with our load obligations and hedging the related financial risks. These
transactions range from terms of intra-hour up to multiple years.
Avista Corp. makes continuing projections of
electric loads at various points in time (ranging from intra-hour to multiple years) based on, among other things,
estimates of customer usage and weather, historical data and contract terms, and
resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of
streamflows, availability of generating units, historic and forward market information, contract terms, and
experience.
On the basis of these projections, we make purchases and sales of electric capacity and energy, fuel for electric generation, and related
derivative instruments to match expected resources to expected electric load requirements and reduce our exposure to electricity (or
fuel) market price changes. Resource optimization involves generating plant dispatch and scheduling available resources and also
includes transactions such as:
purchasing fuel for generation,
when economical, selling fuel and substituting wholesale electric purchases, and
other wholesale transactions to capture the value of generation and transmission resources and fuel delivery capacity
contracts.
Avista Corp.'s optimization process includes entering into hedging transactions to manage risks. Transactions include both physical
energy contracts and related derivative instruments.
As part of its resource procurement and management of its natural gas business, Avista Corp. makes continuing projections of its
natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning
typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations
to Avista Corp.'s distribution system. However, daily variations in natural gas demand can be significantly different than monthly
demand projections. On the basis of these projections, Avista Corp. plans and executes a series of transactions to hedge a significant
portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions
may extend as much as four natural gas operating years (November through October) into the future. Avista Corp. also leaves a
significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.
Natural gas resource optimization activities include:
[FERC FORM NO. 213-0 (REV 12-07) 122.7
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2) A Resubmission 04/12/2013 20121Q4
Notes to Financial Statements
wholesale market sales of surplus natural gas supplies,
optimization of interstate pipeline transportation capacity not needed to serve daily load, and
purchases and sales of natural gas to optimize use of storage capacity.
The following table presents the underlying energy commodity derivative volumes as of December 31, 2012 that are expected to settle
in each respective year (in thousands of MWhs and mmBTUs):
Purchases Sales
Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives
Physical (1) Financial (1) Physical Financial Physical Financial Physical Financial
Year MWH MWH mmBTUs mmBTUs MWH MWH mmBTUs mmBTUs
2013 713 3,365 18,523 88,391 264 2,712 7,252 91,962
2014 397 801 6,394 55,407 377 1,844 1,786 33,623
2015 379 614 3,390 42,930 286 982 - 35,575
2016 367 - 1,365 455 287 - - -
2017 366 - - - 286 - - -
Thereafter 583 - - - 443 - - -
(I) Physical transactions represent commodity transactions where Avista will take delivery of either electricity or natural gas and
financial transactions represent derivative instruments with no physical delivery, such as futures, swaps, options, or forward
contracts.
The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during
the period they settle and will be included in the various recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case
process, and are expected to eventually be collected through retail rates from customers.
Foreign Currency Exchange Contracts
A significant portion of Avista Corp.'s natural gas supply (including fuel for power generation) is obtained from Canadian sources.
Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.'s short-term
natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled
within sixty days with U.S. dollars. Avista Corp. economically hedges a portion of the foreign currency risk by purchasing Canadian
currency contracts when such commodity transactions are initiated. This risk has not had a material effect on the Company's financial
condition, results of operations or cash flows and these differences in cost related to currency fluctuations were included with natural
gas supply costs for ratemaking. The following table summarizes the foreign currency hedges that the Company has entered into as of
December 31 (dollars in thousands):
2012 2011
Number of contracts 20 28
Notional amount (in United States dollars) $ 12,621 $ 7,033
Notional amount (in Canadian dollars) 12,502 7,192
Interest Rate Swap Agreements
Avista Corp. hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swaps and
U.S. Treasury lock agreements. These interest rate swap agreements are considered economic hedges against fluctuations in future cash
flows associated with anticipated debt issuances.
The following table summarizes the interest rate swaps that the Company has entered into as of December 31 (dollars in thousands):
Number of contracts
Notional amount
Mandatory cash settlement date
Number of contracts
2012 2011
- 3
$ - $ 75,000
- July 2012
2 2
I FERC FORM NO. 2/3-Q (REV 12-07) 122.8 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
Notional amount $ 85,000 $ 85,000
Mandatory cash settlement date June 2013 June 2013
Number of contracts 2 -
Notional amount $ 50,000 $ -
Mandatory cash settlement date October 2014 -
Number of contracts 1 -
Notional amount $ 25,000 $ -
Mandatory cash settlement date October 2015 -
In May 2012, the Company cash settled interest rate swap contracts (notional amount of $75.0 million) and paid a total of $18.5
million. The interest rate swap contracts were settled in connection with the pricing of $80.0 million of First Mortgage Bonds. In
September 2011, the Company cash settled interest rate swap contracts (notional amount of $85.0 million) and paid a total of $10.6
million. The interest rate swap contracts were settled in connection with the pricing of $85.0 million of First Mortgage Bonds.
Upon settlement of the interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a
component of interest expense over the life of the forecasted interest payments.
Derivative Instruments Summary
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 31,
2012 (in thousands):
Fair Value
Collateral Net Asset
Derivative Balance Sheet Location Asset Liability Netting (Liability)
Foreign currency contracts Derivative instrument liabilities
—Hedges $ 7 $ (34) $ - $ (27)
Interest rate contracts Derivative instrument liabilities
-Hedges - (1,406) - (1,406)
Interest rate contracts Long-term portion of derivative
instrument assets -Hedges 7,265 - - 7,265
Commodity contracts Derivative instrument assets
current 10,772 (6,633) - 4,139
Commodity contracts Long-term portion of derivative
assets 18,779 (17,686) - 1,093
Commodity contracts Derivative instrument liabilities
current 50,227 (89,449) 9,707 (29,515)
Commodity contracts Long-term portion of derivative
liabilities 2,247 (28,558) - (26,311)
Total derivative instruments recorded on the balance sheet $ 89,297$ (143,766) $ 9,707 $ (44,762)
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 31,
2011 (in thousands):
Balance Sheet Location Asset
Fair Value
Liability
Net Asset
(Liability)
Derivative instrument assets —Hedges $ 32 $ - $ 32
Derivative instrument liabilities —Hedges - (16,253) (16,253)
Long-term portion of derivative
instrument liabilities - Hedges - (2,642) (2,642)
Derivative instrument assets
current 1,618 (479) 1,139
Long-term portion of
derivative assets 185 - 185
Derivative instrument liabilities
current 40,090 (110,914) (70,824)
12-07) 122.9
Derivative
Foreign currency contracts
Interest rate contracts
Interest rate contracts
Commodity contracts
Commodity contracts
Commodity contracts
I FERC FORM NO. 2/3-Q (H
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 20121Q4
Notes to Financial Statements
Commodity contracts Long-term portion of
derivative instrument liabilities 44,308 (84,838) (40,530)
Total derivative instruments recorded on the balance sheet $ 86,233 $ (215,126) $ (128,893)
Exposure to Demands for Collateral
The Company's derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or
reductions or terminations of a portion of the contract through cash settlement, in the event of a downgrade in the Company's credit
ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden
and significant demands may be made against the Company's credit facilities and cash. The Company actively monitors the exposure to
possible collateral calls and takes steps to mitigate capital requirements. As of December 31, 2012, the Company had cash deposited as
collateral of $10.1 million and letters of credit of $28.1 million outstanding related to its energy derivative contracts. The Balance
Sheet at December 31, 2012 reflects the offsetting of $9.7 million of cash collateral against net derivative positions where a legal right
of offset exists.
Certain of the Company's derivative instruments contain provisions that require the Company to maintain an investment grade credit
rating from the major credit rating agencies. If the Company's credit ratings were to fall below "investment grade," it would be in
violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand
immediate and ongoing collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative
instruments with credit-risk-related contingent features that are in a liability position as of December 31, 2012 was $35.9 million. If the
credit-risk-related contingent features underlying these agreements were triggered on December 31, 2012, the Company could be
required to post $25.8 million of additional collateral to its counterparties.
Credit Risk
Credit risk relates to the potential losses that the Company would incur as a result of non-performance by counterparties of their
contractual obligations to deliver energy or make financial settlements. The Company often extends credit to counterparties and
customers and is exposed to the risk that it may not be able to collect amounts owed to the Company. Credit risk includes potential
counterparty default due to circumstances:
relating directly to it,
caused by market price changes, and
relating to other market participants that have a direct or indirect relationship with such counterparty.
Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits are
established. Should a counterparty fail to perform, the Company may be required to honor the underlying commitment or to replace
existing contracts with contracts at then-current market prices.
We enter into bilateral transactions between Avista and various counterparties. We also trade energy and related derivative instruments
through clearinghouse exchanges.
The Company seeks to mitigate bilateral credit risk by:
• entering into bilateral contracts that specify credit terms and protections against default,
• applying credit limits and duration criteria to existing and prospective counterparties,
• actively monitoring current credit exposures,
• asserting our collateral rights with counterparties,
• carrying out transaction settlements timely and effectively, and
• conducting transactions on exchanges with fully collateralized clearing arrangements that significantly reduce
counterparty default risk.
The Company's credit policy includes an evaluation of the financial condition of counterparties. Credit risk management includes
collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees. The Company enters into
various agreements that address credit risks including standardized agreements that allow for the netting or offsetting of positive and
FERC FORM NO. 2!3-Q (REV 12-07) 122.10 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)XAn Original (Mo, Da, Yr)
(2)_A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
negative exposures.
The Company has concentrations of suppliers and customers in the electric and natural gas industries including:
• electric and natural gas utilities,
• electric generators and transmission providers,
• natural gas producers and pipelines,
• financial institutions including commodity clearing exchanges and related parties, and
energy marketing and trading companies.
In addition, the Company has concentrations of credit risk related to geographic location as it operates in the western United States and
western Canada. These concentrations of counterparties and concentrations of geographic location may impact the Company's overall
exposure to credit risk because the counterparties may be similarly affected by changes in conditions.
The Company maintains credit support agreements with certain counterparties and margin calls are periodically made and/or received.
Margin calls are triggered when exposures exceed contractual limits or when there are changes in a counterparty's creditworthiness.
Price movements in electricity and natural gas can generate exposure levels in excess of these contractual limits. Negotiating for
collateral in the form of cash, letters of credit, or performance guarantees is common industry practice.
NOTE 6. JOINTLY OWNED ELECTRIC FACILITIES
The Company has a 15 percent ownership interest in a twin-unit coal-fired generating facility, the Colstrip Generating Project
(Colstrip) located in southeastern Montana, and provides financing for its ownership interest in the project. The Company's share of
related fuel costs as well as operating expenses for plant in service are included in the corresponding accounts in the Statements of
Income. The Company's share of utility plant in service for Colstrip and accumulated depreciation were as follows as of December 31
(dollars in thousands):
Utility plant in service
Accumulated depreciation
NOTE 7. ASSET RETIREMENT OBLIGATIONS
2012 2011
$ 344,958 $ 342,539
(234,126) (225,746)
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the
liability is initially recorded, the associated costs of the asset retirement obligation are capitalized as part of the carrying amount of the
related long-lived asset. The liability is accreted to its present value each period and the related capitalized costs are depreciated over
the useful life of the related asset. Upon retirement of the asset, the Company either settles the retirement obligation for its recorded
amount or incurs a gain or loss. The Company records regulatory assets and liabilities for the difference between asset retirement costs
currently recovered in rates and asset retirement obligations recorded since asset retirement costs are recovered through rates charged
to customers. The regulatory assets do not earn a return.
Specifically, the Company has recorded liabilities for future asset retirement obligations to:
• restore ponds at Coistrip,
• cap a landfill at the Kettle Falls Plant,
• remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease,
• remove asbestos at the corporate office building, and
• dispose of PCBs in certain transformers.
Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the:
• removal and disposal of certain transmission and distribution assets, and
I FERC FORM NO. 213-Q (REV 12-07) 122.11
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities.
The following table documents the changes in the Company's asset retirement obligation during the years ended December 31 (dollars
in thousands):
2012 2011
Asset retirement obligation at beginning of year $ 3,513 $ 3,887
New liability recognized - -
Liability settled (559) (612)
Accretion expense 214 238
Asset retirement obligation at end of year $ 3,168 $ 3,513
NOTE 8. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a defined benefit pension plan covering substantially all regular full-time employees at Avista Corp. Individual
benefits under this plan are based upon the employee's years of service, date of hire and average compensation as specified in the plan.
The Company's funding policy is to contribute at least the minimum amounts that are required to be funded under the Employee
Retirement Income Security Act, but not more than the maximum amounts that are currently deductible for income tax purposes. The
Company contributed $44 million in cash to the pension plan in 2012 and $26 million in 2011. The Company expects to contribute $44
million in cash to the pension plan in 2013.
The Company also has a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to executive
officers of the Company. The SERP is intended to provide benefits to executive officers whose benefits under the pension plan are
reduced due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred
compensation plans. The liability and expense for this plan are included as pension benefits in the tables included in this Note.
The Company expects that benefit payments under the pension plan and the SERP will total (dollars in thousands):
2013 2014 2015 2016 2017 Total 2018-2022
Expected benefit payments $ 24,504 $ 24,280 $ 25,434 $ 26,567 $ 27,797 $ 162,488
The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments
held by the plan. In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with
maturities similar to that of the expected term of pension benefits.
The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company
accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. The Company
elected to amortize the transition obligation of $34.5 million over a period of 20 years, beginning in 1993.
The Company has a Health Reimbursement Arrangement to provide employees with tax-advantaged funds to pay for allowable
medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on the employee's years
of service and the ending salary. The liability and expense of this plan are included as other postretirement benefits.
The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement.
Under the plan, an executive officer's designated beneficiary will receive a payment equal to twice the executive officer's annual base
salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer's total annual pension
benefit). The liability and expense for this plan are included as other postretirement benefits.
The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands):
2013 2014 2015 2016 2017 Total 2018-2022
Expected benefit payments $ 6,099 $ 6,160 $ 6,261 $ 6,389 $ 6,571 $ 36,342
The Company expects to contribute $6.1 million to other postretirement benefit plans in 2013, representing expected benefit payments
to be paid during the year. The Company uses a December 31 measurement date for its pension and other postretirement benefit plans.
I FERC FORM NO. 213-Q (REV 12-07) 122.12
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
I FERC FORM NO. 213-Q (REV 12-07) 122.13 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
The following table sets forth the pension and other postretirement benefit plan disclosures as of December 31, 2012 and 2011 and the
components of net periodic benefit costs for the years ended December 31, 2012 and 2011 (dollars in thousands):
Other Post-
Pension Benefits retirement Benefits
2012 2011 2012 2011
Change in benefit obligation:
Benefit obligation as of beginning of year $ 494,192 $ 433,491 $ 104,730 $ 60,339
Service cost 15,551 12,936 2,804 1,805
Interest cost 24,349 24,134 5,056 4,126
Actuarial loss 72,170 44,148 24,543 42,476
Transfer of accrued vacation - - 336 450
Benefits paid (21,643) (20,517) (4,928) (4,466)
Benefit obligation as of end of year $ 584,619 $ 494,192 $ 132,541 $ 104,730
Change in plan assets:
Fair value of plan assets as of beginning of year $ 328,150 $ 306,712 $ 22,455 $ 22,875
Actual return on plan assets 54,318 14,705 2,833 (420)
Employer contributions 44,000 26,000 - -
Benefits paid (20,407) (19,267) - -
Fair value of plan assets as of end of year $ 406,061 $ 328,150 $ 25,288 $ 22,455
Funded status $ (178,558) $ (166,042) $ (107,253) $ (82,275)
Unrecognized net actuarial loss 223,308 192,883 94,202 76,187
Unrecognized prior service cost 319 665 (856) (1,005)
Unrecognized net transition obligation - - - 505
Prepaid (accrued) benefit cost 45,069 27,506 (13,907) (6,588)
Additional liability (223,627) (193,54) (93,346) (75,687)
Accrued benefit liability $ (178,558) $ (166,042) $ (107,253) $ (82,275)
Accumulated pension benefit obligation $ 505,695 A 429,135 - -
Accumulated postretirement benefit obligation:
For retirees 49,232 $ 39,470
For fully eligible employees 35,570 $ 29,597
For other participants 47,739 $ 35,663
Included in accumulated comprehensive loss (income) (net of
tax):
Unrecognized net transition obligation $ - $ - $ - $ 328
Unrecognized prior service cost 207 433 (556) (653)
Unrecognized net actuarial loss 145,150 125,374 61,231 49,522
Total 145,357 125,807 60,675 49,197
Less regulatory asset (138,184) (119,360) (60,981) (49,873)
Accumulated other comprehensive loss (income) $ 7,173 $ 61447 $ (306) $ (676)
Other Post-
Pension Benefits retirement Benefits
2012 2011 2012 2011
Weighted average assumptions as of December 31:
Discount rate for benefit obligation
Discount rate for annual expense
Expected long-term return on plan assets
Rate of compensation increase
Medical cost trend on 65 - initial
Medical cost trend pre-age 65 - ultimate
Ultimate medical cost trend year pre-age 65
Medical cost trend post-age 65 - initial
Medical cost trend post-age 65 - ultimate
4.15% 5.04% 4.15% 4.98%
5.04% 5.68% 4.98% 5.53%
6.95% 7.40% 6.55% 7.00%
4.89% 4.87%
7.00% 7.50%
5.00% 5.00%
2019 2017
7.50% 8.00%
5.00% 6.00%
I FERC FORM NO. 213-Q (REV 12-07) 122.14 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 20121Q4
Notes to Financial Statements
Ultimate medical cost trend year post-age 65 2021 2018
Pension Benefits Other Postretirement Benefits
2012 2011 2012 2011
Components of net periodic benefit
cost:
Service cost $ 15,551 $ 12,936 $ 2,804 $ 1,805
Interest cost 24,349 24,134 5,056 4,126
Expected return on plan assets (23,810) (23,115) (1,471) (1,601)
Transition obligation recognition - - 505 505
Amortization of prior service cost 346 475 (149) (149)
Net loss recognition 11,637 9,493 5,020 3,458
Net periodic benefit cost $ 28,073 $ 23,923 $ 11,765 $ 8,144
Plan Assets
The Finance Committee of the Company's Board of Directors approves investment policies, objectives and strategies that seek an
appropriate return for the pension plan and other postretirement benefit plans and reviews and approves changes to the investment and
funding policies.
The Company has contracted with investment consultants who are responsible for managing/monitoring the individual investment
managers. The investment managers' performance and related individual fund performance is periodically reviewed by an internal
benefits committee and by the Finance Committee to monitor compliance with investment policy objectives and strategies.
I FERC FORM NO 2/3-0 (REV 12-07) 122.15 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
Pension plan assets are invested primarily in marketable debt and equity securities. Pension plan assets may also be invested in real
estate, absolute return, venture capital/private equity and commodity funds. In seeking to obtain the desired return to fund the pension
plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the
internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established
target investment allocation percentages by asset classes as indicated in the table below:
2012 2011
Equity securities 51% 51%
Debt securities 31% 31%
Real estate 5% 5%
Absolute return 10% 10%
Other 3% 3%
The market-related value of pension plan assets invested in debt and equity securities was based primarily on fair value (market
prices). The fair value of investment securities traded on a national securities exchange is determined based on the last reported sales
price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market
prices are not readily available or for which market prices do not represent the value at the time of pricing, are fair-valued by the
investment manager based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and
industry). Investments in common/collective trust funds are presented at estimated fair value, which is determined based on the unit
value of the fund. Unit value is determined by an independent trustee, which sponsors the fund, by dividing the fund's net assets by its
units outstanding at the valuation date. The fair value of the closely held investments and partnership interests is based upon the
allocated share of the fair value of the underlying assets as well as the allocated share of the undistributed profits and losses, including
realized and unrealized gains and losses.
The market-related value of pension plan assets invested in real estate was determined by the investment manager based on three basic
approaches:
• properties are externally appraised on an annual basis by independent appraisers, additional appraisals may be
performed as warranted by specific asset or market conditions,
• property valuations are reviewed quarterly and adjusted as necessary, and
• loans are reflected at fair value.
The market-related value of pension plan assets was determined as of December 31, 2012 and 2011.
The following table discloses by level within the fair value hierarchy (see Note 15 for a description of the fair value hierarchy) of the
pension plan's assets measured and reported as of December 31, 2012 at fair value (dollars in thousands)
Level 1 Level 2 Level 3 Total
Mutual funds:
Fixed income securities $ 83,037 $ - $ - $ 83,037
U.S. equity securities 135,436 - - 135,436
International equity securities 79,448 - - 79,448
Absolute return (1) 20,764 - - 20,764
Commodities (2) 8,258 - - 8,258
Common/collective trusts:
Fixed income securities - 43,107 - 43,107
Real estate - - 17,596 17,596
Partnership/closely held investments:
Absolute return (1) - - 17,755 17,755
Private equity funds (3) - - 660 660
Total $ 326,943 $ 43,107 $ 36,011 $ 406,061
I FERC FORM NO. 2/3-Q (REV 12-07) 122.16 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
The following table discloses by level within the fair value hierarchy (see Note 15 for a description of the fair value hierarchy) of the
pension plan's assets measured and reported as of December 31, 2011 at fair value (dollars in thousands):
Cash equivalents
Mutual funds:
Fixed income securities
U.S. equity securities
International equity securities
Absolute return (1)
Commodities (2)
Common/collective trusts:
Fixed income securities
U.S. equity securities
Real estate
Partnership/closely held investments:
Absolute return (1)
Private equity funds (3)
Total
Level 1 Level 2 Level 3 Total
$ - $ 7,550 $ - $ 7,550
76,486 - - 76,486
102,790 - - 102,790
52,241 - - 52,241
16,121 - - 16,121
6,526 - - 6,526
- 27,774 - 27,774
- 12,669 - 12,669
- - 8,598 8,598
- - 16,587 16,587
- - 808 808
$ 254,164 $ 47,993 $ 25,993 $ 3289 150
(1)This category invests in multiple strategies to diversify risk and reduce volatility. The strategies include: (a) event driven,
relative value, convertible, and fixed income arbitrage, (b) distressed investments, (c) long/short equity and fixed income, and
(d) market neutral strategies.
(2)The fund primarily invests in derivatives linked to commodity indices to gain exposure to the commodity markets. The fund
manager fully collateralizes these positions with debt securities.
(3)This category includes private equity funds that invest primarily in U.S. companies.
The table below discloses the summary of changes in the fair value of the pension plan's Level 3 assets for the year ended
December 31, 2012 (dollars in thousands):
Common/collective trusts Partnership/closely held investments
Balance, as of January 1, 2012
Realized gains
Unrealized gains (losses)
Purchases (sales), net
Balance, as of December 31, 2012
Real
estate
Absolute
return
Private equity
funds
$ 8,598 $ 16,587 $ 808
411 - 108
1,087 1,168 80
7,500 - (336)
$ 17,596 $ 17,755 $ 660
The table below discloses the summary of changes in the fair value of the pension plan's Level 3 assets for the year ended
December 31, 2011 (dollars in thousands):
Common/collective trusts Partnership/closely held investments
Balance, as of January 1, 2011
Realized gains (losses)
Unrealized gains (losses)
Purchases (sales), net
Balance, as of December 31, 2011
Absolute
return
Real
estate
Absolute
return
Private equity
funds
$ 95 $ 423 $ 16,917 $ 1,272
(748) 22 - 373
746 1,098 (330) (218)
(93) 71055 - (619)
$ - $ 8,598 $ 16,587 $ 808
The market-related value of other postretirement plan assets invested in debt and equity securities was based primarily on fair value
(market prices). The fair value of investment securities traded on a national securities exchange is determined based on the last
reported sales price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for
I FERC FORM NO. 2/3Q(REVI207) 12217 I
Name of Respondent This Report is: Date of Report Year/Period of Report
I (1)An Original (Mo, Da, Yr)
L (2)- A Resubmission 04/12/2013 2012/04
I Notes to Financial Statements
which market prices are not readily available or for which market prices do not represent the value at the time of pricing, are
fair-valued by the investment manager based upon other inputs (including valuations of securities that are comparable in coupon,
rating, maturity and industry). The target asset allocation was 62 percent equity securities and 38 percent debt securities in 2012 and
2011.
The market-related value of other postretirement plan assets was determined as of December 31, 2012 and 2011.
The following table discloses by level within the fair value hierarchy (see Note 15 for a description of the fair value hierarchy) of other
postretirement plan assets measured and reported as of December 31, 2012 at fair value (dollars in thousands):
Cash equivalents
Mutual funds:
Fixed income securities
U.S. equity securities
International equity securities
Total
Level 1 Level 2 Level 3 Total
$ —$ 6$ —$ 6

9,314 — — 9,314

10,266 — — 10,266

5,702 — — 5,702
$ 25,282 $ 6 $ — $ 25,288
The following table discloses by level within the fair value hierarchy (see Note 15 for a description of the fair value hierarchy) of other
postretirement plan assets measured and reported as of December 31, 2011 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Cash equivalents $ — $ 86 $ — $ 86
Mutual funds:
Fixed income securities 8,683 — — 8,683
U.S. equity securities 7,278 — — 7,278
International equity securities 4,766 — — 4,766
U.S. equity securities 1,569 — — 1,569
Other 73 — — 73
Total $ 22,369 A 86 $ — $ 22,455
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point
increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of
December 31, 2012 by $20.8 million and the service and interest cost by $1.4 million. A one-percentage-point decrease in the assumed
health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as of December 31, 2012 by
$16.7 million and the service and interest cost by $1.1 million.
The Company has a salary deferral 40 1(k) plans that is a defined contribution plan and cover substantially all employees. Employees
can make contributions to their respective accounts in the plan on a pre-tax basis up to the maximum amount permitted by law. The
Company matches a portion of the salary deferred by each participant according to the schedule in the plan.
Employer matching contributions were as follows for the years ended December 31 (dollars in thousands):
2012 2011
Employer 401(k) matching contributions $ 5,813 $ 5,452
The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer
until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of
their incentive payments. Deferred compensation funds are held by the Company in a Rabbi Trust. There were deferred compensation
assets and corresponding deferred compensation liabilities on the Balance Sheets of the following amounts as of December 31 (dollars
in thousands):
2012 2011
Deferred compensation assets and liabilities 8,806 $ 8,653
NOTE 9. ACCOUNTING FOR INCOME TAXES
1 FERC FORM NO. 2/3-Q (REV 12-07) 122.18
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) A An Original (Mo, Da, Yr)
(2)_A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards. As of December 31, 2012, the
Company had $13.9 million of state tax credit carryforwards. State tax credits expire from 2015 to 2025. The Company recognizes the
effect of state tax credits generated from utility plant as they are utilized.
The realization of deferred income tax assets is dependent upon the ability to generate taxable income in future periods. The Company
evaluated available evidence supporting the realization of its deferred income tax assets and determined it is more likely than not that
deferred income tax assets will be realized.
The Company and its eligible subsidiaries file consolidated federal income tax returns. The Company also files state income tax returns
in certain jurisdictions, including Idaho, Oregon and Montana. Subsidiaries are charged or credited with the tax effects of their
operations on a stand-alone basis. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2009 and
all issues were resolved related to these years. The IRS has not completed an examination of the Company's 2010 through 2011 federal
income tax returns. The Company does not believe that any open tax years for federal or state income taxes could result in any
adjustments that would be significant to the financial statements.
The Company did not incur any penalties on income tax positions in 2012 or 2011
The Company had net regulatory assets related to the probable recovery of certain deferred income tax liabilities from customers
through future rates as of December 31 (dollars in thousands):
2012 2011
Regulatory assets for deferred income taxes $ 79,406 $ 84,576
NOTE 10. ENERGY PURCHASE CONTRACTS
Avista Corp. has contracts for the purchase of fuel for thermal generation, natural gas for resale and various agreements for the
purchase or exchange of electric energy with other entities. The termination dates of the contracts range from one month to the year
2055. Total expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs were as follows for the years
ended December 31 (dollars in thousands):
2012 2011
Utility power resources $ 523,416 $ 557,619
The following table details Avista Corp.'s future contractual commitments for power resources (including transmission contracts) and
natural gas resources (including transportation contracts) (dollars in thousands):
2013 2014 2015 2016 2017 Thereafter. Total
Power resources $ 196,877 $ 132,378 $ 118,054 $ 117,779 $ 116,580 $ 1,025,941 $ 1,707,609
Natural gas resources 109,406 961092 77,688 60,104 51,950 678,042 1,073,282
Total $ 306,283 $ 228,470 $ 195,742 $ 177,883 $ 168,530 $ 1,703,983 $ 2,780,891
These energy purchase contracts were entered into as part of Avista Corp.'s obligation to serve its retail electric and natural gas
customers' energy requirements. As a result, these costs are recovered either through base retail rates or adjustments to retail rates as
part of the power and natural gas cost deferral and recovery mechanisms.
In addition; Avista Corp. has operational agreements, settlements and other contractual obligations for its generation, transmission and
distribution facilities. The following table details future contractual commitments for these agreements (dollars in thousands):
2013 - 2014 2015 2016 2017 Thereafter Total
Contractual obligations $ 30,913 $ 31,732 $ 29,259 $ 35,844 $ 27,708 $ 230,453 $ 385,909
Avista Corp. has fixed contracts with certain Public Utility Districts (PUD) to purchase portions of the output of certain generating
facilities. Although Avista Corp. has no investment in the PUD generating facilities, the fixed contracts obligate Avista Corp. to pay
certain minimum amounts (based in part on the debt service requirements of the PUD) whether or not the facilities are operating.
I FERC FORM NO. 2/3-Q (REV 12-07) 122.19
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 20121Q4
Notes to Financial Statements
Expenses under these PUD contracts were as follows for the years ended December 31 (dollars in thousands):

2012 2011
PUD contract costs $ 8,436 $ 10,533
Information as of December 31, 2012 pertaining to these PUD contracts is summarized in the following table (dollars in thousands):
Company's Current Share of
Debt
Kilowatt Annual Service Bonds Expiration
Output Costs (1)
Douglas County PUD:
Wells Project 3.4% 24,048 2,716 874 3,117 - 2018
Grant County PUD:
Priest Rapids and
Wanapum Projects 3.3% 65,800 51717 21425 30,655 2055
Totals 89,848 $ 8,433 $ 31299 $ 33,772
(1) The annual costs will change in proportion to the percentage of output allocated to Avista Corp. in a particular year. Amounts
represent the operating costs for 2012. Debt service costs are included in annual costs.
The estimated aggregate amounts of required minimum payments (Avista Corp.'s share of existing debt service costs) under these PUD
contracts are as follows (dollars in thousands):
2013 2014 2015 2016 2017 Thereafter Total
Minimum payments $ 3,348 $ 3,332 $ 3,223 $ 3,222 $ 3,220 $ 42,988 $ 59,333
In addition, Avista Corp. will be required to pay its proportionate share of the variable operating expenses of these projects.
NOTE 11. NOTES PAYABLE
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million with an expiration
date of February 2017.
The committed line of credit is secured by non-transferable First Mortgage Bonds of the Company issued to the agent bank that would
only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the
committed line of credit.
The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant
which does not permit the ratio of "consolidated total debt" to "consolidated total capitalization" of Avista Corp. to be greater than 65
percent at any time. As of December 31, 2012, the Company was in compliance with this covenant.
Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company's revolving committed lines of
credit were as follows as of December 31 (dollars in thousands):

2012 2011
Balance outstanding at end of period $ 52,000 $ 61,000
Letters of credit outstanding at end of period $ 35,885 $ 29,030
Average interest rate at end of period 1.12% 1.12%
NOTE 12. BONDS
The following details bonds outstanding as of December 31 (dollars in thousands):
Maturity Interest
Year Description Rate 2012 2011
2012 Secured Medium-Term Notes 7.37% $ - $ 7,000
2013 First Mortgage Bonds 1.68% 50,000 50,000
I FERC FORM NO. 213-Q (REV 12-07) 122.20
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)XAn Original (Mo, Da, Yr)
(2) A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
2018 First Mortgage Bonds 5.95% 250,000 250,000
2018 Secured Medium-Term Notes 7.39%-7.45% 22,500 22,500
2019 First Mortgage Bonds 5.45% 90,000 90,000
2020 First Mortgage Bonds 3.89% 52,000 52,000
2022 First Mortgage Bonds 5.13% 250,000 250,000
2023 Secured Medium-Term Notes 7.18%-7.54% 13,500 13,500
2028 Secured Medium-Term Notes 6.37% 25,000 25,000
2032 Secured Pollution Control Bonds (1) (1) 66,700 66,700
2034 Secured Pollution Control Bonds (2) (2) 17,000 17,000
2035 First Mortgage Bonds 6.25% 150,000 150,000
2037 First Mortgage Bonds 5.70% 150,000 150,000
2040 First Mortgage Bonds 5.55% 35,000 35,000
2041 First Mortgage Bonds 4.45% 85,000 85,000
2047 First Mortgage Bonds (3) 4.23% 80,000 -
Total secured bonds 1,336,700 1,263,700
2023 Unsecured Pollution Control Bonds 6.00% 4,100
Settled interest rate swaps (27,900) (10,629)
Secured Pollution Control Bonds held by Avista
Corporation (1) (2) (83,700) (83,700)
Total bonds $ 1,225,100 $ 1 117371
(1)In December 2010, $66.7 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista
Corporation Coistrip Project) due 2032, which had been held by Avista Corp. since 2008, were refunded by a new bond issue
(Series 201 OA). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions.
The Company expects that at a later date, subject to market conditions, these bonds may be remarketed to unaffiliated
investors. So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on
Avista Corp.'s Balance Sheet.
(2)In December 2010, $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds, (Avista
Corporation Colstrip Project) due 2034, which had been held by Avista Corp. since 2009, were refunded by a new bond issue
(Series 20 lOB). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions.
The Company expects that at a later date, subject to market conditions, the bonds may be remarketed to unaffiliated investors.
So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s
Balance Sheet.
(3)In November 2012, the Company issued $80.0 million of 4.23 percent First Mortgage Bonds due in 2047.
The following table details future long-term debt maturities including advances from associated companies (see Note 13) (dollars in
thousands):

2013 2014 2015 2016 2017 Thereafter Total
Debt maturities $ 50,000 $ - $ - $ - $ - $ 1,254,547 $ 1,304,547
Substantially all utility properties owned by the Company are subject to the lien of the Company's mortgage indenture. Under the
Mortgage and Deed of Trust securing the Company's First Mortgage Bonds (including Secured Medium-Term Notes), the Company
may issue additional First Mortgage Bonds in an aggregate principal amount equal to the sum of: 1) 66-2/3 percent of the cost or fair
value (whichever is lower) of property additions which have not previously been made the basis of any application under the
Mortgage, or 2) an equal principal amount of retired First Mortgage Bonds which have not previously been made the basis of any
application under the Mortgage, or 3) deposit of cash. However, the Company may not issue any additional First Mortgage Bonds
(with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the Company's "net earnings" (as defined in
the Mortgage) for any period of 12 consecutive calendar months out of the preceding 18 calendar months were at least twice the annual
interest requirements on all mortgage securities at the time outstanding, including the First Mortgage Bonds to be issued, and on all
indebtedness of prior rank. As of December 31, 2012, property additions and retired bonds would have allowed, and the net earnings
test would not have prohibited the issuance of $640.1 million in aggregate principal amount of additional First Mortgage Bonds.
See Note 11 for information regarding First Mortgage Bonds issued to secure the Company's obligations under its committed line of
credit agreement.

FERC FORM NO. 213-Q (REV 12-07) 122.21
Low distribution rate
High distribution rate
Distribution rate at the end of the year
2012 2011
1.19% 1.137T
1.40 1.40
1.19 1.40
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
NOTE 13. ADVANCES FROM ASSOCIATED COMPANIES
In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of
$51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of
Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly. The distribution
rates paid were as follows during the years ended December 31:
Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the
Company. These debt securities may be redeemed at the option of Avista Capital II on or after June 1, 2007 and mature on June 1,
2037. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities.
The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on,
and redemption price and liquidation amount for, the Preferred Trust Securities to the extent that Avista Capital II has funds available
for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust
Securities will be mandatorily redeemed.
NOTE 14. LEASES
The Company has multiple lease arrangements involving various assets, with minimum terms ranging from 1 to forty-five years. Rental
expense under operating leases was as follows for the years ended December 31 (dollars in thousands):

2012 2011
Rental expense $ 3,274 $ 2,853
Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one
year as of December 31 were as follows (dollars in thousands):
2013 2014 2015 2016 2017 Thereafter Total
Minimum payments required $ 1,749 $ 1,517 $ 498 $ 162 $ 148 $ 2,712 $ 6,786
NOTE 15. FAIR VALUE
The carrying values of cash and cash equivalents, special deposits, accounts and notes receivable, accounts payable and notes payable
are reasonable estimates of their fair values. Bonds and advances from associated companies are reported at carrying value on the
Balance Sheets.
The following table sets forth the carrying value and estimated fair value of the Company's financial instruments not reported at
estimated fair value on the Balance Sheets as of December 31 (dollars in thousands):
2012 2011
Carrying Estimated Carrying Estimated
Value Fair Value Value Fair Value
Bonds (Level 2) $ 951,000 $ 1,164,639 $ 962,100 $ 1,135,536
Bonds (Level 3) 302,000 320,892 222,000 234,226
Advances from associated companies (Level 3) 51,547 43,686 51,547 43,810
These estimates of fair value were primarily based on available market information.
The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted
prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3
measurement).
FERC FORM NO. 213-Q (REV 12-07) 12222
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 201 21Q4
Notes to Financial Statements
The three levels of the fair value hierarchy are defined as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which
transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2— Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly
observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation
methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward
prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well
as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term
of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the
marketplace.
Level 3 - Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be
used with internally developed methodologies that result in management's best estimate of fair value.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value
measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and
may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination
of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of
credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.'s nonperformance risk on its
liabilities.
I FERC FORM NO. 213-Q (REV 12-07) 122.23 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
The following table discloses by level within the fair value hierarchy the Company's assets and liabilities measured and reported on the
Balance Sheets as of December 31, 2012 and 2011 at fair value on a recurring basis (dollars in thousands):
Counterparty
and Cash
Collateral
Level I Level 2 Level 3 Netting (1) Total
December 31, 2012
Assets:
Energy commodity derivatives $ - $ 81,640 $ - $ (76,408) $ 5,232
Level 3 energy commodity derivatives:
Power exchange agreements - - 385 (385) -
Foreign currency derivatives - 7 - (7) -
Interest rate swaps - 7,265 - - 7,265
Deferred compensation assets:
Fixed income securities 2,010 - - - 2,010
Equity securities 5,955 - - - 5,955
Total $ 7,965 $ 88,912 $ 385 $ (76,800) $ 20,462
Liabilities:
Energy commodity derivatives $ - $ 119,390 $ - $ (86,115) $ 33,275
Level 3 energy commodity derivatives:
Natural gas exchange agreements - - 2,379 - 2,379
Power exchange agreements - - 19,077 (385) 18,692
Power option agreements - - 1,480 - 1,480
Foreign currency derivatives - 34 - (7) 27
Interest rate swaps - 1,406 - - 1,406
Total $ - $ 120,830 $ 22,936 $ (86,507) $ 57,259
I FERC FORM NO. 213-Q (REV 12-07) 122.24 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)XAn Original (Mo, Da, Yr)
(2)A Resubmission 04/12/2013 20121Q4
Notes to Financial Statements
Counterparty
and Cash
Collateral
Level 1 Level 2 Level 3 Netting (1) Total
December 31, 2011
Assets:
Energy commodity derivatives
Level 3 energy commodity derivatives:
Natural gas exchange agreements
Power exchange agreements
Foreign currency derivatives
Deferred compensation assets:
Fixed income securities
Equity securities
Total
Liabilities:
Energy commodity derivatives
Level 3 energy commodity derivatives:
Natural gas exchange agreements
Power exchange agreements
Power option agreements
Interest rate swaps
Total

80,571 $ - $ (79,247) $ 1,324
- - 956 (956) -
— - 4,674 (4,674) -
- 32 - - 32

2,116 - - - 2,116

5,252 - - - 51252
$ 7,368 $ 80,603 $ 5,630 $ (84,877) $ 81724
$ - $ 177,743 $ - $ (79,247) $ 98,496
- - 2,644 (956) 1,688
- - 14,584 (4,674) 9,910
- - 1,260 - 1,260
- 18,895 - - 18,895
$ - $ 196,638 $ 18,488 $ (84,877) $ 130,249
(1) The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable
master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and
receivables for cash collateral held or placed with these same counterparties.
Avista Corp. enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified
period, in the future. These contracts are entered into as part of Avista Corp.'s management of loads and resources and certain
contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in
respective levels and the amount of derivative assets and liabilities disclosed on the Balance Sheets is due to netting arrangements with
certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of utility derivative
commodity instruments included in Level 2. In particular, electric derivative valuations are performed using broker quotes, adjusted
for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange
(NYMEX) pricing for similar instruments, adjusted for basin differences, using broker quotes. Where observable inputs are available
for substantially the full term of the contract, the derivative asset or liability is included in Level 2.
Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan.
These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table
above excludes cash and cash equivalents of $0.8 million as of December 31, 2012 and $1.3 million as of December 31, 2011.
Level 3 Fair Value
For power exchange agreements, the Company compares the Level 2 brokered quotes and forward price curves described above to an
internally developed forward price which is based on the average operating and maintenance (O&M) charges from four surrogate
nuclear power plants around the country for the current year. Because the nuclear power plant O&M charges are only known for one
year, all forward years are estimated assuming an annual escalation. In addition to the forward price being estimated using
unobservable inputs, the Company also estimates the volumes of the transactions that will take place in the future based on historical
average transaction volumes per delivery year (November to April). Significant increases or decreases in any of these inputs in
isolation would result in a significantly higher or lower fair value measurement. Generally, a change in the current year O&M charges
for the surrogate plants is accompanied by a directionally similar change in O&M charges in future years. There is generally not a
correlation between external market prices and the O&M charges used to develop the internal forward price.
For power commodity option agreements, the Company uses the Black-Scholes Merton valuation model to estimate the fair value, and
.1 FERC FORM NO. 2/3-Q (REV 12-07) 122.25
Name of Respondent This Report is: Date Of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
this model includes significant inputs not observable or corroborated in the market. These inputs include 1) the strike price (which is
an internally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and other
O&M charges, 2) estimated delivery volumes for years beyond 2013, and 3) volatility rates for periods beyond January 2016.
Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value
measurement. Generally, changes in overall commodity market prices and volatility rates are accompanied by directionally similar
changes in the strike price and volatility assumptions used in the calculation.
For natural gas commodity exchange agreements, the Company uses the same Level 2 brokered quotes described above; however, the
Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions.
Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because
the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions
can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based
on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with
market prices and market volatility.
The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities
above as of December 31, 2012 (dollars in thousands):
Fair Value (Net)
at

December 31, Valuation
2012 Technique Unobservable Input Range
Power exchange agreements $ (18,692) Surrogate facility O&M charges $30.49-$53 .82/MWh (1)
pricing

Escalation factor 5% - 2013 to 2015
3% - 2016 to 2019
Transaction volumes 365,619 - 379,156 MWhs
Power option agreements (1,480) Black-Scholes- Strike price $52.61/MWh - 2013
Merton
$76.63/MWh - 2019
Delivery volumes 128,491 - 287,147 MWhs
Volatility rates 0.20(2)
Natural gas exchange (2,379) Internally derived Forward purchase
agreements weighted average prices
cost ofgas $3.19-$3.38/mmBTU
Forward sates prices $3.29 - $4.46/mmBTU
Purchase volumes 135,000 -465,000 mmBTUs
Sales volumes 140,010 - 620,000 mmBTUs
(1)The average O&M charges for 2012 were $40.87 per MWh.
(2)The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.33 for 2012 to 0.21 in January 2016
Avista Corp.'s risk management team and accounting team are responsible for developing the valuation methods described above and
both groups report to the Chief Financial Officer. The valuation methods, the significant inputs, and the resulting fair values described
above are reviewed on at least a quarterly basis by the risk management team and the accounting team to ensure they provide a
reasonable estimate of fair value each reporting period.
I FERC FORM NO. 213-Q (REV 12-07) 122.26 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)_A Resubmission 04112/2013 2012/Q4
Notes to Financial Statements
The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant
unobservable inputs (Level 3) for the years ended December 31 (dollars in thousands):

Natural Gas Power

Exchange Exchange Power Option

Agreements Agreements Total
Year ended December 31, 2012:
Balance as of January 1, 2012 $ (1,688) $ (9,910) $ (1,260) $ (12,858)
Total gains or losses (realized/unrealized):
Included in net income - - - -
Included in other comprehensive income - - -
Included in regulatory assets/liabilities (1) 343 (15,236) (220) (15,113)
Purchases - - -
Issuance - - - -
Settlements (1,034) 6,454 - 5,420
Transfers to/from other categories - - - -
Ending balance as of December 31, 2012 $ (2,379) $ (18,692) $ (1,480) $ (22,551)
Year ended December 31,2011:
Balance asof January l,2011 $ - $ 15,793 $ (2,334) $ 13,459
Total gains or losses (realized/unrealized):
Included in net income - - -
Included in other comprehensive income - - - -
Included in regulatory assets/liabilities (1) 2,621 (28,571) 1,074 (24,876)
Purchases - - - -
Issuance - - - -
Settlements 95 2,868 - 2,963
Transfers from other categories (2) (4,404) - - (4,404)
Ending balance as of December 31, 2011 $ (1,688) $ (9,910) $ (1,260) $ (12,858)
(1)The UTC and the IPUC issued accounting orders authorizing Avista Corp. to offset commodity derivative assets or liabilities
with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and
losses on energy commodity transactions until the period of settlement. The orders provide for Avista Corp. to not recognize
the unrealized gain or loss on utility derivative commodity instruments in the Statements of Income. Realized gains or losses
are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses,
subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in
Washington, the PCA mechanism in Idaho, and periodic general rates cases.
(2)A derivative contract was reclassified from Level 2 to Level 3 during 2011 due to a particular unobservable input becoming
more significant to the fair value measurement. There were not any reclassifications between Level 1 and Level 2. The
Company's policy is to reclassify identified items as of the end of the reporting period.
NOTE 16. COMMON STOCK
The Company has a Direct Stock Purchase and Dividend Reinvestment Plan under which the Company's shareholders may
automatically reinvest their dividends and make optional cash payments for the purchase of the Company's common stock at current
market value.
The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock contained in
the Company's Articles of Incorporation, as amended.
In August 2012, the Company entered into two sales agency agreements under which the Company may sell up to 2,726,390 shares of
its common stock from time to time. As of December 31, 2012, the Company had 1,795,199 shares available to be issued under these
agreements.
I FERC FORM NO. 2/3-Q (REV 12-07) 122.27 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
Shares issued under sales agency agreements were as follows in the year ended December 31:
2012 2011
Shares issued under sales agency agreement 931,191 807,000
The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of
December 31, 2012 and 2011.
NOTE 17. STOCK COMPENSATION PLANS
A vista Corp.
1998 Plan
In 1998, the Company adopted, and shareholders approved, the Long-Term Incentive Plan (1998 Plan). Under the 1998 Plan, certain
key employees, officers and non-employee directors of the Company and its subsidiaries may be granted stock options, stock
appreciation rights, stock awards (including restricted stock) and other stock-based awards and dividend equivalent rights. The
Company has available a maximum of 4.5 million shares of its common stock for grant under the 1998 Plan. As of December 31, 2012,
0.7 million shares were remaining for grant under this plan.
2000 Plan
In 2000, the Company adopted a Non-Officer Employee Long-Term Incentive Plan (2000 Plan), which was not required to be
approved by shareholders. The provisions of the 2000 Plan are essentially the same as those under the 1998 Plan, except for the
exclusion of non-employee directors and executive officers of the Company. The Company has available a maximum of 2.5 million
shares of its common stock for grant under the 2000 Plan. However, the Company currently does not plan to issue any further options
or securities under the 2000 Plan. As of December 31, 2012, 1.9 million shares were remaining for grant under this plan.
Stock Compensation
The Company records compensation cost relating to share-based payment transactions in the financial statements based on the fair
value of the equity or liability instruments issued. The Company recorded stock-based compensation expense (included in other
operating expenses) and income tax benefits in the Statements of Income of the following amounts for the years ended December 31
(dollars in thousands):
2012 2011
Stock-based compensation expense $ 5,792 $ 5,756
Income tax benefits 2,027 2,014
Stock Options
The following summarizes stock options activity under the 1998 Plan and the 2000 Plan for the years ended December 31:
2012 2011
Number of shares under stock options:
Options outstanding at beginning of year
Options granted
Options exercised
Options canceled
Options outstanding and exercisable at end of year
Weighted average exercise price:
Options exercised
Options canceled
Options outstanding and exercisable at end of year
Cash received from options exercised (in thousands)
Intrinsic value of options exercised (in thousands)
Intrinsic value of options outstanding (in thousands)
92,499 201,674
(89,499) (107,575)
- (1,600)
3,000 92,499
$ 10.63 $ 12.25
$ - $ 11.80
$ 12.41 $ 10.69
$ 951 $ 1,318
$ 1,349 $ 1,279
$ 35 $ 1,393
I FERC FORM NO. 2/3-Q (REV 12-07) 122.28 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
- (2)- A Resubmission 04/12/2013 20121Q4
Notes to Financial Statements
Information for options outstanding and exercisable as of December 31, 2012 is as follows:
Weighted Weighted
Average Average
Number Exercise Remaining
Exercise Price prine T ife (in yearc)
$12.41 3,000 12.41 0.35
As of December 31, 2012 and 2011, the Company's stock options were fully vested and expensed.
Restricted Shares
Restricted share awards vest in equal thirds each year over a three-year period and are payable in Avista Corp. common stock at the
end of each year if the service condition is met. In addition to the service condition, the Company must meet a return on equity target
in order for the CEO's restricted shares to vest. During the vesting period, employees are entitled to dividend equivalents which are
paid when dividends on the Company's common stock are declared. Restricted stock is valued at the close of market of the Company's
common stock on the grant date. The weighted average remaining vesting period for the Company's restricted shares outstanding as of
December 31, 2012 was 0.7 years. The following table summarizes restricted stock activity for the years ended December 31:
2012 2011
Unvested shares at beginning of year 93,482 84,134
Shares granted 70,281 50,618
Shares canceled (790) (431)
Shares vested (45,855) (40,839)
Unvested shares at end of year 117,118 93,482
Weighted average fair value at grant date $ 25.83 $ 23.06
Unrecognized compensation expense at end of year (in thousands) $ 1,428 $ 932
Intrinsic value, unvested shares at end of year (in thousands) $ 2,824 $ 2,407
Intrinsic value, shares vested during the year (in thousands) $ 1,173 $ 934
Performance Shares
Performance share awards vest after a period of three years and are payable in cash or Avista Corp. common stock at the end of the
three-year period. Performance share awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain
circumstances, and are subject to meeting specific performance conditions. Based on the attainment of the performance condition, the
amount of cash paid or common stock issued will range from 0 to 150 percent of the performance shares granted for grants prior to
2011 and 0 to 200 percent for grants in 2011 and after, depending on the change in the value of the Company's common stock relative
to an external benchmark. Dividend equivalent rights are accumulated and paid out only on shares that eventually vest.
Performance share awards entitle the grantee to shares of common stock or cash payable once the service condition is satisfied. Based
on attainment of the performance condition, grantees may receive 0 to 150 percent of the original shares granted for grants prior to
2011 and 0 to 200 percent for shares granted in 2011 and after. The performance condition used is the Company's Total Shareholder
Return performance over a three-year period as compared against other utilities; this is considered a market-based condition.
Performance shares may be settled in common stock or cash at the discretion of the Company. Historically, the Company has settled
these awards through issuance of stock and intends to continue this practice. These awards vest at the end of the three-year period.
Performance shares are equity awards with a market-based condition, which results in the compensation cost for these awards being
recognized over the requisite service period, provided that the requisite service period is rendered, regardless of when, if ever, the
market condition is satisfied.
The Company measures (at the grant date) the estimated fair value of performance shares awarded. The fair value of each performance
share award was estimated on the date of grant using a statistical model that incorporates the probability of meeting performance
targets based on historical returns relative to a peer group. Expected volatility was based on the historical volatility of Avista Corp.
common stock over a three-year period. The expected term of the performance shares is three years based on the performance cycle.
The risk-free interest rate was based on the U.S. Treasury yield at the time of grant. The compensation expense on these awards will
only be adjusted for changes in forfeitures.
I FERC FORM NO. 213-0 (REV 12-07) 122.29 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)A An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
The following summarizes the weighted average assumptions used to determine the fair value of performance shares and related
compensation expense as well as the resulting estimated fair value of performance shares granted:
Risk-free interest rate
Expected life, in years
Expected volatility
Dividend yield
Weighted average grant date fair value (per share)
The fair value includes both performance shares and dividend equivalent rights.
The following summarizes performance share activity:
Opening balance of unvested performance shares
Performance shares granted
Performance shares canceled
Performance shares vested
Ending balance of unvested performance shares
Intrinsic value of unvested performance shares (in thousands)
Unrecognized compensation expense (in thousands)
2012 2011
0.3% 1.2%
3 3
22.7% 26.9%
4.5% 4.7%
$ 26.06 $ 20.79
2012 2011

351,345 325,700

181,000 184,600

(4,544) (2,177)

(168,101) (156,778)

359,700 351,345
$ 8,672 $ 9,047
$ 3,800 $ 2,991
The weighted average remaining vesting period for the Company's performance shares outstanding as of December 31, 2012 was 1.5
years. Unrecognized compensation expense as of December 31, 2012 will be recognized during 2013. The following summarizes the
impact of the market condition on the vested performance shares:
2012 2011
Performance shares vested 168,101 156,778
Impact of market condition on shares vested (168,101) (15,678)
Shares of common stock earned - 141,100
Intrinsic value of common stock earned (in thousands) $ - $ 3,633
Shares earned under this plan are distributed to participants in the quarter following vesting.
Outstanding performance share awards include a dividend component that is paid in cash. This component of the performance share
grants is accounted for as a liability award. These liability awards are revalued on a quarterly basis taking into account the number of
awards outstanding, historical dividend rate, and the change in the value of the Company's common stock relative to an external
benchmark. Over the life of these awards, the cumulative amount of compensation expense recognized will match the actual cash paid.
As of December 31, 2012 and 2011, the Company had recognized compensation expense and a liability of $0.7 million and $1.0
million related to the dividend component of performance share grants.
NOTE 18. COMMITMENTS AND CONTINGENCIES
In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters,
including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation
or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and pursue its
rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested
proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Corp.'s operations, the Company intends to
seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.
Federal Energy Regulatory Commission Inquiry
In April 2004, the Federal Energy Regulatory commission (FERC) approved the contested Agreement in Resolution of Section 206
Proceeding (Agreement in Resolution) between Avista Corp., Avista Energy and the FERC's Trial Staff which stated that there was: (1)
no evidence that any executives or employees of Avista Corp. or Avista Energy knowingly engaged in or facilitated any improper
trading strategy during 2000 and 2001; (2) no evidence that Avista Corp. or Avista Energy engaged in any efforts to manipulate the
FERC FORM NO. 213-Q (REV 12-07) 122.30 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 20121Q4
Notes to Financial Statements
western energy markets during 2000 and 2001; and (3) no finding that Avista Corp. or Avista Energy withheld relevant information
from the FERC's inquiry into the western energy markets for 2000 and 2001 (Trading Investigation). The Attorney General of the State
of California (California AG), the California Electricity Oversight Board, and the City of Tacoma, Washington (City of Tacoma)
challenged the FERC's decisions approving the Agreement in Resolution, which are now pending before the United States Court of
Appeals for the Ninth Circuit (Ninth Circuit). In May 2004, the FERC provided notice that Avista Energy was no longer subject to an
investigation reviewing certain bids above $250 per MW in the short-term energy markets operated by the California Independent
System Operator (Ca1ISO) and the California Power Exchange (Ca1PX) from May 1, 2000 to October 2, 2000 (Bidding Investigation).
That matter is also pending before the Ninth Circuit, after the California AG, Pacific Gas & Electric (PG&E), Southern California
Edison Company (SCE) and the California Public Utilities Commission (CPUC) filed petitions for review in 2005.
Based on the FERC's order approving the Agreement in Resolution in the Trading Investigation and order denying rehearing requests,
the Company does not expect that this proceeding will have any material effect on its financial condition, results of operations or cash
flows. Furthermore, based on information currently known to the Company regarding the Bidding Investigation and the fact that the
FERC Staff did not find any evidence of manipulative behavior, the Company does not expect that this matter will have a material
effect on its financial condition, results of operations or cash flows.
California Refund Proceeding
In July 2001, the FERC ordered an evidentiary hearing to determine the amount of refunds due to California energy buyers for
purchases made in the spot markets operated by the CalISO and the CaIPX during the period from October 2, 2000 to June 20, 2001
(Refund Period). Proposed refunds are based on the calculation of mitigated market clearing prices for each hour. The FERC ruled that
if the refunds required by the formula would cause a seller to recover less than its actual costs for the Refund Period, sellers may
document these costs and limit their refund liability commensurately. In September 2005, Avista Energy submitted its cost filing claim
pursuant to the FERC's August 2005 order. The filing was initially accepted by the FERC, but in March 2011, the FERC ordered
Avista Energy to remove any return on equity in a compliance filing with the CalISO, which Avista Energy did in April 2011. A
challenge to Avista Energy's cost filing by the California AG, the CPUC, PG&E and SCE was denied in July 2011 as a collateral attack
on the FERC's prior orders accepting Avista Energy's cost filing. In July 2011, the California AG, the CPUC, PG&E and SCE filed a
petition for review of the FERC's orders regarding Avista Energy's cost filing with the Ninth Circuit.
The 2001 bankruptcy of PG&E resulted in a default on its payment obligations to the CaIPX. As a result, Avista Energy has not been
paid for all of its energy sales during the Refund Period. Those funds are now in escrow accounts and will not be released until the
FERC issues an order directing such release in the California refund proceeding. The CalISO continues to work on its compliance
filing for the Refund Period, which will show "who owes what to whom." In July 2011, the FERC accepted the preparatory rerun
compliance filings by the Ca1PX and CalISO, and responded to the Ca1PX request for guidance on issues related to completing the
final determination of "who owes what to whom." The FERC directed both the Ca1ISO and the Ca1PX to prepare and submit to the
FERC their final refund rerun compliance filings. The FERC's order also directs the CaIPX to pay past due principal amounts to
governmental entities. In February 2012, the FERC denied the challenges made to the July 2011 order by the California AG, the
CPUC, PG&E and SCE. As of September 30, 2012, Avista Energy's accounts receivable outstanding related to defaulting parties in
California were fully offset by reserves for uncollected amounts and funds collected from the defaulting parties.
In August 2006, the Ninth Circuit upheld October 2, 2000 as the refund effective date for the FPA section 206 refund proceeding, but
remanded to the FERC its decision not to consider an FPA section 309 remedy for tariff violations prior to that date. In an order issued
in May 2011, the FERC clarified the issues set for hearing for the period May 1, 2000 - October 1, 2000 (Summer Period): (1) which
market practices and behaviors constitute a violation of the then-current CalISO, Ca1PX, and individual seller's tariffs and FERC
orders; (2) whether any of the sellers named as respondents in this proceeding engaged in those tariff violations; and (3) whether any
such tariff violations affected the market clearing price. The FERC reiterated that the California Parties are expected to be very
specific when presenting their arguments and evidence, and that general claims would not suffice. The FERC also gave the California
Parties an opportunity to show that exchange transactions with the CalISO during the Refund Period were not just and reasonable.
Avista Energy has one exchange transaction with the Ca1ISO. The California AG, the CPUC, PG&E and SCE filed for rehearing of the
FERC's May 2011 order, arguing that it improperly denies them a market-wide remedy for the pre-refund period. That request for
rehearing was denied in an order issued by FERC on November 2, 2012. The California AG, the CPUC, PG&E and SCE filed a
petition for review of the May 2011 and November 2012 orders with the Ninth Circuit on November 7, 2012.
A FERC hearing commenced on April 11, 2012 and concluded on July 19, 2012. On August 27, 2012, the Presiding Administrative
Law Judge issued a partial initial decision granting Avista Corp.'s motion for summary disposition, based on the stipulation by the
FERC FORM NO. 213-0 (REV 12-07) 122.31
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da,Yr)
(2) _A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
California Parties that there are no allegations of tariff violations made against Avista Corp. in this proceeding and therefore no tariff
violations by Avista Corp. that affected the market clearing price in any hour during the Summer Period. On November 2, 2012, FERC
issued an order affirming the partial initial decision and dismissing Avista Corp. from the proceeding, thereby terminating all claims
against Avista Corp. for the Summer Period. In the same order, FERC also held that a market-wide remedy would not be appropriate
with regard to any respondent during the Summer Period. FERC stated that it is clear that the Ninth Circuit did not mandate a specific
remedy on remand and, instead, left it to the FERC's discretion to determine which remedy would be appropriate. On December 3,
2012, the California Parties filed a request for clarification and rehearing of the November 2, 2012 order. On February 15, 2013, the
Administrative Law Judge issued an initial decision finding that certain Respondents committed various tariff and other violations that
affected the market clearing price in the California organized markets during the Summer Period. The tariff violations identified for
Avista Energy are type II and III bidding violations; false export violations; and selling ancillary services without market-based rate
authority. The initial decision did not discuss evidence offered by Avista Energy, on an hour by hour basis, rebutting the alleged
violations and Avista Energy is currently preparing briefs on exceptions which will identify these errors. With respect to Avista
Energy's one exchange transaction with the Ca1ISO during the Refund Period, the judge made no findings with respect to the justness
and reasonableness of that transaction, but nonetheless determined that Avista Energy owed approximately $0.2 million in refunds with
regard to the transaction.
Because the resolution of the California refund proceeding remains uncertain, legal counsel cannot express an opinion on the extent of
the Company's liability, if any. However, based on information currently known, the Company does not expect that the refunds
ultimately ordered for the Refund Period would result in a material loss. In the event that the Commission does not overturn the legal
and factual errors in the February 15, 2013 initial decision, the Company does not expect that the refunds ultimately ordered for that
period would result in a material loss either. This is primarily due to the fact that the FERC orders have stated that any refunds will be
netted against unpaid amounts owed to the respective parties and the Company does not believe that refunds would exceed unpaid
amounts owed to the Company.
Pacific Northwest Refund Proceeding
In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market
sales of wholesale energy in the Pacific Northwest between December 25, 2000 and June 20, 2001 were just and reasonable. In June
2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of
refunds. In August 2007, the Ninth Circuit found that the FERC, in denying the request for refunds, had failed to take into account new
evidence of market manipulation in the California energy market and its potential ties to the Pacific Northwest energy market and that
such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC's findings must be
reevaluated in light of the evidence. In addition, the Ninth Circuit concluded that the FERC abused its discretion in denying potential
relief for transactions involving energy that was purchased by the California Energy Resources Scheduling (CERS) in the Pacific
Northwest and ultimately consumed in California. The Ninth Circuit expressly declined to direct the FERC to grant refunds. The Ninth
Circuit denied petitions for rehearing by various parties, and remanded the case to the FERC in April 2009.
On October 3, 2011, the FERC issued an Order on Remand, finding that, in light of the Ninth Circuit's remand order, additional
procedures are needed to address possible unlawful activity that may have influenced prices in the Pacific Northwest spot market
during the period from December 25, 2000 through June 20, 2001. The Order establishes an evidentiary, trial-type hearing before an
Administrative Law Judge (AU), and reopens the record to permit parties to present evidence of unlawful market activity during the
relevant period. The Order also allows participants to supplement the record with additional evidence on CERS transactions in the
Pacific Northwest spot market from January 18, 2001 to June 20, 2001. The Order states that parties seeking refunds must submit
evidence demonstrating that specific unlawful market activity occurred, and must demonstrate that such activity directly affected
negotiations with respect to the specific contract rate about which they complain. Simply alleging a general link between the
dysfunctional spot market in California and the Pacific Northwest spot market will not be sufficient to establish a causal connection
between a particular seller's alleged unlawful activities and the specific contract negotiations at issue. Claimants filed notice of their
claims on August 17, 2012, and they filed their direct testimony on September 21, 2012. Respondents' filed their answering testimony
on December 17, 2012 and staff filed its answering testimony on February 5, 2013. Respondents' cross-answering testimony is due
February 22, 2013 and claimants' rebuttal testimony is due March 12, 2013. The hearing is scheduled to begin on April 15, 2013. On
July 11, 2012, Avista Energy and Avista Corp. filed settlements of all issues in this docket with regard to the claims made by the City
of Tacoma. On September 21, 2012, and September 26, 2012, the FERC issued orders approving the settlements between the City of
Tacoma and Avista Corp. and Avista Energy, respectively, thus terminating those claims. The two remaining direct claimants against
Avista Corp. and Avista Energy in this proceeding are the City of Seattle, Washington, and the California Attorney General (on behalf
of CERS).
I FERC FORM NO. 2/3-Q (REV 12-07) 122.32
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
Both Avista Corp. and Avista Energy were buyers and sellers of energy in the Pacific Northwest energy market during the period
between December 25, 2000 and June 20, 2001 and, are subject to potential claims in this proceeding, and if refunds are ordered by the
FERC with regard to any particular contract, could be liable to make payments. The Company cannot predict the outcome of this
proceeding or the amount of any refunds that Avista Corp. or Avista Energy could be ordered to make. Therefore, the Company cannot
predict the potential impact the outcome of this matter could ultimately have on the Company's results of operations, financial
condition or cash flows.
California Attorney General Complaint (the "Lockyer Complaint")
In May 2002, the FERC conditionally dismissed a complaint filed in March 2002 by the California AG that alleged violations of the
FPA by the FERC and all sellers (including Avista Corp. and its subsidiaries) of electric power and energy into California. The
complaint alleged that the FERC's adoption and implementation of market-based rate authority was flawed and, as a result, individual
sellers should refund the difference between the rate charged and a just and reasonable rate. In May 2002, the FERC issued an order
dismissing the complaint. In September 2004, the Ninth Circuit upheld the FERC's market-based rate authority, but held that the FERC
erred in ruling that it lacked authority to order refunds for violations of its reporting requirement. The Court remanded the case for
further proceedings.
In March 2008, the FERC issued an order establishing a trial-type hearing to address "whether any individual public utility seller's
violation of the FERC's market-based rate quarterly reporting requirement led to an unjust and unreasonable rate for that particular
seller in California during the 2000-2001 period." Purchasers in the California markets were given the opportunity to present evidence
that "any seller that violated the quarterly reporting requirement failed to disclose an increased market share sufficient to give it the
ability to exercise market power and thus cause its market-based rates to be unjust and unreasonable." In March 2010, the Presiding
ALJ granted the motions for summary disposition and found that a hearing was "unnecessary" because the California AG, CPUC,
PG&E and SCE "failed to apply the appropriate test to determine market power during the relevant time period." The judge
determined that "[w]ithout a proper showing of market power, the California Parties failed to establish a prima facie case." In May
2011, the FERC affirmed "in all respects" the AL's decision. In June 2011, the California AG, CPUC, PG&E and SCE filed for
rehearing of that order. Those rehearing requests were denied by the FERC on June 13, 2012. On June 20, 2012, the California AG,
CPUC, PG&E and SCE filed a petition for review of the FERC's order with the Ninth Circuit. On February 6, 2013, the California AG,
CPUC, PG&E, and SCE filed an unopposed motion with the Ninth Circuit, requesting that a briefing schedule be established, such that
petitioners' joint opening brief would be due May 17, 2013; respondents' answering brief would be due July 16, 2013;
respondent-intervenors' joint brief would be due August 6, 2013; and petitioners' optional joint reply brief would be due September 10,
2013.
Based on information currently known to the Company's management, the Company does not expect that this matter will have a
material effect on its financial condition, results of operations or cash flows.
Coistrip Generating Project Complaint
In March 2007, two families that own property near the holding ponds from Units 3 & 4 of the Colstrip Generating Project (Colstrip)
filed a complaint against the owners of Colstrip and Hydrometrics, Inc. in Montana District Court. Avista Corp. owns a 15 percent
interest in Units 3 & 4 of Coistrip. The plaintiffs alleged that the holding ponds and remediation activities adversely impacted their
property. They alleged contamination, decrease in water tables, reduced flow of streams on their property and other similar impacts to
their property. They also sought punitive damages, attorney's fees, an order by the court to remove certain ponds, and the forfeiture of
profits earned from the generation of Colstrip. In September 2010, the owners of Colstrip filed a motion with the court to enforce a
settlement agreement that would resolve all issues between the parties. In October 2011 the court issued an order which enforces the
settlement agreement. The plaintiffs subsequently appealed the court's decision and, on December 31, 2012, the Montana Supreme
Court issued its decision, holding that the District Court properly granted the motion to enforce the settlement agreement. A petition
for rehearing before the Supreme Court was denied on February 5, 2013. Under the settlement, Avista Corp.'s portion of payment
(which was accrued in 20 10) to the plaintiffs was not material to its financial condition, results of operations or cash flows.
Sierra Club and Montana Environmental Information Center Notice
On July 30, 2012, Avista Corp. received a Notice of Intent to Sue for violations of the Clean Air Act at Coistrip Steam Electric Station
(Notice) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (TvIEIC), an Amended Notice
was received on September 4, 2012, and a Second Amended Notice was received on October 1, 2012. A "supplemental" Notice was
received on December 4, 2012. The Notice, Amended Notice, Second Amended Notice and Supplemental Notice were all addressed to
I FERC FORM NO. 213-Q (REV 12-07) 122.33
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)_A Resubmission 04/12/2013 20121Q4
Notes to Financial Statements
the Owner or Managing Agent of Coistrip, and to the other Colstrip co-owners: PPL Montana, Puget Sound Energy, Portland General
Electric Company, NorthWestern Energy and PacifiCorp. The Notice alleges certain violations of the Clean Air Act, including the
New Source Review, Title V and opacity requirements. The Amended Notice alleges additional opacity violations at Colstrip, and the
Second Amended Notice alleges additional Title V allegations. All three notices state that Sierra Club and MEIC will request a United
States District Court to impose injunctive relief and civil penalties, require a beneficial environmental project in the areas affected by
the alleged air pollution and require reimbursement of Sierra Club's and MEIC's costs of litigation and attorney's fees. Under the Clean
Air Act, lawsuits cannot be filed until 60 days after the applicable notice date. Avista Corp. is evaluating the allegations set forth in the
Notice, Amended Notice and Second Amended Notice and Supplemental Notice, and cannot at this time predict the outcome of this
matter.
Harbor Oil Inc. Site
Avista Corp. used Harbor Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB transformer oil in the late 1980s and early
1990s. In June 2005, the Environmental Protection Agency (EPA) Region 10 provided notification to Avista Corp. and several other
parties, as customers of Harbor Oil, that the EPA had determined that hazardous substances were released at the Harbor Oil site in
Portland, Oregon and that Avista Corp. and several other parties may be liable for investigation and cleanup of the site under the
Comprehensive Environmental Response, Compensation, and Liability Act, commonly referred to as the federal "Superfund" law,
which provides for joint and several liability. The initial indication from the EPA is that the site may be contaminated with PCBs,
petroleum hydrocarbons, chlorinated solvents and heavy metals. Six potentially responsible parties, including Avista Corp., signed an
Administrative Order on Consent with the EPA on May 31, 2007 to conduct a remedial investigation and feasibility study (RI/FS). The
draft final RI/FS was submitted to the EPA in December 2011 and was accepted as pre-final in March 2012. The EPA issued a notice
of its plan to make a finding of No Further Action in November 2012. Should the EPA make a No Further Action determination, the
EPA stated it would then propose removal of the site from the National Priority List. Based on the review of its records related to
Harbor Oil, the Company does not believe it is a significant contributor to this potential environmental contamination based on the
small volume of waste oil it delivered to the Harbor Oil site. As such, the Company does not expect that this matter will have a material
effect on its financial condition, results of operations or cash flows. The Company has expensed its share of the R1/FS ($0.5 million)
for this matter.
Spokane River Licensing
The Company owns and operates six hydroelectric plants on the Spokane River. Five of these (Long Lake, Nine Mile, Upper Falls,
Monroe Street, and Post Falls) are regulated under one 50-year FERC license issued in June 2009 and are referred to as the Spokane
River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. The license
incorporated the 4(e) conditions that were included in the December 2008 Settlement Agreement with the United States Department of
Interior and the Coeur d'Alene Tribe, as well as the mandatory conditions that were agreed to in the Idaho 401 Water Quality
Certifications and in the amended Washington 401 Water Quality Certification.
As part of the Settlement Agreement with the Washington Department of Ecology (Ecology), the Company has participated in the
Total Maximum Daily Load (TMDL) process for the Spokane River and Lake Spokane, the reservoir created by Long Lake Dam. On
May 20, 2010, the EPA approved the TMDL and on May 27, 2010, Ecology filed an amended 401 Water Quality Certification with
the FERC for inclusion into the license. The amended 401 Water Quality Certification includes the Company's level of responsibility,
as defined in the TMDL, for low dissolved oxygen levels in Lake Spokane. The Company submitted a draft Water Quality Attainment
Plan for Dissolved Oxygen to Ecology in May 2012 and this was approved by Ecology in September 2012. This plan was subsequently
approved by the FERC. The Company will begin to implement this plan, and management believes costs will not be material. On July
16, 2010, the City of Post Falls and the Hayden Area Regional Sewer Board filed an appeal with the United States District Court for
the District of Idaho with respect to the EPA's approval of the TMDL. The Company, the City of Coeur d'Alene, Kaiser Aluminum and
the Spokane River Keeper subsequently moved to intervene in the appeal. In September 2011, the EPA Issued a stay to the litigation
that will be in effect until either the permits are issued and all appeals and challenges are complete or the court lifts the stay. The stay is
still in effect.
The IPUC and the UTC approved the recovery of licensing costs through the general rate case settlements in 2009. The Company will
continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to implementing the license for
the Spokane River Project.
Cabinet Gorge Total Dissolved Gas Abatement Plan
FERC FORM NO. 213-Q (REV 12-07) 122.34 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)XAn Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
Dissolved atmospheric gas levels in the Clark Fork River exceed state of Idaho and federal water quality standards downstream of the
Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) during periods when excess river flows must be diverted over the
spillway. Under the terms of the Clark Fork Settlement Agreement as incorporated in Avista Corp.'s FERC license for the Clark Fork
Project, Avista Corp. has worked in consultation with agencies, tribes and other stakeholders to address this issue. In the second
quarter of 2011, the Company completed preliminary feasibility assessments for several alternative abatement measures. In 2012,
Avista Corp., with the approval of the Clark Fork Management Committee (created under the Clark Fork Settlement Agreement),
moved forward to test one of the alternatives by constructing a spill crest modification on a single spill gate. The modification will be
tested in 2013 to evaluate whether this approach will provide significant TDG reduction, and whether it could be applied to other spill
gates. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to
this issue.
Fish Passage at Cabinet Gorge and Noxon Rapids
In 1999, the USFWS listed bull trout as threatened under the Endangered Species Act. The Clark Fork Settlement Agreement describes
programs intended to help restore bull trout populations in the project area. Using the concept of adaptive management and working
closely with the USFWS, the Company evaluated the feasibility of fish passage at Cabinet Gorge and Noxon Rapids. The results of
these studies led, in part, to the decision to move forward with development of permanent facilities, among other bull trout
enhancement efforts. As of the end of 2012, fishway design for Cabinet Gorge was still being finalized. Construction cost estimates
and schedules will be developed in 2013. Fishway design for Noxon Rapids has also been initiated, and is still in early stages.
In January 2010, the USFWS revised its 2005 designation of critical habitat for the bull trout to include the lower Clark Fork River as
critical habitat. The Company believes its ongoing efforts through the Clark Fork Settlement Agreement continue to effectively address
issues related to bull trout. The Company will continue to seek recovery, through the ratemaking process, of all operating and
capitalized costs related to fish passage at Cabinet Gorge and Noxon Rapids.
Aluminum Recycling Site
In October 2009, the Company (through its subsidiary Pentzer Venture Holdings II, Inc. (Pentzer)) received notice from Ecology
proposing to find Pentzer liable for a release of hazardous substances under the Model Toxics Control Act, under Washington state
law. Pentzer owns property that adjoins land owned by the Union Pacific Railroad (UPR). UPR leased their property to operators of a
facility designated by Ecology as "Aluminum Recycling - Trentwood." Operators of the UPR property maintained piles of aluminum
dross, which designate as a state-only dangerous waste in Washington State. In the course of its business, the operators placed a
portion of the aluminum dross pile on the property owned by Pentzer. Pentzer does not believe it is a contributor to any environmental
contamination associated with the dross pile, and submitted a response to Ecology's proposed findings in November 2009. In
December 2009, Pentzer received notice from Ecology that it had been designated as a potentially liable party for any hazardous
substances located on this site. UPR completed a Remedial Investigation/Feasibility Study during 2011, which was approved by
Ecology in 2012. Based on information currently known to the Company's management, the Company does not expect this issue will
have a material effect on its financial condition, results of operations or cash flows.
Collective Bargaining Agreements
The Company's collective bargaining agreement with the International Brotherhood of Electrical Workers represents approximately 45
percent of all of Avista Corp.'s employees. The agreement with the local union in Washington and Idaho representing the majority
(approximately 90 percent) of the bargaining unit employees expires in March 2014. Two local agreements in Oregon, which cover
approximately 50 employees, expire in March 2014.
Other Contingencies
In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company
believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of
operations or cash flows. It is possible that a change could occur in the Company's estimates of the probability or amount of a liability
being incurred. Such a change, should it occur, could be significant.
The Company routinely assesses, based on studies, expert analyses and legal reviews, its contingencies, obligations and commitments
for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties
who either have or have not agreed to a settlement as well as recoveries from insurance carriers. The Company's policy is to accrue
and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation,
I FERC FORM NO. 213-Q (REV 12-07) 122.35
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/04
Notes to Financial Statements
cleanup and monitoring costs to be incurred. For matters that affect Avista Corp.'s operations, the Company seeks, to the extent
appropriate, recovery of incurred costs through the ratemaking process.
The Company has potential liabilities under the Endangered Species Act for species of fish that have either already been added to the
endangered species list, listed as "threatened" or petitioned for listing. Thus far, measures adopted and implemented have had minimal
impact on the Company. However, the Company will continue to seek recovery, through the ratemaking process, of all operating and
capitalized costs related to this issue.
Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights.
The state of Montana is examining the status of all water right claims within state boundaries. Claims within the Clark Fork River basin
could adversely affect the energy production of the Company's Cabinet Gorge and Noxon Rapids hydroelectric facilities. The state of
Idaho has initiated adjudication in northern Idaho, which will ultimately include the lower Clark Fork River, the Spokane River and the
Coeur d'Alene basin. In addition, the state of Washington has indicated an interest in initiating adjudication for the Spokane River
basin in the next several years. The Company is and will continue to be a participant in these adjudication processes. The complexity
of such adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to
estimate the impact of any outcome at this time.
NOTE 19. INFORMATION SERVICES CONTRACTS
The Company has information services contracts that expire at various times through 2018. The largest of these contracts provides for
increases due to changes in the cost of living index and further provides flexibility in the annual obligation from year-to-year subject to
a three-year true-up cycle. Total payments under these contracts were as follows for the years ended December 31 (dollars in
thousands):
2012 2011
Information service contract payments 13,221 $ 13,038
The majority of the costs are included in other operating expenses in the Statements of Income. The following table details minimum
future contractual commitments for these agreements (dollars in thousands):
2013 2014 2015 2016 2017 Thereafter Total
Contractual obligations $ 11,175 $ 9,400 $ 8,700 $ 8,700 $ 8,600 $ 900 $ 47,475
I FERC FORM NO. 213-0 (REV 12-07) 122.36 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 20121Q4
Notes to Financial Statements
NOTE 20. REGULATORY MATTERS
Power Cost Deferrals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge on the Balance Sheets for future prudence review and recovery through
retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista
Corp. and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in:
short-term wholesale market prices and sales and purchase volumes,
the level of hydroelectric generation,
the level of thermal generation (including changes in fuel prices), and
. retail loads.
In Washington, the Energy Recovery Mechanism (ERM) allows Avista Corp. to periodically increase or decrease electric rates with
UTC approval to reflect changes in power supply costs. The ERIvI is an accounting method used to track certain differences between
actual net power supply costs, net of the margin on wholesale sales and sales of fuel, and the amount included in base retail rates for
Washington customers. In the 2010 Washington general rate case settlement, the parties agreed that there would be no deferrals under
the ERM for 2010. Deferrals under the ERM resumed in 2011. Total net deferred power costs under the ERM were a liability of $22.2
million as of December 31, 2012, and this balance represents the customer portion of the deferred power costs. As part of the approved
Washington general rate case settlement filed on October 19, 2012 and approved on December 26, 2012, during 2013 a one-year credit
of $4.4 million would be returned to electric customers from the existing ERM deferral balance so the net average electric rate increase
to customers in 2013 would be 2.0 percent. Additionally, during 2014 a one-year credit of $9.0 million would be returned to electric
customers from the then-existing ERM deferral balance, if such funds are available, so the net average electric rate increase to
customers effective January 1, 2014 would be 2.0 percent. The credits to customers from the ERM balances would not impact the
Company's net income.
Under the ERM, the Company absorbs the cost or receives the benefit from the initial amount of power supply costs in excess of or
below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0
million. The Company will incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. The
Company shares annual power supply cost variances between $4.0 million and $10.0 million with its customers. There is a 50 percent
customers/50 percent Company sharing ratio when actual power supply expenses are higher (surcharge to customers) than the amount
included in base retail rates within this band. There is a 75 percent customers/25 percent Company sharing ratio when actual power
supply expenses are lower (rebate to customers) than the amount included in base retail rates within this band. To the extent that the
annual power supply cost variance from the amount included in base rates exceeds $10.0 million, 90 percent of the cost variance is
deferred for future surcharge or rebate. The Company absorbs or receives the benefit in power supply costs of the remaining 10 percent
of the annual variance beyond $10.0 million without affecting current or future customer rates.
The following is a summary of the ERM:
Deferred for Future
Surcharge or Rebate Expense or Benefit
Annual Power Supply Cost Variability to Customers
within +1- $0 to $4 million (deadband) 0% 100%
higher by $4 million to $10 million 50% 50%
lower by $4 million to $10 million 75% 25%
higher or lower by over $10 million 90% 10%
As part of the 2012 Washington general rate case settlement, the proposed modifications to the ERM deadband and other sharing
bands that were included in the original April 2012 general rate case filing were not agreed to and the ERM will continue unchanged.
However, the trigger point at which rates will change under the ERM was modified to be $30 million rather than the current 10 percent
of base revenues (approximately $45 million) under the mechanism.
Avista Corp. has a Power Cost Adjustment (PCA) mechanism in Idaho that allows it to modify electric rates on October 1 of each year
with Idaho Public Utilities Commission (IPUC) approval. Under the PCA mechanism, Avista Corp. defers 90 percent of the difference
between certain actual net power supply expenses and the amount included in base retail rates for its Idaho customers. These annual
I FERC FORM NO. 213-0 (REV 12-07) 122.37
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)A An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. Total net
power supply costs deferred under the PCA mechanism were a regulatory liability of $5.1 million as of December 31, 2012 and $0.7
million as of December 31, 2011.
Natural Gas Cost Deferrals and Recovery Mechanisms
Avista Corp. files a purchased gas cost adjustment (PGA) in all three states it serves to adjust natural gas rates for: 1) estimated
commodity and pipeline transportation costs to serve natural gas customers for the coming year, and 2) the difference between actual
and estimated commodity and transportation costs for the prior year. These annual PGA filings in Washington and Idaho provide for
the deferral, and recovery or refund, of 100 percent of the difference between actual and estimated commodity and pipeline
transportation costs, subject to applicable regulatory review. The annual PGA filing in Oregon provides for deferral, and recovery or
refund, of 100 percent of the difference between actual and estimated pipeline transportation costs and commodity costs that are fixed
through hedge transactions. Commodity costs that are not hedged for Oregon customers are subject to a sharing mechanism whereby
Avista Corp. defers, and recovers or refunds, 90 percent of the difference between these actual and estimated costs. Total net deferred
natural gas costs to be refunded to customers were a liability of $6.9 million as of December 31, 2012 and $12.1 million as of
December 31, 2011.
Washington General Rate Cases
In December 2011, the UTC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in May
2011. As agreed to in the settlement agreement, base electric rates for the Company's Washington customers increased by an average
of 4.6 percent, which is designed to increase annual revenues by $20.0 million. Base natural gas rates for the Company's Washington
customers increased by an average of 2.4 percent, which is designed to increase annual revenues by $3.75 million. The new electric
and natural gas rates became effective on January 1, 2012.
As part of the settlement agreement, the Company agreed to not file a general rate case in Washington prior to April 1, 2012.
The settlement agreement also provides for the deferral of certain generation plant maintenance costs. In order to address the
variability in year-to-year maintenance costs, beginning in 2011, the Company is deferring changes in maintenance costs related to its
Coyote Spring 2 natural gas-fired generation plant and its 15 percent ownership interest in Units 3 & 4 of the Colstrip generation plant.
The Company compares actual, non-fuel, maintenance expenses for the Coyote Springs 2 and Colstrip plants with the amount of
baseline maintenance expenses used to establish base retail rates, and defers the difference. The deferral occurred annually, with no
carrying charge, with deferred costs being amortized over a four-year period, beginning in January of the year following the period
costs are deferred. The amount of expense to be requested for recovery in future general rate cases would be the actual maintenance
expense recorded in the test period, less any amount deferred during the test period, plus the amortization of previously deferred costs.
Total net deferred costs under this mechanism in Washington were a regulatory asset of $4.0 million as of December 31, 2012
compared to a regulatory liability of $0.5 million as of December 31, 2011.
As part of the settlement agreement in October 2012 to the Company's latest general rate case discussed in further detail below, the
parties have agreed that the maintenance cost deferral mechanism on these generation plants will terminate on December 31, 2012,
with the four-year amortization of the 2011 and 2012 deferrals to conclude in 2015 and 2016, respectively.
In December 2012, the UTC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in
April 2012. As agreed to in the settlement, effective January 1, 2013, base rates for Washington electric customers increased by an
overall 3.0 percent (designed to increase annual revenues by $13.6 million), and base rates for Washington natural gas customers
increased by an overall 3.6 percent (designed to increase annual revenues by $5.3 million). The settling parties agree that a one-year
credit of $4.4 million will be returned to electric customers from the existing ERM deferral balance so the net average electric rate
increase impact to the Company's customers in 2013 will be 2.0 percent. The credit to customers from the ERM balance will not
impact the Company's earnings.
The settlement also provided that, effective January 1, 2014, the Company will implement temporary base rate increases for
Washington electric customers by an overall 3.0 percent (designed to increase annual revenues by $14.0 million), and for Washington
natural gas customers by an overall 0.9 percent (designed to increase annual revenues by $1.4 million). The settling parties agree that a
one-year credit of $9.0 million will be returned to electric customers from the then-existing ERM deferral balance, if such funds are
available, so the net average electric rate increase to customers effective January 1, 2014 would be 2.0 percent. The credit to customers
FERC FORM NO. 213-Q (REV 12-07) 122.38 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
from the ERM balance will not impact the Company's earnings.
The UTC order approving the settlement agreement included certain conditions. The new retail rates to become effective January 1,
2014 will be temporary rates, and on January 1, 2015 electric and natural gas base rates will revert back to 2013 levels absent any
intervening action from the UTC. The settlement agreement also states that the Company will not file a general rate case in
Washington that would cause an increase in base retail rates before January 1, 2015. The Company could, however, make a filing prior
to January 2015, but new rates resulting from the filing would not take effect prior to January 1, 2015. This does not preclude the
Company from filing annual rate adjustments such as the PGA.
In addition, in its Order, the UTC found that much of the approved base rate increases are justified by the planned capital expenditures
necessary to upgrade and maintain the Company's utility facilities. If these capital projects are not completed to a level that was
contemplated in the original settlement agreement, this could result in base rates which are considered too high by the UTC. As a
result, Avista Corp. must file capital expenditure progress reports with the UTC on a periodic basis so that the UTC can monitor the
capital expenditures and ensure they are in line with those contemplated in the settlement agreement.
The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 47.0 percent, resulting in an
overall return on rate base of 7.64 percent.
Idaho General Rate Cases
In September 2011, the IPUC approved a settlement agreement in the Company's general rate case filed in July 2011. The new electric
and natural gas rates became effective on October 1, 2011. As agreed to in the settlement agreement, base electric rates for the
Company's Idaho customers increased by an average of 1.1 percent, which was designed to increase annual revenues by $2.8 million.
Base natural gas rates for the Company's Idaho customers increased by an average of 1.6 percent, which was designed to increase
annual revenues by $1.1 million.
As part of the settlement agreement, the Company agreed to not seek to make effective a change in base electric or natural gas rates
prior to April 1, 2013, by means of a general rate case filing. This does not preclude the Company from filing annual rate adjustments
such as the PCA and the PGA.
The settlement agreement also provides for the deferral of certain generation plant operation and maintenance costs. In order to address
the variability in year-to-year operation and maintenance costs, beginning in 2011, the Company is deferring changes in operation and
maintenance costs related to the Coyote Spring 2 natural gas-fired generation plant and its 15 percent ownership interest in Units 3 & 4
of the Coistrip generation plant. The Company compares actual, non-fuel, operation and maintenance expenses for the Coyote Springs
2 and Colstrip plants with the amount of expenses authorized for recovery in base rates in the applicable deferral year, and defers the
difference from that currently authorized. The deferral occurs annually, with no carrying charge, with deferred costs being amortized
over a three-year period, beginning in January of the year following the period costs are deferred. The amount of expense to be
requested for recovery in future general rate cases will be the actual operation and maintenance expense recorded in the test period,
less any amount deferred during the test period, plus the amortization of previously deferred costs. Total net deferred costs under this
mechanism in Idaho were regulatory assets of $2.3 million as of December 31, 2012 and $0.1 million as of December 31, 2011.
On October 11, 2012, the Company filed electric and natural gas general rate cases with the IPUC. The Company requested an overall
increase in electric rates of 4.6 percent and an overall increase in natural gas rates of 7.2 percent. The filings were designed to increase
annual electric revenues by $11.4 million and increase annual natural gas revenues by $4.6 million. The Company's requests were
based on a proposed overall rate of return of 8.46 percent, with a common equity ratio of 50 percent and a 10.9 percent return on
equity.
On February 6, 2013, Avista Corp. and certain other parties filed a settlement agreement with the IPUC with respect to Avista Corp.'s
electric and natural gas general rate cases. Parties to the settlement agreement include the staff of the IPUC, Clearwater Paper
Corporation, Idaho Forest Group, LLC, the Idaho Conservation League, and the Company. Community Action Partnership Association
of Idaho (CAPAI), a low-income customer advocacy group, and the Snake River Alliance did not join in the settlement agreement.
However, on February 20, 2013 the Snake River Alliance provided a letter to the IPUC supporting the settlement agreement. This
settlement agreement is subject to approval by the IPUC and would conclude the proceedings related the general rate requests filed by
the Company on October 11, 2012. New rates would be implemented in two phases: April 1, 2013 and October 1,2013.
I FERC FORM NO 2/3-Q (REV 12-07) 122.39 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
The settlement agreement proposes that, effective April 1, 2013, Avista Corp. would be authorized to implement a base rate increase
for Idaho natural gas customers of 4.9 percent (designed to increase annual revenues by $3.1 million). There would be no change in
base electric rates on April 1, 2013. However, the settlement agreement would provide for the recovery of the costs of the Palouse
Wind Project through the Power Cost Adjustment mechanism beginning April 1, 2013.
The settlement agreement also proposes that, effective October 1, 2013, Avista Corp. would be authorized to implement a base rate
increase for Idaho natural gas customers of 2.0 percent (designed to increase annual revenues by $1.3 million). A credit resulting from
deferred natural gas costs of $1.6 million would be returned to the Company's Idaho natural gas customers from October 1, 2013
through December 31, 2014, so the net annual average natural gas rate increase to natural gas customers effective October 1, 2013
would be 0.3 percent.
Further, the settlement proposes that, effective October 1, 2013, Avista Corp. would be authorized to implement a base rate increase
for Idaho electric customers of 3.1 percent (designed to increase annual revenues by $7.8 million). A $3.9 million credit resulting from
a payment to be made to Avista Corp. by the Bonneville Power Administration relating to its prior use of Avista Corp.'s transmission
system would be returned to Idaho electric customers from October 1, 2013 through December 31, 2014, so the net annual average
electric rate increase to electric customers effective October 1, 2013 would be 1.9 percent.
The $1.6 million credit to Idaho natural gas customers and the $3.9 million credit to Idaho electric customers would not impact the
Company's net income.
Also included in the settlement agreement is a provision that Avista Corp. may file a general rate case in Idaho in 2014;
however, new rates resulting from the filing would not take effect prior to January 1, 2015.
The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 50.0 percent.
The settlement also includes an after-the-fact earnings test for 2013 and 2014, such that if Avista Corp., on a consolidated basis for
electric and natural gas operations in Idaho, earns more than a 9.8 percent return on equity, Avista Corp. would refund to customers 50
percent of any earnings above the 9.8 percent.
Oregon General Rate Cases
In March 2011, the OPUC approved an all-party settlement stipulation in the Company's general rate case that was filed in September
2010. The settlement provides for an overall rate increase of 3.1 percent for the Company's Oregon customers, designed to increase
annual revenues by $3.0 million. Part of the rate increase became effective March 15, 2011, with the remaining increase effective
June 1, 2011. An additional rate adjustment designed to increase revenues by $0.6 million will occur on June 1, 2012 to recover capital
costs associated with certain reinforcement and replacement projects upon a demonstration that such projects are complete and the
costs were prudently incurred.
On January 1, 2013, Avista Corp. purchased the Klamath Falls Lateral (Lateral), a 15-mile, 6-inch natural gas transmission pipeline
from Williams Northwest Pipeline (Williams). The Klamath Falls Lateral interconnects with another interstate pipeline, Gas
Transmission Northwest, to transport natural gas to serve Avista Corp.'s customers in Klamath Falls, Oregon. The purchase price was
approximately $2.3 million and will save Oregon customers approximately $1.4 million annually as Avista Corp. will be able to reduce
its contracted natural gas transportation requirements from Williams. In Order No. 12-429, the OPUC approved the Company's request
to recover from customers the revenue requirement associated with the purchase of the Lateral, which is approximately $0.5 million
annually. This approval will provide a return of and a return on Avista Corp.'s investment in the lateral. While the OPUC approved the
recovery of the revenue requirement, it will not determine whether the purchase of the Lateral was prudent until the Company's next
Oregon general rate case.
ftERC FORM NO. 213-Q (REV 12.07) 122.40 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)A Resubmission 04/12/2013 2012/Q4
Notes to Financial Statements
NOTE 21. SUPPLEMENTAL CASH FLOW INFORMATION (in thousands)
2012 2011
Cash paid for interest $68,508 $63,876
Cash paid for income taxes $6,631 $16,631
I FERC FORM NO 2134 (REV 12-07) 12241 I
This Page Intentionally Left B lank
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(MO, Da, Yr) 1 04/1212013
Year/Period of Report
End of 2012/Q4
Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization and Depletion
Line
No.
Item
(a)
Total Company
For the Current
Quarter/Year
1 UTILITY PLANT
2 In Service I 3 Plant in Service (Classified) 4,032,753,210
4 Property Under Capital Leases 6,442,349
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 1 Experimental Plant Unclassified
8 TOTAL Utility Plant (Total of lines 3 thru 7) 4,039,195,559
9 Leased to Others
10 Held for Future Use 4,989,371
11 Construction Work in Progress 139,513,892
12 1 Acquisition Adjustments
13 TOTAL Utility Plant (Total of lines 8 thru 12) 4,183,698,822
14 Accumulated Provisions for Depreciation, Amortization, & Depletion 1,408,153,972
15 Net Utility Plant (Total of lines 13 and 14) 2,775,544,850
16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17 1 In Service:
18 Depreciation (1,375,661,340)'
19 Amortization and Depletion of Producing Natural Gas Land and Land Rights
20 Amortization of Underground Storage Land and Land Rights
21 Amortization of Other Utility Plant ( 32,492,632)
22 TOTAL In Service (Total of lines 18 thru 21) (1,408,153,972)
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 TOTAL Leased to Others (Total of lines 24 and 25)
27 Held for Future Use
26 Depreciation
29 Amortization
30 TOTAL Held for Future Use (Total of lines 28 and 29)
31 Abandonment of Leases (Natural Gas)
32 Amortization of Plant Acquisition Adjustment
33 TOTAL Accum. Provisions (Should agree with line 14 above)(Total of lines 22, 26, 30, 31, and 32) ( 1,408,153,972)
FERC FORM NO. 2 (12-96) Page 200
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year Period of Report
End of 20121Q4
Summary of Utility Plant and Accumulated Provisions for Depreciation, Amortization and Depletion (continued)
Line
No.
Electric
(C)
I
Gas
(d)
I
Other (specify)
(e)
Common
(f)
2
31 3,033,013,6601 777,111,351 ' 222,628,199
4 858,865 5,583,484
5
6
7
8 3,033,013,660 777,970,216 228,211,683
9
10 4,773,791 215,580
11 80,205,686 18,296,122 41,012,084
12
13 3,117,993,137 796,481,918 269,223,767
14 1,075,820,044 269,742,833 62,591,095
15 2,042,173,093 526,739,085 20
16
17
18 (1,065,032,018) ( 268,498,775) I (
19
20
I ( 20,460,547) 21 ( 10,788,026) I ( 1,244,059)
22 ( 1,075,820,044) ( 269,742,834) ( 62,591,094)
23
24
25
26
27
28
29
30
31
32
33 (1,075,820,044) ( 269,742,834) ( 62,591,094)
FERC FORM NO. 2 (12-96) Page 201
Name of Respondent This Re ort Is:
(1)X An Original
(2)CIA Resubmission
Date of Report
(MO, Da, Yr)
04/1212013
Yea Period of Report
End of 2012/Q4
Gas Plant in Service (Accounts 101, 102, 103, and 106)
1.Report below the original cost of gas plant in service according to the prescribed accounts.
2.In addition to Account 101, Gas Plant in Service (Classified), this page and the next include Account 102, Gas Plant Purchased or Sold, Account
103, Experimental Gas Plant Unclassified, and Account 106, Completed Construction Not Classified-Gas.
3.Include in column (C) and (d), as appropriate corrections of additions and retirements for the current or preceding year.
4.Enclose in parenthesis credit adjustments of plant accounts to indicate the negative effect of such accounts.
5.Classify Account 106 according to prescribed accounts, on an
estimated basis if necessary, and include the entries in column (c).AIso to be included in column (c) are entries for reversals of tentative distributions of
prior year reported in column (b). Likewise, if the respondent has a significant amount of plant retirements which have not been classified to primary
accounts at the end of the year, include in column (d) a tentative distribution of such retirements, on an estimated basis, with appropriate contra entry to
the account for accumulated depreciation provision. Include also in column (d) reversals of tentative distributions of prior years unclassified retirements.
Attach supplemental statement showing the account distributions of these tentative classifications in columns (c) and (d),
Line
No
Account
(a)
Balance at
Beginning of Year
(b)
Additions
(c)
1 INTANGIBLE PLANT
301 Organization 2
3 302 Franchises and Consents
4 303 Miscellaneous Intangible Plant 3,172,4761 627,074
5 TOTAL Intangible Plant (Enter Total of lines 2 thru 4) 3,172,4761 627,074
6 PRODUCTION PLANT
7 Natural Gas Production and Gathering Plant
I 8 325.1 Producing Lands I
9 325.2 Producing Leaseholds
10 325.3 Gas Rights
11 325.4 Rights-of-Way
12 325.5 Other Land and Land Rights
13 326 Gas Well Structures
14 327 Field Compressor Station Structures
15 328 Field Measuring and Regulating Station Equipment
16 329 Other Structures
17 330 Producing Gas Wells-Well Construction
18 331 Producing Gas Wells-Well Equipment
19 332 Field Lines
20 333 Field Compressor Station Equipment
21 334 Field Measuring and Regulating Station Equipment
22 335 Drilling and Cleaning Equipment
23 336 Purification Equipment
24 337 Other Equipment
25 338 Unsuccessful Exploration and Development Costs
26 339 Asset Retirement Costs for Natural Gas Production and
27 TOTAL Production and Gathering Plant (Enter Total of lines 8
28 PRODUCTS EXTRACTION PLANT
340 Land and Land Rights 29
30 341 Structures and Improvements
31 342 Extraction and Refining Equipment
32 343 Pipe Lines
33 344 Extracted Products Storage Equipment
FERC FORM NO. 2 (12-96) Page 204
Name of Respondent This Re ort Is:
(1)X An original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
Gas Plant in Service (Accounts 101, 102, 103, and 106) (continued)
including the reversals of the prior years tentative account distributions of these amounts. Careful observance of the above instructions and the texts of
Account 101 and 106 will avoid serious omissions of respondent's reported amount for plant actually in service at end of year.
6.Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (U the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102. In showing the clearance of Account 102, include in column (e)the
amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (U only the offset to the debits or
credits to primary account classifications.
7.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 requirements of these pages.
8.For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchaser,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give date of
such filing.
Line
No
Retirements
(d)
Adjustments
(e)
Transfers
(U
Balance at
End of Year
(g)
2
3
4 54,251
5 54,251 "3,745,299
6
7
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
FERC FORM NO. 2 (12-96) Page 206
FERC FORM NO. 2 (12-96) Page 206
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Gas Plant in Service (Accounts 101, 102, 103, and 106) (continued) -
Line
No
Account
(a)
Balance at
Beginning of Year
(b)
Additions
(C)
34 345 Compressor Equipment
35 346 Gas Measuring and Regulating Equipment
36 347 Other Equipment
37 348 Asset Retirement Costs for Products Extraction Plant
38 TOTAL Products Extraction Plant (Enter Total of lines 29 thru 37)
39 TOTAL Natural Gas Production Plant (Enter Total of lines 27 and
40 Manufactured Gas Production Plant (Submit Supplementary 7,628
41 TOTAL Production Plant (Enter Total of lines 39 and 40) 7,628 I
42 NATURAL GAS STORAGE AND PROCESSING PLANT
43 Underground Storage Plant
407,111 I 44 350.1 Land
45 350.2 Rights-of-Way 59,812
46 351 Structures and Improvements 1,366,042 89,810
47 352 Wells 13,470,575 ( 17,524)
48 352.1 Storage Leaseholds and Rights 254,354
49 352.2 Reservoirs 1,667,492
50 352.3 Non-recoverable Natural Gas 5,810,311
51 353 Lines 1,106,781
52 354 Compressor Station Equipment 14,221,273 270,042
53 355 Other Equipment 173,784 120,765
54 356 Purification Equipment 407,617
55 357 Other Equipment 1,485,146 84,367
56 358 Asset Retirement Costs for Underground Storage Plant
57 TOTAL Underground Storage Plant (Enter Total of lines 44 thru 40,430,298 547,460
58 Other Storage Plant
59 360 Land and Land Rights
60 361 Structures and Improvements
61 362 Gas Holders
62 363 Purification Equipment
63 363.1 Liquefaction Equipment
64 363.2 Vaporizing Equipment
65 363.3 Compressor Equipment
66 363.4 Measuring and Regulating Equipment
67 363.5 Other Equipment
68 363.6 Asset Retirement Costs for Other Storage Plant
69 TOTAL Other Storage Plant (Enter Total of lines 58 thru 68)
70 Base Load Liquefied Natural Gas Terminaling and Processing Plant
71 364.1 Land and Land Rights
72 364.2 Structures and Improvements
73 364.3 LNG Processing Terminal Equipment
74 364.4 LNG Transportation Equipment
75 364.5 Measuring and Regulating Equipment
76 364.6 Compressor Station Equipment
77 364.7 Communications Equipment
78 364.8 Other Equipment
79 364.9 Asset Retirement Costs for Base Load Liquefied Natural Gas
80 TOTAL Base Load Liquefied Nat'l Gas, Terminaling and
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
- Gas Plant in Service (Accounts 101, 102, 103, and 106) (continued)
Line
No.
-
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at
End of Year
(g)
34
35
36
37
38
39
40 7,628
41 I 7,6281
42
43
441 I I 407,111 '
45 59,812
46 1,455,852
47 13453,051
48 254,354
49 1,667,492
50 5,810,311
51 1,106,781
52 63,794 14,427,521
53 ( 19,819) 274,730
54 ( 3,905) 403,712
55 1,569,513
56
57 63,794 ( 23,724) 40,890,240
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
FERC FORM NO 2 (12-96) Page 207
Name of Respondent This Re ort is:
(1)X An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
Gas Plant in Service (Accounts 101, 102, 103, and 106) (continued) -
Line
No
Account
(a)
Balance at
Beginning of Year
(b)
Additions
(C)
81 TOTAL Nat'l Gas Storage and Processing Plant (Total of lines 57, 40,430,298 547,460
82 TRANSMISSION PLAN
83 365.1 Land and Land Rights
84 365.2 Rights-of-Way
85 366 Structures and Improvements
86 367 Mains
87 368 Compressor Station Equipment
88 369 Measuring and Regulating Station Equipment
89 370 Communication Equipment
90 371 Other Equipment
91 372 Asset Retirement Costs for Transmission Plant
92 TOTAL Transmission Plant (Enter Totals of lines 83 thru 91)
93 DISTRIBUTION PLANT
267,688 94 374 Land and Land Rights
95 375 Structures and Improvements 1,070,308 55,108
96 376 Mains 362,516,823 11,417,728
97 377 Compressor Station Equipment
98 378 Measuring and Regulating Station Equipment-General 9,020,760 333,061
99 379 Measuring and Regulating Station Equipment-City Gate 7414,781 134,723
100 380 Services 202,206,046 6,636,204
101 381 Meters 97189,594 5,453,681
102 382 Meter Installations
103 383 House Regulators
104 384 House Regulator Installations
105 385 Industrial Measuring and Regulating Station Equipment 4,045,449 229,675
106 386 Other Property on Customers' Premises
107 387 Other Equipment 539
108 388 Asset Retirement Costs for Distribution Plant
109 TOTAL Distribution Plant (Enter Total of lines 94 thru 108) 683,731,988 24,260,180
110 GENERAL PLANT
949,240 111 389 Land and Land Rights
112 390 Structures and Improvements 5,193,175 150,451
113 391 Office Furniture and Equipment 429,445 47,380
114 392 Transportation Equipment 9,171,373 1,007,736
115 393 Stores Equipment 141,498
116 394 Tools, Shop, and Garage Equipment 3,875,874 504,165
117 395 Laboratory Equipment 480,676
118 396 Power Operated Equipment 3,964,851 560,606
119 397 Communication Equipment 2,899,266 133,487
120 398 Miscellaneous Equipment 2,367
121 Subtotal (Enter Total of lines 111 thru 120) 27,107,765 2,403,825
122 399 Other Tangible Property
123 399.1 Asset Retirement Costs for General Plant
124 TOTAL General Plant (Enter Total of lines 121, 122 and 123) 27,107,765 2,403,825
125 TOTAL (Accounts 101 and 106) 754,450,155 27,838,539
126 Gas Plant Purchased (See Instruction 8)
127 (Less) Gas Plant Sold (See Instruction 8)
128 Experimental Gas Plant Unclassified
129 TOTAL Gas Plant In Service (Enter Total of lines 125 thru 128) 754,450,155 27,838,539
FERC FORM NO. 2 (12-96) Page 208
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Yea Period of Report
End of 2012/04
- Gas Plant in Service (Accounts 101, 102, 103, and 106) (continued)
Line
No
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at
End of Year
(g)
81 63,794 ( 23,724) 40,890,240
82
83
84
85
86
87
88
89
90
91
92
93
94 267,688
95 636 1,124,780
96 594,414 373,340,137
97
98 42,957 9,310,864
99 31,195 7,518,309
100 343,250 208,499,000
101 2,356,541 100,286,734
102
103
104
105 4,275,124
106
107 539
108
109 3,368,993 704,623,175
110
111 949,240
112 15,391 5,328,235
113 476,825
114 324,728 9,854,381
115 141,498
116 72,683 4,307,356
117 74,044 406,632
118 295,498 4,229,959
119 25,372 3,007,381
120 2,367
121 807,716 28,703,874
122
123
124 807,716 28,703,874
125 4,294,754 ( 23,724) 777,970,216
126
127
128
129 4,294,754 ( 23,724) 777,970,216
FERC FORM NO. 2 (12-96) Page 209
Name of Respondent This Re ort Is:
(1)X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Yea Period of Report
End of 2012/Q4
Gas Plant Held for Future Use (Account 105)
1.Report separately each property held for future use at end of the year having an original cost of $1,000,000 or more. Group other
items of property held for future use.
2.For property having an original cost of $1,000,000 or more previously used in utility operations, now held for future use, give in
column (a), in addition to other required information, the date that utility use of such property was discontinued, and the date the
original cost was transferred to Account 105.
Line
No.
Description and Location
of Property
(a)
Date Originally Included
in this Account
(b)
Date Expected to be Used
in Utility Service
(c)
Balance at
End of Year
(d)
1 Gas Distribution Mains and Services 03/01/2007 184,818
2 located in Coeur d'Alene, Idaho
3 Gas Distribution Mains and Services 07/01/2011 30,762
4 located in Coeur d'Alene, Idaho
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 Total 215,580
FERC FORM NO. 2 (12-96) Page 214
Name of Respondent This Re ort Is:
(1)X An Original
(2)E A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Construction Work in Progress-Gas (Account 107)
1.Report below descriptions and balances at end of year of projects in process of construction (Account 107).
2.Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development,
and Demonstration (see Account 107 of the Uniform System of Accounts).
3.Minor projects (less than $1,000,000) may be grouped.
Line
No.
Description of Project
(a)
Construction Work in
Progress-Gas
(Account 107)
(b)
Estimated Additional
Cost of Project
(C)
1 Aldyl-A Pipe Replacement Project 4,456,690 53,410,000
2 Klamath Falls Lateral Project 2,525,019
3 Gas Distribution Non-Revenue Blanket 2,351,146 186,744
4 Gas Revenue Blanket 2,126,113 12,848
5 Transportation Equipment Blanket 1,362,050 57,435
6 Gas Replace - Street & Highway Blanket 1,222,007 1,012,920
7 Minor Projects under $1,000,000 4,253,097 4,160,944
8
9 Notes:
10 (1) Aldyl-A replacement Estimated Additional Cost
11 amount represents a 5 year budget total.
12 (2) Blankets are an accumulation of many projects. The
13 Estimated Additional Costs represent expected spend on
14 projects open at year end.
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 Total 18,296,122 58,840,891
FERC FORM NO. 2 (12-96) Page 216
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
General Description of Construction Overhead Procedure
1.For each construction overhead explain: (a) the nature and extent of work, etc., the overhead charges are intended to cover, (b) the genera
procedure for determining the amount capitalized, (C) the method of distribution to construction jobs, (d) whether different rates are applied to
different types of construction, (e) basis of differentiation in rates for different types of construction, and (f) whether the overhead is directly or
indirectly assigned.
2.Show below the computation of allowance for funds used during construction rates, in accordance with the provisions of Gas Plant
Instructions 3 (17) of the Uniform System of Accounts.
3.Where a net-of-tax rate for borrowed funds is used, show the appropriate tax effect adjustment to the computations below in a manner that
clearly indicates the amount of reduction in the gross rate for tax effects.
Construction costs with a direct relationshiD to new con
identified with specific projects are charged to overhead pools. The established pools are:
• Construction Overhead North Gas
• Construction Overhead South Gas
Pool costs are allocated monthly to gas construction projects on a percent rate applied to direct project costs, excluding
AFUDC. Each pool's rate is calculated separately and applied only to the related gas construction projects for allocation.
Allowance for funds used during construction (AFUDC) is calculated system-wide using a rate that is equivalent to the
allowed rate of return approved in the latest rate order from the company's primary state commission (Washington State).
For 2012, Avista used a rate of 7.62% which is the allowed rate of return contained in the Washington Utilties and
Transportation Commission Final Order 06 dated December 16, 2011 for consolidated Dockets UE-1 10876 and
UG-1 10877.
(FERC FORM NO. 2 (REV 12-07) 218.1 I
Name of Respondent This Re ort Is:
(1)An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012104
General Description of Construction Overhead Procedure (continued)
COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES
1.For line (5), column (d) below, enter the rate granted in the last rate proceeding. If not available, use the average rate earned during the preceding 3 years.
2.Identify, in a footnote, the specific entity used as the source for the capital structure figures.
3.Indicate, in a footnote, if the reported rate of return is one that has been approved in a rate case, black-box settlement rate, or an actual three-year average rate.
1. Components of Formula (Derived from actual book balances and actual cost rates):
Line
No.
Title
(a)
Amount
(b)
Capitalization
Ration (percent)
(C)
Cost Rate
Percentage
(d)
(1)Average Short-Term Debt I S
- (2)Short-Term Interest
(3)Long-Term Debt (D d
- (4)Preferred Stock P p
- (5)Common Equity C c
(6)Total Capitalization I
- (7) Average Construction Work In Progress Balance W
2. Gross Rate for Borrowed Funds s(S/W) + d[(DI(D+P+C)) (1-(S/W))]
3. Rate for Other Funds [1 -(S/W)] [p(P/(D+P+C)) + c(C/(D+P+C))]
4. Weighted Average Rate Actually Used for the Year:
a.Rate for Borrowed Funds - 3.06
b.Rate for Other Funds - 4.56
FERC FORM NO. 2 (REV 12-07) Page 218a
ol
This Page Intentionally Left Blank
Name of Respondent This Re art Is:
(1)X An Original
(2)MA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Accumulated Provision for Depreciation of Gas 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 10, column (c), and that reported for gas
plant in service, page 204-209, column (d), excluding retirements of nondepreciable property.
3.The provisions of Account 108 in the Uniform System of Accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been
recorded and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize
the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate
functional classifications.
4.Show separately interest credits under a sinking fund or similar method of depreciation accounting.
5.At lines 7 and 14, add rows as necessary to report all data. Additional rows should be numbered in sequence, e.g., 7.01, 7.02, etc.
Line
No
Item
(a)
Total
(c+d+e)
(b)
Gas Plant in
Service
(c)
Gas Plant Held
for Future Use
(d)
Gas Plant Leased
to Others
(e)
-
1
Section A. BALANCES AND CHANGES DURING YEAR
256,805,7951 256,805,7951 I Balance Beginning of Year
2
3
Depreciation Provisions for Year, Charged to
(403) Depreciation Expense 15,965,536 15,965,536
4 (403.1) Depreciation Expense for Asset Retirement Costs
5 (413) Expense of Gas Plant Leased to Others
6 Transportation Expenses - Clearing 276,862 276,862
7 Other Clearing Accounts
8 Other Clearing (Specify) (footnote details): _________________
9 _____________________
10 TOTAL Deprec. Prov. for Year (Total of lines 3 thru 8) 16,242,398 16,242,398
11
12
Net Charges for Plant Retired:
Book Cost of Plant Retired ( 4,247,572) ( 4,247,572)
13 Cost of Removal 295,612 295,612
14 Salvage (Credit) ( 9,676) ( 9,676)
15 TOTAL Net Chrgs for Plant Ret (Total of lines 12 thru 14) ( 3,942,284) ( 3,942,284)
16 Other Debit or Credit Items (Describe) (footnote details): ( 607,135) ( 607,135)
17
18 Book Cost of Asset Retirement Costs
19 Balance End of Year (Total of lines 1,10,15,16 and 18) 268,498,774 268,498,774
Section B. BALANCES AT END OF YEAR ACCORDING TO
FUNCTIONAL CLASSIFICATIONS
21 Productions-Manufactured Gas
22 Production and Gathering-Natural Gas
23 Products Extraction-Natural Gas
24 Underground Gas Storage 12,870,672 12,870,672
25 1 Other Storage Plant
26 Base Load LNG Terminaling and Processing Plant
27 Transmission
28 Distribution 246,429,510 246,429,510
29 General 9,198,592 9,198,592
30 TOTAL (Total of lines 21 thru 29) 268,498,774 268,498,774
FERC FORM NO. 2 (12-96) Page 219
Name of Respondent This Report Is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)EIA Resubmission 04/12/2013 End of 2012/Q4
Gas Stored (Accounts 117.1, 117.2, 117.3, 117.4, 164.1, 164.2, and 164.3)
1.If during the year adjustments were made to the stored gas inventory reported in columns (d), (f), (g), and (h) (such as to correct cumulative inaccuracies
of gas measurements), explain in a footnote the reason for the adjustments, the Dth and dollar amount of adjustment, and account charged or credited.
2.Report in column (e) all encroachments during the year upon the volumes designated as base gas, column (b), and system balancing gas, column (c),
and gas property recordable in the plant accounts.
3.State in a footnote the basis of segregation of inventory between current and noncurrent portions. Also, state in a footnote the method used to report
storage (i.e., fixed asset method or inventory method).
Line Description Noncurrent Current LNG LNG
No (Account (Account (Account (Account (Account (Account (Account Total
117.1) 117.2) 117.3) 117.4) 164.1) 164.2) 164.3)
- (a) (b) (C) (d) (e) (f) (g) (h) (i)
1 Balance at Beginning of 6,992,076 23,609,47 30,601,546
2 Gas Delivered to Storage 23,177,60E 23,177,606
3 Gas Withdrawn from 29,510,78E 29,510,769
4 Other Debits and Credits
5 Balance at End of Year 6,992,0761 17,276,28 24,268,363
6 Dth 1,253,060 7,463,64: 8.716,703
7 mount Per Dth 5.5800 2.314 2.7841
FERC FORM NO. 2 (REV 04-04) Page 220
This Page Intentionally Left Blank
Name of Respondent This Re ort Is:
X (1)An Original
(2)[JA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Investments (Account 123, 124, and 136)
1.Report below investments in Accounts 123, Investments in Associated Companies, 124, Other Investments, and 136, Temporary Cash Investments.
2.Provide a subheading for each account and list thereunder the information called for
(a)Investment in Securities-List and describe each security owned, giving name of issuer, date acquired and date of maturity. For bonds, also give principal amount, date of issue,
maturity, and interest rate. For capital stock (including capital stock of respondent reacquired under a definite plan for resale pursuant to authorization by the Board of Directors, and
included in Account 124, Other Investments) state number of shares, class, and series of stock. Minor investments may be grouped by classes. Investments included in Account 136,
Temporary Cash Investments, also may be grouped by classes.
(b)Investment Advances-Report separately for each person or company the amounts of loans or investment advances that are properly includable in Account 123. Include advances
subject to current repayment in Account 145 and 146. With respect to each advance, show whether the advance is a note or open account
Line
-
Description of Investment
(a)
*
(b)
Book Cost at Beginning of Year
(If book cost is different from
cost to respondent, give cost to
respondent in a footnote and
explain difference)
(c)
Purchases or
Additions
During the Year
(d)
1 Investment in Spokane Energy (123000) 500,000
2 Investment in Avista Capital 11 (123010) 11,547,000
3 Other Investment - WZN Loans Sandpoint (124350) 61,177
4 Other Investment - Coil Cash Value (124600) 13,293,355
5 Other Investment - Coil Borrowings (124610) ( 13,293,355)
6 Other Investment - WZN Loans Oregon (124680) 45,031
7 Other Investment - WNP3 Exchange Power (124900) 79,626,000
8 Other Investment - AMT WNP3 Exchange (124930) ( 60,842,823)
9 Temp Cash Investments (136000) 60,913
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
FERC FORM NO. 2 (12-96) Page 222
Name of Respondent This Report Is:
(1)[g ]An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Investments (Account 123, 124, and 136) (continued)
List each note, giving date of issuance, maturity date, and specifying whether note is a renewal. Designate any advances due from officers directors, stockholders, or employees.
3.Designate with an asterisk in column (b) any securities, notes or accounts that were pledged, and in a footnote state the name of pledges and purpose of the pledge.
4.If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and cite Commission, date of authorization, and case or docket
number.
5.Report in column (h) interest and dividend revenues from investments including such revenues from securities disposed of during the year.
6.In column (I) report for each investment disposed of during the year the gain or loss represented by the difference between cost of the investment (or the other amount at which
carried in the books of account if different from cost) and the selling price thereof, not including any dividend or interest adjustment includible in column (h).
Line
O
-
Sales or Other
Dispositions
During Year
(e)
Principal Amount or
No. of Shares at
End of Year
(f)
Book Cost at End of Year
(If book cost is different from cost
to respondent give cost to
respondent in a footnote and
explain difference)
(g)
Revenues for
Year
(h)
Gain or Loss from
Investment
Disposed of
(i)
1 500,000
2 11,547,000
3 61,177
4 ( 1,383,948) 14,677,303
5 1,383,948 ( 14,677,303)
6 299 44,732
7 79,626,000
8 2,450,031 ( 63,292,854)
9 ( 190,477) 251,390
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
FERC FORM NO. 2 (12-96) Page 223
Name of Respondent This Report Is:
(1)X An Original
(2)JA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Investments in Subsidiary Companies (Account 123.1)
1, Report below investments in Account 123.1, Investments in Subsidiary Companies.
2. Provide a subheading for each company and list thereunder the information called for below. Sub-total by company and give a total in columns (e), (f), (g) and (h).
(a)Investment in Securities-List and describe each security owned. For bonds give also principal amount, date of issue, maturity, and interest rate.
(b)Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment but which are not subject to current settlement With respect
to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal.
3. Report separately the equity in undistitbuted subsidiary earnings since acquisition. The total in column (e) should equal the amount entered for Account 418.1.
Line
Description of Investment
(a)
Date
Acquired
(b)
Date of
Maturity
(c)
Amount of
Investment at
Beginning of Year
(d)
1 Avista Capital - Common Stock 01/01/1997 170,053,827
2 Avista Capital - Equity in Earnings ( 101,447,380)
3 OCI Investment in Subs 134,045
4 Avista Capital - Other Changes in Net Investment 3,230,876
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 j
40 1 TOTAL Cost of Account 123.1$ TOTAL 71,971,368
FERC FORM NO. 2 (12-96) Page 224
Name of Respondent This Re ort Is:
(1)An Original
(2)JA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Investments in Subsidiary Companies (Account 123.1) (continued)
4.Designate in a footnote, any securities, notes, or accounts that were pledged, and state the name of pledgee and purpose of the pledge.
5.If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or
docket number.
6.Report in column (t) interest and dividend revenues from investments, including such revenues from securities disposed of during the year.
7.In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which
carried in the books of account if different from cost), and the selling price thereof, not including interest adjustments includible in column (f).
B. Report on Line 40, column (a) the total cost of Account 123.1.
Line
No.
Equity in Subsidiary
Earnings for Year
(e)
Revenues for Year
(f)
Amount of Investment
at End of Year
(g)
Gain or Loss from
Investment
Disposed of
(h)
46,675,006) 216,728,833
2 ( 1,206,861) ( 102,654,241)
3 ( 33,216) 167,261
4 ( 1,241,694) 4,472,570
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40 ( 1,206,861) ( 47,949,916) 118,714,423
FERC FORM NO. 2 (12-96) Page 225
Name of Respondent This Report Is:
(1)X An original
(2)[:]A Resubmission
Dateof Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Prepayments (Acct 165), Extraordinary Property Losses (Acct 182.1), Unrecovered Plant and Regulatory Study Costs (Acct 182.2)
PREPAYMENTS (ACCOUNT 165)
1. Report below the particulars (details) on each prepayment.
Line
No.
-
Nature of Payment
(a)
Balance at End
of Year
(in dollars)
(b)
1 Prepaid Insurance 2,490,855
2 Prepaid Rents
3 Prepaid Taxes
4 Prepaid Interest
5 Miscellaneous Prepayments 13,599,625
6 TOTAL 16090,480
FERC FORM NO. 2 (12-96) Page 230a
Name of Respondent This Re ort Is:
(1)X An original
(2)i::i Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Other Regulatory Assets (Account 182.3)
1.Report below the details called for concerning other regulatory assets which are created through the ratemaking actions of regulatory agencies (and not includable
in other accounts).
2.For regulatory assets being amortized, show period of amortization in column (a).
3.Minor items (5% of the Balance at End of Year for Account 182.3 or amounts less than $250,000, whichever is less) may be grouped by classes.
4.Report separately any Deferred Regulatory Commission Expenses that are also reported on pages 350-351, Regulatory Commission Expenses.
5.Provide in a footnote, for each line item, the regulatory citation where authorization for the regulatory asset has been granted (e.g. Commission Order, state
commission order, court decision).
Line
No.
Description and Purpose of
Other Regulatory Assets
(a)
Balance at
Beginning
Current
Quarter/Year
(b)
Debits
(c)
Written off During
Quarter/Year
Account
Charged
(d)
Written off
During Period
Amount Recovered
(e)
Written off
During Period
Amount Deemed
Unrecoverable
(0
Balance at End of
Current
Quarter/Year
(g)
1 Regulatory Asset FAS 106 472,752 472,752
2 Guaranteed Residual Value-Airplane
3 Reg Asset Post Ret Liab 260,358,633 46,049,036 306,407,669
4 Reg Asset FAS 109 Utility Plant 70,616,515 5,151,910 65,464,605
5 Reg Asset FAS 109 DSIT Non Plant 1,762,314 97,548 1,664,766
6 Reg Asset FAS 109 DSIT State Tax cr 6,669,689 794,495 7,464,184
7 Reg Asset FAS 109 WNP3 5,653,819 737,462 4,916,337
8 Reg Asset-Spokane River Relicense 701,098 78,736 622,362
9 Reg Asset-Spokane River PM&E 649,198 73,312 575,886
10 Reg Asset-Lake CDA Fund 9,648,664 211,065 9,437,599
11 Reg Asset- Decouplings Surcharge 190,282 182,958 7,324
12 Regulatory Asset AMR 70.934 70,934
13 Reg Asset RTO Deposits ID
14 Reg Asset BPA Residental Exchange 104,636 436,169
15 Reg Asset ERM Approved for Recovery
16 ID Wind Gen AFUDC 358,264 11,109 369,373
17 Reg Asset Wartsilla Units 1,089,605 337,788 751,817
18 MTM St Regulatory Asset 69,684,643 34,603,118 35,081,525
19 Reg Asset- FAS 143 Asset Retirement Obligation 2,717,489 318,644 2,398,845
20 Reg Asset AN CDA Lake Settlement 39,156,540 1,559,332 37,627,208
21 Reg Asset WA CDA Lake Settlement 1,356,388 152,118 1,204,270
22 Reg Asset Workers Comp 2,623,100 344,422 2,278,678
23 CS2 Lev Rat 1,250,099 340,600 909,499
24 Reg Asset ID PCA Deferral 1
25 Reg Asset ID PCA Deferral 2 2,017,929 2,017,929
26 Reg Asset ID PCA Deferral 3 1 2,762,169) 2,762,168 ( )
27 Reg Asset- Future Payments Lake CDA
28 DSM Asset 798,418 2,578,599 798,418 2,578,599
29 Lancaster Generation 5,326,667 1,360,000 3,966,667
30 CDA Fund 2,000,000 2,000,000
31 MTM LT Reg Asset 40,345,338 15,127,641 25,217,697
32 Roseburg/Medford 142,470 122,541 265,011
33 CNC Trransmission 735,905 252,637 - 483,269
34 CS2 & Colslrip 143,226 6,685,420 516,251 6,312,395
35 Lldar O&M 337,879 249,379 587,258
36 SWAPS on FMBS 40,697,807 40,697,807
37
38
39
40 Total 524,M,326 100,386,72" 84,805,595 0 559,831,454
FERC FORM NO. 2/30 (REV 12-07) Page 232
Name of Respondent This Rort Is: ep
(1)An Original
(2)f A Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/ Period of Report
End of 2012/04
Miscellaneous Deferred Debits (Account 186)
1.Report below the details called for concerning miscellaneous deferred debits.
2.For any deferred debit being amortized, show period of amortization in column (a).
3.Minor items (less than $250,000) may be grouped by classes.
Line
No.
-
Descripon of Miscellaneous
Deferred Debits
(a)
Balance at
Beginning
of Year
(b)
Debits
(c)
Credits
Account
Charged
(d)
Credits
Amount
(e)
Balance at
End of Year
(f)
2 Colsttip Common Fac. 1,110,999 1,110,999
3 Regulatory Asset-Decoupling def ( 19,852) 19,852
4
5 Regulatory Asset-Mt lease pymt 1,713,249 540 360,684 1,352,565
6 j Regulatory Asset-Mt lease pymt 3,383,112 540 676,632 2,706,480
7 Colstrip Common Fac. 2,355,642 2,355,642
8 Prepaid airplane Lease LT 466,025 931 147,166 318,859
9 Misc DD-Airplane lase cap 90,181 12,556 102,737
10 Plant allocation of clrg journal 1,140,273 2,444,223 3,584,496
11 Misc DD-IR Swaps 18,895,143 245 18,895,143
12 Misc Error Suspense 5,225 var 342,205 ( 336,980)
13 Renewable Energy-Cert Fees 174,000 557 9,156 164,844
14 Nez Perce Settlement 165,961 557 5,212 160,749
15 Long Term Note Rec acct 209,469 143 204,050 5,419
16 Reg Asset ID-Lake Cda 271,030 506 30,974 240,056
17 1Misc deffered debits/WA FRED DEF var 277,010 ( 277,010)
18 ID Panhandle Forest Use Permit 181,017 181,017
19 Credit Union Labor & Exp 25,762 9,248 35,010
20 Outdoor Lghtng Greenbelt Pathwy 65,248 32,979 98,227
21 Horizon Wind Interco 61,845 61,845
22 Insurance Recv CDA Lake 320,932 var 320,932
23 KF Water Rights Supply 1,179,357 310 1,178,588 769
24 Reclass Idaho CIk Fork Relic 452,846 537 265,896 186,950
25 Reclass misc def debits 357,784 357,784
26 Misc Work Orders <$50,000 ( 149,432) 275,641 126,209
27 Subsidiary Billings 42,452 135,814 178,266
28 "Null" Projects directly to 186 15,197 15,197
29 Conservation
30 Regulatory Assets Consv ( 200) 200
31 Regulatory Assets Consv 1,845,898 var 185,185 1,660,713
32
33 Optional Wind Power 909 186,231 ( 186,231)
34
35
36 Misc deffered debits/Res Acct 1,577,5311 1 1,577,531
37 Deffered Palouse Wind %Thornton SW ST 1557 1 80,774 ( 80,774)
38 I
39 Miscellaneous Work in Progress
40 Total 34,001,379 4,865,828 23,165,838 15,701,369
FERC FORM NO. 2 (12-96) Page 233
This Page Intentionally Left Blank
Name of Respondent This Re ort Is:
(1)X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Accumulated Deferred Income Taxes (Account 190)
1.Report the information called for below concerning the respondents accounting for deferred income taxes.
2.At Other (Specify), include deferrals relating to other income and deductions.
3.Provide in a footnote a summary of the type and amount of deferred income taxes reported in the beginning-of-year and end-of-year balances for deferred income
taxes that the respondent estimates could be included in the development of jurisdictional recourse rates.
Line
No.
Account Subdivisions
(a)
Balance at
Beginning
of Year
(b)
Changes During
Year
Amounts Debited
to Account 4l0.1
(C) I
Changes During
Year
Amounts Credited
to Account 4ll.1
(d)
1 Account 190
9302,194 2 Electric
3 Gas 1,056,689
4 Other (Define) (footnote details) 143,049,537
5 Total (Total of lines 2 thru 4) 153,408,420
6 Other (Specify) (footnote details)
7 TOTAL Account 190 (Total of lines 5 thru 6) 153,408,420
8 Classification of TOTAL
9 Federal Income Tax 153,408,420
10 State Income Tax
11 Local Income Tax
FERC FORM NO. 2 (REV 12-07) Page 234
Name of Respondent This Re ort Is:
(1)X An Original
(2)DA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year Period of Report
End of 2012/Q4
Accumulated Deferred Income Taxes (Account 190) (continued)
Line
No.
Changes Dung
Year
Amounts Debited
to Account 410.2
(e)
Changes Dung
Year
Amounts Credited
to Account 411.2
(f)
Adjustments
Debits
Account No.
(g)
Adjustments
Debits
Amount
(h)
Adjustments
Credits
Account No.
(i)
Adjustments
Credits
Amount
U)
Balance at
End of Year
(k)
2 3,041,126 6,261,068
3 1,105,243 2,161,932
4 3,047,068 140,002,469
5 6,088,194 1,105,243 148,425,469
6
7 6,088,1941 1 1,105,2431 148,425,469
8
6,088,194 1.105,243 148,425,469 9
10
FERC FORM NO. 2 (REV 12-07) Page 235
Name of Respondent This Re ort Is:
(1)X An Original
(2)EJA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Capital Stock (Accounts 201 and 204)
1.Report below the 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.
2.Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
3.Give details concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued.
Line
No.
-
Class and Series of Stock and
Name of Stock Exchange
(a)
Number of Shares
Authorized by Charter
(b)
Par or Stated Value
per Share
(c)
Call Price at
End of Year
(d)
1 Acct. 201 - Common Stock Issued:
2 No Par Value 200,000,000
3 Restriced shares
4 TOTAL Common 200,000,000
5
6
7 Account 204- Preferred Stock Issued 10,000,000
8
9 Total Preferred 10,000,000
10
11 I
12
13
14
15
16
17
18
19
20
21
22 1
23
24
25
26
27
28
29.
30
31
32 1
33
34
35
36
37
38
39
40
FERC FORM NO. 2 (12-96) Page 250
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(MO Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Capital Stock (Accounts 201 and 204)
4.The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or noncumulative.
5.State in a footnote if any capital stock that has been nominally issued is nominally outstanding at end of year.
6.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
purpose of pledge.
Line
No.
Outstanding per Bal. Sheet
(total amt outstanding
without reduction for amts
held by respondent)
Shares
(e)
Outstanding per Bal.
Sheet
Amount
(f)
Held by
Respondent
As Reacquired
Stock (Acct 217)
Shares
(g)
Held by
Respondent
As Reacquired
Stock (Acct 217)
Cost
(h)
Held by
Respondent
In Sinking and
Other Funds
Shares
(I)
Held by
Respondent
In Sinking and
Other Funds
Amount
U)
2 59,812,796 863,316,222 117,118.00 3,025,158.00
3
4 59,812,796 863,316,222 117,118.00 3,025,158.00
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
FERC FORM NO. 2 (12-96) Page 251
Name of Respondent This Re ort Is:
(1)X An Original
(2)DA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
Other Paid-In Capital (Accounts 208-211)
1. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital
accounts. Provide a subheading for each account and show a total for the account, as well as a total of all accounts for reconciliation
with the balance sheet, page 112. Explain changes made in any account during the year and give the accounting entries effecting
such change.
(a)Donations Received from Stockholders (Account 208) - State amount and briefly explain the origin and purpose of each donation.
(b)Reduction in Par or Stated Value of Capital Stock (Account 209) - State amount and briefly explain the capital changes that gave
rise to amounts reported under this caption including identification with the class and series of stock to which related.
(c)Gain or Resale or Cancellation of Reacquired Capital Stock (Account 210)- Report balance at beginning of year, credits, debits,
and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which
related.
(d)Miscellaneous Paid-In Capital (Account 211) - Classify amounts included in this account according to captions that, together with
brief explanations, disclose the general nature of the transactions that gave rise to the reported amounts.
Line
No.
Item
(a)
Amount
(b)
1 Equity transactions of subsidiaries 10,942,942
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40 Total 10,942,942
FERC FORM NO. 2 (12-96) Page 253
This Page Intentionally Left Blank
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
DISCOUNT ON CAPITAL STOCK (ACCOUNT 213)
1.Report the balance at end of year of discount on capital stock for each class and series of capital stock. Use as many rows as necessary to report all data.
2.If any change occurred during the year in the balance with respect to any class or series of stock, attach a statement giving details of the change. State the reason for any charge-off
during the year and specify the account charged.
Line
No.
Class and Series of Stock
(a)
Balance at
End of Year
(b)
2
3
4
5
6
7
8
9
10
12
13
14
TOTAL
CAPITAL STOCK EXPENSE (ACCOUNT 214)
1.Report the balance at end of year of capital stock expenses for each class and series of capital stock Use as many rows as necessary to report all data. Number the rows in
sequence starting from the last row number used for Discount on Capital Stock above.
2.If any change occurred during the year in the balance with respect to any class or series of stock, attach a statement giving details of the change. State the reason for any charge-off
of capital stock expense and specify the account charged.
Line
No.
Class and Series of Stock
(a)
Balance at
End of Year
(b)
16 Common Stock - No Par Value
17
18
19
20
21
22
23
24
25
26
27
28
- TOTAL ( 14,977,565)
FERC FORM NO. 2 (12-96) Page 254
Name of Respondent This Report is: Date of Report Year/Period of Report
I (1)An Original (Mo, Da, Yr)
L (2)- A Resubmission 04/12/2013 2012/Q4
I FOOTNOTE DATA
Schedule Page: 254 Line No.: 16 Column: b
Capital Stock expense activity, 2012
Beginning Balance: $(11,086,811)
Issuance of Common Stock: 558,210
Tax Benefit - Options Exercised: 34,614
Excess Tax Benefits on Stock Comp: 1,230,724
Stock compensation accrual: (5,714,302)
Ending Balance: $(14,977,565)
I FERC FORM NO. 2 (12-96) Page 552.1 I
This Page Intentionally Left Blank
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
Securities Issued or Assumed and Securities Refunded or Retired During the Year
1.Furnish a supplemental statement briefly describing security financing and refinancing transactions during the year and the accounting for
the securities, discounts, premiums, expenses, and related gains or losses. Identify as to Commission authorization numbers and dates.
2.Provide details showing the full accounting for the total principal amount, par value, or stated value of each class and series of security
issued, assumed, retired, or refunded and the accounting for premiums, discounts, expenses, and gains or losses relating to the securities. Set
forth the facts of the accounting clearly with regard to redemption premiums, unamortized discounts, expenses, and gain or losses relating to
securities retired or refunded, including the accounting for such amounts carried in the respondents accounts at the date of the refunding or
refinancing transactions with respect to securities previously refunded or retired.
3.Include in the identification of each class and series of security, as appropriate, the interest or dividend rate, nominal date of issuance,
maturity date, aggregate principal amount, par value or stated value, and number of shares. Give also the issuance of redemption price and
name of the principal underwriting firm through which the security transactions were consummated.
4.Where the accounting for amounts relating to securities refunded or retired is other than that specified in General Instruction 17 of the
Uniform System of Accounts, cite the Commission authorization for the different accounting and state the accounting method.
5.For securities assumed, give the name of the company for which the liability on the securities was assumed as well as details of the
transactions whereby the respondent undertook to pay obligations of another company. If any unamortized discount, premiums, expenses, and
gains or losses were taken over onto the respondent's books, furnish details of these amounts with amounts relating to refunded securities
clearly earmarked.
on June 28, 2012, redeemed the Stevens County Public Corporation Pollution Control Revenue
Refunding Bonds (The Washington Water Power Company Kettle Falls Project), Series 1993, due in 1201-2023 for the
entire principal amount of $4.1 million at par.
On November 30, 2012, Avista Corporation issued $80.0 million of 4.23 percent First Mortgage Bonds due in 2047 under a
bond purchase agreement with certain institutional investors in the private placement market. The new First Mortgage
Bonds were issued under and in accordance with the Mortgage and Deed of Trust, dated as of June 1, 1939, from the
Company to Citibank, N.A., trustee, as amended and supplemented by various supplemental indentures and other
instruments. The total net proceeds from the sale of the new bonds were used to repay a portion of the borrowings
outstanding under the Company's $400.0 million committed line of credit. The new issuance is based on the following state
commission orders:
1.Order of the Washington Utilities and Transportation Commission entered July 13, 2011, as amended on August 24,
2011 in Docket No. U-111176;
2.Order of the Idaho Public Utilities Commission, Order No. 32338, entered August 25, 2011;
3.Order of the Public Utility Commission of Oregon, Order No. 11334, entered August 26, 2011;
4.Order of the Public Service Commission of the State of Montana, Default Order No. 4535
FERC FORM NO. 2 (12-96) 255.1 I
Name of Respondent This Re ort Is:
(1)X An Original
(2)[]A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Long-Term Debt (Accounts 221, 222, 223, and 224)
1.Report by Balance Sheet Account the details concerning long-term debt included in Account 221 Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and
224, Other Long-Term Debt
2.For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
3.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.
4.For receivers' certificates, show in column (a) the name of the court and date of court order under which such certificates were issued.
Line
No.
-
Class and Series of Obligation and
Name of Stock Exchange
(a)
Nominal Date
of Issue
(b)
Date of
Maturity
(c)
Outstanding
(Total amount
outstanding without
reduction for amts
held by respondent)
(d)
1 FMBS - SERIES A - 7.53% DUE 05/05/2023 05/06/1993 05/05/2023 5,500,000
2 FMBS - SERIES A - 7.37% DUE 05110/2012 05/10/1993 05/10/2012
3 FMBS - SERIES A - 7.54% DUE 5/05/2023 05/07/1993 05/05/2023 1,000,000
4 FMBS - SERIES A - 7.39% DUE 5/11/2018 05111/1993 05/1112018 7,000,000
5 FMBS - SERIES A - 7.45% DUE 6/11/2018 06/09/1993 06/11/2018 15,500,000
6 FMBS - SERIES A - 718% DUE 8/11/2023 08/12/1993 08/11/2023 7,000,000
7 KETTLE FALLS P C REV BONDS DUE 14 07/29/1993 12/01/2023
8 ADVANCE ASSOC IATED-A VISTA CAPITAL II (T0PRS) 06/03/1997 06/01/2037
9 FMBS - 6.37% SERIES C 06/19/1998 06/19/2028 25,000,000
10 FMBS - 5.45% SERIES 11/18/2004 12/01/2019 90,000,000
11 FMBS - 6.25% SERIES 11/17/2005 12/01/2035 150,000,000
12 FMBS - 5.70% SERIES 12/15/2006 07/01/2037 150,000,000
13 FMBS -5.95% SERIES 04/02/2008 06/01/2018 250,000,000
14 FMBS - 5.125% SERIES 09/22/2009 04/01/2022 250,000,000
15 COLSTRIP 2010A PCRBS DUE 2032 12/15/2010 10/01/2032 66,700,000
16 COLSIRIP 2010B PCRB5 DUE 2034 12/15/2010 03101/2034 17,000,000
17
18 FMBS - 1.68% SERIES 12/30/2010 12/30/2013 50,000,000
19 FMBS - 3.89% SERIES 12/20/2010 12/20/2020 52,000,000
20 FMBS - 5.55% SERIES 12/20/2010 12/20/2040 35,000,000
21 FMBS - 4.45% SERIES 12/14/2011 12/14/2041 85,000,000
22
23
24
25 11/30/2012 11/29/2047 80,000,000
26
27
28
29
30
31
32
33
34
35
36
37 -
38
39
40 TOTAL 1,388,247,000
FERC FORM NO. 2 (12-96) Page 256
Name of Respondent This Report Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Long-Term Debt (Accounts 221, 222, 223, and 224)
5.In a supplemental statement, 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)
pnncipal advanced during year (b) interest added to principal amount, and (c) principal repaid during year. Give Commission authorization numbers and dates.
6.If the respondent has pledged any of its long-term debt securities, give particulars (details) in a footnote, including name
of the pledgee and purpose of the pledge.
7.If the respondent has any long-term securities that have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote.
8.If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (f). Explain in a footnote any
difference between the total of column (f) and the total Account 427, Interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
9.Give details concerning any long-term debt authorized by a regulatory commission but not yet issued.
Line
No.
-
Interest for
Year
Rate
(in %)
(e)
Interest for
Year
Amount
(f)
Held by
Respondent
Reacquired Bonds
(Acct 222)
(g)
Held by
Respondent
Sinking and
Other Funds
(h)
Redemption Price
per $100 at
End of Year
(I)
7.530 414,150
2 7.370 214,958
7.540 75,400
4 7.390 517,300
5 7.450 1,154,750
6 7.180 502,600
7 6.000 120,950
8 1.350 541,503
9 6.370 1,592,500
10 5.450 4,905,000
11 6.250 9,375,000
i 5.700 8,550,000
13 5.950 14,875,000
14 5.125 12812,500
15 0.463 309,043 66,700,000
16 0.463 78,766 17,000,000
17
18 1.680 840,000
19 3.890 2,022,800
20 5.550 1,942,500
21 4.450 3,782,500
22
23
24
25 4.230 291,400
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40 - 83,700,000
FERC FORM NO. 2 (12-96) Page 267
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/04
FOOTNOTE DATA
$chedule Page: 256 Line No.: 8 Column: d
Upon issuance Avista Capital II isued $1.5 million of Common Trust Securities to the Avista Corp. In December 2000,
Avista Corp purchased $10.0 million of the Preferred Trust Securities. The interest for the year disclosed in column
(i)reflects the amount of interest owed to third parties.
Schedule Page: 256 Line No.: 25 Column: a
The new issuance is based on the following commission orders:
1.Order of the Washington Utilities and Transportation Commission entered July 13, 2011, as
amended on August 24, 2011 in Docket No. U-Ill 176;
2.Order of the Idaho Public Utilities Commission, Order No. 32338, entered August 25, 2011;
3.Order of the Public Utility Commission of Oregon, Order No. 11334, entered August 26, 2011;
Order of the Public Service Commission of the State of Montana, Default Order No. 4535
Schedule Page: 256 Line No.: 40 Column: f
The 427 and 430 account differences are primarly related to the amortization of settled interest rate swaps and other
related interest expense items.
FERC FORM NO 2 (12-96) Page 552.1
Name of Respondent This Re ort Is:
(1)X An original
(2)UA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
Unamortized Debt Expense, Premium and Discount on Long-Term Debt (Accounts 181, 225, 226)
1 Report under separate subheadings for Unamortized Debt Expense, Unamortized Premium on Long-Term Debt and Unamortized Discount on Long-Term Debt, details of expense,
premium or discount applicable to each class and series of long-term debt
2.Show premium amounts by enclosing the figures in parentheses.
3.In column (b) show the principal amount of bonds or other long-term debt originally issued,
4.In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
Line
No.
Designation of
Long-Term Debt
(a)
Principal Amount
of Debt Issued
(b)
Total Expense
Premium or
Discount
(c)
Amortization
Period
Date From
(d)
Amortization
Period
Date To
(e)
1 j FMBS - SERIES A - 7.53% DUE 05/05/2023 5,500,000 42,712 05/06/1993 05/05/2023
2 FMBS - SERIES A - 7.54% DUE 5/05/2023 1,000,000 7,766 05/0711993 05/05/2023
3 FMBS - SERIES A - 7.37% DUE 5/10/2012 7000,000 49,114 05/1011993 05/10/2012
4 FMBS - SERIES A - 7.39% DUE 5/11/2018 7,000,000 54,364 05/11/1993 05/11/2018
5 FMBS - SERIES A - 7.45% DUE 6/11/2018 15,500,000 170,597 06/09/1993 06/11/2018
6 FMBS - SERIES A - 7.18% DUE 8/11/2023 7,000,000 54,364 08112/1993 08/11/2023
7 KETTLE FALLS PC REV BONDS DUE 14 4,100,000 135,855 07/29/1993 12/01/2023
8 ADVANCE ASSOCIATED-AVISTA CAPITAL II (T0PRS) 51,547,000 1,296,086 06/03/1197 06/01/2037
9 SERIES C SET UP COST 666,169 06/15/1998 06/15/2013
10 FMBS - 6.37% SERIES C 25,000,000 158,304 06/19/1998 06/19/2028
11 FMBS - 5.45% SERIES 90,000,000 1,432,081 11/18/2004 12/01/2019
12 FMBS - 6.25% SERIES 150,000,000 2,180,435 11117/2005 12101/2035
13 FMBS - 5.70% SERIES 150,000,000 4,924,304 12/1512006 07/01/2037
14 FMBS - 5,95% SERIES 250,000,000 3,081,419 04/02/2008 06/01/2018
15 FMBS - 5.125% SERIES 250,000,000 2,859,788 09122/2009 04/0112022
16 FMBS - 1.68% SERIES 50,000,000 305,790 12130/2010 12/30/2013
17 FMBS - 3.89% SERIES 52,000,000 383,338 12/20/2010 12120/2020
18 FMBS - 5.55% SERIES 35,000,000 258,834 1212012010 12/20/2040
19 Short-Term Credit Facility 12114/2011 02110/2017
20 4.45% SERIES DUE 12-14-2041 85,000,000 692,722 12/1412011 12/1412041
21 14.23% SERIES DUE 11-29-2047 80,000,000 725,635 11/30/2012 11/29/2047
22 Rathrum 2005 71,646 09130005 12/01/2035
23 Debt Strategies 56,760
24
25
26
27
28
29
30
31
32
33
34
35
36 T
37
38
39
40
FERC FORM NO. 2 (12-96) Page 258
Name of Respondent This Re ort Is:
(1)An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04112/2013
Yea Pero of Report
End of 2012/Q4
Unamortized Debt Expense, Premium and Discount on Long-Term Debt (Accounts 181, 225, 226)
5.Furnish in a footnote 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.
6.Identify separately undisposed amounts applicable to issues which were redeemed in prior years.
7.Explain any debits and credits other than amortization debited to Account 428, Amortization of Debt Discount and Expense, or credited to Account 429, Amortization of Premium on
Debt-Credit.
Line
No.
Balance at
Beginning
of Year
Debits During
Year
(g)
Credits During
Year
(h)
Balance at
End of Year
(i)
16,254 1,424 14,830
2 2,956 259 2,697
3 1,077 1,077
4 13,953 2,175 11,778
5 1 44,355 6,824 37,531
6 21,142 1,812 19,330
7 55,163 55,163
8 357,377 14,015 343,362
9 70,772 47,181 23,591
10 87,067 5,277 81,790
11 734,219 98,947 635,272
12 1,741,654 72,569 1,669,085
13 4,119,725 161,032 3,958,693
14 1,944,831 303,090 1,641,741
15 2,351,460 227,561 2,123,899
16 203,955 101,977 101,978
17 345,029 38,377 306,652
18 250,206 8,628 241,578
19. 2,840,910 525,366 2,315,544
20 642,946 49,776 22,708 670,014
21 724,054 724,054
22 56,843 2,368 54,475
23 13,497 6,183 7,314
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 2 (12-96) Page 269
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)XAn Original (Mo, Da, Yr)
(2) - A Resubmission 04/12/2013 20121Q4
FOOTNOTE DATA
Schedule Page: 258 Line No.: 23 Column: d
Various
I FERC FORM NO 2 (12-96) Page 552.1 I
This Page Intentionally Left Blank
Name of Respondent This Re ort Is:
(1)X An Original
(2)DA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Unamortized Loss and Gain on Reacquired Debt (Accounts 189, 257)
1.Report under separate subheadings for Unamortized Loss and Unamortized Gain on Reacquired Debt, details of gain and loss,
including maturity date, on reacquisition applicable to each class and series of long-term debt. If gain or loss resulted from a refunding
transaction, include also the maturity date of the new issue.
2.In column (c) show the principal amount of bonds or other long-term debt reacquired.
3.In column (d) show the net gain or net loss realized on each debt reacquisition as computed in accordance with General Instruction
17 of the Uniform Systems of Accounts.
4.Show loss amounts by enclosing the figures in parentheses.
5.Explain in a footnote any debits and credits other than amortization debited to Account 428.1, Amortization of Loss on Reacquired
Debt,or credited to Account 429.1, Amortization of Gain on Reacquired Debt-Credit.
Line
No
Designation of
Long-Term Debt
(a)
Date
Reacquired
(b)
Principal
of Debt
Reacquired
(c)
Net Gain or
Loss
(d)
Balance at
Beginning
of Year
(e)
Balance at
End of Year
(I)
1 FMBS-7.25% SERIES 12120/2010 30,000,000 ( 5,646,298 ( 5,018,931)
2 FMBS - 6.125% SERIES 12/20/2010 45,000,000 ( 5,088,361 ( 4,912,900)
3 AVA Capital Trust III 04101/2009 60,000,000 ( 2,369,170 ( 2,139,896)
4 Misc Debt Repurchases I 05/10/1993 ( 1,331,831 ( 1,132,224)
5 Misc Debt Repurchases II 06/19/1998 ( 103,757) ( 97,469)
6 Misc Debt Repurchases III 07/29/1993 ( 57,755)
7 Kettle Falls PCRBs 06/28/2012 4,100,000 104,770
8 Misc 2008 Repurchases Costs 01/01/2008 32,488 29,792
9 Misc 2006 Repurchases Costs 01/01/2006 ( 96,592) ( 80,627)
10 M1sc2005 Repurchases Costs 01/01/2005 ( 983,868) ( 885,227)
11 Misc 2004 Repurchases Costs 01/01/2004 ( 2,671,997) ( 2,098,009)
12 Misc 2003 Repurchases Costs 01/01/2003 ( 393,133) ( 315,799)
13 Misc 2002 Repurchases Costs 01/01/2002 ( 45,341) ( 42,492)
14 Repurchase of 10 million of Capital II 12/01/2000 10,000,000 1,240,421 1,191,618
15 Misc 2002 Repurchase Gains 01/01/2002 874,467 819,527
16 Misc 2003 Repurchase Gains 01/01/2003 369,767 343,974
17 COLSTRIP 2010A PCRBs DUE 2032 12/10/2010 66,700,000 ( 3,237,046) ( 3,087,411)
18 COLSTRIP 2010B PCRBs DUE 2034 12I10/2010 17,000,000 ( 1,044,481) ( 1,749,450)
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. 2 (12-96) Page 260
Name of Respondent This Re art Is:
(1)X An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
Reconciliation of Reported Net Income with Taxable Income for Feder Income Taxes
1.Report the reconciliation of reported net income for the year with taxable income used in computing Federal Income Tax accruals
and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on
Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate
clearly the nature of each reconciling amount.
2.If the utility is a member of a group that files consolidated Federal tax return, reconcile reported net income with taxable net income
as if a separate return were to be filed, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State
names of group members, tax assigned to each group member, and basis of allocation, assignments, or sharing of the consolidated tax
among the group members.
Line Details
(a)
Amount
(b)
1 Net Income for the Year (Page 116) 78,210,066
2 Reconciling Items for the Year
3
4 Taxable Income Not Reported on Books
3,398,971
6
7
8 TOTAL 3,398,971
9 Deductions Recorded on Books Not Deducted for Return
124,136,767
11
12
13 TOTAL 124,136,767
14 Income Recorded on Books Not Included in Return
14,239,687
16
17
18 TOTAL 14,239,687
19 Deductions on Return Not Charged Against Book Income
( 205,058,564) 20
21
22
23
24
25
26 TOTAL ( 205,058,564)
27 Federal Tax Net Income 61,262,765
28 Show Computation of Tax:
29 State Tax 379,911
30 Federal Rax Net Income less state tax 61642,676
31
32 Federal Tax © 35% 21,574,937
33 Prior year & misc true ups ( 8,077,924)
34 Cabinet Gorge Tax Credits 200,441
35 Total Federal Expense 13,311,067
FERC FORM NO. 2 (12-96) Page 261
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
1.Give details of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and
other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual or estimated amounts of such taxes are known 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 the
portion of prepaid taxes charged to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts.
4.List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Line
No
-
Kind of Tax
(See Instruction 5)
(a)
Balance at
Beg. of Year
Taxes Accrued
(b)
Balance at
Beg. of Year
Prepaid Taxes
(c)
1 FEDERAL:
2 Income Tax 2009 ( 118,190)
3 Income Tax 2olo 142,150
4 Income Tax 2011 ( 9,963,974)
5 Income Tax (Current)
6 Retained Earnings
7 Prior Retained Earnings (2010) ( 1,392,676)
8 Prior Retained Earnings (2011) ( 3,302,066)
9 Current Retained Earnings
10 Total Federal ( 14,634,756)
11
12 STATE OF WASHINGTON
13 Property Tax (2010) ( 3,193)
14 Property Tax (2011) 9,704,000
15 Properly Tax (2012)
16 Excise Tax (2010) ( 22,495)
17 Excise Tax (2011) 2,585,031
18 Excise Tax (2012)
19 Natural Gas Use Tax 12,729
20 Municipal Occupation Tax 3,123,004
21 Sales & Use Tax (2006) ( 8,173)
22 Sales & Use Tax (2011) 186,525
23 Sales & Use Tax (2012)
24 Motor Vehicle Tax (2012)
25 Total Washington 15,577,428
26
27 STATE OF IDAHO:
28 Income Tax (2010) ( 4,633)
29 Income Tax (2011) 258,945
30 Income Tax (2012)
31 Property Tax (2009) 1,647
32 Property Tax (2010) ( 3,870)
33 Property Tax (2011) 2,631,938
34 Property Tax (2012)
35 Motor Vehicle Tax (2012)
36 Sales & Use Tax (2005) 436
37 Sales & Use Tax (2010)
38 Sales & Use Tax (2011) 42,032
39 Sales & Use Tax (2012)
FERC FORM NO. 2 (REV 12-07) Page 262a
Name of Respondent This Re ort Is:
(1)X An Original (2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/1212013
Year/Period of Report
End of 2012/04
Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
(continued)
5.If any tax (exclude Federal and State income taxes) covers more than 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 footnote. Designate debit adjustments by parentheses.
7.Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing
authority.
8.Show in columns (i) thru (p) how the taxes accounts were distributed. Show both the utility department and number of account charged. For taxes charged to utility plant show the
number of the appropriate balance sheet plant account or subaccount
9.For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
10.Items under $250,000 may be grouped.
11 Report in column (q) the applicable effective state income tax rate.
Line
No
-
Taxes Charged
During Year
(d)
Taxes Paid
During Year
(e)
Adjustments
(f)
Balance at
End of Year
Taxes Accrued
(Account 236)
(g)
Balance at
End of Year
Prepaid Taxes
(Included in Acct 165)
(h)
2 ( 118,190)
3 6,913,541 1,370,785 ( 6,552,932) ( 868,026)
4 ( 2,571,551) ( 11,352,573) 5,321,340 4,138,388
5 16,441,880 15,012,803 1,429,077
6
7 ( 1,392,676)
8 1,231,592 ( 2,070,474)
9 ( 1,994,624) ( 1,994,624)
10 18,789,246 4,912,825 ( 758,335)
11
12
13 ( 8) 660 3,861
14 171,510 9,871,649 ( 3,861)
15 10,622,012 10,622,012
IL ( 22,495)
17 ( 17,932) 2,567,100
18 24,039,256 21,712,032 2,327,224
19 10,947 14,885 ( 8,181) 610
20 22,227,744 22,808,413 2,542,334
21 ( 8,173)
22 186,514 12
23 566,682 511,779 54,903
5,473 5,473
25 57,625,684 57,678,505 ( 8,181) 15,516,427
26
27
28 ( 4,633)
29 ( 129,632) ( 6,327)
_
135,640
30 377,042 400,000 ( 22,958)
31 ( 1,640) 7
32 3,870
33 ( 36,462) 2,595,476
34 6,179245 2,902,249 3,276,997
35 570 570
36 436
37
38 42,032
39 134,186 132,017 2,169
FERC FORM NO. 2 (REV 12-07) Page 263a
Name of Respondent This Re ort Is:
(1)X An Original (2)flA Resubmission
Date of Report
(Mo Da, Yr)
04/12/2013
Year/Period of Report
End of 2012104
Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
1.Give details of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and
other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual or estimated amounts of such taxes are known, 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 the
portion of prepaid taxes charged 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,
DISTRIBUTION OF TAXES CHARGED (Show utility department where applicable and account charged.)
Line
No
Electric
(Account 408.1,
409.1)
(i)
Gas
(Account 408. 1.
409.1)
U)
Other Utility Dept
(Account 408.1,
409.1)
(k)
Other Income and
Deductions
(Account 408.2,
409.2)
(I)
2
3 ( 73,728) 13,672
4 ( 1,292,964) ( 1,313,201)
5 19,284,594 ( 1964,559) ( 1,342,747)
6
7
8
9
10 17,917,902 ( 1,964,559) ( 2,642,276)
11
12
8)
14 145,116 5,098 21,642
15 8,493,012 2,093,000 36,000
16
17 (20,384) (1,867) 3,316
18 18,386,314 5,567,862 85,550
19 3,578
20 16,405,423 5,413,949
21
22
23
24
25 43,413,059 13,078,034 146,508
26
27
28
29 (103,706) (25,926)
30 388,842 (11,800)
31 (1,640)
32 4,316 (48)
33 (76,485) 78,341 (11,877)
34 5,064,040 1,112,585 10,630
35
36
37
38
39
FERC FORM NO. 2 (REV 12-07) Page 262b
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
(continued)
5.If any tax (exclude Federal and State income taxes) covers more than 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 ( and explain each adjustment in a footnote. Designate debit adjustments by parentheses.
7.Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing
authority.
8.Show in columns (i) thru (p) how the taxes accounts were distributed. Show both the utility department and number of account charged. For taxes charged to utility plant, show the
number of the appropriate balance sheet plant account or subaccount.
9.For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
10.Items under $250,000 may be grouped.
11.Report in column (q) the applicable effective state income tax rate.
DISTRIBUTION OF TAXES CHARGED (Show utility department where applicable and account charged.)
Line
No.
Extraordinary Items
(Account 409.3)
(m)
Other Utility Opn.
Income
(Account 408. 1,
409.1)
(n)
Adjustment to Ret.
Earnings
(Account 439)
(0)
Other
(p)
State/Local
Income Tax
Rate
(q)
2
3 6,973,597
4 34,614
5 464,593
6
7
8
9 ( 1,994,624)
10 5,478,180
11
12
13
14 ( 346)
15
16
17 1,003
18 ( 470)
19 7,369
20 408,372
21
22
23 566,682
24 5,473
25 988,083
26
27
28
29
30
31
32 ( 398)
33 ( 26,441)
34 ( 8,010)
35 570
36
37
38
39 134,186
FERC FORM NO. 2 (REV 12-07) Page 263b
Name of Respondent This Re ort Is:
(1)X An Original
(2)DA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
(continued)
Line
No
-
Kind of Tax
(See Instruction 5)
(a)
Balance at
Beg. of Year
Taxes Accrued
(b)
Balance at
Beg. of Year
Prepaid Taxes
(c)
1 Irrigation Credits (2012)
2 KWH Tax (2010) 1
3 KWH Tax (2011) 20,705
4 KWH Tax (2012)
5 Franchise Tax (2010) ( 15,507)
6 Franchise Tax (2011) 1,629,882
7 Franchise Tax (2012)
8 Total Idaho 4,561,576
9
10 STATE OF MONTANA
11 Income Tax (2010) ( 171,969)
12 Income Tax (2011) 489,040
13 Income Tax (2012)
14 Property Tax (2011) 3,454,233
15 Property Tax (2012)
16 Colstrip Generation Tax
17 KWH Tax (2011) 267,607
18 KWH Tax (2012)
19 Motor Vehicle Tax (2012)
20 Consumer Council Tax 6
21 Public Commission Tax 10
22 Total Montana 4,038,927
23
24 STATE OF OREGON
25 Income Tax (2007) ( 230,262)
26 Income Tax (2010) 91,318
27 Income Tax (2011) 386,749
28 Income Tax (2012)
29 Property Tax (2009)
30 Property Tax (2010) ( 1,791,031)
31 Property Tax (2011) ( 95,501)
32 Property Tax (2012)
33 Motor Vehicle Tax (2012)
34 BETC Credit (2010) 1,448
35 BETC Credit (2011) ( 365,909)
36 BETC Credit (2012)
37 Glendate Regulatory Cr. 2008 ( 210,889)
38 Glendale Regulatory Cr. 2009 70,289
39 Franchise Tax (2010) 25,602
FERC FORM NO. 2 (REV 12-07) Page 262a.1
Name of Respondent This Re ort Is:
(1)An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Yea Period of Report
End of 2012/04
Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
(continued)
Line
-
Taxes Charged
During Year
(d)
Taxes Paid
During Year
(e)
Adjustments
(0
Balance at
End of Year
Taxes Accrued
(Account 236)
(g)
Balance at
End of Year
Prepaid Taxes
(Included in Acct 165)
(h)
2 1 2
3 264 20,969
4 399,680 364,000 35,680
5 15,507
6 1,614,375 ( 15,507)
7 4,318,446 2,837,684 1,480,762
8 11,245,570 10,903,054 4,904,093
9
10
11 ( 179,683) 7,714
12 ( 99,269) 389,771
13 252,779 225,000 27,779
14 965 3,455,198
15 7,219,743 3,619,369 3,600,374
16 3,048 3,048
17 267,608
18 1,137,780 858,252 279,528
19 1,819 1,819
20 50 21 34
21 138 35 113
22 8,517,053 8,250,667 4,305,313
23
24
25 230,262
26 ( 230,262) ( 138,944)
27 ( 379,351) 7,398
28 356,742 125,000 231,742
29
30 1,894,942 ( 103,911)
31 1,973,371 1,927,159 49,289
32 2,030,655 54,622 ( 1,976,033)
33 2,057 2,057
34 1,448
35 ( 365,909)
36 ( 18,696) ( 18,696)
37 ( 210,889)
38 70,289
39 24,921 681
FERC FORM NO. 2 (REV 12-07) Page 263a.1
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
(continued)
DISTRIBUTION OF TAXES CHARGED (Show utility department where applicable and account charged.)
Line
No.
-
Electric
(Account 408,1,
409.1)
(I)
Gas
(Account 408. 1,
409.1)
)
Other Utility Dept
(Account 408.1,
409.1)
(k)
Other Income and
Deductions
(Account 408.2,
409.2)
(I)
1
3 264
4 399,680
5
6
7 3,150,983 1,160,207
8 8,826,295 2,313,407 ( 1,295)
9
10
11
12 ( 99,269)
13 252,779
14 965
15 7,219,743
16 3,048
17
18 1,137,780
19
50
21 138
22 8,515,234
23
24
25
26
27 ( 94,838) ( 284,513)
28 89,184 267,558
29
30 1,004,911 890,031
31 896,176 1,077,196
32
33
34
35
36
37
38
39
FERC FORM NO. 2 (REV 12-07) Page 262b.1
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Yea Period of Report
End of 2012/Q4
Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
(continued)
DISTRIBUTION OF TAXES CHARGED (Show utility department where applicable and account charged.)
Line
No.
Extraordinary Items
(Account 409.3)
(m)
Other Utility Opn.
Income
(Account 408.1,
409.1)
(n)
Adjustment to Ret
Earnings
(Account 439)
(0)
Other
(p)
State/Local
Income Tax
Rate
(q)
2
3
4
5
6
7 7,256
8 107,163
9
10
11
12
13
14
15
16
17
18
19 1819
20
21
22 1819
23 _ 24
25
26
27
28
29 _ 30
31
32
33 _2057
34
35
36 (18696)
37
38
39
FERC FORM NO. 2 (REV 12-07) Page 263b.1
Name of Respondent This Re ort Is:
(1)X An Original
(2)DA Resubmission
Date of Report
(Mo, Da, Yr) 1 04/12/2013
Year/Period of Report
End of 2012/04
Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
(continued)
Line
No
-
Kind of Tax
(See Instruction 5)
(a)
Balance at
Beg. of Year
Taxes Accrued
(b)
Balance at
Beg. of Year
Prepaid Taxes
(c)
1 Franchise Tax (2011) 903,082
2 Franchise Tax (2012)
3 Total Oregon ( 1,215,104)
4
5 STATE OF CALIFORNIA
6 Income Tax (2010) ( 800)
7 Income Tax (2011) ( 7,925)
8 Income Tax (2012)
9 Total California ( 8,725)
10
11 MISCELLANEOUS STATES:
12 Income Tax (2011)
13 Income Tax (2012)
14 Total Misc States
15
16 COUNTY & MUNICIPAL
17 WA Renewable Energy ( 561)
18 Misc. ( 26,441)
19 Total County ( 27,002)
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
TOTAL 8,292,344
FERC FORM NO. 2 (REV 12-07) Page 262a.2
Name of Respondent This Re art Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Yea Period of Report
End of 2012/Q4
Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
(continued)
Line
No
-
Taxes Charged
During Year
(d)
Taxes Paid
During Year
(e)
Adjustments
(0
Balance at
End of Year
Taxes Accrued
(Account 236)
(g)
Balance at
End of Year
Prepaid Taxes
(Included in Acct 165)
(h)
1 876,166 26,916
2 3,672,794 2,924,589 748,205
3 7,501,659 7,910,547 ( 1,623,792)
4
5
6 ( 800)
7 1,600 ( 6,325)
8 1,600 ( 1,600)
9 1,600 800 ( 7,925)
10
11
12
13
14
15
16
17 ( 103,659) ( 103,659) ( 561)
18 28,535 35,852 8,181 ( 25,577)
19 ( 75,124) ( 67,807) 8,181 ( 26,138)
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
39
TOTAL 103,605,888 89,588,591 ( 1) 22,309,642
FERC FORM NO. 2 (REV 12-07) Page 263a.2
Name of Respondent This Re ort Is:
(1)X An Original
(2)E]A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
(continued)
DISTRIBUTION OF TAXES CHARGED (Show utility department where applicable and account charged.)
Line
No.
-
Electric
(Account 408.1
409.1)
(I)
Gas
(Account 408.1,
409.1)
(j)
Other Utility Dept
(Account 408.1
409.1)
(k)
Other Income and
Deductions
(Account 408,2,
409.2)
(I)
2 3650,378
3 1895,433 5,600,650
4
5
6
7 1,600
8
1,600
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
TOTAL 80,567,923 19,029,132 ( 2,497,063)
FERC FORM NO. 2 (REV 12-07) Page 262b.2
Name of Respondent This Rort Is: ep
(1)An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Taxes Accrued, Prepaid and Charged During Year, Distribution of Taxes Charged (Show utility dept where applicable and acct charged)
(continued)
DISTRIBUTION OF TAXES CHARGED (Show utility department where applicable and account charged.)
Line
No.
Extraordinary Items
(Account 409.3)
Other Utility Opn.
Income
(Account 408.1
409.1)
(n)
Adjustment to Ret
Earnings
(Account 439)
(0)
Other
(p)
State/Local
Income Tax
Rate
(q)
2 22,416
3 5,777
4
5
6
7
8
9
10
11
12
13
14
15
16
17 ( 103,659)
18 28,535
19 ( 75,124)
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
TOTAL 6,505,898
FERC FORM NO. 2 (REV 12-07) Page 263b.2
Name of Respondent This Re ort Is:
(1)X An Original
(2)[JA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Miscellaneous Current and Accrued Liabilities (Account 242)
1.Describe and report the amount of other current and accrued liabilities at the end of year.
2.Minor items (less than $250,000) may be grouped under appropriate title.
Line
No.
Item
(a)
Balance at
End of Year
(b)
1 Margin Call Deposit (242050) 470,000
2 Forest Use Permits (242060) 3,761,270
3 Settlement Payable (242090) 500,000
4 Mirabeau Accrued Rent (242095) 55,958
5 Audit Exp Acc (242200)
6 FERC Admin Fee ACC (242300) 543,000
7 FERC Elec Admin Charge (242310) 88,522
8 MT Lease Payments (242375) 4,479,200
9 Misc Non Mon Power Exchange (242500) 70,279
10 DSM Tariff Rider
11 Payroll EOLZTN (242700) 17,013,973
12 Low Income Energy Assist (242700) 3,618,273
13 Avista Grants Eng Sustain WSU-ASL (242780) 225,566
14 Mobius (242790) 250,000
15 Worker's Comp Liability (242830) 2,278,678
16 Accts Payable Inventory Accruals-SC (242900) 507,173
17 Accts Paybel Expense Accruals-SC (242910) 3,178,046
18 Current Portion-Benefit Liab 4,815,885
19 Misc Clearing Adjustments 19,475,834
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 Total 61,331,657
FERC FORM NO. 2 (12-96) Page 268
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Other Deferred Credits (Account 253)
1.Report below the details called for concerning other deferred credits.
2.For any deferred credit being amortized, show the period of amortization.
3.Minor items (less than $250,000) may be grouped by classes,
Line
No. Description of Other
Deferred Credits
(a)
Balance at
Beginning
of Year
(b)
Debit
Contra
Account
(c)
Debit
Amount
(d)
Credits
(e)
Balance at
End of Year
(t)
1 Defer Gas Exchange (253028) 1,500,000 495 10 1,499,990
2 Pacificorp Capacitor (253080)
3 Centralia Enviromental (253110)
4 Rathdrum Refund (253120) 273,398 550 33,822 239,576
5 NE Tank Spill (253130) 70,367 186 53,570 16,797
6 Bills Pole Rentals (253140) 257,105 23,855 280,960
7 CR-CS2 GE LTSA (253150) 2,999,302 2,999,302
8
9 Regulatory Accruals (253650)
10 Sale/Leaseback on Bldg(253850)
11 ID Clark Fork Relic ( 452,847) 452,847
12 Defer Comp Retired Execs (253900) 79,658 431 20,409 59,249
13 Defer Comp Active Execs (253910) 8,652,744 153,406 8,806,150
14 Executive Incent Plan (253920) 140,000 140,000
15 Unbilled Revenue (253990) 1,812,993 908 1,129,552 683,441
16
17 DOC EECE Grant 850,255 136 97,705 752,550
18 DOC EECE Admin Fee
19 Idaho Clark Fork 452,846 452,846
20 L ERM 12,947,628 12,947,628 8,756,638 8,756,638
21 f Misc Def Debits 357,782 357,782
22 Credit Resource Mng 1,577,531 1,577,531
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45 Total 26,584,147 14,735,542 14,321,361 26,169,966
FERC FORM NO. 2 (12-96) Page 269
Name of Respondent This Re ort Is:
(1)X An Original
(2)[]A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Accumulated Deferred Income Taxes-Other Property (Account 282)
1.Report the information called for below concerning the respondents accounting for deferred income taxes relating to property not subject to accelerated amortization.
2.At Other (Specify), include deferrals relating to other income and deductions.
Line °
-
Account Subdivisions
(a)
Balance at
Beginning
of Year
(b)
Amounts
Debited to
Account 410.1
(C)
Amounts
Credited to
Account 411.1
(d)
1 Account 282
269,492281 7,435,394 2 Electric
3 Gas 96,448,805 5,665,663
4 Other (Define) (footnote details) 32,559,207 7,690,353
5 Total (Enter Total of lines 2 thru 4) 398,500,293 20,791,410
6 Other (Specify) (footnote details)
7 TOTAL Account 282 (Enter Total of lines 5 thr 398500,293 20,791,410
8 Classification of TOTAL
20,791,410 9 Federal Income Tax 387,433,970
10 State Income Tax 11,066,323
11 Local Income Tax
FERC FORM NO. 2 (REV 12-07) Page 274
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Accumulated Deferred Income Taxes-Other Property (Account 282) (continued)
3. Provide in a footnote a summary of the type and amount of deferred income taxes reported in the beginning-of-year and end-of-year balances for deferred income taxes that the
respondent estimates could be included in the development of jurisdictional recourse rates.
Line
No.
Changes during
Year
Amounts Debited
to Account 410.2
(e)
Changes during
Year
Amounts Credited
to Account 411.2
(f)
Adjustments
Debits
Acct. No.
(g)
Adjustments
Debits
Amount
(h)
Adjustments
Credits
Account No.
(i)
Adjustments
Credits
Amount
(j)
Balance at
End of Year
(k)
2 276,927675
3 102,114,468
4 ( 75090) 40,174,470
5 ( 75,090) 419,216,613
6
7 ( 75,090) 419,216,613
8
9 ( 75,090) 408,150,290
11,066,323
11
FERC FORM NO. 2 (REV 12-07) Page 275
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Accumulated Deferred Income Taxes-Other (Account 283)
1.Report the information called for below concerning the respondents accounting for deterred income taxes relating to amounts recorded in Account 283.
2.At Other (Specify), include deferrals relating to other income and deductions.
Line
O
-
Account Subdivisions
(a)
Balance at
Beginning
of Year
(b)
Changes During Year
Amounts
Debited to
Account410.1
(c)
Changes During Year
Amounts
Credited to
Account 411.1
(d)
1 Account 283
28,652,909 ( 8,327,674) 512,038 2 Electric
3 Gas ( 3,884,914) 1,801,980
4 Other (Define) (footnote details) 234,876,525 4,169,890
5 Total (Total of lines 2 thru 4) 259,644,520 ( 2,355,804) 512,038
6 Other (Specify) (footnote details)
7 TOTAL Account 283 (Total of lines 5 thru 259,644,520 ( 2,355,804) 512,038
8 Classification of TOTAL
9 Federal Income Tax 255,410,714 ( 2,355,804) 512,038
10 State Income Tax 4,233,806
11 Local Income Tax
FERC FORM NO. 213Q (REV 12-07) Page 276
Name of Respondent This Report Is:
(1)An Original
(2)JA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Accumulated Deferred Income Taxes-Other (Account 283) (continued)
3. Provide in a footnote a summary of the type and amount of deferred income taxes reported in the beginning-of-year and end-of-year balances for deferred income taxes that the
respondent estimates could be included in the development of jurisdictional recourse rates.
Line
Changes during
Year
Amounts Debited
to Account 410.2
(e)
Changes during
Year
Amounts Credited
to Account 411.2
(f)
Adjustments
Debits
Acct. No.
(g)
Adjustments
Debits
Amount
(h)
Adjustments
Credits
Account No.
(I)
Adjustments
Credits
Amount
U)
Balance at
End of Year
(k)
737,482 17,538,524 2 ( 1,537,191)
3 ( 279,708) ( 1,803,226)
4 4,818,267 ( 4,281,489) 229,946,659
5 ( 1,537,191) 4,818,267 ( 4,281,489) 457,774 245,681,957
6
7 ( 1,537,191) 4,818,267 ( 4,281,489)1 457,774 245,681,957
8
( 4,281,489) 457,774 241,448151 9 ( 1,537,191) 4,818,267
10 4,233,806
11
FERC FORM NO. 2!30 (REV 12-07) Page 277
This Page Intentionally Left Blank
Name of Respondent I This Re ort Is:
(1)X An Original
(2)DA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
Other Regulatory Liabilities (Account 254)
1.Report below the details called for concerning other regulatory liabilities which are created through the ratemaking actions of regulatory agencies (and not
includable in other amounts).
2.For regulatory liabilities being amortized, show period of amortization in column (a).
3.Minor items (5% of the Balance at End of Year for Account 254 or amounts less than $250,000, whichever is less) may be grouped by classes.
4.Provide in a footnote, for each line item, the regulatory citation where the respondent was directed to refund the regulatory liability (e.g. Commission Order, state
commission order, court decision).
Line
No Description and Purpose of
Other Regulatory Liabilities
(a)
Balance at
Beginning of
Current
Quarter/Year
(b)
Written off during
Quarter/Period
Account
Credited
(c)
Written off
During Period
Amount
Refunded
(d)
Written off
During Period
Amount Deemed
Non-Refundable
(e)
Credits
(f)
Balance at
End of Current
Quarter/Year
(g)
1 Idaho Investment Tax Credit (254005) 12,316,7 190 8,670 12,308,073
2 Oregon BETC Credit (254010) 69,82: 1,484,162 1,553,984
3 Noxon, ITC (254025) 2,737,10: 606,909 3,344,017
4 Defer Gas Exchange (254028)
5 FAS 109 Invest Tax Credit (254180) 126,25 190 22,64 103,608
6 jNez Perce (254220) 704,374 557 22,008 682,364
7 Oregon Senate Bill (254250) 771,59A 407 842,062 1 70,470)
8 Reg Liability CCX CR ID (254300)
9 Accrue Lake CDA IPA mt (254325)
10 BPA Res Exch Regulatory Liab (254345) 178,32E 186 178,328
11 Unrealized Currency Exchange (254399) 11,09J 143 7,495 3,602
12 Reg Liability Other (254700)
13 Mark to Market ST (254740) 25,46E 176 25,46
14 Mark to Market FAS1 33 (254750)
15 Idaho DSIT 3,483,47d 407 3,483,47
16 Colstrip/CS2 516,251 516,251 1
17 Oregon Commercial Fee ( 655 805 1,288 ( 1,943)
18 Decoupling Rebate 5,531 5,531
19 Reg Liability WA Recs 93,222 93,222
20 Idaho PCA 18,566,192 18,566,192
21 SWAPS on FMBS 18,656,780 18,656,780
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45 Total 20,939,852M 5,107,686 0 39,412,796 55,244,962 r
FERC FORM NO. 2130 (REV 12-07) Page 278
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Gas Operating Revenues
1.Report below natural gas operating revenues for each prescribed account total. The amounts must be consistent with the detailed data on succeeding pages.
2.Revenues in columns (b) and (C) include transition costs from upstream pipelines.
3.Other Revenues in columns (f) and (g) include reservation charges received by the pipeline plus usage charges, less revenues reflected in columns (b) through (e). Include in
columns (t) and (g) revenues for Accounts 480-495.
Line
No.
-
Title of Account
(a)
Revenues for
Transition
Costs and
Take-or-Pay
Amount for
Current Year
(b)
Revenues for
Transition
Costs and
Take-or-Pay
Amount for
Previous Year
(c)
Revenues for
GRI and ACA
Amount for
Current Year
(d)
Revenues for
GRI and ACA
Amount for
Previous Year
(e)
1 480 Residential Sales
2 481 Commercial and Industrial Sales
3 482 Other Sales to Public Authorities
4 483 Sales for Resale
5 484 Interdepartmental Sales
6 485 lntracompany Transfers
7 487 Forfeited Discounts
8 488 Miscellaneous Service Revenues
9
-
489.1 Revenues from Transportation of Gas of Others
Through Gathering Facilities
10
-
489.2 Revenues from Transportation of Gas of Others
Through Transmission Facilities
11
-
489.3 Revenues from Transportation of Gas of Others
Through Distribution Facilities
12 489.4 Revenues from Storing Gas of Others
13 490 Sales of Prod. Ext from Natural Gas
14 491 Revenues from Natural Gas Proc. by Others
15 492 Incidental Gasoline and Oil Sales
16 493 Rent from Gas Property
17 494 Interdepartmental Rents
18 495 Other Gas Revenues
19 Subtotal:
20 496 (Less) Provision for Rate Refunds
21 TOTAL:
FERC FORM NO. 2 (REV 12-07) Page 300
Name of Respondent This Re ort Is:
(1)X An Original
(2)[:]A Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
ear Period of Report
End of 2012/Q4
Gas Operating Revenues
4.If increases or decreases from previous year are not derived from previously reported figures, explain any inconsistencies in a footnote.
5.On Page 108, include information on major changes during the year, new service, and important rate increases or decreases.
6.Report the revenue from transportation services that are bundled with storage services as transportation service revenue.
Line
No.
-
Other
Revenues
Amount for
Current Year
(f)
Other
Revenues
Amount for
Previous Year
(g)
Total
Operating
Revenues
Amount for
Current Year
(Ii)
Total
Operating
Revenues
Amount for
Previous Year
(i)
Dekatherm of
Natural Gas
Amount for
Current Year
a)
Dekatherm of
Natural Gas
Amount for
Previous Year
(k)
1 196,718,688 219,557,360 196,718,688 219,557,360 18,915,226 20720,154
2 104,861,465 118,663,581 104,861465 118,663,581 12,451,835 13,550,183
3
4 160,769,449 210,967,741 160,769,449 210,967,741 60,478,027 53,875,981
5 291,260 347,915 291,260 347,915 38,137 i 44,000
6
7
8 169,923 168,994 169,923 168,994
10
11
7,031,672 6,708,968 7,031,672 6,708,968 15,470,439 15,251503
13
14
15
16 3,713 2,939 3,713 2,939
17
18 6,465,265 6,894,207 6,465,265 6,894,206
19 476,311,435 563,311,705 476,311,435 563,311,704
20
21 476,311,435 563,311,705 476,311,435 563,311704
FERC FORM NO. 2 (REV 12-07) Page 301
Name of Respondent This Re ort Is:
(1)X An Original
(2)El A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/ Period of Report
End of 2012/Q4
Other Gas Revenues (Account 495)
Report below transactions of $250,000 or more included in Account 495, Other Gas Revenues. Group all transactions below $250,000
in one amount and provide the number of items.
Line
No
Description of Transaction
(a)
Amount
(in dollars)
(b)
1 Commissions on Sale or Distribution of Gas of Others
2 Compensation for Minor or Incidental Services Provided for Others
3 Profit or Loss on Sale of Material and Supplies not Ordinarily Purchased for Resale
4 Sales of Stream, Water, or Electricity, including Sales or Transfers to Other Departments
5 Miscellaneous Royalties
6 Revenues from Dehydration and Other Processing of Gas of Others except as provided for in the Instructions to Account 495
7 Revenues for Right and/or Benefits Received from Others which are Realized Through Research, Development, and Demonstration Ventures
8 Gains on Settlements of Imbalance Receivables and Payables
9 Revenues from Penalties earned Pursuant to Tariff Provisions, including Penalties Associated with Cash-out Settlements
10 Revenues from Shipper Supplied Gas
11 Other revenues (Specify):
12 Misc Bills 428,851
13 DSM Lost Margin (Oregon) 36,414
14 Deferred Exchange Revenue 6,000,000
15
16
17
18 j
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35-
36
37
38
39
Total 6,465,265
FERC FORM NO. 2 (12-96) Page 308
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year Period of Report
End of 2012/04
Gas Operation and Maintenance Expenses
Line
No.
-
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
1 1. PRODUCTION EXPENSES
2 A. Manufactured Gas Production
0 0 3 Manufactured Gas Production (Submit Supplemental Statement) I
4 B. Natural Gas Production
5 BI. Natural Gas Production and Gathering
6 Operation
0 0 7 750 Operation Supervision and Engineering
8 751 Production Maps and Records 0 0
9 752 Gas Well Expenses 0 0
10 753 Field Lines Expenses 0 0
11 754 Field Compressor Station Expenses 0 0
12 755 Field Compressor Station Fuel and Power 0 0
13 756 Field Measuring and Regulating Station Expenses 0 0
14 757 Purification Expenses 0 0
15 758 Gas Well Royalties 0 0
16 759 Other Expenses 0 0
17 760 Rents 0 0
18 TOTAL Operation (Total of lines 7 thru 17) 0 0
19 Maintenance
20 761 Maintenance Supervision and Engineering 0 0
21 762 Maintenance of Structures and Improvements 0 0
22 763 Maintenance of Producing Gas Wells 0 0
23 764 Maintenance of Field Lines 0 0
24 765 Maintenance of Field Compressor Station Equipment 0 0
25 766 Maintenance of Field Measuring and Regulating Station Equipment 0 0
26 767 Maintenance of Purification Equipment 0 0
27 768 Maintenance of Drilling and Cleaning Equipment 0 0
28 769 Maintenance of Other Equipment 0 0
29 TOTAL Maintenaflee (Total of lines 20 thru 28) 0 0
30 TOTAL Natural Gas Production and Gathering (Total of lines 18 and 29) 0 0
FERC FORM NO. 2 (12-96) Page 317
Name of Respondent This Report Is:
(1)X An Original
(2)[]A Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
- Gas Operation and Maintenance Expenses(continued)
Line
No.
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(C)
31 B2. Products Extraction
32 Operation
0 0 33 770 Operation Supervision and Engineering
34 771 Operation Labor 0 0
35 772 Gas Shrinkage 0 0
36 773 Fuel 0 0
37 774 Power 0 0
38 775 Materials 0 0
39 776 Operation Supplies and Expenses 0 0
40 777 Gas Processed by Others 0 0
41 778 Royalties on Products Extracted 0 0
42 779 Marketing Expenses 0 0
43 780 Products Purchased for Resale 0 0
44 781 Variation in Products Inventory S 9 0
45 (Less) 782 Extracted Products Used by the Utility-Credit 0 0
46 783 Rents 0 0
47 TOTAL Operation (Total of lines 33 thru 46) 0 0
48 Maintenance
0 0 49 784 Maintenance Supervision and Engineering
50 785 Maintenance of Structures and Improvements 0 0
51 786 Maintenance of Extraction and Refining Equipment 0 0
52 787 Maintenance of Pipe Lines 0 0
53 788 Maintenance of Extracted Products Storage Equipment 0 0
54 789 Maintenance of Compressor Equipment 0 0
55 790 Maintenance of Gas Measuring and Regulating Equipment 0 0
56 791 Maintenance of Other Equipment 0 0
57 TOTAL Maintenance (Total of lines 49 thru 56) 0 0
58 TOTAL Products Extraction (Total of lines 41 and 57) 0 0
FERC FORM NO. 2 (12-96) Page 318
Name of Respondent This Re ort Is:
(1)X An Original
(2)EJA Resubmission
Date of Report (Mo, Da, Yr) 1 04/12/2013
Year/Period of Report
End of 2012/04
Gas Operation and Maintenance Expenses(continued) -
Line
No.
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(C)
59 C. Exploration and Development
60 Operation
0 0 61 795 Delay Rentals
62 796 Nonproductive Well Drilling 0 0
63 797 Abandoned Leases 0 0
64 798 Other Exploration 0 0
65 TOTAL Exploration and Development (Total of lines 61 thru 64) 0 0
66 D. Other Gas Supply Expenses
67 Operation
0 0 68 800 Natural Gas Well Head Purchases I
69 800.1 Natural Gas Well Head Purchases, Intracompany Transfers 0 0
70 801 Natural Gas Field Line Purchases 0 0
71 802 Natural Gas Gasoline Plant Outlet Purchases 0 0
72 803 Natural Gas Transmission Line Purchases 0 0
73 804 Natural Gas City Gate Purchases 324,767,750 419,658,497
74 804.1 Liquefied Natural Gas Purchases 0 0
75 805 Other Gas Purchases 0 0
76 (Less) 805.1 Purchases Gas Cost Adjustments 5,804,491 10,040,828
77 TOTAL Purchased Gas (Total of lines 68 thru 76) 318,963,259 409,617,669
78 806 Exchange Gas 0 0
79 Purchased Gas Expenses
0 0 80 807.1 Well Expense-Purchased Gas
81 807.2 Operation of Purchased Gas Measuring Stations 0 0
82 807.3 Maintenance of Purchased Gas Measuring Stations 0 0
83 807.4 Purchased Gas Calculations Expenses 0 0
84 807.5 Other Purchased Gas Expenses 0 0
85 TOTAL Purchased Gas Expenses (Total of lines 80 thru 84) 0 0
FERC FORM NO. 2 (12-96) Page 319
Name of Respondent This Re ort Is:
(1)X An Original
(2)E]A Resubmission
Date of Report
(MO, Da, Yr) 1 04/12/2013
Year/Period of Report
End of 2012/04
Gas Operation and Maintenance Expenses(continued) -
Line
No.
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(C)
86 808.1 Gas Withdrawn from Storage-Debit 29,510,790 35,608,018
87 (Less) 808.2 Gas Delivered to Storage-Credit 23,177,606 41,974,554
88 809.1 Withdrawals of Liquefied Natural Gas for Processing-Debit 0 0
89 (Less) 809.2 Deliveries of Natural Gas for Processing-Credit 0 0
90 Gas used in Utility Operation-Credit
0 0 91 810 Gas Used for Compressor Station Fuel-Credit
92 811 Gas Used for Products Extraction-Credit 1,648,718 1,866,763
93 812 Gas Used for Other Utility Operations-Credit 0 0
94 TOTAL Gas Used in Utility Operations-Credit (Total of lines 91 thru 93) 1,648,718 1,866,763
95 813 Other Gas Supply Expenses 1,881,894 2,060,484
96 TOTAL Other Gas Supply Exp. (Total of lines 77,78,85,86 thru 89,94,95) 325,529,619 403,444,854
97 TOTAL Production Expenses (Total of lines 3, 30, 58, 65, and 96) 325,529,619 403,444,854
98 2. NATURAL GAS STORAGE, TERMINALING AND PROCESSING EXPENSES
99 A. Underground Storage Expenses
100 Operation
18,245 13,813 101 814 Operation Supervision and Engineering
102 815 Maps and Records 0 0
103 816 Wells Expenses 0 0
104 817 Lines Expense 0 0
105 818 Compressor Station Expenses 0 0
106 819 Compressor Station Fuel and Power 0 0
107 820 Measuring and Regulating Station Expenses 0 0
108 821 Purification Expenses 0 0
109 822 Exploration and Development 0 0
110 823 Gas Losses 0 0
111 824 Other Expenses 600,910 472,924
112 825 Storage Well Royalties 0 0
113 826 Rents 0 0
114 TOTAL Operation (Total of lines of 101 thru 113) 619,155 486,737
I
FERC FORM NO. 2 (12-96) Page 320
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
Gas Operation and Maintenance Expenses(continued) -
Line
No.
Account -
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(C)
115 Maintenance
0 0 116 830 Maintenance Supervision and Engineering
117 831 Maintenance of Structures and Improvements 0 0
118 832 Maintenance of Reservoirs and Wells 0 0
119 833 Maintenance of Lines 0 0
120 834 Maintenance of Compressor Station Equipment 0 0
121 835 Maintenance of Measuring and Regulating Station Equipment 0 0
122 836 Maintenance of Purification Equipment 0 0
123 837 Maintenance of Other Equipment 504,736 430,728
124 TOTAL Maintenance (Total of lines 116 thru 123) 504,736 430,728
125 TOTAL Underground Storage Expenses (Total of lines 114 and 124) I 1123,891 917,465
126 B. Other Storage Expenses
127 Operation
0 0 128 840 Operation Supervision and Engineering
129 841 Operation Labor and Expenses 0 0
130 842 Rents 0 0
131 842.1 Fuel 0 0
132 842.2 Power 0 0
133 842.3 Gas Losses 0 0
134 TOTAL Operation (Total of lines 128 thru 133) 0 0
135 Maintenance
0 0 136 843.1 Maintenance Supervision and Engineering
137 843.2 Maintenance of Structures 0 0
138 843.3 Maintenance of Gas Holders 0 0
139 843.4 Maintenance of Purification Equipment 0 0
140 843.5 Maintenance of Liquefaction Equipment 0 0
141 843.6 Maintenance of Vaporizing Equipment 0 0
142 843.7 Maintenance of Compressor Equipment 0 0
143 843.8 Maintenance of Measuring and Regulating Equipment 0 0
144 843.9 Maintenance of Other Equipment 0 0
145 TOTAL Maintenance (Total of lines 136 thru 144) 0 0
146 TOTAL Other Storage Expenses (Total of lines 134 and 145) 0 0
FERC FORM NO. 2 (12-96) Page 321
Name of Respondent This Re ort Is:
(1)X An Original
(2)[JA Resubmission
Date of Report
(Mo, Da, Yr) 1 04/12/2013
Year/Period of Report
End of 2012/04
Gas Operation and Maintenance Expenses(continued) -
Line
No.
-
Account
(a)
Amount for
Current Year
(b)
I
Amount for
Previous Year
(c)
147 C. Liquefied Natural Gas Terminaling and Processing Expenses
148 Operation
0 0 149 844.1 Operation Supervision and Engineering
150 844.2 LNG Processing Terminal Labor and Expenses 0 0
151 844.3 Liquefaction Processing Labor and Expenses 0 0
152 844.4 Liquefaction Transportation Labor and Expenses 0 0
153 844.5 Measuring and Regulating Labor and Expenses 0 0
154 844.6 Compressor Station Labor and Expenses 0 0
155 844.7 Communication System Expenses 0 0
156 844.8 System Control and Load Dispatching 0 0
157 845.1 Fuel 0 0
158 845.2 Power 0 0
159 845.3 Rents 0 0
160 845.4 Demurrage Charges 0 0
161. 845.5 Wharfage Receipts-Credit 0 0
162 845.6 Processing Liquefied or Vaporized Gas by Others 0 0
163 846.1 Gas Losses 0 0
164 846.2 Other Expenses 0 0
165 TOTAL Operation (Total of lines 149 thru 164) 0 0
166 Maintenance
0 0 167 847.1 Maintenance Supervision and Engineering
168 847.2 Maintenance of Structures and Improvements 0 0
169 847.3 Maintenance of LNG Processing Terminal Equipment 0 0
170 847.4 Maintenance of LNG Transportation Equipment 0 0
171 847.5 Maintenance of Measuring and Regulating Equipment 0 0
172 847.6 Maintenance of Compressor Station Equipment 0 0
173 847.7 Maintenance of Communication Equipment 0 0
174 847.8 Maintenance of Other Equipment 0 0
175 TOTAL Maintenance (Total of lines 167 thru 174) 0 0
176 TOTAL Liquefied Nat Gas Terminaling and Proc Exp (Total of lines 165 and 175) 0 0
177 TOTAL Natural Gas Storage (Total of lines 125, 146, and 176) 1,123,891 917,465
FERC FORM NO. 2 (12-96) Page 322
Name of Respondent This Re ort Is:
(1)X An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
Gas Operation and Maintenance Expenses(continued) -
Line
No.
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
178 3. TRANSMISSION EXPENSES
0 ' 0
179 Operation
180 850 Operation Supervision and Engineering I
181 851 System Control and Load Dispatching 0 0
182 852 Communication System Expenses 0 0
183 853 Compressor Station Labor and Expenses 0 0
184 854 Gas for Compressor Station Fuel 0 0
185 855 Other Fuel and Power for Compressor Stations 0 0
186 856 Mains Expenses 0 0
187 857 Measuring and Regulating Station Expenses 0 0
188 858 Transmission and Compression of Gas by Others 0 0
189 859 Other Expenses 0 0
190 860 Rents 0 0
191 TOTAL Operation (Total of lines 180 thru 190) 0 0
192 Maintenance
0 0 193 861 Maintenance Supervision and Engineering
194 862 Maintenance of Structures and Improvements 0 0
195 863 Maintenance of Mains 0 0
196 864 Maintenance of Compressor Station Equipment 0 0
197 865 Maintenance of Measuring and Regulating Station Equipment 0 0
198 866 Maintenance of Communication Equipment 0 0
199 867 Maintenance of Other Equipment 0 0
200 TOTAL Maintenance (Total of lines 193 thru 199) 0 0
201 TOTAL Transmission Expenses (Total of lines 191 and 200) 0 0
202 4. DISTRIBUTION EXPENSES
203 Operation
1,741,877 1,527,573 I
204 870 Operation Supervision and Engineering
205 871 Distribution Load Dispatching 0 0
206 872 Compressor Station Labor and Expenses 0 0
207 873 Compressor Station Fuel and Power 0 0
FERC FORM NO. 2 (12-96) Page 323
Name of Respondent This Rort Is:
(1)
ep
An Original
(2)DA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Gas Operation and Maintenance Expenses(continued) -
Line
No.
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(C)
208 874 Mains and Services Expenses 4,351,422 4,541,093
209 875 Measuring and Regulating Station Expenses-General 374,276 431,912
210 876 Measuring and Regulating Station Expenses-Industrial 9,972 34,524
211 877 Measuring and Regulating Station Expenses-City Gas Check Station 189,438 253,679
212 878 Meter and House Regulator Expenses 962,147 997,986
213 879 Customer Installations Expenses 2,438,556 2,574,363
214 880 Other Expenses 2,741,914 2,812,262
215 881 Rents 44,690 46,573
216 TOTAL Operation (Total of lines 204 thni 215) 12,854,292 13,219,965
217 Maintenance
151,586 222,923 218 885 Maintenance Supervision and Engineering
219 886 Maintenance of Structures and Improvements 0 0
220 887 Maintenance of Mains 3,009,123 2,957,960
221 888 Maintenance of Compressor Station Equipment 0 0
222 889 Maintenance of Measuring and Regulating Station Equipment-General 330,619 212,883
223 890 Maintenance of Meas. and Reg. Station Equipment-Industrial 254,583 125,295
224 891 Maintenance of Meas. and Reg. Station Equip-City Gate Check Station 72,997 120,959
225 892 Maintenance of Services 1679,077 1,257,549
226 893 Maintenance of Meters and House Regulators 1,728,218 1,449,627
227 894 Maintenance of Other Equipment 379,407 339,210
228 TOTAL Maintenance (Total of lines 218 thru 227) 7,605,610 6,686,406
229 TOTAL Distribution Expenses (Total of lines 216 and 228) 20,459,902 19,906,371
230 5. CUSTOMER ACCOUNTS EXPENSES
231 Operation
514,213 562,996 232 901 Supervision
233 902 Meter Reading Expenses 2,027,562 1,916,151
234 903 Customer Records and Collection Expenses 7,246,845 7,077,555
FERC FORM NO. 2 (12.96) Page 324
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report
(MO, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
Gas Operation and Maintenance Expenses(continued) -
Line
No.
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(C)
235 904 Uncollectible Accounts 1,894,921 2,339,734
236 905 Miscellaneous Customer Accounts Expenses 204,166 123,184
237 TOTAL Customer Accounts Expenses (Total of lines 232 thru 236) I 11,887,707 12,019,620
238 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
239 Operation
0 0 240 907 Supervision
241 908 Customer Assistance Expenses 9,662,065 15,489,692
242 909 Informational and Instructional Expenses 968,533 950,702
243 910 Miscellaneous Customer Service and Informational Expenses 156,805 118,938
244 TOTAL Customer Service and Information Expenses (Total of lines 240 thru 243) 10,787,403 I 16,559,332
245 7. SALES EXPENSES
0 0
246 Operation
247 911 Supervision I
248 912 Demonstrating and Selling Expenses 9,538 9,884
249 913 Advertising Expenses 0 96
250 916 Miscellaneous Sales Expenses 0 ( 2,314)
251 TOTAL Sales Expenses (Total of lines 247 thru 250) I 9,538 7,666
252 8. ADMINISTRATIVE AND GENERAL EXPENSES
253 Operation
I 13,722,096 I 9,045,117 254 920 Administrative and General Salaries
255 921 Office Supplies and Expenses 1637,195 1,551,004
256 (Less) 922 Administrative Expenses Transferred-Credit 36,687 30,489
257 923 Outside Services Employed 4,454,643 5,461,172
258 924 Property Insurance 440,286 401,856
259 925 Injuries and Damages 1,163,461 1,347,333
260 926 Employee Pensions and Benefits 355,696 371,905
261 927 Franchise Requirements 0 0
262 928 Regulatory Commission Expenses 2,110,126 1,744,486
263 (Less) 929 Duplicate Charges-Credit 0 0
264 930.1 General Advertising Expenses 796 288
265 930.2Miscellaneous General Expenses 1,368,295 1,148,499
266 931 Rents 362,461 316,193
267 TOTAL Operation (Total of lines 254 thru 266) 25,578,368 21,357,364
268 Maintenance
2,785,790 2,770,102 269 932 Maintenance of General Plant
270 TOTAL Administrative and General Expenses (Total of lines 267 and 269) 28,364,158 24,127,466
271 TOTAL Gas O&M Expenses (Total of lines 97,177,201,229,237,244,251, and 270) 398,162,218 476,982,774
FERC FORM NO. 2 (12-96) Page 325
Name of Respondent This Re ort Is:
(1)X An Original (2)flA Resubmission
Date of Report
(MO, Da, Yr)
04/1212013
Year/Period of Report
End of 2012/Q4
Gas Used in Utility Operations
1.Report below details of credits during the year to Accounts 810, 811, and 812.
2.If any natural gas was used by the respondent for which a charge was not made to the appropriate operating expense or other account, list separately in column (c) the Dth of gas
used, omitting entries in column (d).
Line
No.
Purpose for Which Gas
Was Used
(a)
Account
Charged
(b)
Natural Gas
Gas Used
0th
(c)
Natural Gas
Amount of
Credit
(in dollars)
(d)
Natural Gas
Amount of
Credit
(in dollars)
(d)
Natural Gas
Amount of
Credit
(in dollars)
(d)
1 810 Gas Used for Compressor Station Fuel - Credit 804 4,085,538
2 811 GasUsedforProductsExtraction -Credit 811 2,145,630 1,648,718
3 Gas Shrinkage and Other Usage in Respondents
Own Processing
4
-
Gas Shrinkage, etc. for Respondents Gas
Processed by Others
5 812 Gas Used for Other Utility Operations - Credit
(Report separately for each principal use. Group
minor uses.)
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25 Total 6,231,168 1,648,718
FERC FORM NO. 2 (12-96) Page 331
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
(2)_A Resubmission 04/12/2013 2012/Q4
FOOTNOTE DATA
$chedule Page: 331 Line No.: I Column: d
Dollar values related to compressor fuel are not separately recorded. These dollars are included in total gas purchase
costs.
I FERC FORM NO. 2 (12-96) Page 552.1 I
Name of Respondent This Re ort Is:
(1)[X ]An Original
(2)DA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Other Gas Supply Expenses (Account 813)
1. Report other gas supply expenses by descriptive tifles that clearly indicate the nature of such expenses. Show maintenance expenses, revaluation of monthly encroachments
recorded in Account 117.4, and losses on settlements of imbalances and gas losses not associated with storage separately. Indicate the functional classification and purpose of property
to which any expenses relate. List separately items of $250000 or more.
Line
No.
Description
(a)
Amount
(in dollars)
(b)
1 Gas Resource Management
2 Labor 663,194
3 Labor Loading 558230
4 Other Expenses (Professional Services, Travel, Office Supplies, Training) 180,504
5
6 Regulatory Affairs
7 Labor 165,591
8 Labor Loading 139,207
9 Other Expenses (Travel, Transportation, Gas Technology Institute payments) 175,168
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25 Total .
1881,894
FERC FORM NO. 2 (12-96) Page 334
Name of Respondent This Re ort Is:
(1)X An Original
(2)CIA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Yea Period of Report
End of 2012/Q4
Miscellaneous General Expenses (Account 930.2)
1.Provide the information requested below on miscellaneous general expenses.
2.For Other Expenses, show the (a) purpose, (b) recipient and (c) amount of such items. List separately amounts of $250,000 or more however, amounts less than $250,000 may be
grouped if the number of items of so grouped is shown.
Line
No.
Description
(a)
Amount
(in dollars)
(b)
1 Industry association dues. 488,891
2 Experimental and general research expenses.
a.Gas Research Institute (GRI)
b.Other
3 Publishing and distributing information and reports to stockholders, trustee, registrar, and transfer
41,480 - agent fees and expenses, and other expenses of servicing outstanding securities of the respondent
4 Other expenses
5 Director Fees and Expenses
6 Miscellaneous General Expenses
19,095 7 Community Relations
8 Educational - Informational 54,757
9 Other miscellaneous General Expenses 110
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25 Total 1,368,295
FERC FORM NO. 2 (12-96) Page 336
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
FOOTNOTE DATA
,le Page: 335 Line No.: 5 Column: b
ule Pane: 335 Line No.: 10
Directors 2012 Expenses
Vendor Name
HEIDI B STANLEY $26,325
MARC F RACICOT $23,691
ERIK ANDERSON $24,410
KRISTIANNE BLAKE $24,453
REBECCA A KLEIN $19,638
JOHN F KELLY $30,846
MICHAEL L NOEL $18,141
R JOHN TAYLOR $20,925
SCOTT L MORRIS $3,375
RICK R HOLLEY $22,626
DONALD C BURKE $19,929
ne Page: 335 Line No.: 6 Column: b
ule Page: 335 Line No.: 6
Vendor
Vendors Under
$5000
ALDERBROOK RESORT & SPA
AMEREN
AMERICAN GAS ASSOCIATION
AMERICAN STOCK TRANSFER & TRUST
CO
AZAR'S FOOD SERVICES
BROADRIDGEICS
CITIBANK NA
COATES KOKES
COMPUTERSHARE SHAREOWNER
SERVICES LLC
Purpose Amount
59,245
Employee Lodging 1559.71
Professional Services 2734.94
Miscellaneous 20495
General Services 2251.3
Employee Business 3090.52
Meals
General Services 22975.06
Miscellaneous 17378.65
Professional Services 2050.26
Postage 29266.4
CORP€REDIT CARD Telecommunication 56255.72
Use
CORPORATE RISK SOLUTIONS INC Professional Services 0
CUTAWAY MEDIA Miscellaneous 1956.92
DAVID D HOLMES Office Supplies 834.76
DAVIS HIBBITTS & MIDGHALL INC Professional Services 3843.95
DAVIS WRIGHT TREMA[NE LLP Miscellaneous 3686.16
DENNIS P VERMILLION Employee Misc 1963.86
Expenses
DESAUTEL HEGE COMMUNICATIONS Professional Services 12136.84
DUFFY RESEARCH Miscellaneous 2053.02
ENTERPRISE RENT A CAR Miscellaneous 2450.16
HANNA & ASSOCIATES INC Printing 4043.41
INLAND NORTHWEST PARTNERS Subscriptions 1600.42
INNOVATE WASHINGTON FOUNDATION Professional Services 9281.38
JASON R THACKSTON Employee Misc 5097.76
I FERC FORM NO. 2 (12-96) Page 552.1
Name of Respondent This Report is: Date of Report Year/Period of Report
(l)An Original (Mo, Da, Yr)
(2) _A Resubmission 04/12/2013 2012/04
FOOTNOTE DATA
Expenses
KAREN S FELTES Employee Misc 2881.85
Expenses
KLUNDT HOSMER DESIGN Professional Services 7291.55
MARK I THIES Employee Misc 2472.82
Expenses
MDI MARKETING Advertising Expenses 2667.37
MELLON INVESTOR SERVICES LLC Miscellaneous 6359.82
MICHAEL G ANDREA Employee Misc 6960.12
Expenses
MICHAEL J FAULKENBERRY Employee Misc 7711.72
Expenses
MOODYS INVESTORS SERVICE Miscellaneous 37740.6
NYSE MARKET INC General Services 15189.33
RICOH USA INC Printing 2970.8
ROCKY MOUNTAIN INSTITUTE Professional Services 6989
SIXTH MAN MARKETING LLC Professional Services 3075.16
STANDARD & POORS Miscellaneous 29625.78
THE BANK OF NEW YORK MELLON Miscellaneous 3298.25
THE DAVENPORT HOTEL Miscellaneous 5466.57
UNION BANK OF CALIFORNIA Miscellaneous 9784.6
VAN NESS FELDMAN Legal Services 6374.63
I FERC FORM NO. 2 (12-96) Page 552.2 1
Name of Respondent This Re ort Is:
(1)X An Original
(2)CIA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Depreciation, Depletion and Amortization of Gas Plant (Accts 403, 404.1, 404.2, 404.3, 405) (Except Amortization of
Acquisition Adjustments)
1 Report in Section A the amounts of depreciation expense, depletion and amortization for the accounts indicated and classified according to the plant functional groups shown.
2. Report in Section B, column (b) all depreciable or amortizable plant balances to which rates are applied and show a composite total. (If more desirable, report by plant account,
subaccount or functional classifications other than those pre-printed in column (a). Indicate in a footnote the manner in which column (b) balances are
- Section A. Summary of Depreciation, Depletion, and Amortization Charges
Line
No.
-
Functional Classification
(a)
Depreciation
Expense
(Account 403)
(b)
Amortization
Expense for
Asset
Retirement
Costs
(Account
403.1)(c)
Amortization and
Depletion of
Producing Natural
Gas Land and Land
Rights
(Account 404.1)
(d)
Amortization of
Underground Storage
Land and Land
Rights
(Account 404.2)
(e)
1 Intangible plant 228
2 Production plant, manufactured gas
3 Production and gathering plant, natural gas
4 Products extraction plant
5 Underground gas storage plant 737,828
6 Other storage plant
7 Base load LNG terminating and processing plant
8 Transmission plant
9 Distribution plant 14,449,547
10 General plant 778,160 4,411
11 Common plant-gas 3,205,573 8,100
12 TOTAL 19,171,108 12,739
FERC FORM NO. 2 (12-96) Page 336
Name of Respondent This Re ort Is:
(1)X An Original
(2)DA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
Depreciation, Depletion and Amortization of Gas Plant (Accts 403, 404.1, 404.2, 404.3, 405) (Except Amortization of
Acquisition Adjustments) (continued)
obtained. If average balances are used, state the method of averaging used. For column (c) report available information for each plant functional classification listed in column (a). If
composite depreciation accounting is used, report available information called for in columns (b) and (c) on this basis. Where the unit-of-production method is used to determine
depreciation charges, show in a footnote any revisions made to estimated gas reserves.
3. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state in a footnote the amounts and nature of the
provisions and the plant items to which related.
Section A. Summary of Depreciation, Depletion, and Amortization Charges
Line
No.
Amortization of
Other Limited-term
Gas Plant
(Account 404.3)
(f)
Amortization of
Other Gas Plant
(Account 405)
(g)
Total
(b tog)
(h)
Functional Classification
I (a)
414,325 414,553 Intangible plant
2 Production plant, manufactured gas
3 Production and gathering plant, natural gas
4 Products extraction plant
5 737,828 Underground gas storage plant
6 Other storage plant
7 Base load LNG temlinaling and processing plant
& Transmission plant
9 14,449,547 Distribution plant
10 782,571 General plant
11 1 2,200,415 5,414,088 Common plant-gas
12 2,614,740 21,798,587 TOTAL
FERC FORM NO. 2 (12-96) Page 337
Name of Respondent This Report Is:
(1)X An Original
(2)[JA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Depreciation, Depletion and Amortization of Gas Plant (Accts 403, 404.1, 404.2, 404.3, 405) (Except Amortization of
Acquisition Adjustments) (continued)
4. Add rows as necessary to completely report all data. Number the additional rows in sequence as 2.01, 2.02, 3.01, 3.02 etc.
Section B. Factors Used in Estimating Depreciation Charges
Line Functional Classification
Plant Bases
(in thousands)
Applied Depredation
or Amortization Rates
(percent)
I Production and Gathering Plant
2 Offshore (footnote details)
3 Onshore (footnote details)
4 Underground Gas Storage Plant (footnote details)
5- Transmission Plant
6 Offshore (footnote details)
7 Onshore (footnote details)
B General Plant (footnote details)
9
10
11
12
13
14
15
FE.RC FORM NO. 2 (12-96) Page 338
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Particulars Concerning Certain Income Deductions and Interest Charges Accounts
Report the information specified below, in the order given, for the respective income deduction and interest charges accounts.
(a)Miscellaneous Amortization (Account 425)-Describe the nature of items included in this account, the contra account charged, the total of amortization charges for the year, and the
period of amortization.
(b)Miscellaneous Income Deductions-Report the nature, payee, and amount of other income deductions for the year as required by Accounts 426.1, Donations; 426.2, Life Insurance;
426.3, Penalties; 426.4, Expenditures for Certain Civic, Political and Related Activities; and 426.5, Other Deductions, of the Uniform System of Accounts. Amounts of less than $250,000
may be grouped by classes within the above accounts.
(c)Interest on Debt to Associated Companies (Account 430)-For each associated company that incurred interest on debt during the year, indicate the amount and interest rate
respectively for (a) advances on notes, (b) advances on open account, (c) notes payable, (d) accounts payable, and (e) other debt, and total interest. Explain the nature of other debt on
which interest was incurred during the year.
(d)Other Interest Expense (Account 431)- Report details including the amount and interest rate for other interest charges incurred during the year.
Line
No.
Item
(a)
Amount
(b)
1 Acct. 425.00 Miscellaneous Amortizations
2 Items under $250,000
3 Total-425.00
4 Acct. 426.10 Donations
5 Items under $250,000 2,272,123
6 Total-426.10 . 2,272,123
7 Acct. 426.20 Life Insurance
8 Officers Life Insurance 162,955
9 SERP 2,306,433
10 Items under $250,000 64,164
11 Total -426.20 2,533,552
12 Acct. 426.30
13 Items under $250,000 15,251
14 Total-426.30 15,251
15 Acct. 426.40 Exp. for Certain Civic, Political and Related Activities
16 Items under $250,000 1,414,338
17 Total -426.40 1,414,338
18 Acct. 426.50 Other Deductions
19 Executive Deferred Compensation 856,263
20 Items under $250,000 959,063
21 Total -426.50 1,815,326
22 Acct. 430.00 Interest on Debt to Assoc. Companies
23 Avista Capital II (long-term debt) (variable rate ranged from 1.19 to 1.40 pot.) 541,503
24 Avista Capital, Inc. 343,620
25 Total-430.00 885,123
26 Acct 431.00 Other Interest Expense
27 Interest on electric deferrals 648,676
28 Interest on natural gas deferrals 664,048
29 Interest on committed line of credit 751,925
30 Interest on demand side management programs 211,752
31 Interest related to IRS audits 253,118
32 Other 52,888
33 Total 431.00 2,582,407
34
35
FERC FORM NO. 2 (12-96) Page 340
Name of Respondent This Re ort Is:
(1)X An original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
ea Period of Report
End of 2012/Q4
Regulatory Commission Expenses (Account 928)
1.Report below details of regulatory commission expenses incurred during the current year (or in previous years, if being amortized) relating to formal cases before a regulatory body,
or cases in which such a body was a party.
2.In column (b) and (c), indicate whether the expenses were assessed by a regulatory body or were otherwise incurred by the utility.
Line
No
-
Description
(Furnish name of regulatory commission
or body, the docket number, and a
description of the case.)
(a)
Assessed by
Regulatory
Commission
(b)
Expenses
of
Utility
(c)
Total
Expenses
to Date
(d)
Deferred in
Account 182.3
at Beginning
of Year
(e)
1 Federal Energy Regulatory Commission
2 Charges include annual fee and license fee
3 for the Spokane River Project, the Cabinet
4 Gorge Project and Noxon Rapids Project
2,431,364 185,496 2616,860
5
6 Washington Utilities and Transportation Commission
7 Includes annual fee and various other electric dockets
960,565 1301,327 2,261,892
8
9 Includes annual fee and various other natural gas
dockets 320,188 495,445 815,633
-
10
11 Idaho Public Utilities Commission
12 Includes annual fee and various other electric dockets
620,838 245,606 866,444
13
14 Includes annual fee and various other natural gas
dockets 172,199 111,074 283,273
-
15
16 Public Utility Commission of Oregon
17 Includes annual fee and various other dockets
528,779 127,724 656,503
18
19 Not directly assigned electric
913,764 913,764
20 Not directly assigned natural gas
354,716 354,716
21
22
23
24
25 Total 5,033,933 3,735,152 8,769,085
FERC FORM NO. 2 (12-96) Page 350
Name of Respondent This Re oil Is Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)flA Resubmission 04/1212013 End of 20121Q4
Regulatory Commission Expenses (Account 928)
3.Show in column (k) any expenses incurred in prior years that are being amortized. List in column (a) the period of amortization.
4.Identify separately all annual charge adjustments (ACA).
5.List in column (I), (g), and (Ii) expenses incurred during year which were charges currently to income, plant, or other accounts.
6.Minor items (less than $250,000) may be grouped,
Expenses Expenses Expenses Expenses Amortized Amortized
Incurred Incurred Incurred Incurred During Year During Year
Line During Year During Year During Year During Year Deferred in
No Charged Charged Charged Account 182.3
Currently To Currently To Currently To Deferred to Contra Amount End of Year
Account Account
Department Account No. Amount 182.3
- (I) (g) (h) (I) (j) (k) (I)
2
3
4
- Electric 928 2,616,860
5
6
7
Electric 928 2,261892
8
9
- Gas 928 815,633
10
11
12
Electric 928 866,444
13
14
Gas 928 283,273
15
16
17
- Gas 928 656,503
18
19
- Electric 928 913,764
20
Gas 928 354,716
21
22
23
24
25 8,769,085
FERC FORM NO. 2 (12-96) Page 351
Name of Respondent This Re ort Is:
(1)X An Original
(2)1A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Employee Pensions and Benefits (Account 926)
1. Report below the items contained in Account 926, Employee Pensions and Benefits.
Line
No.
Expense
(a)
Amount
(b)
1 Pensions - defined benefit plans 300,135
2 Pensions - other
3 Post-retirement benefits other than pensions (PBOP) 55,561
4 Post- employment benefit plans
5 Other (Specify)
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
Total I 355,696
FERC FORM NO. 2 (NEW 12-07) Page 352
This Page Intentionally Left Blank
Name of Respondent This Report Is:
(1)MAn Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 201 2/Q4
Distribution of Salaries and Wages
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals
and Other Accounts, and enter such amounts in the appropriate lines and columns provided. Salaries and wages billed to the Respondent by an affiliated company must be assigned to
the particular operating function(s) relating to the expenses.
In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used. When
reporting detail of other accounts, enter as many rows as necessary numbered sequentially starting with 75.01 75.02 etc.
Line
No.
-
Classification
(a)
Direct Payroll
Distribution
(b)
Payroll Billed
by Affiliated
Companies
(c)
Allocation of
Payroll Charged
for Clearing
Accounts
(d)
Total
(e)
1 Electric
10,264,2001 10,264,200j
2 Operation
3 Production I
4 Transmission 2,656,676 2,656,676
5 Distribution 7,508,530 7,508,530
6 Customer Accounts 6,924,109 6,924,109
7 Customer Service and Informational 711,342 711,342
8 Sales 5,487 5,487
9 Administrative and General 16,143,773 16,143,773
10 TOTAL Operation (Total of lines 3 thru 9) 44,214,1171 44,214,117
11 Maintenance
12 Production 3,410,007 3,410,007
13 Transmission 985,166 985,166
14 Distribution 4,058,266 4,058,266
15 Administrative and General 10,330,471 10,330,471
16 TOTAL Maintenance (Total of lines 12 thru 15) 8,453,439 10,330,471 18,783,910
17
—48
Total Operation and Maintenance
Production (Total of lines 3 and 12) 13,674,207 13,674,207
19 Transmission (Total of lines 4 and 13) 3,641,842 3,641,842
20 Distribution (Total of lines 5 and 14) 11,566,796 11,566,796
21 Customer Accounts (line 6) 6,924,109 6,924,109
22 Customer Service and Informational (line 7) 711,342 711,342
23 Sales (line 8) 5,487 5,487
24 Administrative and General (Total of lines 9 and 15) 16,143,773 10,330,4711 26,474,244
25 TOTAL Operation and Maintenance (Total of lines 18 thru 24) 52,667,556 10,330,4711 62,998,0271
26 Gas
I I I 27 Operation
28 Production - Manufactured Gas
29 Production - Natural Gas(lncluding Exploration and Development)
30 Other Gas Supply 828,785 826,785
31 Storage, LNG Terrninaling and Processing 8,363 8,363
32 Transmission
33 Distribution 3,578,184 3,578,184
34 Customer Accounts 2,710,084 2,710,084
35 Customer Service and Informational 349,486 349,486
36 Sales 1,488 1,488
37 Administrative and General 5,910,8091 5,910,809
38 TOTAL Operation (Total of lines 28 thru 37) 13,387,199 13,387,199
39 Maintenance
40 Production - Manufactured Gas
41 Production - Natural Gas(lncluding Exploration and Development)
42 Other Gas Supply
43 Storage, LNG Terminaling and Processing
44 Transmission 866,735 866,735
45 Distribution 2,641,8101 2,641,810
FERC FORM NO. 2 (REVISED) Page 354
Name of Respondent This Report Is:
(1)IX:jAn Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
- Distribution of Salaries and Wages (continued)
Line
No.
-
Classification
(a)
Direct Payroll
Distribution
(b)
Payroll Billed
by Affiliated
Companies
(C)
Allocation of
Payroll Charged
for Clearing
Accounts
(d)
Total
(e)
46 Administrative and General 3,381,1091 1 3,381,109
47 TOTAL Maintenance (Total of lines 40 thru 46) 3,508,5451 3,381,1091 1 6,889,6541
48 Gas (Continued)
I I.
49
50
Total Operation and Maintenance
Production - Manufactured Gas (Total of lines 28 and 40)
51 Production - Natural Gas (Including Expl. and Dev.)(ll. 29 and 41)
52 Other Gas Supply (Total of lines 30 and 42) 828,785 828,785
53 Storage, LNG Terminating and Processing (Total of II. 31 and 43) 8,363 8,363
54 Transmission (Total of lines 32 and 44) 866,735 866,735
55 Distribution (Total of lines 33 and 45) 6219,994 6,219,994
56 Customer Accounts (Total of line 34) 2,710,084 2,710,084
57 Customer Service and Informational (Total of line 35) 349,486 349,486
58 Sales (Total of line 36) 1,488 1,488
59 Administrative and General (Total of lines 37 and 46) 5,910,809 3,381,109 9,291,918
60 Total Operation and Maintenance (Total of lines 50 thru 59) 16,895,744 3,381,109 20,276,853
61 Other Utility Departments
62 Operation and Maintenance
63 TOTAL ALL Utility Dept (Total of lines 25, 60, and 62) 69,563,3001 13,711,5801 83,274,880 I
64
65
66
Utility Plant
Construction (By Utility Departments)
Electric Plant 29,696,4851 9,212,974 38,909,459 I
67 Gas Plant 8275,727 2,948,876 11,224,603
68 Other
69 TOTAL Construction (Total of lines 66 thru 68) 37,972,212 12,161,850 50,134,062
70 Plant Removal (By Utility Departments)
1,508,765 290,831 1,799,596 71 Electric Plant
72 Gas Plant 124,325 23,965 148,290
73 Other
74 TOTAL Plant Removal (Total of lines 71 thru 73) 1,633,090 314,796 1,947,886
75 Other Accounts (Specify) (footnote details) 31,023,866 ( 26,241,727)
76 TOTAL Other Accounts 31,023,866 ( 26,241,727) 4,782,139
77 TOTAL SALARIES AND WAGES 140,192,468 ( 53,501) 140,138,967
FERC FORM NO. 2 (REVISED) Page 356
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
FOOTNOTE DATA
Schedule Page: 354 Line No.: 75 Column: e
Stores Expense (163) 1,901,710 (1,901,710) 0
Unamortized debt expense (18 1) 0 0
Regulatory Assets (182) 0 0
Preliminary Survey and Investigation (183) 71,274 71,274
Small Tool Expense (184) 3,296,582 (3,296,582) 0
Miscellaneous Deferred Debits (186) 1,349,092 1349,092
Capital Stock Expense (214) 0 0
Merchandising Expenses (416) 0 0
Non-operating Expenses (417) 747,089 747,089
Expenditures of Certain Civic, Political and Related 0
Activities (426) 620,960 620,960
Employee Incentive Plan (232380) 4,843,441 (4,843,441) 0
DSM Tarrif Rider and Payroll Equalization Liability 18,112,648 (16,199,994) 1,912,654
(242600, 242700)
Incentive I Stock Compensation (238000) 81,070 81,070
0
0
TOTAL Other Accounts 31,023,8661 (26,241,727)] 4,782,139
I FERC FORM NO. 2 (12-96) Page 552.1
This Page Intentionally Left Blank
Name of Respondent This Report Is: Date of Report Yea r/Penod of Report
(1)X An Original (Mo, Da, Yr) I
(2)EJA Resubmission 04/12/2013 End of 2012/04
Charges for Outside Professional and Other Consultative Services
1 Report the information specified below for all charges made during the year included in any account (including plant accounts) for outside consultative and other professional services.
These services include rate, management, construction, engineering, research, financial, valuation, legal, accounting, purchasing, advertising,labor relations, and public relations,
rendered for the respondent under written or oral arrangement, for which aggregate payments were made during the year to any corporation partnership, organization of any kind, or
individual (other than for services as an employee or for payments made for medical and related services) amounting to more than $250,000, including payments for legislative services,
except those which should be reported in Account 426.4 Expenditures for Certain Civic, Political and Related Activities.
(a)Name of person or organization rendering services.
(b)Total charges for the year.
2.Sum under a description Other, all of the aforementioned services amounting to $250,000 or less.
3.Total under a description "Total", the total of all of the aforementioned services.
4.Charges for outside professional and other consultative services provided by associated (affiliated) companies should be excluded from this schedule and be reported on Page 358,
according to the instructions for that schedule.
- Description Amount
Line (in dollars)
No. (a) (b)
1 AECOM TECHNICAL SERVICES INC 371,555
2 AQUA TECHNEX 446,359
3 BAlM & COMPANY INC 1,445,669
4 BAKER CONSTRUCTION & DEVELOPMENT INC 2,692,983
5 BOOZ & COMPANY INC 595,139
6 CATS EYE EXCAVATING INC 596,348
7 COBRA BEC INC 450,696
8 COEUR 0 ALENE TRIBE 427,238
9 COLUMBIA GRID 399,008
10 COMPUTER FINANCIAL CONSULTANTS INC 324,414
11 DAVIS WRIGHT TREMAINIE LLP 281,532
12 DINERO SOLUTIONS LLC 506,437
13 EFACEC ADVANCED CONTROL SYSTEMS 325,934
14 ELECTRICAL CONSULTANTS INC 631,055
15 EP2M LLC 2119,166
16 GARCO CONSTRUCTION INC 3,094616
17 GARTNER INC 288,000
18 HANNA & ASSOCIATES INC 518,459
19 IBM CORPORATION 908,160
20 INTERIOR SOLUTIONS INC 470,304
21 JAMES A CAROTHERS 250,000
22 LAND EXPRESSIONS 376,691
23 MAGNER SANBORN 873,892
24 MANSFIELD GAS EQUIPMENT SYSTEMS 1,522,336
25 MAX J KUNEY COMPANY 324,919
26 MCKINSTRY ESSENTION INC 3,523,557
27 MWH AMERICAS INC 546,356
28 NORTHWEST HYDRAULIC CONSULTANTS 477,804
29 PAINE HAMBLEN LLP 730,400
30 POWER PLAN INC 621,460
31 PRICE WATERHOUSE COOPERS LLP 255,302
32 PRO BUILDING SYSTEMS 259,434
33 SAPERE CONSULTING INC 307,505
34 SPIRAE INC 438,828
35 TILTON EXCAVATON LLC 324,246
FERC FORM NO. 2 (REVISED) Page 357
Name of Respondent This Report Is:
(1)X An Original (2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
Charges for Outside Professional and Other Consultative Services (continued) -
Line
No.
Description
(a)
Amount
(in dollars)
(b)
1 URS CORPORATION 304,961
2 URS ENERGY & CONSTRUCTION INC 438,211
3 US FOREST SERVICE 319,005
4 WESTERN ELECTRICITY 561,133
5 WIN MILL SOFTWARE INC 333,266
6 CERIUM NETWORKS 308,016
7 DELOITTE & TOUCHE LLP 1677,630
8 Other 21,697,438
9
10
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
FERC FORM NO. 2 (REVISED) Page 357.1
This Page Intentionally Left Blank
Name of Respondent This Report Is:
(1)X An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Transactions with Associated (Affiliated) Companies
1. Report below the information called for concerning all goods or services received from or provided to associated (affiliated) companies amounting to more than $250,000.
2, Sum under a description Other, all of the aforementioned goods and services amounting to $250,000 or less.
3.Total under a description Total", the total of all of the aforementioned goods and services.
4.Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote the basis of the allocation.
Line
No.
Description of the Good or Service
(a)
-
Name of Associated/Affiliated Company
(b)
Account(s)
Charged or
Credited
(C)
Amount
Charged or
Credited
(d)
1 Goods or Services Provided by Affiliated Company
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20 Goods or Services Provided for Affiliated Company
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 2 (NEW 12-07) Page 358
Name of Respondent This Re ort Is:
(1)An Original
(2)[]A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
ea Period of Report
End of 2012/04
Gas Storage Projects
1. Report injections and withdrawals of gas for all storage projects used by respondent.
Line
No.
-
Item
(a)
Gas
Belonging to
Respondent
(Dth)
(b)
Gas
Belonging to
Others
(Dth)
(c)
Total
Amount
(Dth)
(d)
- STORAGE OPERATIONS (in Dth)
1 Gas Delivered to Storage
274,154 2 January 274,154
3 February ( 11,595) ( 11,595)
4 March 863,671 863,671
5 April 1,037,110 1,037,110
6 May 2,683,096 2,683,096
7 June 2,806,026 2,806,026
8 July 142,804 142,804
9 August 1552,236 1552,236
10 September 922,548 922,548
11 October 82,884 82,884
12 November 24,923 24,923
13 December 9,276 9,276
14 TOTAL (Total of lines 2 thru 13) 10,387,133 10,387,133
15 Gas Withdrawn from Storage
2,722606 2,722,606 16 January
17 February 2,592,318 2,592,318
18 March 158,823 158,823
19 April 39,000 39,000
20 May 159,054 159,054
21 June 72,000 72,000
22 July 17,684 17,684
23 August 1,536,560 1,536,560
24 September 932,467 932,467
25 October 50,000 50,000
26 November 89,040 89,040
27 December 788,069 788,069
28 TOTAL (Total of lines 16 thru 27) 9,157,621 9,157,621
FERC FORM NO 2 (12-96) Page 512_
Name of Respondent This Re ort Is:
(1)X An Original
(2)EA Resubmission
Date of Report
(MO, Da, Yr)
04/12/2013
Yea Period of Report
End of 2012/Q4
Gas Storage Projects
1. On line 4, enter the total storage capacity certificated by FERC.
2, Report total amount in 0th or other unit, as applicable on lines 2, 3, 4, 7. If quantity is converted from Mcf to Dth, provide conversion factor in a footnote.
Line
No.
Item
(a)
Total Amount
(b)
STORAGE OPERATIONS
8,528,000 0th 1 Top or Working Gas End of Year
2 Cushion Gas (Including Native Gas) 7,730,668 Dth
3 Total Gas in Reservoir (Total of line 1 and 2) 16,258,668 Dth
4 Certificated Storage Capacity 16,258,668 Dth
5 Number of Injection - Withdrawal Wells 54
6 Number of Observation Wells 48
7 Maximum Days' Withdrawal from Storage 133,267
8 Date of Maximum Days' Withdrawal 01/18/2012
9 LNG Terminal Companies (in 0th)
10 Number of Tanks
11 Capacity of Tanks
12 LNG Volume
13 Received at "Ship Rail"
14 Transferred to Tanks
15 Withdrawn from Tanks
16 Boil OW Vaporization Loss
FERC FORM NO. 2 (12-96) Page 513_
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
(2)- A Resubmission 04/12/2013 2012/Q4
FOOTNOTE DATA
Schedule Page: 513 Line No.: 7 Column: c
Mcf converted to Dth using factor of 1.04
I FERC FORM NO 2 (12-96) Page 552.1 I
This Page Intentionally Left Blank
Name of Respondent This Report Is:
(1)X An Original
(2)EIA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
Auxiliary Peaking Facilities
1.Report below auxiliary facilities of the respondent for meeting seasonal peak demands on the respondents system, such as underground storage projects, liquefied petroleum gas
installations, gas liquefaction plants, oil gas sets, etc.
2.For column (c), for underground storage projects, report the delivery capacity on February 1 of the heating season overlapping the year-end for which this report is submitted.
For other facilities, report the rated maximum daily delivery capacities.
3.For column (d), include or exclude (as appropriate) the cost of any plant used jointly with another facility on the basis of predominant use, unless the auxiliary peaking facility is a
separate plant as contemplated by general instruction 12 of the Uniform System of Accounts.
Line
No.
-
Location of
Facility
(a)
Type of
Facility
(b)
Maximum Daily
Delivery Capacity
of Facility
0th
(c)
Cost of
Facility
(in dollars)
(d)
Was Facility
Operated on Day
of Highest
Transmission Peak
Delivery?
2 Chehalis, Washington Underground Natural Gas 358,800 34678,708
3 Storage Field
4 Washington & Idaho Supply
5
6 Chehalis, Washington Underground Natural Gas 39,867 5751,589
7 Storage Field
8 Oregon Supply
9
10 Chehalis, Washington Underground Natural Gas 2,623
11 Storage Field
12 Oregon Supply
13
14 Rock Springs, Wyoming Underground Natural Gas 186,125
15 Storage Field
16 Washington & Idaho Supply
17
18 Rock Springs, Wyoming Underground Natural Gas 63,875
19 Storage Field
20 Oregon Supply
21
22
23
24
25
26
27
28
29
30
FERC FORM NO. 2 (12-96) Page 519
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
(2)A Resubmission 04/12/2013 2012/Q4
FOOTNOTE DATA
Schedule Page: 519 Line No.: 10 Column: d
Respondent is a participant in the facilities, not an owner and is charged a fee for demand deliverability and capacity.
Schedule Page: 519 Line No.: 14 Column: d
Respondent is a participant in the facilities, not an owner and is charged a fee for demand deliverability and capacity.
ISchedule Paqe: 519 Line No.: 18 Column: d
Respondent is a participant in the facilities, not an owner and is charged a fee for demand deliverability and capacity.
FERC FORM NO. 2 (12-96) Page 552.1 I
Name of Respondent This Report Is:
(1)X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
Gas Account - Natural Gas
1.The purpose of this schedule is to account for the quantity of natural gas received and delivered by the respondent.
2.Natural gas means either natural gas unmixed or any mixture of natural and manufactured gas.
3.Enter in column (c) the year to date Dth as reported in the schedules indicated for the items of receipts and deliveries.
4.Enter in column (d) the respective quarters Dth as reported in the schedules indicated for the items of receipts and deliveries.
5.Indicate in a footnote the quantities of bundled sales and transportation gas and specify the line on which such quantities are listed.
6.If the respondent operates two or more systems which are not interconnected, submit separate pages for this purpose.
7.Indicate by footnote the quantities of gas not subject to Commission regulation which did not incur FERC regulatory costs by showing (1) the local distribulion volumes another jurisdictional pipeline delivered to the
local distribution company portion of the reporting pipeline (2) the quantities that the reporting pipeline transported or sold through its local distribution facilities or intrastate facilities and which the reporting pipeline
received through gathering facilities or intrastate facilities, but not through any of the interstate portion of the reporting pipeline, and (3) the gathering line quantities that were not destined for interstate market or that
were not transported through any interstate portion of the reporting pipeline.
8.Indicate in a footnote the specific gas purchase expense account(s) and related to which the aggregate volumes reported on line No.3 relate.
9.Indicate in a footnote (1) the system supply quantities of gas that are stored by the reporting pipeline, during the reporting year and also reported as sales,transportation and compression volumes by the reporting
pipeline during the same reporting year, (2) the system supply quantities of gas that are stored by the reporting pipeline during the reporting year which the reporting pipeline intends to sell or transport ina future
reporting year, and (3) contract storage quantities.
10.Also indicate the volumes of pipeline production field sales that are included in both the company's total sales figure and the company's total transportation figure. Add additional inforniation as necessary to the
footnotes.
Line
No.
-
Item
(a)
Ref. Page No. of
(FERC Form Nos.
212-A)
(b)
Total Amount
ofDth
Year to Date
(c)
Current Three
Months
Ended Amount of Dth
Quarterly Only
01 Name of System:
2 GAS RECEIVED
94,679,606 3 Gas Purchases (Accounts 800-805)
4 Gas of Others Received for Gathering (Account 489.1) 303
5 Gas of Others Received for Transmission (Account 489.2) 305
6 Gas of Others Received for Distribution (Account 489.3) 301 15,470,439
7 Gas of Others Received for Contract Storage (Account 489.4) 307
8 Gas of Others Received for Production/Extraction/Processing (Account 490 and 491)
9 Exchanged Gas Received from Others (Account 806) 328
10 Gas Received as Imbalances (Account 806) 328 83,769
11 Receipts of Respondents Gas Transported by Others (Account 858) 332
12 Other Gas Withdrawn from Storage (Explain)
13 Gas Received from Shippers as Compressor Station Fuel
14 Gas Received from Shippers as Lost and Unaccounted for
15 Other Receipts (Specify) (footnote details)
16 Total Receipts (Total of lines 3 thru 15) 110,233,814
17 GAS DELIVERED
________________ 91,883,224 18 Gas Sales (Accounts 480-484)
19 Deliveries of Gas Gathered for Others (Account 489.1) 303
20 Deliveries of Gas Transported for Others (Account 489.2) 305
21 Deliveries of Gas Distributed for Others (Account 489.3) 301 15,470,439
22 Deliveries of Contract Storage Gas (Account 489.4) 307
23 Gas of Others Delivered for Production/Extraction/Processing (Account 490 and 491)
24 Exchange Gas Delivered to Others (Account 806) 328
25 Gas Delivered as Imbalances (Account 806) 328
26 Deliveries of Gas to Others for Transportation (Account 858) 332
27 Other Gas Delivered to Storage (Explain) ( 1,205,387)
28 Gas Used for Compressor Station Fuel 509 4,085,538
29 Other Deliveries and Gas Used for Other Operations
30 Total Deliveries (Total of lines 18 thru 29) 110,233,814
31 GAS LOSSES AND GAS UNACCOUNTED FOR
32 Gas Losses and Gas Unaccounted For
33 TOTALS
110,233,814 34 Total Deliveries, Gas Losses & Unaccounted For (Total of lines 30 and 32)
FERC FORM NO.2 (REV 01-11) Page 520
A VU 60 6
t_.._
2:13tR30 F1 2:35
: ri4
Avista Corp.
2012
IDAHO
State Natural Gas Annual Report
(IC 61-405)
AW %
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/ddlyyyy
4/12/2013
Year! Period of Report
End of 2012 / 04
STATEMENT OF UTILITY OPERATING INCOME - IDAHO
Instructions
1.For each account below, report the amount attributable to the state of Idaho based on Idaho jurisdictional Results of Operations.
2.Provide any necessary important notes regarding this statement of utility operating income in a footnote in the available space at the bottom of this page
Line
No.
-
Account
(a)
Refer to
Form 2
Page
(b)
TOTAL SYSTEM - IDAHO
Current Year
(c)
Prior Year
(d)
- - UTILITY OPERATING INCOME
_2 - Operating Revenues (400) 300-301 450.171.070 I 490.826.505
- Operating Expenses
_4 Operation Expenses (401) 317-325 313,684,985 372,734,080
- - Maintenance Expenses (402) 317-325 20,099,052 1,449,373
- - Depreciation Expense (403) 336-338 33,505,585 32,159,853
- Depreciation Expense for Asset Retirement Costs (403.1) 336-338 - -
8 JAmortization & Depletion of Utility Plant (404-405) 336-338 3,047,756 2,650,538
9 Amortization of Utility Plant Acquisition Adjustment (406) 336-338 67,304 67,304
10 Amort. of Property Losses, Unrecov Plant and Regulatory Study Costs (407) - -
11 Amortization of Conversion Expenses (407)
12 Regulatory Debits (407.3) (1,870,742) (9,642,712)
13 (Less) Regulatory Credits (407.4) (5,824,027) (2,460,999)
14 Taxes Other Than Income Taxes (408.1) 262-263 14,639,363 14,029,701
15 1 Income Taxes - Federal (409.1) 262-263 6,730,137 11,858,943
16 - Other (409.1) 262-263 - -
17 Provision for Deferred Income Taxes (410.1) 234-235 10,655,054 8,946,025
18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 234-235 - -
19 Investment Tax Credit Adjustment - Net (411.4) (85,353) (69,896)
20 Less) Gains from Disposition of Utility Plant (411.6) -
21 Losses from Disposition Of Utility Plant (411.7) - -
22 (Less) Gains from Disposition of Allowances (411.8) - -
23 Losses from Disposition of Allowances (411.9) - -
24 Accretion Expense (411.10) - -
25 TOTAL Utility Operating Expenses (Total of line 4 through 24) 394,649,114 431,722,210
26 Net Utility Operating Income (Total line 2 less 25) 55,521,956 1 59,104,295
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.114-115
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year / Period of Report
End of 2012 / 04
STATEMENT OF UTILITY OPERATING INCOME - IDAHO
Instructions
or in a separate schedule.
3. Explain in a footnote if the previous years figures are different from those reported in prior reports.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY Line
Current Year
(e)
354.298.765
237,642,238
I
Prior Year
(
374.727.202
276,342,925
Current Year
(9)
I 95.872.305
76,042,747
I
Prior Year
116 099.303 .1
96,391,155
(h)
Current Year
I
Prior Year
I I
1
No.
2
3
17,657,900 - 2,441,152 1,449,373 _5 -
28,775,543 27,602,346 4,730,042 4,557,507 _6 -
7
2,502,863 2,133,508 544,893 517,030 8 -
67,304 67,304 -
- - 10
11
(1,870,742) (9,332,082) (310,630) JL
(5,824027) (2,460,999) -
12,291,725 11,783,114 2,347,638 2,246,587 ii.
6,585,305 11,102,578 144,832 756,365 15
- - 16
8,217,502 6,419,332 2,437,552 2,526,693 J.L.
- 18
(68,625) (52,928) (16,728) (16,968) 19
- 20
- 21
- 22
- 23
- - 24
305,976,986 323,605,098 1 88,672,128 108,117,112 - -
48,321,779 51122,104 7,200,177 7,982,191 1 IL
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.114-115
Name of Respondent
Avista Corporation
This Report is:
[] An Original
A Resubmission
Date of Report
mmldd/yyyy
4/12/2013
Year / Period of Report
End of 2012 / 04
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION - IDAHO
Instructions
1.Report below the original cost of utility plant in service necessary to furnish utility service to customers in the state of Idaho, and the
accumulated provisions for depreciation, amortization, and depletion attributable to that plant in service.
2.Report in column (c) the amount for electric function, in column (d) the amount for gas function, in columns (e), (f), and (g) report other (specify),
Line
No.
-
Account
(a)
Total Company
End of Current Year
(b)
Electric
(c)
1 Utility Plant
2 InService
3 1 Plant in Service (Classified) 1344,873,821 1,096,648,568 I
4 Property Under Capital Leases 334,898
5 Plant Purchased or Sold -
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (Total lines 3 through 7) 1,345,208,719 1,096,648,568
9 Leased to Others -
10 Held for Future Use 414,587 199,007
11 Construction Work in Progress 42,866,262 28,686,005
12 Acquisition Adjustments -
13 Total Utility Plant (Total lines 8 through 12) 1,388,489,568 1,125,533,580
14 Accumulated Provision for Depreciation, Amortization, and Depletion 470,102,780 389,935,675
15 Net Utility Plant (Line 13 less line 14) 918,386,788 735.597.905 I
Detail of Accumulated Provision for Depreciation, Amortization, and Depletion
In Service 387,309,090 Depreciation 461,324,559
V19
Amortization and Depletion of Producing Natural Gas Lands / Land Rights -
Amortization of Underground Storage Lands / Land Rights
Amortization of Other Utility Plant 8,778,221 2,626,585
22 ITotal (Total lines 18 through 21) 470,102.780 389,935,675
Leased to Others
Depreciation - 25 Amortization and Depletion -
P8
Total Leased to Others
Held for Future Use
Depreciation
29 Amortization
30 Total Held for Future Use - -
31 Abandonment of Leases (Natural Gas) -
32 Amortization of Plant Acquisition Adjustment
33 Total Accumulated Provision (Total lines 22, 26, 30, 31, 32) 470,102,780 389,935,675
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61405) G.ID.200-201
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/ddlyyyy
4/12/2013
Year / Period of Report
End of 2012 / Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION - IDAHO
Instructions
and in column (h) common function.
3. In order to accurately reflect utility plant in service necessary to furnish utility service to customers in the state of Idaho, electric and gas
plant not directly assigned is allocated to the state of Idaho as appropriate and included in column (c) and (d).
Gas
(d)
176 ,602,456
Other (Specify)
(e)
Other (Specify)
(f)
I
Other (Specify)
(g)
Common
(h)
71,622,797 I
Line
No.
3
274,405 60,493 4
5
6
7
176,876,861 - - 71,683,290 8
9
215,580 _10
1,950,046 12,230,211 11
12
179,042,487 - - - 83,913,501 13
59,175,488 - - - 20991,617 14
119.866.999
58,893,849
- -
I
-
I
I 62.921.884
15,121,620118
15
16
17
19
20
281,639 5,869,997 21
59,175,488 - - - 20,991617 22
23
24
25
- - - - - 26
IL 28
29
- - - - - 30
31
32
59,175,488 - - - 20,991,617 33
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.lD.200-201
Name of Respondent
Avista Corporation
This Report is:
FTJ An Original
LI A Resubmission
Date of Report
mm/dd/yyyy
4/1212013
Year / Period of Report
End of 2012 / Q4
GAS PLANT IN SERVICE - IDAHO (Account 101, 102,103 and 106)
Instructions
1.Report below the original cost of gas plant in service necessary to furnish natural gas utility service to customers in the state of Idaho.
Include gas plant not directly assigned as allocated to the state of Idaho.
2.In addition to Account 101 Gas Plant in Service (Classified), this page and the next include Account 102, Gas Plant Purchased or Sold; Account
103, Experimental Gas Plant Unclassified; and Account 106, Completed Construction Not Classified-Gas.
3.Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4.For revisions to the amount of initial asset retirement costs capitalized, include by primary plant account increases in column (C), additions, and
reductions in column (e), adjustments.
5.Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such amounts.
6.Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (C). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year in column (b). Likewise, if the respondent has a significant amount of plant
retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements,
on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of
Line
No.
-
Account
(a)
Balance
Beginning of Year
(b)
Additions
(c)
1 INTANGIBLE PLANT
2 301 Organization - -
3 302 Franchises and Consents - -
4 303 Miscellaneous Intangible Plant 532,012 193,226
5 TOTAL Intangible Plant (Total of lines 2, 3, and 4) 532,012 193.226
6 PRODUCTION PLANT
7 Natural Gas Production and Gathering Plant
8 325.1 Producing Lands - -
9 325.2 Producing Leaseholds - -
10 325.3 Gas Rights - -
11 1 325.4 Rights-of-Way - -
12 325.5 Other Land and Land Rights - -
13 326 Gas Well Structures - -
14 327 Field Compressor Station Structures - -
15 328 Field Measuring and Regulating Station Equipment - -
16 329 Other Structures - -
17 330 Producing Gas Wells-Well Construction - -
18 331 Producing Gas Wells-Well Equipment -
19 332 Field Lines - -
20 333 Field Compressor Station Equipment - -
21 334 Field Measuring and Regulating Station Equipment - -
22 335 Drilling and Cleaning Equipment - -
23 336 Purification Equipment - -
24 337 Other Equipment - -
25 338 Unsuccessful Exploration and Development Costs - -
26 339 Asset Retirement Costs for Natural Gas Production and Gathering Plant - -
27 TOTAL Natural Gas Production and Gathering Plant (Total of lines 8 through 26) - -
28 Products Extraction Plant
29 340 Land and Land Rights -
30 341 Structures and Improvements - -
31 342 Extraction and Refining Equipment - -
32 343 Pipe Lines - -
33 344 Extracted Products Storage Equipment - -
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.204-205
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mmldd/yyyy
4/12/2013
Year I Period of Report
End of 2012/04
GAS PLANT IN SERVICE - IDAHO (Account 101, 102,103 and 106)
Instructions
these tentative classifications in columns (c) and (d), including the reversals of the prior year's tentative account distributions of these amounts. Careful
observance of these instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent's plant
actually in service at end of year.
7.Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102; include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (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 account comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and
date of transaction. If proposed journal entries have been filed as required by the Uniform System of Accounts, give also the date of such filing.
Retirements
(d)
Adjustments
(e)
Transfers
(t)
Balance
End of Year
(g)
Line
No.
2
- - - - 3
- (84,439 - 640,799 4
-
-
(84.439)
-'
- 640.799 i 5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
- - - - 27
29
30
31
32
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.204-205
Name of Respondent
Avista Corporation
This Report is:
FTJ An Original
A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year / Period of Report
End of 2012 F Q4
GAS PLANT IN SERVICE - IDAHO (Account 101, 102,103 and 106) (Continued)
Line
No.
-
Account
(a)
Balance
Beginning of Year
(b)
Additions
(c)
34 345 Compressor Equipment - -
35 346 Gas Measuring and Regulating Equipment - -
36 347 Other Equipment - -
37 348 Asset Retirement Costs for Products Extraction Plant - -
38 TOTAL Products Extraction Plant (Total of lines 29 through 37) - -
39 TOTAL Natural Gas Production Plant (Total lines 27 and 38) - -
40 Manufactured Gas Production Plant (Submit Supplementary Schedule) - -
41 TOTAL Production Plant (Total lines 39 and 40) - -
42 NATURAL GAS STORAGE AND PROCESSING PLANT
43 lUnderground Storage Plant
44 350.1 Land 123,808 -
45 350.2 Rights-of-Way 18,195 -
46 351 Structures and Improvements 410,249
47 352 Wells 3,822,993 -
48 352.1 Storage Leaseholds and Rights 77,375 -
49 352.2 Reservoirs 61,853 -
50 352.3 Non-recoverable Natural Gas 1,630,418 -
51 353 Lines 317,730 -
52 354 Compressor Station Equipment 3,460,192 -
53 355 Other Equipment 52,865 -
54 356 Purification Equipment 123,997 -
55 357 Other Equipment 449,589 -
56 358 Asset Retirement Costs for Underground Storage Plant - -
57 ITOTAL Underground Storage Plant 10,549.264 -
58 Other Storage Plant
59 360 Land and Land Rights - -
60 361 Structures and Improvements - -
61 362 Gas Holders - -
62 363 Purification Equipment - -
63 363.1 Liquefaction Equipment - -
64 1 363.2 Vaporizing Equipment - -
65 363.3 Compressor Equipment - -
66 363.4 Measuring and Regulating Equipment - -
67 363.5 Other Equipment - -
68 363.6 Asset Retirement Costs for Other Storage Plant - -
69 TOTAL Other Storage Plant (Total of lines 58 through 68) - -
70 Base Load Liquefied Natural Gas Terminating and Processing Plant -.
- - 71 1 364.1 Land and Land Rights
72 364.2 Structures and Improvements - -
73 364.3 LNG Processing Terminal Equipment - -
74 364.4 LNG Transportation Equipment - -
75 364.5 Measuring and Regulating Equipment - -
76 364.6 Compressor Station Equipment - -
77 364.7 Communications Equipment - -
78 1 364.8 Other Equipment - -
79 364.9 Asset Retirement Costs for Base Load Liquefied Natural Gas - -
80
TOTAL Base Load Liquefied Natural Gas Terminaling and Processing Plant (Total lines 71
through 79) - -
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.206-207
Name of Respondent
Avista Corporation
This Report is:
[ An Original
LII A Resubmission
Date of Report
mm/ddlyyyy
4/12/2013
Year / Period of Report
End of 2012/04
GAS PLANT IN SERVICE IDAHO (Account 101, 102,103 and 106) (Continued)
Retirements
(d)
Adjustments
(e)
Transfers
(t)
Balance
End of Year
(g)
Line
No.
-
- - - - 34
- - - - 35
- - 36
- - - - 37
- - - - 38
- - - .. 39
40
-L
(1,669)
-I
-
-
122,139
.41
42
43
44
- (246) - 17,949 45
- 18,821 - 429,070 46
- (56,278) - 3,766,715 47
- (1043) - 76,332 48
- (834) - 61,019 49
- (21,975) - 1,608,443 50
- - (4,282) - 313,448 51
- 7,439 - 3,467,631 3,467,631 52
- 26,084 - 78,949 53
- (2,843) - 121,154 54
- 16,816 - 466,405 55
(20.0) 10.529.254 f7
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.206-207
Name of Respondent
Avista Corporation
This Report is:
FTJ An Original
F--j A Resubmission
Date of Report
mm/ddlyyyy
4/12/2013
Year / Period of Report
End of 2012 /04
GAS PLANT IN SERVICE - IDAHO (Account 101, 102,103 and 106) (Continued)
Line
No.
-
Account
(a)
Balance
Beginning of Year
(b)
Additions
(c)
81 TOTAL Natural Gas Storage and Processing Plant (Total of lines 57, 69 and 80) 10.549.264
82 TRANSMISSION PLANT
83 1 365.1 Land and Land Rights - -
84 365.2 Rights-of-Way - -
85 366 Structures and Improvements - -
86 367 Mains - -
87 368 Compressor Station Equipment - -
88 369 Measuring and Regulating Station Equipment - -
89 370 Communication Equipment - -
90 371 Other Equipment - -
91 372 Asset Retirement Costs for Transmission Plant - -
92 TOTAL Transmission Plant (Total lines 83 through 91) - -
93 DISTRIBUTION PLANT
94 374 Land and Land Rights 87,805 -
95 375 Structures and Improvements 274,015 6,605
96 376 Mains 79,334,656 4,355,969
97 377 Compressor Station Equipment - -
98 378 Measuring and Regulating Station Equipment-General 2,031,029 122,021
99 379 Measuring and Regulating Station Equipment-City Gate 4,163,318 41,330
100 380 Services 47,435,736 1,179,679
101 381 Meters 20,524,890 714,500
102 382 Meter Installations - -
103 383 House Regulators - -
104 384 House Regulator Installations - -
105 385 Industrial Measuring and Regulating Station Equipment 604,939 27,694
106 386 Other Property on Customers' Premises - -
107 387 Other Equipment - -
108 388 Asset Retirement Costs for Distribution Plant
109 ITOTAL Distribution Plant (Total lines 94 through 108) 154,456,388 6.447.798
110 GENERAL PLANT
111 389 Land and Land Rights - -
112 390 Structures and Improvements - 1,210
113 391 Office Furniture and Equipment 98,238 13,928
114 392 Transportation Equipment 1,841,886 240,176
115 393 Stores Equipment - -
1161 394 Tools, Shop, and Garage Equipment 834,270 67,612
1171 395 Laboratory Equipment 79,910 -
118 396 Power Operated Equipment 976,176 171,246
119 397 Communication Equipment 661,135 18,227
120 398 Miscellaneous Equipment - -
121 Subtotal (Total of Lines 111 through 120) 4,491,615 512,399
122 399 Other Tangible Property - -
123 399.1 Asset Retirement Costs for General Plant - -
124 TOTAL General Plant (Total of lines 121, 122 and 123) 41491,615 512,399
12 TOTAL (Accounts 101 and 106) 170,029,279 7,153,423
Gas Plant Purchased (See Instruction 8)

r29
(Less) Gas Plant
Experimental Gas Plant Unclassified
TOTAL Gas Plant in Service (Total of lines 125 through 128) 170,029,279 7,153,423
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.lD.208-209
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year! Period of Report
End of 2012! Q4
GAS PLANT IN SERVICE - IDAHO (Account 101, 102,103 and 106) (Continued)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance
End of Year
(g)
Line
No.
- (20,010) - 10,529,254 81
82
83
84
85
86
87
88
89
90
91
-
-
-
-
-
-
87,805
92
93
- (168) - 280,452 95
131,161 8,820 - 83,568,284 96
- - - - 97
42,423 201 - 2,110,828 98
26,348 (18,576) - 4,159,724 99
28,835 - - 48,586,580 100
47,921 - 384,357 21,575,826 101
- - - 102
103
- - - - 104
- - - 632,633 105
- - - - 106
107
- - - - 108
276.688 (9,723) 384,357 161.002.132 109
110
- (1,210) - 112
- (11,620) 100,546 113
30,960 (33,343) 2,017,759 114
- - - 115
15,676 (51,610) 834,596 116
10,534 (5,176) 64,200 117
104,451 (15,828) 1,027,143 118
1 (18,930 - 660,431 119
- - - - 120
161 ,622 (137,717) - 4,704,675 121
- - - - 122
- - - - 123
161,622 (137,717) - 4,704,675 124
438,310 (251,889) 384,357 176,876,860 125
- - - - 126
127
- - - - 128
438,310 (251,889) 384,357 176,876,860 129
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.208-209
This Page Intentionally Left Blank
Name of Respondent This Report is: Date of Report Year I Period of Report
Avista Corporation IA I An Original mm/ddlyyyy End of 2012/04
A Resubmission 4/12/2013
GAS STORED. IDAHO (Accounts 117.1, 117.2, 117.3, 164.1, 164.2, and 164.3)
Instructions
1.If during the year adjustments were made to the stored gas inventory reported in columns (d), (f), (g), and (h) (such as to correct cumulative
inaccuracies of gas measurements), explain in a footnote (in the available space at the bottom of this page or in a separate schedule) the reason for
the adjustments, the Dth and dollar amount of adjustment, and account charged or credited.
2.Report in column (e) all encroachments during the year upon the volumes designated as base gas, column (b), and system balancing gas, column (c),
and gas property recordable in the plant accounts.
3.State in a footnote, in the available space at the bottom of this page or in a separate schedule, the basis of segregation of inventory between current
and noncurrent portions. Also, state in a footnote the method used to report storage (i.e., fixed asset method or inventory method).
Line Description (Account (Account Noncurrent (Account Current LNG LNG Total
No. 117.1) 117.2) (Account 117.4) (Account (Account (Account
117.3) 164.1) 164.2) 164.3)
- (a) (b) (c) (d) (e) (f) (g) (h) (I)
1 Balance at beginning of year 1772,478 7,793,165 9,565,643
2 Gas delivered to storage 6,709,964 6,709,964
3 Gas withdrawn from storage 8,114581 8,114,581
4 Other debits and credits -
5 Balance at end of year 1,772,478 - - - 6,388,548 - - 8,161,026
6 Dth 317,648 2,780,623 3,098,271
7 Amount per Dth 5.58 2.30 2.63
(1)Fuel is accounted for within injections and withdrawal accounts.
(2)All gas reported is current working gas. Avista uses the inventory method to report all working gas stored.
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.lD.220
Name of Respondent
Avista Corporation
This Report is:
An Original
[II] A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year / Period of Report
End of 2012/04
GAS OPERATING REVENUES - IDAHO
Instructions
1.Report below natural gas operating revenues attributable to the state of Idaho for each prescribed account total in accordance with jurisdictional
Results of Operations.
2.Revenues in columns (b) and (c) include transition costs from upstream pipelines.
3.Other Revenues in columns (f) and (g) include reservation charges received by the pipeline plus usage charges, less revenues reflected in columns
(b) through (e). Include in columns (f) and (g) revenues for Accounts 480-495.
Line
No. Account
Revenues for
Transition Costs
and Take-or-Pay
Revenues for
GRI and ACA
Current Year Previous Year Current Year Previous Year
1 480 Residential Sales - - - -
2 481 Commercial and Industrial Sales - - - -
3 482 Other Sales to Public Authorities - - - - -
4 483 Sales for Resale
5 484 Interdepartmental Sales - - - -
6 485 Intracompany Transfers - - - -
7 487 Forfeited Discounts - - - -
8 488 Miscellaneous Service Revenues - - - -
9
—
489.1 Revenues from Transportation of Gas for Others
through Gathering Facilities
- - - -
10
—
489.2 Revenues from Transportation of Gas for Others
through Transmission Facilities
- - - -
11 489.3 Revenues from Transportation of Gas for Others
through Distribution Facilities
- - - -
-
12 1489.4 Revenues from Storing Gas of Others - - - -
13 490 Sales of Products Extracted from Natural Gas - - - -
14 491 Revenues from Natural Gas Processed by Others - - - -
15 492 Incidental Gasoline and Oil Sales - - - -
16 493 Rent from Gas Property - - - -
17 494 Interdepartmental Rents - - - -
18 495 Other Gas Revenues - - - -
19 ISubtotal - - - -
20 496 (Less) Provision for Rate Refunds - - - -
21 TOTAL - - - -
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.I13.300401
Name of Respondent
Avista Corporation
This Report is:
FTJ An Original
A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year / Period of Report
End o2012/04
GAS OPERATING REVENUES - IDAHO
Instructions
4.If increases or decreases from previous year are not derived from previously reported figures, explain any inconsistencies in a footnote in the
available space at the bottom of this page or attached in a separate schedule.
5.See pages 108 in the FERC Form 2, Important Changes During the Quarter/Year, for information on major changes during the year, new service,
and important rate increases or decreases.
6.Report the revenue from transportation services that are bundled with storage services as transportation service revenue.
Other
Revenues
Total
Operating
Revenues
Dekatherm of
Natural Gas Line
No.
Current Year
(l
Previous Year
(g)
Current Year
(h)
Previous Year
(i)
Current Year
(j)
Previous Year
(k) -
41,903,811 48,200,412 41,903,811 48,200,412 4,423,673 4,831,289 1 1
21,614,522 24,903,280 21,614,522 24,903,280 2,784,757 2,984,271 2
- - - -I - -3
29;868,942 40,464,215 29,868,942 40,464,215 11,217,223 10,279,117 4
30,256 35,822 30,256 35,822 I 3,798 1 4.287i 5
- - - - 7
11,838 13,299 11,838 13,299 8
- - - -I - -'9
- - - - - - 10
413,674 436,576 413,674 436,576 4,456,597 4,477,021 11
- - - -' - -
- - - - 13
- - - - 14
- - - - 15
- - - - 16
- - - - 17
2,029,262 2,045,699 2,029,262 2,045,699 18
95,872,305 116,099,303 95,872,305 116,099,303 19
- - - 20
95,872,305 116,099,303 95,872,305 116,099,303 21
(1) Sales for resale dollars are allocated based on the Washington / Idaho average monthly commodity allocation used in Results of Operations.
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.300-301
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year / Period of Report
End of 2012 / 04
GAS OPERATION AND MAINTENANCE EXPENSES - IDAHO
Instructions
1.For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
2.If the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.
-
Account
(a)
Amount for
Current Year I (b)
Amount for
Previous Year
(c)
1 1. PRODUCTION EXPENSES
2 A. Manufactured Gas Production
3 Manufactured Gas Production (Submit Supplemental Statement)
4 B. Natural Gas Production
5 131. Natural Gas Production and Gathering
6 Operation
7 750 Operation Supervision and Engineering
8 751 Production Maps and Records - -
9 752 Gas Well Expenses - -
10 1 753 Field Lines Expenses - -
11 754 Field Compressor Station Expenses -
12 755 Field Compressor Station Fuel and Power - -
13 756 Field Measuring and Regulating Station Expenses - -
14 757 Purification Expenses - -
15 758 Gas Well Royalties - -
16 759 Other Expenses - -
17 760 Rents -
18 TOTAL Operation (Total of lines 7 through 17) - -
19 Maintenance
20 761 Maintenance Supervision and Engineering - -
21 762 Maintenance of Structures and Improvements - -
22 763 Maintenance of Producing Gas Wells - -
23 764 Maintenance of Field Lines - -
24 765 Maintenance of Field Compressor Station Equipment - -
25 766 Maintenance of Field Measuring and Regulating Station Equipment - -
26 767 Maintenance of Purification Equipment - -
27 768 Maintenance of Drilling and Cleaning Equipment - -
28 769 Maintenance of Other Equipment - -
29 TOTAL Maintenance (Total of lines 20 through 28) - -
30 ITOTAL Natural Gas Production and Gathering (Total of lines 18 and 29) - -
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.317
Name of Respondent
Avista Corporation
This Report is:
FTJ An Original
A Resubmission
Date of Report
mm!dd/yyyy
4/12/2013
Year / Period of Report
End of 2012 / Q4
GAS OPERATION AND MAINTENANCE EXPENSES - IDAHO
Instructions
1.For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
2.If the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.
-
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
31 82. Products Extraction
32 Operation I
33 770 Operation Supervision and Engineering - -
34 771 Operation Labor - -
35 772 Gas Shrinkage -
36 773 Fuel - -
37 774 Power -
38 775 Materials -
39 776 Operation Supplies and Expenses - -
40 777 Gas Processed by Others - -
41 778 Royalties on Products Extracted - -
42 779 Marketing Expenses -
43 780 Products Purchased for Resale - -
44 781 Variation in Products Inventory - -
45 782 (Less) Extracted Products Used by the Utility-Credit - -
46 783 Rents - -
47 TOTAL Operation (Total of line 33 through 46) -
48 IMaintenance
49 784 Maintenance Supervision and Engineering - -
50 785 Maintenance of Structures and Improvements - -
51 786 Maintenance of Extraction and Refining Equipment - -
52 787 Maintenance of Pipe Lines - -
53 788 Maintenance of Extracted Products Storage Equipment - -
54 789 Maintenance of Compressor Equipment - -
55 1 790 Maintenance of Gas Measuring and Regulating Equipment - -
56 791 Maintenance of Other Equipment - -
57 TOTAL Maintenance (Total of lines 49 through 56) - -
58 TOTAL Products Extraction (Total of lines 47 and 57) - -
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.318
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mmlddlyyyy
4/12/2013
Year / Period of Report
End of 2012/04
GAS OPERATION AND MAINTENANCE EXPENSES - IDAHO
Instructions
1 For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
2. If the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.
-
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
59 C. Exploration and Development
60 Operation
61 1 795 Delay Rentals
62 796 Nonproductive Well Drilling - -
63 797 Abandoned Leases
64 798 Other Exploration - -
65 TOTAL Exploration and Development (Total of lines 61 through 64) -
66 D. Other Gas Supply Expenses
67 Operation
68 800 Natural Gas Well Head Purchases -
69 800.1 Natural Gas Well Head Purchases, Intracompany Transfers -
70 801 Natural Gas Field Line Purchases - -
71 802 Natural Gas Gasoline Plant Outlet Purchases - -
72 803 Natural Gas Transmission Line Purchases - -
73 804 Natural Gas City Gate Purchases 63,071,309 82,779,458
74 604.1 Liquefied Natural Gas Purchases -
75 805 Other Gas Purchases - -
76 805.1 (Less) Purchased Gas Cost Adjustments -
77 TOTAL Other Gas Supply Expenses (Total of lines 68 through 76) 63,071,309 82,779,458
78 806 Exchange Gas - -
79 Purchased Gas Expenses
80 807.1 Well Expense-Purchased Gas
81 807.2 Operation of Purchased Gas Measuring Stations - -
82 807.3 Maintenance of Purchased Gas Measuring Stations - -
83 807.4 Purchased Gas Calculations Expenses - -
84 807.5 Other Purchased Gas Expenses 1,404,617 (1,980,923)
85 TOTAL Purchased Gas Expenses (Total of lines 80 through 84) 1,404,617 (1,980,923)
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) 0.10.319
Name of Respondent
Avista Corporation
This Report is:
An Original
LII A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year / Period of Report
End of 2012 / Q4
GAS OPERATION AND MAINTENANCE EXPENSES - IDAHO
Instructions
1 For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
2. If the amount for previous year is not derived from previously reported figures, explain in a footnote.
-
Line
No. Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
86 808.1 Gas Withdrawn from Storage-Debit - -
87 808.2 (Less) Gas Delivered to Storage-Credit - -
88 1 809.1 Withdrawals of Liquefied Natural Gas for Processing-Debit - -
89 809.2 (Less) Deliveries of Natural Gas for Processing-Credit - -
90 Gas Used in Utility Operation-Credit
91 810 Gas Used for Compressor Station Fuel-Credit -
92 811 Gas Used for Products Extraction-Credit (365,847) (415,999)
93 812 Gas Used for Other Utility Operations-Credit - -
94 TOTAL Gas Used in Utility Operations-Credit (Total of lines 91 through 93) (365,847) 1 (415,999)
95 1 813 Other Gas Supply Expenses 411,155 471,203
96 TOTAL Other Gas Supply Expenses (Total of lines 77, 78, 85, 86 through 89, 94, 95) 64,521,234 80853,739
97 TOTAL Production Expenses (Total of lines 3, 30, 58, 65, and 96) 64.521.234 80.853.739 I
98 2. NATURAL GAS STORAGE, TERMINALING AND PROCESSING EXPENSES
99 A. Underground Storage Expenses
100 Operation I 101 814 Operation Supervision and Engineering 5,475 4,202
1021 815 Maps and Records - -
103 816 Wells Expenses - -
104 817 Lines Expense - -
105 818 Compressor Station Expenses - -
106 819 Compressor Station Fuel and Power - -
107 820 Measuring and Regulating Station Expenses - -
108 821 Purification Expenses - -
1091 822 Exploration and Development - -
110 823 Gas Losses - -
111 824 Other Expenses 162,931 131,765
112 825 Storage Well Royalties - -
113 826 Rents - -
114 TOTAL Operation (Total of lines 101 through 113) 168,406 135,967
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.320
Name of Respondent
Avista Corporation
This Report is:
FTJ An Original
A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year / Period of Report
End of 2012 / 04
GAS OPERATION AND MAINTENANCE EXPENSES - IDAHO
Instructions
1.For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
2.It the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.
-
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
115 Maintenance
116 830 Maintenance Supervision and Engineering - -
1171 831 Maintenance of Structures and Improvements - -
118 832 Maintenance of Reservoirs and Wells - -
119 833 Maintenance of Lines - -
120 834 Maintenance of Compressor Station Equipment - - -
121 835 Maintenance of Measuring and Regulating Station Equipment - - -
122 836 Maintenance of Purification Equipment - -
837 Maintenance of Other Equipment 136,854 120,008
TOTAL Maintenance (Total of lines 116 through 123) 136,854 120,008
125 TOTAL Underground Storage Expenses (Total of lines 114 and 124) .305260 255.975
_126 B. Other Storage Expenses
127 Operation
128 840 Operation Supervision and Engineering I - -
129 841 Operation Labor and Expenses - -
_130 842 Rents - -
131 842.1 Fuel - -
_132 842.2 Power - -
_133 842.3 Gas Losses -
134 TOTAL Operation (Total of lines 128 through 133) - -
135 Maintenance -
- 136 843.1 Maintenance Supervision and Engineering -
137 843.2 Maintenance of Structures - -
138 843.3 Maintenance of Gas Holders -
139 843.4 Maintenance of Purification Equipment - -
140 843.5 Maintenance of Liquefaction Equipment - -
141 843.6 Maintenance of Vaporizing Equipment - -
142 843.7 Maintenance of Compressor Equipment -
143 843.8 Maintenance of Measuring and Regulating Equipment - -
144 843.9 Maintenance of Other Equipment - -
145 TOTAL Maintenance (Total of lines 136 through 144) -
146 ITOTAL Other Storage Expenses (Total of lines 134 and 145)
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.lD.321
Name of Respondent
Avista Corporation
This Report is:
[ An Original
A Resubmission
Date of Report
mmldd/yyyy
4/12/2013
Year/ Period of Report
End of 2012/ Q4
GAS OPERATION AND MAINTENANCE EXPENSES - IDAHO
Instructions
1.For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
2.If the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.
-
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
147 C. Liquefied Natural Gas Terminating and Processing Expenses
148 Operation
149 844.1 Operation Supervision and Engineering - -
150 844.2 LNG Processing Terminal Labor and Expenses - -
151 844.3 Liquefaction Processing Labor and Expenses - -
152 844.4 Liquefaction Transportation Labor and Expenses - -
153 844.5 Measuring and Regulating Labor and Expenses - -
154 844.6 Compressor Station Labor and Expenses - -
155 844.7 Communication System Expenses - -
156 844.8 System Control and Load Dispatching - -
157 845.1 Fuel - -
158 845.2 Power - -
159 845.3 Rents -
160 845.4 Demurrage Charges - -
161 845.5 (Less) Wharfage Receipts-Credit - -
162 845.6 Processing Liquefied or Vaporized Gas by Others - -
163 846.1 Gas Losses - -
164 846.2 Other Expenses - -
165 TOTAL Operation (Total of lines 149 through 164) - -
166 Maintenance
167 847.1 Maintenance Supervision and Engineering - -
168 847.2 Maintenance of Structures and Improvements - -
169 847.3 Maintenance of LNG Processing Terminal Equipment - -
170 847.4 Maintenance of LNG Transportation Equipment - -
171 847.5 Maintenance of Measuring and Regulating Equipment - -
172 847.6 Maintenance of Compressor Station Equipment - -
173 847.7 Maintenance of Communication Equipment - -
174 847.8 Maintenance of Other Equipment - -
175 TOTAL Maintenance (Total of lines 167 through 174) - -
176 TOTAL Liquefied Nat Gas Terminaling and Proc Exp (Total of lines 165 and 175) - -
177 TOTAL Natural Gas Storage (Total of lines 125, 146, and 176) 305,260 255,975
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.lD.322
Name of Respondent
Avista Corporation
This Report is:
FTJ An Original
A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year! Period of Report
End of 2012/04
GAS OPERATION AND MAINTENANCE EXPENSES - IDAHO
Instructions
1 For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
2. If the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.
-
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
178 3. TRANSMISSION EXPENSES
179 Operation
1801 850 Operation Supervision and Engineering
1811 851 System Control and Load Dispatching - -
182 852 Communication System Expenses - -
183 853 Compressor Station Labor and Expenses - -
184 854 Gas for Compressor Station Fuel -
185 855 Other Fuel and Power for Compressor Stations - -
186 856 Mains Expenses - -
187 857 Measuring and Regulating Station Expenses -
1881 858 Transmission and Compression of Gas by Others - -
189 859 Other Expenses - -
190 860 Rents - -
191 TOTAL Operation (Total of lines 180 through 190) - -
192 Maintenance
193 861 Maintenance Supervision and Engineering - -
194 862 Maintenance of Structures and Improvements - -
1951 863 Maintenance of Mains - -
196 864 Maintenance of Compressor Station Equipment - -
197 865 Maintenance of Measuring and Regulating Station Equipment - -
_198 866 Maintenance of Communication Equipment - -
199 867 Maintenance of Other Equipment - - -
TOTAL Maintenance (Total of lines 193 through 199) - -
- TOTAL Transmission (Total of lines 191 and 200)
20214. DISTRIBUTION EXPENSES -
- Operation
870 Operation Supervision and Engineering 341,011 319,207
- 871 Distribution Load Dispatching - -
206 872 Compressor Station Labor and Expenses - -
207 873 Compressor Station Fuel and Power - -
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.lD.323
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year / Period of Report
End of 2012/ Q4
GAS OPERATION AND MAINTENANCE EXPENSES - IDAHO
Instructions
1.For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
2.If the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.
-
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
208 874 Mains and Services Expenses 808,340 1,195,312
209 875 Measuring and Regulating Station Expenses-General 36,747 50,902
210 876 Measuring and Regulating Station Expenses-Industrial 3,998 18,187
211 877 Measuring and Regulating Station Expenses-City Gas Check Station 101,186 134,763
212 878 Meter and House Regulator Expenses 81,580 220,929
213 879 Customer Installations Expenses 592,987 653,138
214 880 Other Expenses 614,652 593,802
215 881 Rents 9,175 10,176
216 TOTAL Operation (Total of lines 204 through 215) 2,589,676 3.196416
217 1 Maintenance
218 885 Maintenance Supervision and Engineering 65,118 94,786
219 886 Maintenance of Structures and Improvements - -
220 887 Maintenance of Mains 550,807 474,538
221 888 Maintenance of Compressor Station Equipment - -
222 889 Maintenance of Measuring and Regulating Station Equipment-General 75,852 55,263
223 890 Maintenance of Measuring and Regulating Station Equipment-Industrial 149,231 63,609
2241 891 Maintenance of Meas. and Reg. Station Equipment-City Gate Check Station 15,216 51,202
225 892 Maintenance of Services 387,781 288,194
226 893 Maintenance of Meters and House Regulators 399,920 368,159
227 894 Maintenance of Other Equipment 63,300 53,622
228 TOTAL Maintenance (Total of lines 218 through 227) 1707!225 1,449,373
229 TOTAL Distribution Expenses (Total of lines 216 and 228) 4,296,901 I 4,645,789
230 5. CUSTOMER ACCOUNTS EXPENSES
231 Operation
232 901 Supervision 121118 132,105
233 902 Meter Reading Expenses 250,247 225,931
234 903 Customer Records and Collection Expenses 1,628,274 1,587,749
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.324
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year / Period of Report
End of 2012/ Q4
GAS OPERATION AND MAINTENANCE EXPENSES - IDAHO
Instructions
1.For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
2.If the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.
-
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
235 904 Uncollectible Accounts 446,330 549,010
236 905 Miscellaneous Customer Accounts Expenses 48,089 28,905
237 ITOTAL Customer Accounts Expenses (Total of lines 232 through 236) 2.494.058 2.523,700
238 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
239 Operation
240 907 Supervision - -
241 908 Customer Assistance Expenses 1,166,773 3,865,610
242 909 Informational and Instructional Expenses 237,514 221,791
243 910 Miscellaneous Customer Service and Informational Expenses 36,934 27!908
244 ITOTAL Customer Service and Informational Expenses (Total of lines 240 through 243) 1,441,221 4.115.309
245 7. SALES EXPENSES
246 Operation
247 911 Supervision - -
248
t
912 Demonstrating and Selling Expenses 1,666 2,521
249 913 Advertising Expenses - -
250 916 Miscellaneous Sales Expenses (12)
251 ITOTAL Sales Expenses (Total of lines 247 through 250) 1.666 2.509
252 8. ADMINISTRATIVE AND GENERAL EXPENSES
253 Operation
254 920 Administrative and General Salaries I 2,450,614 2,064,497
255 921 Office Supplies and Expenses 333,111 343,969
256 922 (Less) Administrative Expenses Transferred-Credit (10,833) (10,222)
257 923 Outside Services Employed 931,071 1,246,939
2581 924 Property Insurance 92,090 91,864
259 925 Injuries and Damages 239,786 314,898
260 926 Employee Pensions and Benefits 63,166 73,940
261 927 Franchise Requirements - -
928 Regulatory Commission Expenses 357,471 333,769
929 (Less) Duplicate Charges-Credit - -
930.1 General Advertising Expenses - -
265 930.2 Miscellaneous General Expenses 293,049 266,432
266 931 Rents 76,961 69,517
267 TOTAL Operation (Total of lines 254 through 266) 4.826.486 4.795.603
268 Maintenance
269 932 Maintenance of General Plant 597,073 647,904
270 TOTAL Administrative and General Expenses (Total of lines 267 and 269) 5,423,559 5,443,507
271 TOTAL Gas O&M Expenses (Total of lines 97, 177, 201, 229, 237, 244, 251,270) 78,483,899 97,840,528
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.325
Name of Respondent
Avlsta Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/ddlyyyy
4/12/2013
Year! Period of Report
End of 2012/ Q4
GAS TRANSMISSION MAINS - IDAHO
Instructions
1.Report below the requested details of transmission mains in system operated by respondent at end of year in the state of Idaho.
2.Report separately any lines held under a title other than full ownership. Designate such lines with an asterisk and in a footnote (in the available
space at the bottom of this page or attached in a separate schedule) state the name of owner or co-owner, nature of respondent's title, and
percent ownership if jointly owned.
-
Line
No.
-
Kind of
Material
(a)
Diameter of
Pipe
in Inches
(b)
Total Length in Use
Beginning of Year
in Feet
(c)
Laid During Year
in Feet
(d)
Taken Up
or Abandored
During Year
in Feet
(e)
Total Length
in Use
End of Year
in Feet
(t)
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 1
NOTE:
In accordance with the definitions established in the Uniform System of Accounts for production, transmission, and distribution plant, the Company's
gas mains are appropriately classified as distribution property for accounting purposes (see definitions 29 (B) and (C)).
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.lD.514
Name of Respondent
Avista Corporation
This Report is:
FTJ An Original
A Resubmission
Date of Report
mrn/ddlyyyy
4/12/2013
Year! Period of Report
End of 2012 104
GAS DISTRIBUTION MAINS - IDAHO
Instructions
1.Report below the requested details of distribution mains in system operated by respondent at end of year in the state of Idaho.
2.Report separately any lines held under a title other than full ownership. Designate such lines with an asterisk and in a footnote (in the available
space at the bottom of this page or attached in a separate schedule) state the name of owner or co-owner, nature of respondent's title, and
percent ownership if jointly owned.
-
Line
No.
- -
Kind of
Material
(a)
Diameter of
Pipe
in Inches
(b)
Total Length in Use
Beginning of Year
in Feet
(C)
Laid During Year
in Feet
(d)
Taken Up
or Abandoned
During Year
in Feet
(e)
Total Length
in Use
End of Year
in Feet
(f)
1 Steel Wrapped Less than 2" 1,766,318 - 2,798 1,763,520
2 Steel Wrapped 2"to4" 638,510 - 15,470 623,040
_3 Steel Wrapped 4" to 8" 384,965 15,259 - 400,224
4 Steel Wrapped 8" to 12" 4,594 158 - 4,752
5 Steel Wrapped Over 12" - - - -
6
7
8 Plastic Less than 2" 5,481,221 - 15,893 5,465,328
9 Plastic 2"to4" 1,499,995 - 50,635 1,449,360
10 Plastic 4" to 8" 560,789 39,547 - 600,336
11 Plastic 8" to 12" - - - -
12 Plastic Over 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
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.514A
Name of Respondent
Avista Corporation
This Report is:
[ An Original
LI A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year! Period of Report
End of 2012/04
SERVICE PIPES - GAS - IDAHO
Instructions
1. Report below the requested details of line service pipe in possession of the respondent at the end of the year in the state of Idaho.
Line
No.
-
Type of
Material
(a)
Diameter of
Pipe
in Inches
(b)
Number of
Service Pipes
Beginning of Year
(c)
Added
During Year
(c)
Retired
During Year
(d)
Number of
Service Pipes
End of Year
(e)
Average
Length
in Feet
(f)
1 Steel Wrapped 1" or Less 11,667 - 126 11,541 (1)
2 1 Steel Wrapped 1" to 2" 200 - 2 198 (1)
3 Steel Wrapped 2" to 4' 1 6 1 - 7 (1)
4 Steel Wrapped 4" to 8" 1 1 (1)
5 Steel Wrapped Over 8" - - - - (1)
6 Steel Wrapped Unknown 405 - 7 398 (1)
7
8 Plastic 1" or Less 56,135 761 - 56,896 (1)
9 Plastic 1"to2" 257 6 - 263 (1)
10 Plastic 2"to4" 10 - - 10 (1)
11 Plastic 4"to8" 2 - - 2 (1)
12 Plastic Over 8" - - - - (1)
13 Plastic Unknown 2,684 - 24 2,660 (1)
14
15 Other Unknown 92 - 12 80 (1)
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
(1) Information not available.
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.514B
Name of Respondent
Avista Corporation
This Report is:
FTJ An Original
[II] A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year/ Period of Report
End of 2012/04
REGULATORS - GAS - IDAHO
Instructions
1. Report below the requested details of gas regulators in possession of the respondent at the end of the year in the state of Idaho.
Line
No.
-
Size
(a)
Type
(b)
Make
(c)
Capacity
(d)
In Service
Beginning of Year
(e)
Added During
Year
(f
Retired During
Year
g)
In Plant
End of Year
(h)
2 No Data available
3
4
5
6
7
8
9
10
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40 Total
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.514C
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/ddlyyyy
4/12/2013
Year/ Period of Report
End of 2012/ Q4
CUSTOMER METERS GAS - IDAHO
Instructions
1. Report below the requested details of gas customer meters in possession of the respondent at the end of the year in the state of Idaho.
Line
No.
Size
(a)
Type
(b)
Make
(c)
Capacity
(d)
In Service
Beginning of Year
(e)
Added During
Year
(f)
Retired During
Year
(g)
In Plant
End of Year
(h)
All All All All 75,815 693 - 76,508
2
3
4
5
6
7
8 - -
9
10
11 1 -
12
13
14
15
16
17
18 1
19
20
21
22
23
24
25 1
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
(1) The Company's systems do not supply meter information tracking by type of meter.
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.ID.514D
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year / Period of Report
End of 2012/ Q4
- GAS ACCOUNT - NATURAL GAS - IDAHO
Instructions
1.The purpose of this schedule is to account for the quantity of natural gas received and delivered by the respondent for service in the state of Idaho.
2.Natural gas means either natural gas unmixed or any mixture of natural and manufactured gas.
3.Enter in column (C) the year-to-date Dth as reported in the schedules indicated for the items of receipts and deliveries.
4.Indicate in a footnote (in the available space at the bottom of this page or in a separate schedule) the quantities of bundled sales and transportation gas
and specify the line on which such quantities are listed.
5.If the respondent operètes two or more systems which are not interconnected, submit separate pages for this purpose.
6.Indicate by footnote the quantities of gas not subject to FERC regulation which did not incur FERC regulatory costs by showing (1) the local distribution
volumes another jurisdictional pipeline delivered to the local distribution company portion of the reporting pipeline, (2) the quantities that the reporting
pipeline transported or sold through its local distribution facilities or intrastate facilities and which the reporting pipeline received through gathering
facilities or intrastate facilities, but not through any of the interstate portion of the pipeline, and (3) the gathering line quantities that were not destined for
interstate market or that were not transported through any interstate portion of the reporting pipeline.
7.Indicate in a footnote the specific gas purchase expense account(s) and related to which the aggregate volumes report on line 3 relate.
8.Indicate in a footnote (1) the system supply quantities of gas that are stored by the reporting pipeline during the reporting year and also reported as sales,
transportation and compression volumes by the reporting pipeline during the same reporting year, (2) the system supply quantities of gas that are stored
by the reporting pipeline during the reporting year which the reporting pipeline intends to sell or transport in a future reporting year, and (3) contract
storage quantities.
9.Also indicate the volumes of pipeline production field sales that are included in both the company's total sales figure and the company's total transportation
figure. Add additional information as necessary to the footnotes.
Line
No.
-
Account
(a)
Refer to
Form 2
Page
(b)
Amount of Dth Amount of Dth
Year to Date Current 3 Months Ended
Quarterly Only
(c) (d)
1 1 Name of System
2 GAS RECEIVED
3 Gas Purchases (Accounts 800-805) 19,380,270
4 Gas of Others Received for Gathering (Account 489.1) 303
5 Gas of Others Received for Transmission (Account 489.2) 305
6 Gas of Others Received for Distribution (Account 489.3) 301 4,456,597
7 Gas of Others Received for Contract Storage (Account 489.4) 307
8 lExchanged Gas Received from Others (Account 806) 328
9 Gas Received as Imbalances (Account 806) 328 11,143.
10 Receipts of Respondent's Gas Transported by Others (Account 858) 332
11 Other Gas Withdrawn from Storage (Explain)
12 Gas Received from Shippers as Compressor Station Fuel
13 Gas Received from Shippers as Lost and Unaccounted For
14 Other Receipts (Specify) (footnote details)
15 [Total Receipts (Total of lines 3 through 14) 23,848,010
16 GAS DELIVERED
18,448,595 17 Gas Sales (Accounts 480-484) I
18 Deliveries of Gas Gathered for Others (Account 489.1) 303
19 Deliveries of Gas Transported for Others (489.2) 305
20 Deliveries of Gas Distributed for Others (Account 489.3) 301 4,456,597
21 Deliveries of Contract Storage Gas (Account 489.4) 307
22 Exchange Gas Delivered to Others (Account 806) 328
23 lGas Delivered as Imbalances (Account 858) 328
24 Deliveries of Gas to Others for Transportation (Account 858) 332
25 Other Gas Delivered to Storage (Explain) (1) _________ (330,408)
26 Gas Used for Compressor Station Fuel 509 1,273,226
27 Other Deliveries (Specify) (footnote details)
28 Total Deliveries (Total of lines 17 through 27) I 23,848,010
29 GAS UNACCOUNTED FOR
30 Production System Losses I
31 Gathering System Losses
32 Transmission System Losses
33 Distribution System Losses
34 Storage System Losses
35 Other Losses (Specify) (footnote details)
36 ITotal Gas Unaccounted For (Total of lines 30 through 35) -
37 Total Deliveries and Gas Unaccounted For (Total of lines 28 and 36) 23,848,010
(1) Represents net gas withdrawals and injections.
IDAHO STATE NATURAL GAS ANNUAL REPORT (IC 61-405) G.lD.520