2017Annual Report.pdf

tEffi*.
April2T ,2018
Ms. Diane Hanian
Secretary
ldaho Public Utilities Commission
PO Box 83720
Boise, lD 83720-0074
Re: ldaho Power Company's 2017 Annual FERC Form 1 Report
Dear Ms. Hanian:
Enclosed for filing are two copies of ldaho Power Company's FERC Form 1 report and
ldaho supplement for the year ending December 31,2017. One bound and one unbound
copy are being provided as requested by the ldaho Public Utilities Commission. Also
included is the IDACORP 2017 Annual Report.
lf you have any questions, please contact Regulatory Analyst Kelley Noe at 208-
388-5736 or [e-mail].
Very truly yours,
LISA D. NORDSTROM
Lead Counse!
I [e-mail]
LDN:kkt
Enclosures
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Lisa D. Nordstrom
An IDACORP Company
THIS FILING IS
Item 1: E An lnitial(Original)
Submission
OR E Resubmission No. _Pc- E
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
Form 1 Approved
OMB No.1902-4021
(Expires 12131120191
Form 1-F Approved
OMB No.1902-0429
(Expires 12131120191
Form 34 Apprwed
OMB No.l902{t205
(Expires 1213112019\
These reports are mandatory undor the Federal Power Act, Sections 3, 4(a), 3M and 309, and
18 CFR 141.1 and 141.4O0. Failure b report may result in criminal fines, civil penalties and
other sanctions as proMded by law. The Federal Energy Regulatory Commission does not
consider hese reports to be of confidential natrre
Exact Lega! Name of Respondent (Company)
ldaho Power Company
Year/Period of Report
End of 20171Q4
FERC FORM No.1/3-Q (REv. 02-04)
Deloitte.Dcloitte & Toucha LLP
800 West tqain Street
Suite 1400
Boise, IO 83702-7734
U5A
Tel: il 208 3429361
www.deloitte,com
INDEPENDENT AUDITORS' REPORT
Idaho Power Company
Boise, Idaho
We have audited the accompanying financial statements of Idaho Power Company (the
"Company"), which comprise the balance sheet - regulatory basis as of December 3L,20L7,
and the related statements of income - regulatory basis, retained earnings - regulatory basis,
and cash flows - regulatory basis forthe yearthen ended, included on pages 110 through 123
of the accompanying Federal Energy Regulatory Commission Form 1, and the related notes
to the financial statements.
Management's Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial
statements in accordance with the accounting requirements of the Federal Energy Regulatory
Commission as set forth in its applicable Uniform System of Accounts and published
accounting releases; this includes the design, implementation, and maintenance of internal
control relevant to the preparation and fair presentation of financial statements that are free
from material misstatement, whether due to fraud or error.
Auditors' Responsibility
Our responsibility is to express an opinion on these financial statements based on our audit,
We conducted our audit in accordance with auditing standards generally accepted in the
United States of America. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free from material
misstatement.
An audit involves peforming procedures to obtain audit evidence about the amounts and
disclosures in the financial statements. The procedures selected depend on the auditor's
judgment, including the assessment of the risks of material misstatement of the financial
statements, whether due to fraud or error. In making those risk assessments, the auditor
considers internal control relevant to the Company's preparation and fair presentation of the
financial statements in order to design audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the effectiveness of the
Company's internal control. Accordingly, we express no such opinion. An audit also includes
evaluating the appropriateness of accounting policies used and the reasonableness of
significant accounting estimates made by management, as well as evaluating the overall
presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide
a basis for our audit opinion,
Opinion
In our opinion, the regulatory-basis financial statements referred to above present fairly, in
all material respects, the assets, liabilities, and proprietary capital of Idaho Power Company
as of December 31, 2OL7, and the results of its operations and its cash flows for the year then
ended in accordance with the accounting requirements of the Federal Energy Regulatory
Commission as set forth in its applicable Uniform System of Accounts and published
accounting releases.
Basis of Accounting
As discussed in Note 1 to the financial statements, these financial statements were prepared
in accordance with the accounting requirements of the Federal Energy Regulatory Commission
as set forth in its applicable Uniform System of Accounts and published accounting releases,
which is a basis of accounting other than accounting principles generally accepted in the
United States of America. Our opinion is not modified with respect to this matter.
Restricted Use
This report is intended solely for the information and use of the board of directors and
management of the Company and for filing with the Federal Energy Regulatory Commission
and is not intended to be and should not be used by anyone other than these specified parties.
fr.^lrA, ^t {*rol. u4
April 18, 2018
-2-
FERC FORIU| NO. 1/3-Q:
IDENTIFICATION
01 Exact Legal Name of Respondent
ldaho Power Company
02 Year/Period of Report
End of z0trll04
03 Previous Name and Date of Change (lf name changed during yea)
tt
04 Address of Principal ffirce at End of Period (Srraet, CW, Stslta, Zip Code)
1221W ldaho St, P.O. Box 70 Boisa, ld 83707-0070
05 Name of Contact Person
Ken Petersen
06 Title of Conlact Person
VP, Controller and CAO
07 Address of Contact Person (Street, City, State, Zp Cde)
'1221W ldaho St, P.O. Box 70 Boise, ld 83707-0070
08 Telephone of Contact Parson,lncluding
Area Code
[phone]
09 This Report ls
(1) ffi An Original (2) tr A Resubmission
10 Date of Report
(tib, Da, Yr)
04t18t2018
AN}{UAL CORPC}RATE OFFICER CERTIFICATION
have EEmined this .eport and b he b€st of my knowlcdge. lnfurmaton, and bollof all statements of fa6{ oonblnod ln thls ,eport arB oorr€c{ Etatem€nb
the buslnccs afiairs of lhc rorpondent and lhe finandal stabmcnts, and oher f,nandal lnformaUon contained in thie r€port, conbm ln all mabdal
undenBignad offcr cerlifiee hat:
respecG b he Uniform System ot Ac6unb,
01 l,lame
Kcn PctGGcn
04 Date ggned
(Mo, Da, Y0
04,t1u2018
02 Tltle
Mce Prssldent, Conbollor & CAO
03 Signalurc
Ken Pstersen
Ti{e 18, U.S.C. 1001 msk s it r crtmc 6r any poron to lnowingly and willingly to make b any Agacy or Department of hc Unitsd States any
felso, llctltious or fraudulont ltatem€ntB as b any matbr wlthin lts judadctlon.
FERC FORil No.1/3-Q (REv. o2-o4l Page 1
This(1)ls:
Original
Dab of Reoort(Mo, Da, Yi)Year/Period of Report
End of 20171Q4ldaho Power Company (2t A Resubmission 04t1u2018
Enter in column (c) the terms'none," "not applicable," or "NA," as appropriate, where no information or amounts have been r€ported for
certain pages. Omit pages where the respondents are'none,"'not applicable," or "NA".
Line
No.
(a)
Title of Schedule Reference
Page l,lo.
(b)
Remarks
(c)
1 General lnformation 101
2 Conkol Over Respondent 102
3 103
4 Officers 104
5 Directorg 105
6 lnformation on Formula Rates 106(aXb)
7 lmportant Changes During the Year 108-109
8 11G113ComparaUve Balance Sheet
I Statement of lncome for he Year 't14-117
't0 11&119Statement of Retained Eamings for the Year
11 Statement of Cash Flows 120-121
12 Notes to Financial StatemenB 122-123
't3 Slatement of Accum Cornp lncome, Comp lncome, and Hedging Aclivities 122(a\b)
14 200-201Summary of Utility Plant & Accumulatod Provisions br Dep, Amort & Dep
15 Nuclear Fuel Materials 202-203 N/A
16 20+207Elecfic Plant in Service
17 Electic Plant Lsas€d to Others 213 N/A
18 Electic Plant Held for Future Use 214
19 Construc{on Work in Progress-Electric 216
20 Acsrmulated Provision for Depreclation of Electric Utillty Plant 219
21 lnvsstn€nt of Subsidiary Companies 224-225
22722Materials and Supplies
23 Allowances 228(abl-229(abl N/A
24 230 N/AExtaordinary Property Losses
25 Unrecovered Plant and Regulabry Study Costs 230 N/A
26 Transmission Service and Generation lnterconnection Sfudy Costs 231
27 Other Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accumulated Defened lncome Taxes 234
30 250-251Capital Stock
31 Other Paid-in Capital 253
32 Capihl Stock Expense
33 Long-Term Debt 256257
34 261Roconcilhtion of Reported N€t lncome wih Taxable lnc br Fed lnc Tax
35 Taxes Accrued, Prepaid and Charged During the Year 262-263
36 266-267Accumuhted Def€ned lnvestm€nt Tax Cr€dits
FERC FORil NO. r GD. 12-96)Page 2
Corporations Controlled by Respondent
254
Name of Respond€nt
ldaho Power Company
ls:
Original
This(1)
(2t
Date of Report(Mo, Da, Yr)
YaarlPeriod of Report
End of 20171Q4
Resubmission o4t18t2018
Enter in column (c) the terms "none,'"not applicable,'or "N4,'as appropriate, where no inbrmation or amounts have been reported for
certain pages. Omit pages where the rospondents are "none," "not applicable," or'NA".
Line
No.
Refer6nc€
Page No.
(b)(c)
Remarks
(a)
Title of Schedule
26937Other Defened Credits
38 Accumulated Deferred lncome Taxe+Accelerated Amortization Property 272-273 N/A
27+27539Accumulated Dofened lncome Taxes-Othor Property
N 276277Acalmulated Deferred lncome Taxes-Other
41 Other Regulatory Liabilities 278
42 300-301Elecfic Operating Revenues
43 Regional Transmission Service Revenues (Acount 2157.1)3AZ N/A
30444Sales of Electricity by Rate Schedules
45 Sales br Resale 310-31 1
46 320-323Electic Operation and Maintenance Exgenses
47 Purchased Power 326-327
48 328-330Transmission of Eleclridty fur Others
49 Transmission of Electric;ity by ISO/RTOs 331 N/A
33250Transmission of Eleckicity by Others
51 Miscdlaneous General Expensos-Eleetic 335
52 33G337Depreciation and Amortization of Elec{ric Plant
53 R€gulatory Commission Expenses 35G.351
352-35354Research, Development and Demonstration Activities
55 Distribution of Salaries and Wages 35+355
356 N/A56Common Utility Plant and Expenses
57 Amounts induded in ISO/RTO Settement Statements 397 N/A
39858Purcfiase and Sale of Ancillary Services
59 Monthly Transmission System Peak Load 400
400a N/A60Monthly ISO/RTO Transmission System Peak Load
61 Electic Energy Account 401
40162Monthly Peaks and Output
63 Steam Electric Generating Plant Statstics 402403
64 Hydroelecbic Generating Plant Statistics 40il07
65 40&409 N/APumped Storago Generating Plant Statistics
410-41166Generating Plant Statistics Pages
FERC FORM NO. I (ED. r2.e6)Page 3
Name of Respondent
ldaho Power Cornpany
This(1)
(2)
ls:
Orlginal
A Resubmission
Date of Reoort(Mo, Da, Yi)Year/Period of Repofl
End of 2017tQ4
o4118t2018
Enter in column (c) the terms "none,"'not applicable,' or'NA," as appropriate, where no information or anpunts have been reportsd fior
c€rtaan pagos. Omit pages wh€re he rgspondents are "none," 'not applicable," or "NA'.
Line
No.
(a)
Title of Schedule Re{erence
Page No.
(b)(c)
Remarks
42242367Transmission Line Statis0cs Pages
68 Transrnission Lines Added During the Year 424425
69 Substations 426-427
70 Transactlons wlth Associated (Affi liated) Companies 429
45071Foohote Data
Stockholders' Reports Check appropriate box:
E Two copieswill ba submitted
! No annual report lo stockholders is preparud
FERC FORit NO. r {ED. 12-96)Pago 't
GENERAL INFORMATION
1. Provide name and tiUe of officer having custdy of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
X.n Patgrrerr Vice Preaiaieat, Controller anrd CAO, Idrho Porer Collplrry
L22L w. Iddro gtreet, P.o. Bor 70, Boirc, Idabo 83?0?-007O
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
lf incorporated under a special law, gMe reference to such law. lf not incorporated, state that fact and give the type
of organization and the date organized.
Idrho, itune 30, 1989
3. lf at any time during the year the property of respondent was held by a receiver or truste€, give (a) name of
receiver or trust@, (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 truslee ceased.
llot ll[)].ic.b]'c
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
Clais of Utility S.rvice stat.
E].€ctric ldzrho
Electrie oregron
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?
(1) n Yes...Enter the date when such independent accountrant was initially engaged
(2) El No
Name of Respondent
ldaho Power Company
This Report ls:
(1) E An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
0411u2018
Year/Period of Report
End of 2017tad-
FERC FORM No.l (ED.l2{7}PAGE IOl
Name of Respondent
ldaho PowerCompany
This Report ls:
(1) E An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Y)
0411812018
Year/Period of Report
End of 2o17t@
CONTROL OVER RESPONDENT
1. lf any corporation, business trr.rst, or similar organization or a combination of such organizations jointly held
control over the repondent at the end of the year, state name of controlling corporation or organization, manner in
wtrich control was held, and extent of control. lf control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. lf control was held by a trustee(s), state
name of lrustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
ldaho Power Company is a subsidiary of IDACORP, INC
IDACORP owns 1(D% of ldaho Power Company's Common Stock.
IDACORP is a public utility Holding Company incorporated effective 10-1-'t998
FERC FORM NO. 1 (ED.12-S6)P.ge 102
Name of Respondent
ldaho Power Company
This(1)
(2)
ls:
Origlnal
Dal6 of ReDort(Mo, Da, Yi)Year/Period of Report
20't7tQ4
A Rasubrnission 04l18t2cIA End of
CORPORATIONS CONTROLLED BY RESPONDENT
1. Report below the names of all corporations, business truSs, and similar organizations, controlled direc,tly or indirectly by respondent
at any time during the year. lf control ceased prior to end of year, give particulars (details) in a footnote.
2. lf 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. lf control was held joinUy with one or more other interests, state the fact in a footnote and name the other interests.
Defini0ons
1. See the Uniform System of Account's for a definition of control.
2. Direct control is that whicfi is exercised without interposition of an intermediary.
3. lndirect conbol is that which is exelcised by the interposition of an intermediary which exercis€s direct control.
4. Joint contol is that in which neither interest can effsctively control or direct action without the cons€nt of the other, as where the
voting control is equally divided between two holders, or each paily 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 wlthin the meaning of the deffnition of
control in the Uniform System of Accounts, regardless of the rolative voting rights of each party.
Line
No.
Name of Company Contolled
(a)
Kind of Business
(b)
Percent Voling
Stock Owned
(c)
Fooflote
1 Direct Control
2 ldaho Energy Resources Company Coal mining and mineral 100%
3 dovelopment
4
5
6
7
8
I
10
11
12
13
't4
15
16
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO. I (ED. 12-90)Page 103
Ref.
(d)
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 2O17lQ4
Resubmission 04t18t2018ldaho Power Company (2)
OFFICERS
1. Report below the name, title and salary for each oxecutive offfcer whose salary is $50,000 or more. An 'executive ofiicef of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2. lf a change was made during the year in the incumbent of any position, show name and total rclmuneration of the previous
incumbent, and the date the change in incumbency was made.
Lrne
No.
T'UE
(a)
Name ot Officer
(b)
SalarvforYoir(c)
1
2 Pr€sident & Chief Executive Offrcer Darrel T. Anderson 800,000
3
4 Senior Mce President, CFO & Treasurer Steven Keen 420,000
5
t!Senior Mce President, COO Lisa Grow 'm0,000
7
I Senior Mce Prosident, Public Afhirs Jeftey Malmen 295,000
I
10 Senior Mce President, Admin Seryices & Chief HR Offcer Lonnie Krawl 300,000
11
12 Senior Mce President & General Counsel Brian Buckham 300,000
13
14 Mce President, T&D Engineering & Constuc,tion, and CSO Vem Porter 295,000
15
16 Mco President, Power Supply Tessia Park 265,000
17
18 Mce Presid€nt. Customer Operations & Bus. Development Adam Richins 220,000
19
20 Mce President, Corporate Confoller & CAO Ken Petersen 2s5,000
21
22 Mce Prosident of lnformation Tedtnology & CIO Jeff Glenn 240,000
23
24 Mce President of Regulatory Affairs Tim Tatum 180,000
25
26 Corporate Secretary Patrick Haningtcn 202,000
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORrrr NO.1 (ED. 12-S6)Page 104
Name ls:
Originalldaho Power Company (1)
(21 Resubmission
Date of Reoort
(Mo, Da, Yi)
04t't812018
Year/Period of Report
End of 2O17lQ4
DIRECTORS
LtneNo.Name (a%Iire) ol Diroc{or less Aooress
1
2 Judith A. Johansen 10446 E. Palo Brea Dr., Scottsdale, Arizona 85262
3
4 Christine King, Comp. Committee Chair,"'8527 East Old Field Rd
5 Scottsdale, Arizona 85266
6
7 Thomas E. Carlile 2719 North Woodview placs, Boise ldaho 83702
8
I Danel T. Anderson President & CEO, r"*ldaho Power Company,'1221 W. ldaho SUeet,
10 P.O. Box 70, Boise, ldaho tI170ru070
11
12 J. LaMont Keen 481 North Shata Ma Way, Boise ldaho tlil712
13
14 Robert A. Tinstman, Board Chair & Corp Gov Chair, '**4433 W Quail Point Court, Boise, ldaho 83703
't5
16 Richard Dahl, Audit Chair "'60 Laiki Pl.
17 Kailua, Hawaii 96734-1 905
18
19 Dennis L. Johnson 926 W Oakhampton Dr, Eagle, ldaho 83616
20
21 Ronald W. Jibson 417 Aerie Circle, North Salt Lake City, Utah 84054
22
23 Richard J. Navarro 1256 E. Candleridge Ct., Boise, ldaho 83712
24
25 Annette G. Elg (1)3475 E. Rivernest Lane, Boise, ldaho 8370G6928
26
27 (1) Appointed to Board February 2017
28
29
30
31
32
33
u
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO.,t (ED.12-95)Page 105
L Report below the information called for concerning each director of the respondent who held office at any time during the year. lnclude in column (a), abbreviated
titles of the directors who are olficers of the respondenl.
2. Designale members of lhe Execulive Committee by a triple aslerisk and the Chairman of the Executive Committee by a double astaisk,
rnnqpar E
Name of Respondent
ldaho Power Company
This Reoort ls:(1)E An Original
(2) n A Resubmission
Date of Report(Mo. Da, Yr)
04t1u2018
Year/Perioc
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tadff Number FERC Proceeding
Does he respondent have brmula rates?E v""
ENo
'1. Please list the Commlssion acc€pted tormula rates including FERC Rab Sdredule or Tarlff Number and FERC proceeding (i,e, Docket No)
accepting he rate(s) or dranges in the accepted reto.
Line
No,FERC Rate Schedule or Tariff Number FERC Proceeding
1 FERC ElectricTariff
2
3
4
5
6
7
8
I
10
11
12
13
14
15
16
17
18
't9
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
of Report
En6o1 2O17lQ4
FERC FORIUI NO. I (NEW. r2-0E)Page 1l)6
Name of Respondent
ldaho Power Company {2)
ls:
An Original
A Resubmission
Oah of Reoort(Mo, Da, Yi)Year/Period of Report
gn6 s1 2A17lQ4
0411812018
INFORMATION ON FORMUTA RATES
FERC Rate Sdredule/Tariff Number FERC Proceeding
Does the respondent ffle with lhe Commission annual (or more frequent)
fllings containing tho inputs b tho formula rate(s)?I Yes
ENo
2. lf yes, provide a listing of suctr lilings as oontainsd on the Commission's eLibrary website
Line
No.Accession No.
Oocum6nt
Date
\ Filed Date Docket No.Descnption
Formula Rate FERC Rate
Sdredule Number or
Tariff Number
ldaho Power Companl FERC Electric Tariff12017082&5100 au2812017 ER0$.1641-000
2 2017 Annua
3 lnformatlonal Fillinl
4 under ER09-1641-00(
5
o
7
I
I
10
't1
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
I I
FERC FORM NO. I (NEW. 12-08)Pag. 106a
Name of Respondent
ldaho Porver Company Original
Date of Reoort
(Mo, Da, Yi)
This
(1)
(2\A Resubmission 0411812018
INFORMATION ON FORMULA RATES
Formula Rate Variances
1. lf a respondent does not submit such lilings hen indlcaG in a footnote b he appllcable Form 1 sctredule where brmula rate inputs differ ftom
amounts reported in the Form 1.
2. The foohote should provide a narrative desoiption explaining horl he 'rate" (or billing) was derived if diffurent from the reported amount in h6
Form 1.
3. The foohote should explain amounts excluded ftom the ratebase or where labor or oher allocation facto6, operaling expenses, or other items
lmpacting brmula rate inputs difier ftom amounb reported in Form 1 scfiedule amounts.
4. Where the Commlssion has provided guidance on formula rate inputs, the specific proc66ding should bo not6d in fte footnote.
Line
No.Page No(s).Schedule Column Line No
1
2
3
4
5
6
7
8
I
10
11
12
13
14
't5
16
17
'18
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FERC FORM NO. r (NEW. 12.08)Page 100b
Year/Period of Reportgn66 20171Q4
Name of Respondent
ldaho Power Company
This Report ls:
(1)
(21 En An Original
A Resubmission
Date of Report
o4t18t2018
Year/Period of Report
End of 2O17lQ4
IMPORTANT CHANGES DURING THE QUAFTTER/YEAR
Give particulars (details) conceming the matters indicated below. Make the stat€rnents explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter'none,' "not applicable," or'NA'where applicable. lf
information which ansrarers an inquiry is given elsewtere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acguired. lf acquired without the payment of consideration, state that fad.
2, Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars conceming the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto,
and reference to Commission authorization, if any was required. Give date journal entries called for by the Unifurm System of Accounts
were submifted to the Commission.
4. lmportant leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, asslgned or surrendered: Give
effeclive dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. lmportant extension or reductaon of transmission or distribution system: State tenitory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customors added or lost and approximate annual r€lvenues of eacft class of service. Each natural gas company must also state major
new continuing souroes of gas made available to it from punfiases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such anangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guaranteo.
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 efiect 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 hansactions of the respondent not disclosed elsewhere in this report in which an officer,
director, s€curity holder reported on Page 104 or 105 of the Annual Report Form No. I, voting trustee, associated company or known
associate of any of these persons was a party or in which any wch person had a material interest.
11. (Reserved.)
12. lf the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and fumish the data required by lnstructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in officers, directors, major security holders and voting powers of he respondent that may have
occuned during the reporting period.
14. ln the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percsnt please describe the s(7nificant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE 108 ]NTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORit NO. 1 (ED. r2-96)Page 108
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t1812018
Year/Period of Report
2017tQ4
IMPORTANT CHANGES DURING THE QUARTERI/EAR (Continued)
l. None
2. None
3. None
4. None
5. None
6. None
7. None
8. Effective 12130/2017 a3.0o/o general wage adjushnent was implernented.
9. Disclosed in Financial Statement footnotes, see page 123.27.
10. None
11. None
12. None
13. Officer Changes in20l7
Lisa A. Grow's title changed from "Sr. Vice President of Operations" to "Sr. Vice President and
Chief Operating Officer" effective March 1,2017.
N. Vem Porter's title changed from "Vice President of Customer Operations" to "Vice President
of Transmission and Distribution Engineering and Construction and Chief Safety Officer"
effectiveMarch 1,2017.
Adam J. Richins was appointed "Vice President of Customer Operations and Business
Development" effective March l, 2017.
14. Idatro Power and its unregulated parent, IDACORP have separate cash managerrent programs (separate
bank accounts, liquidity facilities, short-term debt and investment programs). No moneyhas been loaned or
advanced from Idaho Power to IDACORP through a cash management progftrm.
o
a
a
FERC FORM NO. 1 Page 109.1ED. 12-s6)
Name of Respondent
ldaho Power Company
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Tifle of Account
(a)
Ref.
Pag€ i,lo.
(b)
Cunent Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12t31
(d)
1 UTILIW PLANT
2 Utility Plant (101-106. 114)200-201 5,914.236,887 5,739,484,446
3 Consbuc{ion Wo* in Progress (107)200-20'l 452,42434 405,068,524
4 TOTAL Utility Plant (Enter Totral of lines 2 and 3)6,366,661,227 6,144,552,970
5 (Less) Acorm. Prov. fur Depr. Amort. Depl. (108, I 10, 'l 1 I , I 1 5)200-201 2,283.266.546 2,175,085,495
6 Net Utility Plant (Enter Total of line 4 less 5)4,083,394,681 3,969.467,475
7 Nudear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120,1)202-203 0 0
I Nudear Fuel Materials and Assemblies-Stock Account (120.2)0 0
I Nudear Fuel Assemblies in Reactor (120.3)0 0
10 Spent Nuclear Fuel (120.4)0 0
11 Nuclear Fuel Under Capital Leases (120.6)0 0
12 (Less) Accum. Prov. br Amort. of Nucl. Fuet Assernblies (120.5)202-203 0 0
't3 Net Nuclear Fuel (Enter Total of lines 7-1 1 less 12)0 0
14 Net Utility Plant (Enter Total of lines 6 and '13)4,083,394,681 3,969,467,475
15 Utility Plant Adjustments ('116)0 0
16 Gas Stored Underground - Nonornent (117)0 0
'17 OTHER PROPERTY AND INVESTMENTS
18 NonutiliV Property (121 )1,071,638 1,071,638
19 (Less) Accum. Prov. br Depr. and Alrl.crl. (1221 0 0
20 lnvestments in Associated Companies (123)0 0
21 lnvestment in Subsidiary Companies (123.1)224-225 72,212,978 77,130,927
22 (For Cost of Account 1 23. 1, See Foohote Page 224, line 421
23 Noncunent Porlion of Allowances 22U229 c 0
24 Other lnvestnents ( 1 24)c 0
25 Sinking Funds ('t25)c 0
26 Depreciation Fund (126)0 0
27 Amortization Fund. Federal (127)0 0
28 Other Special Funds (128)34,265,777 24,018,570
29 Speclal Funds (Non Major Only) (129)0 0
30 Long-Term Portion of Derlvative Assets (175)4,074 0
31 Long-Term Portion of Derivative Assets - Hedges (176)0 0
32 TOTAL Other Property and lnvestments (Lines 18-21 and 23-31)103,554,467 102,221,135
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds (Non-ma.jor Only) (130)0 0
35 Cash (131)34,375,147 14.159,468
36 Sgedal D€posits (132-1341 2,364,499 1,168,084
37 Working Fund (135)10,500 13,600
38 Temporary Cash lnvestnenb (136)10,260,000 29,967,367
39 Notes Receivable (141)-86,399 -83,038
40 Customer Accounts Receivable (142)77,7U,379 73,276,818
41 Other Accounts Receivable (143)28,169,330 25,535,458
42 (Less) Acorm. Prov. br Uncollectible Acct.-Credit (1,14)2,192,252 1,131,759
43 Notes Receivable hom Associated Companies (145)0 0
44 Accounts Receivable ftom Assoc. Companies (146)0 0
45 Fuel Stock (151)227 56,638,45S 53,700,442
46 Fuel Stock Expenses Undistibuted (152)227 5 -2,623
47 Residuals (Elec) and Exraded Produc'ts (153)227 0 0
48 Plant Materials and Operating Supplies (154)227 53,856,63C 54,454,6M
49 Merdundise (155)227 c 0
50 Other Materials and Supplles (156)227 c 0
51 Nuclear Materials H€ld br Sale (157)2A2-2031227 c 0
52 Allowanoos (158.1 and 158.2)228-229 c 0
FERC FORM NO. 1 (REV. 12-03)Page 110
This Report ls:
(1). E An Original
(2',)A Resubmission
Date of Report
(Mo, Da, Yr)
o411u2018
Year/Period of Report
End of 2417lQ4
Name of Respondent '
ldaho Power Company
This Report ls:
(1) E AnOriginal
A Resubmission
Date of Report
(Mo, Da, Yr)
04t192018
Year/Period of Report
End of 2o17tQ4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBlTSFontinueo)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Cunent Year
End of Ouarter/Year
Balance
(c)
Prior Year
End Balance
12,31
(d)
53 0 0(Less) Noncurrent Porlion of Allowances
54 Stores Expense Undistributed (1 63)227 1,888,307 3,403,797
55 Gas Stored Underground - Curent (164.1 )0 0
56 Liquefied Natural Gas Stored and Held for Processing (1il2{il.3)0 0
57 Prepayments (165)16,865,877 18,269,814
58 Advances for eras (16&167)0 0
59 lnterest and Dividends Receivable (171)6,500 24.539
60 0 0Rents Recelvable (1721
61 75,119,761 80,738,420Accrued Utility Revenues (173)
62 Miscellaneous Cunent and Accrued Assets (174)0 0
63 Derivative lnstrument Assets (1 75)22,228 5,951,233
64 (Less) Long-Term Portion of Derivative lnstrument Assets (175)4,074 0
65 Derivatlve lnstrumont Assets - Hedges (176)0 0
66 0(Less) Long-Term Porlion of Dedvative lnstrument Asets - Hedges (176 0
67 355,058,897 359,446,304Total Cunent and Accruod Assets (Lines 34 through 66)
68 DEFERRED DEBITS
69 Unamorlized Debt Expenses (181)15,097,172 't6,313,567
70 Extraordinary Property Losses ( 1 82. I )230a 0 0
71 Unrecovered Plant and Regulatory Study Costs (182.2)230b 0 0
1,471,940,40172Other Regulatory Assets (182.3)232 1,132,096,194
73 c 0Prdim. Survey and lnvestigation Charges (Elocttic) (183)
74 Preliminary Natural Gas Survey and lnvestigation Charges'183.1)c 0
75 Other Preliminary Survey and lnvostigaton Charges (183.2)c 0
76 Clearing Accounts (1 84)535,553 1,290,608
77 Temporary Facililies (185)c 0
78 233 73,132,688 75,332,657Misoellaneous Defened Debits (1 86)
79 c 0Def. Losses from Disposition of Utility Plt. (187)
80 Researdr, Oevel. and Demonstration Expend. (188)352-353 0 0
81 Unamortized Loss on Reaquired Debt (189)39,822,616 41,975,568
82 Accumulated Defuned lncome Taxes (190)234 289,813,91S 2ffi,326,525
83 Unrecovered Purchased Gas Costs (19'l)0 0
84 1,893,179,330Total Defened Debits (lines 69 through 83)1,550,498,14€
85 6,092,506,193 6,324,314,244TOTAL ASSETS (lines 14-16, 32, 67, and 84)
FERC FORM NO. 1 (REV.12-031 Page 111
Name of Respondent
ldaho Power Company
This Report is:
(1) B AnOriginal
(2)A Resubmission
Date of Report
(mo, da, yr)
o4t1u20'18
Year/Period of Report
end of 2017tQ4
CoMPARATTVE BALANCE SHEET (LrABrLtTtES AND OTHER CREDTTS)
Line
No.Title of Acoount
(a)
Ref.
Page No.
(b)
Current Year
End of QuarterfYear
Balance
(c)
Prior Year
End Balanca
12131
(d)
1 PROPRIETARY CAPITAL
2 Common Stock lssued (201)250-251 97,877,030 97,877,030
3 Preferred Stock lssued (204)250-251 0 0
4 Capital Stock Subscribed (202, 2051 c 0
5 Stock Liatrility br Conversion (203, 206)c 0
6 Premium on Capital Stock (207)712,257,435 712,257,435
7 Other Paid-ln Capital (20&21 1)253 0 0
8 lnstallments Received on Capital Stock (212)252 0 0
9 (Less) Discounton Capital Stod (213)254 0 0
10 (Less) Capital Stock Expense (214)254b 2,096,925 2,096,925
'tl Retained Eamings (215, 215.'1. 2161 1't&119 't,234,859,727 1,136,879,473
Unappropriated Undistributed Subsidiary Eamings (216.1)11&119 69,749,884 74,667,833
13 (Less) Reaquired Cagital Stock (217)25G251 0 0
14 Noncorporate Proprietorship (Non-major only) (21 8)U 0
15 Accumulated Other Comprehensive lncome (219)122(a\(b\-26,872,205 -20,881,620
16 Total Proprietary Capital (lines 2 through 15)2,085,774,942 1,998,703,226
't7 LONGTERM DEBT
18 Bonds (221)256257 1,745.460,000 1,745,460,000
19 (Less) Reaquired Bonds (222)256257 0 0
20 Advances from Associated Companies (223)256257 0 0
21 Other Long-Term Debt (224)256-257 't9,885,000 20,948,636
22 Unamortized Premium on Long-Term Dobt (225)0 0
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)4j24,868 4,417,463
24 Total Long-Term Debt (lines 18 hrough 23)1,761 .220,132 1,761,991,173
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncunent (227)c 0
27 Aco.rmulated Provision for Property lnsurance (228.1)c 0
28 Aco.rmulated Provision ior lnjuries and Damages (228.2)1,468,935 1,792,128
29 Accumulated Provision for Pensions and Benefits (228.3)438,886,025 41 1,633,628
30 Acanmulated Miscellaneous Operating Provisions (228.4)0 0
31 1A3,2',t9,162Accumulated Provision for Rate Refunds (229)119,666,875
32 Long-Term Portion of Derivative lnstrument Liabilities 0 0
33 Long-Term Portion of Derivative lnstrument Liabilities - Hedges 0 0
34 Asset Retirement Obligations (230)26,415,381 26,25?,286
35 Total Oher Noncunent Liabilities (lines 26 through 34)586,437,216 542,902,204
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)0 21,800,000
38 Accounts Payable (232)107,891,85S 126,470,087
39 4,083,304 244,435Notes Payable to Associated Companies (233)
40 Accounts Payable to Associated Companies (234)57,561,953 1,056,374
41 Custorns Deposits (235)2,037,068 2,ffi4,762
42 Taxes Accrued (236)262-263 -15,156,342 -11,945,257
43 22,620,139 22,539,658lnterest Accrued (237)
44 Dividends Declared (238)0 0
45 Matured Long-Term Debt (239)0 0
FERC FORM NO. 1 (rev. 12-031 Page 112
'12
Name of Raspondent
ldaho Power Company
This Report is:
(1) B AnOriginal
Date of Report
(mo, da, y')
04t't8/2018
Year/Period of Report
end of 201ttQ4A Resubmission
COMPARATIVE BALANCE SHEET (LlABlLlTlES AND OTHER CREDII&htinued)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Cunent Year
End of Quarterffear
Balanca
(c)
Prior Year
End Balance
1?,31
(d)
46 Matured lnterest (2l())0 0
47 Tax Collections Payable (241)2,751,8U 2,847,908
48 Miscellaneous Current and Accrued Liabilities (242)50,874,603 49,816,656
49 Obligations Under Capital Leases-Cunent (243)0 0
50 Derivative lnstrument LiabiliUes (244)'t,224,571 0
51 (Less) Long-Term Porffon of Derivative lnstrument Liabilities 0 0
52 Derivative lnstrument Liabilities - Hedges (245)0 0
53 (Less) Long-Term Portion of Derivative lnstrument Liabilitios-Hedges 0 0
54 Total Cunent and Accrued Liabilities (lines 37 through 53)233,889,049 215,694,623
55 DEFERRED CREDITS
56 Customer Advances br Conshuclion (252)6,762.256 5,252,737
57 Accumulated Defuned lnvestment Tax Credits (255)26d267 87,384,738 79,959,845
58 Deferred Galns from Disposition of Utility Plant (256)0 0
EO Other Defened Credits (253)269 8,746,270 '10,479,342
60 Other Regulatory Liabilities (254)278 307,404,206 77,043,013
6't Unamortized Gain on Reaquired Debt (257)0 0
62 Accum. Defened lncome Taxe+Accel. Amort.(281 )272-277 0 0
63 Accum. Deferred lncome Taxes-Other Poperty (282)890,330,923 1,449,526,847
64 Accr.rm. Defened lncome Taxes-Other (283)124,556,461 182,761,2U
65 Total Defered Credits (lines 56 lhrough 64)1,425,184,854 1,805,023,018
66 TOTAL LIABILITIES AND STOCKHOLOER EQUITY (lines 't6, 24,35,54 and 65)6,092.506,193 6,324,314,244
FERC FORM NO. 1 (rev. 12-03)Page 113
Nam6 of Respondent
ldaho Po,ver Company
This
(1)
(21
ls:
Original
Date of Report(Mo, Da, Yr)
04t1u2018
Year/Period of Report
End of 2O17lQ4A R€submission
STATEMENT OF INCOME
Quarterly
1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in oolumn (g) plus the data in column (i) plus he
data in column (k), Report ln column (d) simllar data br he previous year. This infornation is repoiled in lhe annual filing only.
2. Enter in column (e) the balance br he reporting quarter and in oolumn (f) the balance for fre same lhree monh period br he prior year,
3. Report in column (g) th6 quarter b date amounts br electrlc utlllty function; in column (l) the quarter to date amounts for gas utlllty, and in column (k)
the quarter b date amounB for other ulility funclion br the cunent year quarlor.
4. Report in column (h) lhe quarter b date amounts br electric ufllity function; in column O the quarter b date amounts fur gas utility, and in column (l)
he quarter b date amounts br other utlity function br the prior year quarter.
5. lf additional columns are needed, place hem in a fuohote.
Annual or Quarterly ffappllcable
5. Do not report burfi quarter data in columns (e) and (0
6. Report amounts for aocounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Ohers, in anolher utillty columnin a slmllar manns to
a utility department Spread he amorn(s) over llnea 2 thru 26 as appropriaG. lndude thee amounts in @lumns (c) and (d) btala.
7. Report amounts in account 414, Oher UUlity Operating lncome, in lhe same manner as acoounb 412 and 413 above.
Line
No.
Tite of Account
(a)
(Rsf.)
Page No.
(b)
fohl
Currcnt Year to
Dab Balance lor
Quarbrffear
(c)
Total
PdorYearto
Dato Balance for
Qurbrffear
(d)
Cunent 3 Monhs
Ended
Quart€rly Only
No 4h Ouarter
(e)
Pdor 3 ibnhs
Ended
Quadoly Only
No 4th Qua.b,
(0
1 UTILITY OPERATING INCOME
2 Operating Revenueo (400)300-301 1,340,860,404 't,255,298,799
3 Openating Expensss
4 Operation Expenses (40'l )320-323 769,799,625 734,428,076
5 320323 60,983,589lvhintenance Expenses ('l{)2)67,074,765
6 Depreciaton Expense (403)336-337 153,958,586 135,048,584
7 Depreciation Expense forAsset Retimment Ccb (,f03.1)$4,$7 566,665 7m,272
I Amort, & Dopl. of Utility Plant (404405)336-337 6,243,722 6,649,455
I 336-3:t7 32,539Amort of Utility Plant Acq. Adi. (406)
10 Amoil. Property Lo6sos, Unr€cov Plant and Regulatory Study Cosb (407)
11 Amorl. of Conversion Erpnses (107)
12 1,289,770 1,242,422Regulatory Debib (407.3)
13 (Less) Regulahry Credits (407.4)-788,738
14 Taxes Ofier Than lncome Taxes (408.1 )262-263 34,089,536 32,823,311
15 llrcome Taxes - Fed€ral (4C8.1)262-263 1,1,701,501 -96,137
16 - Olher (409.1)m2-263 10,557,960 3,659,280
17 2y,272-277 s4,908,265 58,087,034Pmvisbn br tlefuned lncome Taxes (410.1)
18 (Less) Povision for Defuned lncome Tax$-Cr. (411.1)2U,n2-277 80,542,460 26,177,294
19 lnvestment Tar CrcditAdi - Net (411.4)266 7,424,893 304,915
20 (Less) Gains from DEp. of Utility Plant (411.6)
2'.|.Losses from Disp, of Utility Plant (111 .7)
22 (Less) Gains from Disposition of Allowanc$ (111.8)130,740 49,266
23 Losses fom Disposition of Allwances (411.9)
24 221,929 231,983Accretion Expense (41 1.10)
25 1,00r,894,1 18 1,013.947,400TOTAL Utility Operating ExperB$ (Enter Total of lhes 4 thru 24)
26 Net Util Oper lnc (Enter Tot line 2 less 25) Carry b Pg117,lin€ 27 275,966,286 241,351,399
FERC FORU NO.1r3-Q (REV. 02-04)Page 114
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:
Original
A Resubmission
Dale of Report(Mo, Da, Yr)
Year/Period of Reporl
Endof 20171Qd
0/.|1812018
9. Use page 122 tor imptlant notes r€gading the statement of income for any acoount thereof.
10. Give concise explanations cDnosming uns€tflod rate proceedings where a contingenc,y exisls suctr that refunds of a material amount may n€d b bo
made b the utillty's cr.rstomeB or whlch may result in matorial rofund b the utility with r€spect to pow6r or gas purdrases. State br each year effected
the gross rcvenuos or costs to whicfi the contingency relates and the tax effocts tog€ther with an explanatlon of the major frctors whic*r afiect the rights
of he utili$ b retain such revenues or re@ver amounB paid wlth r€spoct b power or gas purchases.
1'l Give concise explanations concemirE significant amounts of any r€ftrnds made or receivod during the year rcsulting from set(ement of any rato
poceeding affecting rgvenues received or o6ts inqred for power or gas purches, and a summary of the adjustnonts made b balance sheet, income,
and expense a@unts.
'12. ll any notes appearing in the report to stokholders are applicable to tho Statement of lncome, such nobs may be indud€d atpege 122.
13. Enter on gage 122 a conclse explanation of only trose changes in acounling m€lhods made during the year which had an effed on net income,
lncluding lhe basis of allocatlons and apporlionments from those used in the Feceding year. Also, give the appropriate dollar effect of such dranges.
14. Explain ln a footrote if the previoue yea/dquarte/s figureo are different fiom that reported in prior reports.
15. lf the columns are insuffcient br roporting eddl0onel utility depertments, supply the approprlate account tltles report the information in a footnote b
his schedulo.
ELECTRIC UTILITY GAS UTIL1TY OTHER UTILITY
Line
No.Current Year to Date
(in dollars)
(s)
Previous Year lo Date
(in dollars)
(h)
Cunent Year to Oate
(in dollars)
(i)
Previous Year to Date
(in dollars)
(i)
cufiEnt Year to Date
(in dollaa)
(k)
Pf€vous Year t0 Date
(in dollals)
(t)
1
't,340,860,404 1,255,298,7W 2
3
4769,799,625 734,428,076
60,983,589 67,074,765 5
6153,958,586 135,048,584
7566,665 720,272
I6,243,722 6,649,455
32,539 9
10
11
121,289,770 1,242,422
13-788,738
34,089,s36 32,*3,3'.t1 14
1544,70't,50'l -96,137
't610,557,S60 3,659,280
1754,908,265 58,087,034
80,542,460 26,177,294 t8
197,424,853 304,915
20
21
130,740 49,266 22
23
24221,929 231,983
251,064,894,118 1,013,947,400
27s,966,286 241,351,399 26
FERC FORM NO. I (ED. 12-00)Page il5
STATEMENT OF INGOME FOR THE YEAR
Name of Respondent
ldaho Power Company
Reoort ls:
[lRn orisinal Date of Reoort(Mo, Da, Yi)This(1)
(z',)
Year/Period of Report
End of 20171Q4A Resubmission 04t1u2018
TOTALLine
No.
Tite of Account
(a)
(Ref.)
Page No.
(b)
Currcnt Year
(c)
Previous Year
(d)
uurgnt J tuonns
Ended
Quaderly Only
No 4th Quarter
(e)
PnorJ Monms
Ended
Quarte/ry only
No 4th Quarter
(f)
27 N€t Utility Opeiatino lncome (Canied fom'ad fiom page 114)275,966,286 241,351,399
28 Ofier lncome and D€dudbn3
29 O$er lncome
30 Nonuflty Operating lncome
4,032,474 4,054,2',1931Revenues Frcm Merchandisiry, Jobbing and Contnct Wott (415)
32 4,104,918 3,E86,708(Less) Cosb and Exp. of Merchandising, Job. & Conbact Wort (416)
33 28,462 31,177Revenues Fmm Nonutlity Operations (4,l7)
34 (Less) Expenses of Nonutlity Opeations (417.1)6't,905 97,371
35 Nonoporatjng R€ntal lncome (418)-7,437 4,136
36 Equily in Eamings of Subsidiary Companies ({18.1)1't9 7,082,051 7,993,s26
37 lnkrest and Dividend lncorne (419)6,043,906 4,21'.t,119
22,430,62238Alburance for Otrer Funds Ussd During Constuc,lion (41 9. 1 )N.784.392
253342 3,064,48939Miscdlaneous Nonoperatng lncome (421 )
40 450,000 7,831Gain on Disposition of Prcperty (421.1)
41 TOTAL Oher lncone (Enter Tohl ol lircs 31 hru 40)34,s00,967 37,434,568
42 Oher lncome Deduc{bns
43 Loss on Dbposition of Poperty (421.2)u Miscellsneous AmortizaUon (425)
881,377 986,82045Donations (426.1)
46 -2,089,825 -2,588,290Life lnsunance (426.2)
47 Penafties (426.3)14,381 -3
48 Exp, for Certain Civic, Poltical & Relaled Activities (126.4)1!42,743 1,549,848
49 Ofi er Deduclions {426.5)8,r64,084 9,203,000
8,412,720 9,15't,37550TOTAL Otlpr lncome Deduc{ions [fohlof lines 43 firu 49)
5'l Taxes Applh. to Oher lncomo and Deduclions
52 Taxes Ofier Than lncome Taxes 262-263 28,163
53 lrrcome Taxes-Federal (409.2)%2-263 20,049 560,490
54 lncome Taxes0ther (409.2)262-263 3,721 107,192
55 Pmvhion for DebrBd lnc. Taxes (410.2)234,272-277 13,168,748 164,060
2U,272-277 1,218,722 2,307,09556(Less) Provision for Defered lncome Taxe+Cr. (1'l 1.2)
57 lnveslment Tax Cmdit Adi.-Net (411.5)
58 (Le6s) lnvestnent Tax Credits (420)
59 TOTAL Taxeg on Other lncome and Dsduclions (Tohl of lines 52-58)1 1,964,818 -1,146,890
60 N€t Other lncoflE and Deduclions (Tolal of lines 41, 50, 59)14J23,429 29,730,083
61 lntelBsl Chargos
62 lnE esl on Long-Torm Dobt (427)8'1,198,430 81,956,468
't,508,990 '1,515,15763Amot of Debt Dbc. and Expense (128)
64 2j52,952 2,033,523Amoilizalion of Loss on Reaquired Debt(428.1)
65 (Less) Amorl. of Premium on Debt{redit (429)
66 (Less) Amodization of Gain on Reaquircd D€btCrcdit (129.1)
67 lnterest on Debt h Assoc. Companies (430)81,933 27,622
7,494.,378 6,s00,4't468Oh€r lnteest Expense (431)
69 8,694,285 10,193,622(Less) Alowance br Bofiuned Fun& Used During Consruclion4r. (432)
70 Net lnterest Chaoes (Tobl of lines 62 hru 69)83,742,398 81,839,s62
71 lncome Bebre Extraordinary ltems (Tohl ol linss Z/, 60 and 70)206,U7,317 ,l89,241.920
72 Exfaordinary ltems
73 Exbaordinary lncome (434)
74 (Less) Extaordinary Deductions (435)
75 Net Extraordinary lbms (Toblof line 73 loss line 74)
76 lncome TaxolFederal and Oher (409.3)262-263
77 Exbaordinary lbms Afier Taxes (lhe 75 le$ line 76)
189,241,52078Nst lncome (Total of fine 71 and r/)206,U7,317
FERC FORM ttlo.lrlQ (REV.02.04)Pago 117
20,22:,
Name of Respondent
ldaho PowerCompany
This
(1)
(2)
ls:
Original
Date of Reoort
(Mo, Da, Yi)
A Resubmission 04118t20't8
Year/Period of Report
End of 2O17tQ4
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained eamings, unappropriated retained eamings, year to date, and unapprcpriated
undlstributed subsidiary eamings forthe year.
3. Each credit and debit during the year should be identified as to the retained eamings aocount in which recorded (Accounts 433, 436
- 439 inclusive). Shon the contra primary account afiected in column (b)
4. State the purpose and amount of each r€sorvation or apprcpriation of retained eamings.
5. List first account 439, Adjustments to Retained Eamings, reflecling adjustments to the opening balance of retained eamings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Eamings.
8. Eplain in a footnote the basis for determining the amount reserved or appropriated. lf such reservation or appropriation is to be
recurrent, state the number and annual amounts to be resorved or appropriated as well as the totals eventually to be accumulated.
9. lf any notes appearing in the report to stockholders are applicable to this statement, include them on pagas 122-123.
Line
No.
Item
(a)
Primary
Affected
(b)
Contra
Account
Cunent
Quarterf/ear
Year to Date
Balance
(c)
Previous
Quarterlfar
Y6rto Date
Balance
(d)
UNAPPROPRIATED RETAI NED EARNINGS (Account 21 6)
1,032,478,271,|Ba lanc6.B6ginning of Period 1,123,606,367
2 Changes
3 Adjustmenb b Retained Eamings (Account 439)
4 Benefit Plan Tax Reform Adjuslrnent
5
o
7
8
I TOTAL Credits to Retainod Eamings (Acct. 439)
10
11
12
13
14
't5 TOTAL Debits to Retrained Earnings (Acct. 439)
16 Balance Transfened from lncome (Account 433 less Account 418.1 )199,202,985 't81,218,394
17 Appropriations of Retained Earnings (Acct, 436)
18
19
20
2'.1
22 TOTAL Apprcpriations of Retained Eamings (Acd. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24
25
26
27
28
29 TOTAL Divldends Dedarcd-Prefened Stock (Acct 437)
30 Dividends Dedared-Common Stock (Account 438)
-113,285,012 ( 105,120,298)31
32
33
34
35
-1',t3,285,012 ( 105,120,298)36 TOTAL Dlvirlends Dedared-Common Stock (Acct. 438)
'15,000,00037Transfers ftom Acct 216.1, Unapprop. Undistib. Subsidiary Eamings
38 1,221,586,621 1,123,606,367Balance - End of Period Clotal 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Acount 215)
FERC FOR*! NO. 1r3.Q (REV.02-04)Page llE
e.462.281
Name of Respondent
ldaho Porer Company
This
(1)
(2)
ls:
Original
Date of Reoort
(Mo. Da, Yi)
Year/Poriod of Report
End ot 20171Q4
Resubmission 04t1u2018
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained eamings, unappropriated retained eamings, yearto date, and unappropriated
undistributed subsidiary eamings for the year.
3. Each credit and debit during the year should be identified as to the retalned €amings aocount in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained eamings.
5. List first account 439, Adjustments to Retained Eamings, reflecting adjustments to the opaning balance of retained eamings. Follow
by credit, then debit items in that order.
6. Shovv dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax efiect of items shown in account 439, Adjustments to Retained Eamings.
8. Explain in a footnote the basis fur determining the amount r€s€rved or appropriated. lf such reservalion or appmpriation is to be
recunent, state the number and annual amounts to be reserved or apprcpriated as well as the totals sventually to be accumulated.
9. lf any notes appearing in the report to stockholderc are applicable to this $atement, include them on gages 122-123.
Line
No.
Item
(a)
Primary
Affected
(b)
Contra
Account
Cunent
Quarterl/ear
Year to Date
Balance
(c)
Prcvlous
QuarterfYear
Year to Date
Belance
(d)
39
40
41
42
43
44
45 TOTAL Appropriated Retained Eamings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46 13,273,106 13,273,106TOTAL Approp. Retained Earnings-Amort. Resorve, Fedoral (Accl. 2'15.1)
47 13,273,106 13,273,106TOTAL Approp. Retained Eamings (Acct. 215, 215.1) (Total 45,46)
48 TOTAL Retain€d Eamings (Acct. 215, 215.1, 216) (Total 38, 471 (216.11 1,2*,859.727 1,1 36,879,173
UNAPPROPRIATED UNDISTRIBUTEO SUBSIDIARY EARNINGS (Account
Report only on an Annusl Basis, no Quarterly
74,667,833 81,674,30E49Balance.Beginning of Year (Debit or Gredit)
50 7,082,05',|7,993,526Equity in Eamings br Year (Credit) (Account 418.1)
51 12,rco,m0 15,000,000(Less) Dividends Reoeived (Debit)
52
53 Balance-End of Year (Total lines 49 thru 52)69,749,884 74,667,834
FERC FORit NO. 1/&Q (REV. 02.0.r)Page ltg
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t1812018
Year/Period of Report
2017tQ4
FOOTNOTE DATA
rans AccountTransferred Subsidiary Unappropriated REfrom a subsidiary closed in prior yearsinto IPC Unapprori-ated RE.62, 2gL
L2,062,28L
1 450.'l
1 i2,000, ooo
This
(1)
(2)
ls:
Original
Dsta of Report(ino. Da, Yr)
A Resubmission 04t18t2018
Year/Period of Report
End of 2O17lQ4ldaho Power Company
STATEMENT OF CASH FLOWS
(1 ) Codes to be used:(a) Net Proceeds or Payrrnts;(b)Bonds, debentues and olhcr long{crm debt; (c) lnclude commercial paper; and (d) ldontify separately such items as
investments, fixed assels, intangibles, etc.
Equivalents at Erd of Period'with relatgd amounts on the Balance Shest.
in those aclivities. Show in the Notos to lhe Finencials lhe amounts of intersst paid (net of amount capitalized) and income taxcs paid.
dollar amounl of loasas cadtalized with the plant cost.
Prsvious Year to Date
QuarterfYear
(c)
Line
No.
Desoiption (See lnsbuction No. 't for Explanation of Codos)
(a)
Current Year to Date
Quad€rfYear
(b)
1 Net Cash Flow from Operating Activities:
2 Net lncome (Line 78(c) on page 117)206347,317 189,241,920
3 Noncash Charges (Credits) to lncome:
4 Depreciation and Depletion 153,958,586 135,048.584
11.378 099 11 ,6,f4,9705Amortization of
6
7
I Defened lncome Taxes (Net)14,370,999 29,875,896
I lnvestnent Tax Credit Adjustment (Net)-20,660,275 't:r5,726
10 Net (lncrease) Decrease in Receivables -2,496,038 3,368,760
11 Net (lncrease) Decrease in lnventory -809,418 7,244,713
't2 Net (lncrease) Decrease in Allowances lnventory
't3 Net lncrease (Deoease) in Payables and Accrued Expenses -3,831,716
14 39,149,025 -18,7,t4.516Net (lncrease) Oecrease in Olher Regulatory Assets
15 Net lncrease (Decrease) in Other Regulatory Liabilities 17,982,095 13,093,929
20,784,392 22,030,62216(Less) Allourance br Other Funds Used During Construc{on
17 (Less) Undistibuted Earnings ftom Subsidiary Companies -4,917,949 -7,006,474
-42,248,O5318Other (provide details in tootrtote):
19
20
21
309,866,06522Net Cash Provided by (Used in) Operating Aciivities (Total 2lhru 21\416,503,799
23
24 Cagh Flows fom lnvestment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuol)-318,978,793.306,254,955
27 Gross Additions to Nuclear Fuel
28 Gross Addlflons to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construclion -20,784,392 -22,030,622
31 Other (provide details in botnote):6.307,326 8,558,677
32
33
34 -277,O73,237 -288,389,494Cash Outflows br Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds fiom Disposal of Noncunent Assets (d)
38
83,03839lnvestnenb in and Advances to Assoc. and Subsidiary Companies 3,362
3,838,869 1,400,63740Contrlbutions and Advances from Assoc. and Subsidiary Companies
41 Disposition of lnveshlonts in (and Advances to)
42 Associated and Subsidiary Companies
43
44 -1 1,356,339 -24,916,896Purchase of lnvestrnent Securities (a)
15,693,37045Proceeds from Sales of lnvestment Securities (a)4,98S,363
FERC FORI NO. t (ED. 12-96)Page 120
-22.985.607
Name of Respondent
ldaho Power Company
This(1)
{2)
ls:
Original
Dat6 of Report(l!lo, Oa, Yr)Year/Pedod of Report
End of 2O17lQ4
Resubmission 04118t2018
STATEMENT OF CASH FLOWS
(1 ) Codes to bo used:(a) Net Proce€ds or Payments(b)Bonds, d€bentures and other long-term d€bt (c) lnclude commeicial paper; and (d) ldontiry soparately such items as
investrnents, fixed assets, intangibles. etc.
Equivalents at End of Pcriod" with related amounls on the Balance Sheet.
in those activities. Show in th. Not€s to tho Financials the amounts of intorast pad (net of amount caFitalized) and income texes psid.
dolbr amount of leas€s capilalized wilh the plant cost.
Line
No.
Description (See lnstuc{ion No. 1 for Explanation of Codes)
(a)
Cunent Year to Dat€
Quarter^f6ar
(b)
Previou8 Yesr b Date
QuarterlYear
(c)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (lncrease) Decreaso in Receivables
50 Net (lncrease ) Decrease in lnventory
51 Net (lncrease) Decrease in Allowances Held fur Speculation
52 Net lncrease (Decrease) in Payables and Aoued Expenses
53 Other (provide details in foohote):-55,676
54
55
56 Net Cash Provided by (Used in) lnvesting Activities
57 Total of lines 34 thru 55)-279,609,941 -296,185,021
58
59 Cash Flows from Financing Activities:
60 Proceeds from lssuance of:
61 Long-Term Debt (b)120,000.000
62 Preferred Stocl
63 Common Stock
64 Other (provide detaals in bohote):
65
66 Net lncrease in Short-Term Debt (c)
67 Oher (provide detrils in fuotnote):
68
69
70 120,000,000Cash Provided by Orlside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
73 Long-term Debt (b)-1,063,634 -101,063,636
74 Prefened Sbck
75 Common Stock
76 Other (provide details in bohote):-15.912,658{40,000
77
78 Net Decrease in Short-Term Debt (c)-21,800,000 21,800,000
79
80 Dividends on PreEred Stock
81 -113,285,012 -105,120,298Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
-136,388,646 -80,296,59283(Total of lines 70 thru 81)
84
85 Net lncrease (Decrease) in Cash and Cash Eguivalents
86 (Total of lines 22,57 and 83)505,212 -66,615,548
87
88 Cash and Cash Equivalents at Beginning of Period 44,140,435 110,755,983
89
90 Cash and Cash Equivalents at End of period 44,645,647 44,140,435
FERC FORm NO. r (ED.12-96)Page 121
"11,959
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
041't812018
Year/Period of Report
20171Q4
FOOTNOTE DATA
Schedule Page: 120 Line No.: 5
Amortization
Plant
Unamortized debt expense
Unamortized discount
Water rights
Other
6,276,261
3,686,183
292,594
1,042,009
81,052
11,378,099
Schedute Page:120 Line No-: 13 Column: b
Gash (received) paid during the period for:
lncome tiaxes
lnterest (net of amount capitalized)
11,968,212
79,918,043
Schedule Page:120 Line No.: 18 Column:
Gash Flow from Operating Activitles (Other)
Pension and postretirement benefit plan expense
Contributions to pension and postretirement benefit plans
Unbilled revenues
Accrued payroll
Company owned life insurance
Other
28,894,314
(46,572,6781
4,323,08
4,264,872
(1,769,7841
(12,125,3791
(22,985,607)
Page:120 Line No.:26 Column: b
Non-cash investing activities:
Additions to PP&E in accounts payable
Schedule Page: 120 Line No.: 3l Column: b
33,220,447
Other Cash Flows from Plant
Payments received fom joint funding partners
Sale of emission allowances and renewable energy certificates
Other
6,073,010
2,059,761
264,555
8,397,326
Schedule Page: 120 Line No.: 53 Column: b
Other lnvesting Gash Flows
Feasibility study costs
Miscellaneous other investing activities
(112,9771
101,018
(11,959)
Scftedule Page:120 Line No.:76 Column: b
Other Financing Cash Flows
Debt issuance costs (240,000)
FERC FORM NO.1 450.1
(240,000)
Column: b
of Respondent This Rsoort ls:(1) S]ln Orisinat
Date of Reoort(Mo, Da, Yi)
0411812018
Year/Period of Report
End of 2O17lQ4ldaho Power Company (2)Resubmission
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1. Repo( in mlumns (b),(c),(d) and (e) the amounts of acanmulated other oomprehensive income iterns, on a net-of-tax basis, where appropriate,
2. Report in columns (0 and (g) the amounts of oth€r categori€s of other cash fiow hedges.
3. For each category of hedges fiat have been accounted for as "falr value hedges", report tre accounts affec'ted and the related amounE in a foohote.
4. Roport dab on a year-Mate basis.
Line
No.
Unreal2ed Gains and
Losses on Available-
br-Sale Securities
(b)
Minimum Pension
Uability adjustnent
(net amount)
(c)(d)
Foreign Curency
Hedges
(e)
Other
Adjustments
Item
(a)
1 Balance of Account 21 I at Beginning of
Preceding Year ( 21,275,73s)
2 Preceding Qlr/Yr to Date RedasslflcaUons
from Acct 219 to Net lncome 2,253,O40
3 Preceding Quarter/Year to Date Changes in
Fair Value ( 1,858,92s)
4 Total (lines 2 and 3)394,115
5 Balance of Account 21 9 at End of
Preceding CUarterA'ear ( 20,881,620)
6 Balance of Account 21 9 at Beginning of
Cunent Year ( 20.881,620)
7 Cunent Qtrf(r b Date Reclassifications
from Acct 219 to N6t lncome 1,882,086
I Cunent Ouarter/Year to Date Changes in
Fair Value ( 7,872,675)
I Total (lines 7 and 8)( 5,990,s89)
10 Balance of Account 21 I at End of Current
Quarterl/ear ( 26,8t2.209)
FERC FORM NO.1 (NEW0C-02)Page 122a
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:
Original
Oate of Reoort(Mo, Da, Yi)
A Resubmission 04t1812018
Year/Period of Report
End of 2O17lQ4
STATEMENTS OF ACCUMUI-ATED @MPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Line
No.
Other Cash Flow
Hedges
lnterest Rate Swaps
(0
Other Cash Flow
Hedges
Insert Foohote at Line 1
b specifyl
(s)
Totals for eactt
category of items
recorded in
Account 2'19
(h)(i)
Net lncome (Cani€d
Fonvard from
Page 117, Line 78)
(i)
Total
Comprehensive
lncoms
1 ( 21,27s,735)
2 2,253,O40
3 ( 1,858,925)
4 394,115 189,241,922 189,636,037
5 ( 20,881,620)
6 ( 20,881,620)
7 1,882.086
I ( 7,872,675)
I ( 5,ee0,s89)206347,317 200,356,728
't0 ( 26.872,249)
FERC FORlul NO. { (NEW06-02}Page 122b
Name of Respondent
ldaho Porer Company
This Report ls:
ED
An Original
A Resubmission
(1)
(2)
Date of Report
04t10P:018
YearPenoo ot t{opon
End of 2O17lQ4
NOTES TO FINANCIAL STATEMENTS
I t. Use the space below for important notes r€gsrding the Bslanoe Sh€et, Statement of lncome for the ye8r, S'tatement of Retained
lEarnings for the year, 8nd Statement of Cash Flows, or any account theroof. Clessify the notes according to each basic atatement,
lproviding a subheading for each statement excapt wh€re a note is applicable to more than one staEment.
2. Fumieh particulars (details) as to any significant contingent aesets or liabilities existing at end of year, including a brief explanation of
any action initiated by the lntemal Revenue Service involving possiUe essessm€nt of additional income ta:<es of material amount, or of
a daim for efund of income taxelr of a material amount initiated by the utility. Give abo a brief explanation of any divi.rends in arrears
on cumulative prelerred stock.
3. For Account 116, Utility Plant Adjustnents, explain the origin of such amount, debits and crcdits durirq the year, and plan of
disposition contemplated, giving references to Cormmission ordere or other authorizalions respecting classificalion of amounts as plant
adiustments and requirements as to disposition thercof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treetment given these items. See General lnstruc{ion 17 of the Uniform System of Accounts.
5. Give a concise explanation of any ptained oamings restrictions arid state the amount of retained earnings affected by such
restrictions.
6. lf the notes to financial statements ,elating to the respondent company appearing in tlre annual report to the stockholders are
applicable and furnbh the data required by instruclions above and on pages 11+121, such notes may be included herein.
7. For the 3Q dbclosures, respondent must provid€ in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contain€d in the most recent FERG Annual Report may be
omitt€d.
8. For the 3Q diEclcsurea, the disclosures shall be provided where eventB subs€quent to the end of the most recent yesr have
occurred which have a material offecl on the respondent. Respondent must includ€ in the notes significant changes since the mo8t
recently cornpleted year in such items as: accounting principl€s and practices; €strmates inherent in the preparation of the financial
statements; status of longrterm contracts; capitalization including significant new borrowinge or modifications of eisting financing
agreoments; and changes resulting froin bwinoss combinEtions or dispositions. However were material contingencies exist, the
disclosure of such matters shall be proviled even though a sBnificant charBe since year erd may not have occuned.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders ars
applicable and furnish the data requircd by the above instuctions, sucfi notes may be included herein.
PAGE,I22 INTENTIONALLY LEFT BIANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORil NO. r (ED. t2-96)Page 122
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
0/.I1812018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
IDAHO POWERCOMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
I. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Idaho Power Company (Idaho Power) is the principal operating subsidiary of IDACORP, Inc. (IDACORP), a holding company
formed in 1998. Idaho Power is an electric utility engaged in the generation, transmission, distribution, sales, and purchase ofelectric
energy and capacity with a service area covering approximately 24,000 square miles in southern Idaho and eastem Oregon. Idaho
Power is regulated primarily by the state utility regulatory commissions of Idaho and Oregon and the Federal Enerry Regulatory
Commission (FERC). Idaho Power is the parent of Idaho Enerry Resources Co. (IERCo), ajoint venturer in Bridger Coal Company
(BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.
Basis of Reporting
The financial statements include the assets, liabilities, revenues and expenses ofldaho Power and have been prepared in accordance
with the accounting requirements of the FERC as set forth in the applicable Uniform System of Accounts and published accounting
releases, which is a comprehensive basis ofaccounting other than accounting principles generally accepted in the United States of
America (U.S. GAAP). As required by the FERC, Idaho Power accounts for its investments in its majority-owned subsidiary on the
equity method rather than consolidating the assets, liabilities, revenues and expenses of the subsidiary as required by U.S GAAP. The
accompanying financial statements include Idaho Power's proportionate share ofthe utility plant and related operations resulting from
its interest in jointly-owned plants. In addition, under the requirements of the FERC, there are differences from U.S. GAAP in the
presentation of ( I ) current portion of long-term debt, (2) assets and liabilities for cost of removal of assets, (3) regulatory assets and
liabilities (4) deferred income taxes, (5) income tax expense, (6) non-utility revenues, (7) accrued taxes, and (8) debt issue costs.
Management Estimates
Management makes estimates and assumptions when preparing financial statements in conformity with generally accepted accounting
principles. These estimates and assumptions include those related to rate regulation, retirement benefits, contingencies, asset
impairment, income taxes, unbilled revenues, and bad debt. These estimates and assumptions affect the reported amounts of assets
and liabilities and the disclosure ofcontingent assets and liabilities at the date ofthe financial statements and the reported amounts of
revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, future
economic factors that are difficult to predict and are beyond management's control. Accordingly, actual results could differ from those
estimates.
Regulation of Utility Operations
As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of govemmental
agencies, including the prices that Idaho Power is authorized to charge for its electric service. These approvals are a critical
factor in determining Idaho Powels results of operations and financial condition.
Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating
Idaho Power. The application of accounting principles related to regulated operations sometimes results in ldaho Power recording
expenses and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. In these
instances, the amounts are deferred or accrued as regulatory assets or regulatory liabilities on the balance sheet and recorded on the
FERC FORM NO. 1 (ED. 12481 Page 123.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
ut't8t2018
YeariPeriod of Report
2017t44
NOTES TO FINANCIAL STATEMENTS (Continued)
income statement when recovered or returned in rates. Additionally, regulators can impose regulatory liabilities upon a regulated
company for amounts previously collected from customers that are expected to be refunded. The effects of applying these regulatory
accounting principles to Idaho Power's operations are discussed in more detail in Note 3 - "Regulatory Matters."
System ofAccounts
The accounting records ofldaho Power conform to the Uniform System ofAccounts prescribed by the FERC and adopted by the
public utility commissions of Idaho, Oregon, and Wyoming.
Cash and Cash Equivalents
Cash and cash equivalents include cash on-hand and highly liquid temporary investments that mature within 90 days of the date of
acquisition.
Receivables and Allowance for Uncollectible Accounts
Customer receivables are recorded at the invoiced amounts and do not bear interest. A late payment fee of one percent may be
assessed on account balances after 30 days. An allowance is recorded for potential uncollectible accounts. The allowance is reviewed
periodically and adjusted based upon a combination ofhistorical write-offexperience, aging ofaccounts receivable, and an analysis of
specific customer accounts. Adjustments are charged to income. Customer accounts receivable balances that remain outstanding after
reasonable collection efforts are written off.
Other receivables are also reviewed for impairment periodically, based upon transaction-specific facts. When it is probable that Idaho
Power will be unable to collect all amounts due according to the contractual terms of the agreement, an allowance is established for
the estimated uncollectible portion of the receivable and charged to income.
There were no impaired receivables without related allowances at December 31, 2017 and 2016. Once a receivable is determined to be
impaired, any further interest income recognized is fully reserved.
Derivative Financial Instruments
Financial instruments such as commodity futures, forwards, options, and swaps are used to manage exposure to commodity price risk
in the electricity and natural gas markets. All derivative instruments are recognized as either assets or liabilities at fair value on the
balance sheet unless they are designated as normal purchases and normal sales. With the exception of forward contracts for the
purchase ofnatural gas for use at Idaho Power's natural gas generation facilities and a nominal number ofpower transactions, Idaho
Power's physical forward contracts are designated as normal purchases and normal sales. Because ofldaho Power's regulatory
accounting mechanisms, Idaho Power records the changes in fair value of derivative instruments related to power supply as regulatory
assets or liabilities.
FERC FORM NO. 1 I 123.2
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t't812018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Revenues
Operating revenues related to Idaho Power's sale ofenergy are recorded when service is rendered or energy is delivered to customers.
Idaho Power accrues estimated unbilled revenues for electric services delivered to customers but not yet billed at year-end. Idaho
Power does not report any collections of franchise fees and similar taxes related to energy consumption on the income statement. In
addition, regulatory mechanisms in place in Idaho and Oregon affect the reported amount of revenue. See Note 3 - "Regulatory
Matters" for additional discussion of certain of the following mechanisms:
energy efficiency riders to fund enerry efficiency program expenditures. Expenditures funded through the riders are reported
as an operating expense with an equal amount ofrevenues recorded in other revenues;
a fixed cost adjustment mechanism that results in recording additional or reduced revenue based on the allowed and actual
fixed costs recovered through current rates;
a sharing mechanism providing for refunds to customers for eamings above stated retums on equity in Idaho; and
collection in base rates of a portion of the allowance for funds used during construction (AFUDC) related to its Hells Canyon
Complex (HCC) relicensing project. Cash collected under this ratemaking mechanism is not recorded as revenue but is
instead deferred as a regulatory liability.
Property, Plant and Equipment and Depreciation
The cost of utility plant in service represents the original cost of contracted services, direct labor and material, AFUDC, and indirect
charges for engineering, supervision, and similar overhead items. Repair and maintenance costs associated with planned major
maintenance are expensed as the costs are incurred, as are maintenance and repairs ofproperty and replacements and renewals of
items determined to be less than units of property. For utility property replaced or renewed, the original cost plus removal cost less
salvage is charged to accumulated provision for depreciation, while the cost ofrelated replacements and renewals is added to property,
plant and equipment.
All utility plant in service is depreciated using the straight-line method at rates approved by regulatory authorities. Annual
depreciation provisions as a percent of average depreciable utility plant in service approximated 2.9 percent in 2017 and 2.6 percent in
2016.
During the period ofconstruction, costs expected to be included in the final value ofthe constructed asset, and depreciated once the
asset is complete and placed in service, are classified as construction work in progress on the consolidated balance sheets. Ifthe
project becomes probable of being abandoned, such costs are expensed in the period such determination is made. Idaho Power may
seek recovery of such costs in customer rates, although there can be no guarantee such recovery would be granted.
Long-lived assets are periodically reviewed for impairment when events or changes in circumstances indicate that the carrying amount
ofan asset may not be recoverable. Ifthe sum ofthe undiscounted expected future cash flows from an asset is less than the carrying
value of the asset, impairment is recognized in the financial statements. There were no material impairments of long-lived assets in
2017 or 2016.
Allowance for Funds Used During Construction
AFUDC represents the cost of financing construction projects with borrowed funds and equity funds. With one exception, as
FERC FORM NO.1 (ED.12{8)Page 123.3
a
a
a
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
04t1812018
Year/Period of Report
20,t7tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
discussed above for the HCC relicensing project, cash is not realized currently from such allowance; it is realized under the
ratemaking process over the service life ofthe related property through increased revenues resulting from a higher rate base and
higher depreciation expense. The component of AFUDC attributable to borrowed funds is included as a reduction to total interest
expense. Idaho Power's weighted-average monthly AFUDC rate was 7.6 percent for 2017 and 2016.
Income Taxes
Idaho Power account for income taxes under the asset and liability method, which requires the recognition ofdeferred tax assets and
liabilities for the expected future tax consequences ofevents that have been included in the financial statements. Under this method
(commonly referred to as normalized accounting), deferred tax assets and liabilities are determined based on the differences between
the financial statements and tax basis ofassets and liabilities using enacted tax rates in effect for the year in which the differences are
expected to reverse. In general, deferred income tax expense or benefit for a reporting period is recognized as the change in deferred
tax assets and liabilities ftom the beginning to the end ofthe period. The effect ofa change in tax rates on deferred tax assets and
liabilities is recognized in income in the period that includes the enactment date unless Idaho Power's primary regulator, the Idaho
Public Utilities Commission (IPUC), orders direct deferral of the eflect of the change in tax rates over a longer period of time.
Consistent with orders and directives of the IPUC, unless contrary to applicable income tax guidance, Idaho Power does not provide
deferred income taxes for certain income tax temporary differences and instead recogrizes the tax impact currently (commonly
referred to as flow-through accounting) for rate making and financial reporting. Therefore, Idaho Power's effective income tax rate is
impacted as these differences arise and reverse. Regulated enterprises are required to recognize such adjustments as regulatory assets
or liabilities if it is probable that such amounts will be recovered from or returned to customers in future rates.
In compliance with the federal income tax requirements for the use of accelerated ta,x depreciation, Idaho Power provides deferred
income taxes related to its plant assets forthe difference between income tax depreciation and book depreciation used for financial
statement purposes. Deferred income taxes are provided for other temporary differences unless accounted for using flow-through.
The state of Idaho allows a three percent investment tax credit on qualifuing plant additions. Investment tax credits earned on
regulated assets are defened and amortized to income over the estimated service lives of the related properties. Credits eamed on
non-regulated assets or investments are recognized in the year eamed.
Income taxes are discussed in more detail in Note 2 - "Income Taxes."
Other Accounting Policies
Debt discount, expense, and premium are deferred and amortized over the terms ofthe respective debt issues. Losses on reacquired
debt and associated costs are amortized over the life ofthe associated replacement debt, as allowed under regulatory accounting.
Supplemental Cash Flows Information
In 2015, Idaho Power executed an agreement to exchange property with another electric utility. Under the terms of the agreement,
each party transferred to the other transmission-related equipment with a book value of approximately $44 million. Idaho Power
received an immaterial amount ofcash, representing the difference in the book value ofthe assets exchanged. Also in 2015, Idaho
Power executed a long-term service agreement and transferred to the service provider approximately $22 million of spare parts in
FERC FORM NO. 1 (ED.12€8)Page 123.4
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
ut't8t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
partial exchange for future services. No cash was exchanged in the 2015 transfer transaction.
Reclassifications
In these consolidated financial statements, certain amounts in prior periods' consolidated financial statements have been reclassified
to conform with current period presentation. On Idaho Power's 2016 consolidated balance sheet, the $9.5 million of American Falls
and Milner water rights which had previously been reported separately was reclassified to "Other" within Deferred Debits. Also, on
Idaho Power's 2016 consolidated balance sheet, $19.7 million was reclassified from "Other" in other assets to the newly created
"Long-term receivables" within Deferred Debits.
New and Recently Adopted Accounting Pronouncements
Recently Adopted Accounting Pronouncements
In February 2018, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2018-02, Income
Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other
Comprehensive Income, which permits a reclassification from Accumulated Other Comprehensive Income (AOCI) to retained
eamings for the stranded tax effects resulting from the decrease in corporate tax rate from the enactment in December 2017 of a tax
reform act, generally referred to as the "Tax Cuts and Jobs Act." For more information on other impacts of the Tax Cuts and Jobs Act,
see Note 2 - "lncome Taxes."
Recent Accounting Pronouncements Not Yet Adopted
In May 2014,the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 is intended to
enable users offinancial statements to better understand and consistently analyze an entity's revenue across industries, transactions,
and geographies. Under the ASU, recognition ofrevenue occurs when a customer obtains control ofpromised goods or services. In
addition, the ASU requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts
with customers. The FASB amended certain aspects of ASU 2014-09 to clariff the implementation guidance, including clarifications
related to principal versus agent considerations, licensing and identiffing performance obligations, narrow scope improvements, and
practical expedients. Idaho Power has assessed the impacts ofASU 2014-09 on its financial statements and have concluded the new
guidance will not affect the timing and amount of revenue recognized. However, the presentation and disclosure requirements of the
standard will result in a change in the presentation of revenue on Idaho Power's consolidated statements of income as well as
expanded disclosures around the disaggregation of revenue, performance obligations, and transaction price. The guidance in ASU
2014-09 is effective for interim and annual reporting periods beginning after December 15, 2017 . The guidance permits two
implementation approaches, one requiring retrospective application of the new standard with restatement of prior years (full
retrospective approach) and the other requiring prospective application ofthe new standard including a cumulative-effect adjustment
with disclosure of results under previous standards (modified-retrospective approach). Idaho Power will adopt ASU 2014-09 on
January l, 2018, using the modified-retrospective approach. As the standard does not change the timing and amount ofrevenue
recognized for Idaho Power, no cumulative-effect adjustment is required.
FERC FORM NO.1 (ED. 12-881 Page 123.5
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
ut18t2018
Year/Period of Report
20't7tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
In January 2016,the FASB issued ASU 2016-01, Financial lnstruments-Overall (Subtopic 825-10): Recognition and Measurement
of Financial Assets and Financial Liabilities, which revises the accounting related to the classification and measurement of
investments in equity securities and the presentation ofcertain fair value changes for financial liabilities measured at fair value. It also
amends certain disclosure requirements associated with the fair value of financial instruments. The new standard is effective for fiscal
years beginning after December 15,2017, including interim periods. Idaho Power concluded the adoption will not have a material
impact on its financial statements.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), intended to improve financial reporting about leasing
transactions. The ASU significantly changes the accounting model used by lessees to account for leases, requiring that all material
leases be presented on the balance sheet. Under the current model, some leases are classified as capital leases and recorded on the
balance sheet while other leases classified as operating leases are not recognized on the balance sheet. The new standard is effective
for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. The standard must be
adopted using a modified-retrospective approach. Idaho Power is evaluating the impact of ASU 2016-02 on its financial statements.
Specifically, Idaho Power is considering whether the new guidance will affect its accounting for purchase power agreements,
easements and rights-of-way, utility pole attachments, and other utility industry-related arrangements. At this time, Idaho Power does
not know, and cannot reasonably estimate, the dollar impact ofthe adoption.
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230l, which amends ASC 230 to clarif guidance
on the classification of certain cash receipts and payments in the statement of cash flows. The FASB issued the ASU with the intent of
reducing diversity in practice with respect to eight types of cash flows. Idaho Power expects the ASU to affect the classification of
proceeds from the settlement ofcorporate-owned life insurance policies and related costs, which will be classified as investing
activities under the new guidance. Idaho Power already presents debt prepayment and extinguishment costs, proceeds from the
settlement of insurance claims (other than corporate-owned life insurance), and distributions received from equity-method investments
in accordance with the new guidance. ASU 2016-15 is e{fective for interim and annual reporting periods beginning after December
15, 2017 . The standard must be adopted retrospectively to all periods presented, unless impracticable to do so. Idaho Power does not
believe the adoption will have a material impact on its financial statements.
In March 2017, the FASB issued ASU 2017-07, Compensation -- Retirement Benefits (Topic 715): Imprwing the Presentation of Net
Periodic Pension Cost and Net Periodic Postretirement BeneJit Cosl, which requires employers to disaggregate the service cost
component from other components of net periodic benefit costs and to disclose the amounts of net periodic benefit costs that are
included in each income statement line item. The standard requires employers to present the service cost component in the same line
item as other compensation costs and to present the other components ofnet periodic benefit costs (which include interest costs,
expected return on plan assets, amortization ofprior service cost or credits and actuarial gains and losses) separately and outside a
subtotal of operating income. In addition, only the service cost component is eligible for capitalization. Idaho Power currently
capitalizes amounts of pension or postretirement costs that are insignificant to the consolidated financial statements. The amendments
in ASU 2017-07 are effective for interim and annual reporting periods beginning after December 15,2017. Entities must use (l) a
retrospective transition method to adopt the requirement for separate presentation in the income statement of service costs and other
components and (2) a prospective transition method to adopt the requirement to limit the capitalization of benefit costs to the service
cost component. While ASU 2017-07 will result in changes to the classification ofthe other components of net periodic benefit costs
on the consolidated statements of income of Idaho Powel the new standard will not materially affect Idaho Power's consolidated
financial statements.
FERC FORM NO. I (ED. 12{8)Page 123.6
Subsequent Events
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04118t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Management has evaluated the impact of events occurring after December 31, 2017 , up to February 22, 2018, the date that Idaho
Power Company's U.S. GAAP financial statements were issued and has updated such evaluation for disclosure purposes through
April 16,2018. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.
2. INCOME TAXES
A reconciliation between the statutory federal income tax rate and the effective tax rate is as follows (dollars in thousands):
2017 !016
Federal ircome ttr €xpease at 35ro,t statutory rate
ChaEe irl tanes resuhiag &oa:
Equity eammgs of subsidirl' compaaies
AFTJDC
Cepiulized iater$t
Isresbed tax crediE
Boad redernption costs
Remol-al costs
Capitalized overhead costs
Capitelized repair corts
StaE income ta-r(es, oet of federal besefit
Depreciatioa
Stare-based coapeosatioa
Reneasuremeat of deferred taxes
Other, aet
$ 89,370 $ 78,?,ll
Total iacsme t&T ex9€ose
G,47e)
(1031e)
1,5 13
(3,Y
(6,280)
{11,200)
(28,700)
8,108
r8,9J3
(r,483)
2,623
(8,031)
$_1!S_
t9.2%
(2,7e8)
(11,378)
3,000
(2,92?)
(4,9e7)
(J,559)
(r0,500)
(2S,000)
4,880
1s,673
(1,5?
(1,855)
L_IIS-
1J_39'6Eftctrrc tflr rate
The items comprising income tax expense are as follows (dollars in thousands):
FERC FORM NO.1 (ED.12{8)Page 123.7
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
c/.t18t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Income trre! cnrrently payeble:
Federal
State
$ 44,12: $ 464
_ 10,562 1,76j
_ 55.284 .r.t3l
(8,416) 31,79S
_ (5.19S) (2.03r)
_ 0l.ll4) 29-.1ffi
Total
Incomc terer deferred:
Federal
Stat
Total
Uncertain tar poritions
Federal
State
Total
Invechent tar crreditr :
Deferred
Restored
10,506 3,22'i
_ (3,081) (2"e?t)
7,{25 305Yotal
Total igcoore tax exp€ose $ 48,99-{ $ 34,102
The components of the net deferred tax liability are as follows (dollars in thousands):
2017
Deferred tax assets:
Regulatory liabilities
Deferred compensation
Deferred revenue
Tax credits
Retirement benefits
Other
$98,744 $
21,025
3l ,086
43,995
94,493
8,435
51,326
29,424
40,354
33,488
r32,362
I I,069
Total 297,778 298,023
Deferred tax liabilities:
Property, plant and equipment
Regulatory assets
Power cost adjustments
Fixed cost adjustment
Retirement benefits
Other
306,002
584,329
8,016
103,407
21,097
500,987
948,540
21,077
17,376
140,083
15,922
Total l,o22,g5l 1,643,985
Net deferred tax liabilities 5 725,073 S t,345,962
FERC FORM NO. 1 (ED. 12{8)Page'123.8
!017 2016
2016
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
ut1812018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
IDACORP's tax allocation agreement provides that each member of its consolidated group compute its income taxes on a separate
company basis. Amounts payable or refundable are settled through IDACORP and are reported as taxes accrued or income taxes
receivable, respectively, on the consolidated balance sheets ofIdaho Power. SeeNote I - "Summary ofSignificant Accounting
Policies" for further discussion ofaccounting policies related to income taxes.
Uncertain Tax Positions
Idaho Power believes that it has no material income tax uncertainties for 2017 and prior tax years. The Company recognizes interest
accrued related to unrecogrized tax benefits as interest expense and penalties as other expense.
Idaho Power is subject to examination by its major tax jurisdictions - U.S. federal and the State of ldaho. The open tax years for
examination are 2017 for federal and 2013-2017 for ldaho. In May 2009, IDACORP formally entered the U.S. Intemal Revenue
Service (IRS) Compliance Assurance Process (CAP) program for its 2009 tax year and has remained in the CAP program for all
subsequent years. The CAP program provides for IRS examination and issue resolution throughout the current year with the objective
of retum filings containing no contested items. ln20l7, the IRS completed its examination of IDACORP's 2016 tax year with no
unresolved income tax issues.
Tax Cuts and Jobs Act
On December 22,2017 , the Tax Cuts and Jobs Act was signed into law, which significantly reforms the Intemal Revenue Code of
1986, as amended. Effective January l, 201 8, the Ta,x Cuts and Jobs Act permanently lowers the corporate tax rate to 2l percent fiom
the existing maximum rate of 35 percent, provides for expanded bonus depreciation, limits the deductibility of interest expense,
eliminates altemative minimum tax, repeals the manufacturing deduction, and imposes additional limitations on the deductibility of
executive compensation. Public utility companies, such as Idaho Power, retain the full deductibility of interest expense and are
excluded from the bonus depreciation provisions; howeveq traditional accelerated tax depreciation methods are still available.
Due to the enactment of the Tax Cuts and Jobs Act and following generally accepted accounting principles, at December 31,2017,
Idaho Power remeasured all deferred income tax assets and liabilities. The effects ofthese adjustments resulted in a net tax expense as
shown in the rate reconciliation table above. Additionally, as shown in the defened income tax table above, the net deferred tax
liabilities at Idaho Power decreased significantly. Idaho Power's regulatory asset deferred income tax liability item decreased as the
related regulatory asset was reduced in two primary ways: I ) the decrease in the federal income tax rate decreased the future cost to
customers for funding the net deferred income tax liabilities resulting from the cumulative impacts of using the flow-through income
tax accounting method for regulatory purposes and 2) the decrease in the federal income tax rate also reduced the net-to-gross
multiplier that increases the regulatory asset to a revenue requirement carrying value. The change in income tax law also reduced the
deferred income tax liability for depreciation-related timing differences under the normalized tax accounting method. As this
reduction will flow back to customers in the future under the statutorily prescribed average rate assumption method, it was recorded as
a regulatory liability on the consolidated balance sheets of the Idaho Power. See Note 3 - "Regulatory Matters" for more information.
The2017 consolidated financial statements reflect the implementation offederal income tax reform as enacted and current regulatory
policies. Additional adjustments may be required in future periods based upon technical corrections to the federal law, changes to
state income tax policies, additional technical guidance from tax authorities, or orders from Idaho Power's regulators.
FERC FORM NO.1 (ED.12{8)Page 123.9
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
ut18t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
3. REGULATORY MATTERS
Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating
Idaho Power. Included below is a summary of Idaho PoweCs regulatory assets and liabilities, as well as a discussion of notable
regulatory matters.
Regulatory Assets and Liabilities
The application of accounting principles related to regulated operations sometimes results in Idaho Power recording some expenses
and revenues in a different period than when an unregulated enterprise would record such expenses and revenues. Regulatory assets
represent incurred costs that have been deferred because it is probable they will be recovered from customers through future rates.
Regulatory liabilities represent obligations to make refunds to customers for previous collections, or represent amounts collected in
advance of incurring an expense.
FERC FORM NO. 1 (ED. 12-88)Page 123.10
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
ut1gnu8
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table presents a summary of Idaho Power's regulatory assets and liabilities (in thousands of dollars):
A: of Decembcr 31,2017
Dercriprioa
Reueiaing
Amortizrtion
Pcriod
Earning a
Ss1a6(r)
Not
Eanring a
Return
Total es of December 31,
:017 2016
Regulatorv AsreG:
Iacome taxes fr
Uofutrded pestretireinmt beaefits{3)
Pe--.ioa expease deferrals
Energy efficieacy program co*d4
Por*er supply costsiS
Fixed coct adjustmeadl
Vatuy Plaut settlemert rtipulationii
Asset retiteneot obligations{ 0
Lorg-term service aEreetneot
Other
$$ 584,329 $
380,166
23,033
J84,3t9
280,166
lt?,72 I
6,t73
3,137
30,856
44,633
15"761
27,90?
il,30?
$ 948,540
263.7'19
105,352
5.552
53,8,r0
44,,145
104,688
6,273
5-t) )
ro,s:o
43.351
t6-178
5.687
2018-?019
?018-20 l9
t0t8-2028
2018-2043
l0t8-20i5
1.28?
1i,16l
ll,129
i.610
t4. I 54
29,0Sr
?.136
Total $ 210,770 $ 921,326 $ r,132,096 $ 1,4?1,899
Rrgllatory Liabititicr;
Ircome taxesQ
Dqrreciatioc-related excess &ferred iac.ome
1xygs{B)
Eaergl' effcieacy prograo costd{
Pox'er supply costs(l
Ivfark-to-muket assets 0B
otier
2018-20 l9
193.991
408
5.443
5.805
408
J,443
22
8,796
51,3?6
10.730
7,83 I
1,114
5 $ 98,714 $ 98,744 $
t93,991
21,
1,991
Total $ 205,6,+i$ 101,757 $ 30?,404 $ 77,001
(l) Eaming a return includes either interest or a retum on the investment as a component ofrate base al the allowed rate ofreturn.
(2) Represents flow{hrough income tax accounting differences which have a conesponding defened tax liability disclosed in Note 2 - "lncome Taxes." The Tax Cuts and
Jobs Act, enacted on December 22, 2017, reduced the deferred income tax assets and liabilities. For timing differences under the flow-through income tax accounting
method, this reduction also reduces the associated regulatory assets generally recoverable over the remaining lives ofthe associated depreciable property
(3) Represents the unfunded obligation ofldaho Power's pension and postretirement benefit plans, which are discussed in Note I I - 'tsenefit Plans."
(4) The energy efficiency asset represents the Oregon jurisdiction balance and the liability represents the Idahojurisdiction balance.
(5) This item is discussed in more detail in this Note 3 - "Regulatory Matters."
(6) Asset retirement obligations are discussed in Note l3 - "Asset Retirement Obligations."
(7) Represents the tax gross-up related to the depreciation-related excess deferred income taxes and investment ta\ credits included in this table and has a conesponding
deferred tax asset disclosed in Note 2 - "lncome Taxes."
FERC FORM NO. 1 (ED.12{8)Page 123.11
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
0/.t1812018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
(8) The Tax Cuts and Jobs Act, enacted on December 22, 201 7, reduced the deferred income tax assets and liabilities. For depreciation-related timing differences under
the normalized tax accounting method, this reduction will flow back to customers under the statutorily prescribed average rate assumption method.
(10) Mark+o-market assets and liabilities are discussed in Note l6 - "Fair Value Measurements."
Idaho Power's regulatory assets and liabilities are typically amortized over the period in which they are reflected in customer rates. In
the event that recovery ofldaho Power's costs through rates becomes unlikely or uncertain, regulatory accounting would no longer
apply to some or all of Idaho Power's operations and the items above may represent stranded investments. If not allowed full recovery
of these items, Idaho Power would be required to write offthe applicable portion, which could have a materially adverse financial
impact.
Power Cost Adjustment Mechanisms and Deferred Power Supply Costs
In both its Idaho and Oregon jurisdictions, Idaho Power's power cost adjustment mechanisms address the volatility of power supply
costs and provide for annual adjustments to the rates charged to its retail customers. The power cost adjustment mechanisms compare
Idaho Power's actual net power supply costs (primarily fuel and purchased power less off-system sales) against net power supply costs
being recovered in Idaho Power's retail rates. Under the power cost adjustment mechanisms, certain differences between actual net
power supply costs incurred by Idaho Power and costs being recovered in retail rates are recorded as a deferred charge or credit on the
balance sheets for future recovery or refund. The power supply costs deferred primarily result from changes in contracted power
purchase prices and volumes, changes in wholesale market prices and transaction volumes, fuel prices, and the levels of Idaho Power's
own generation. The Idaho deferral period or PCA year runs from April I through March 3l . Amounts deferred during the PCA year
are primarily recovered or refunded during the subsequent June I through May 3l period.
Idaho Jurisdicfion Power Cost Adjustment Mechanism.' In the Idaho jurisdiction, the annual PCA adjustment consists of (a) a
forecast component, based on a forecast of net power supply costs in the coming year as compared with net power supply costs
included in base rates; and (b) a true-up component, based on the difference between the previous year's actual net power supply costs
and the previous year's forecast. The latter component also includes a balancing mechanism so that, over time, the actual collection or
refund of authorized true-up dollars matches the amounts authorized. The PCA mechanism also includes:
a cost or benefit sharing ratio that allocates the deviations in net power supply expenses between customers (95 percent) and
shareholders (5 percent), with the exceptions of expenses associated with PURPA power purchases and demand response
incentive payments, which are allocated 100 percent to customers; and
a sales-based adjustment intended to ensure that power supply expense recovery resulting solely from sales changes does not
distort the results of the mechanism.
FERC FORM NO.1 1 123.12
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04h8,nu8
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The table below summarizes the three most recent PCA rate adjustments, all of which also include non-PCA-related rate adjustments
as ordered by the IPUC:
Effective $ ChangeDate (millions) Notes
June l,2017 $10.6 The net increase in PCA rates included an offsetting $13.0 million reduction for the refund of
previously collected Idaho enerry efficiency rider funds.
June 1,2016 $17.3 The net increase in PCA rates included the application of (a) a customer rate credit of $3.2
million for sharing of revenues with customers for the year 2015 under the terms of the
October 2014 settlement stipulation, and (b) $4.0 million of surplus Idaho energy efficiency
rider funds.
Oregon Jufisdiction Power Cost Adjustment Mechanism: Idaho Power's power cost recovery mechanism in Oregon has two
components: an annual power cost update (APCU) and a power cost adjustment mechanism (PCAM). The APCU allows Idaho Power
to reestablish its Oregon base net power supply costs annually, separate from a general rate case, and to forecast net power supply
costs for the upcoming water year. The PCAM is a true-up filed annually in February. The filing calculates the deviation between
actual net power supply expenses incurred for the preceding calendar year and the net power supply expenses recovered through the
APCU for the same period. Under the PCAM, Idaho Power is subject to a portion of the business risk or benefit associated with this
deviation through application of an asymmetrical deadband (or range of deviations) within which Idaho Power absorbs cost increases
or decreases. For deviations in actual power supply costs outside ofthe deadband, the PCAM provides for 90/10 sharing ofcosts and
benefits between customers and Idaho Power. However, collection by Idaho Power will occur only to the extent that Idaho Power's
actual Oregon-jurisdictional retum on equity (Oregon ROE) for the year is at least 100 basis points below Idaho Power's last
authorized Oregon ROE. A refund to customers will occur only to the extent that Idaho Power's actual Oregon ROE for that year is at
least 100 basis points above Idaho Power's last authorized Oregon ROE. Oregonjurisdiction power supply cost changes under the
APCU and PCAM during each of 2017 and 2016 are summarized in the table that follows:
Year and
Mechanism APCU or PCAM Adjustment
Actual net power supply costs were within the deadband, resulting in no deferral.
A rate increase of $0.7 million annually took effect June 1,2017.
Actual net power supply costs were within the deadband, resulting in no deferral.
A rate increase of $0.2 million annually took effect June 1,2016.
20I7 PCAM
2017 APCU
20I6 PCAM
2016 APCU
FERC FORM NO. 1 ED.1 123.13
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)
ut't8t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Notable Idaho Regulatory Matters
Idaho Base Rate Changes.' Idaho base rates were most recently established in 2012, and adjusted in 2014. Effective January I , 2012,
Idaho Power implemented new ldaho base rates resulting from IPUC approval of a settlement stipulation that provided for a 7.86
percent authorized overall rate ofretum on an Idaho-jurisdiction rate base ofapproximately $2.36 billion. The settlement stipulation
resulted ina4.07 percent, or $34.0 million, overall increase in Idaho Power's annual ldaho-jurisdiction base rate revenues. Idaho base
rates were subsequently adjusted again in 2012, in connection with Idaho Power's completion of the Langley Gulch power plant. ln
June 2012, the IPUC issued an order approving a $58. I million increase in annual Idaho-jurisdiction base rates, effective July 1,2012.
The order also provided for a $335.9 million increase in Idaho rate base. Neither the settlement stipulation nor the IPUC orders
adjusting base rates specified an authorized rate ofretum on equity or imposed a moratorium on Idaho Power filing a general rate case
at a future date.
As noted above in this Note 3, the IPUC also issued a March 2014 order approving Idaho Power's request for an increase in the
normalized or "base level" net power supply expense to be used to update base rates and in the determination ofthe PCA rate that
became effective June 1,2014.
October 2014 ldaho Satlement Stipulation' In October 2014, the IPUC issued an order approving an extension, with modifications,
of the terms of a December 201 I Idaho settlement stipulation for the period from 2015 through 2019, or until the terms are otherwise
modified or terminated by order of the IPUC or the full $45 million of additional accumulated deferred
investment tax credits (ADITC) contemplated by the settlement stipulation has been amortized. The provisions of the October 2014
settlement stipulation are as follows:
Ifldaho Power's actual annual Idaho-jurisdiction return on year-end equity (Idaho ROE) in any year is less than 9.5 percent,
then Idaho Power may amortize up to $25 million of additional ADITC to help achieve a 9.5 percent Idatro ROE for that
year, and may amortize up to a total of $45 million of additional ADITC over the 2015 through 2019 period.
Ifldaho PoweCs annual Idaho ROE in any year exceeds 10.0 percent, the amount ofearnings exceeding a 10.0 percent Idaho
ROE and up to and including a 10.5 percent Idaho ROE will be allocated 75 percent to Idaho Power's Idaho customers as a
rate reduction to be effective at the time ofthe subsequent year's PCA and 25 percent to Idaho Power.
Ifldaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount ofeamings exceeding a 10.5 percent Idaho
ROE will be allocated 50 percent to Idaho Power's Idaho customers as a rate reduction to be effective at the time of the
subsequent year's PCA, 25 percent to Idaho Power's Idaho customers in the form ofa reduction to the pension expense
deferral regulatory asset (to reduce the amount to be collected in the future from Idaho customers), and 25 percent to Idaho
Power.
If the full $45 million of additional ADITC contemplated by the settlement stipulation has been amortized the sharing
provisions would terminate.
In the event the IPUC approves a change to ldaho Powe/s Idaho-jurisdictional allowed retum on equity as part ofa general
rate case proceeding seeking a rate change effective prior to January l, 2020, the Idaho ROE thresholds (9.5 percent, I 0.0
percent, and 10.5 percent) will be adjusted prospectively.
FERC FORM NO. I (ED. 12{8)Page 123.14
a
a
a
a
a
Neither the settlement stipulation nor the associated IPUC order impose a moratorium on Idaho Power filing a general rate case or
other form ofrate proceeding during the term ofthe settlement stipulation.
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t't8t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
In both 2016 and 2017,ldaho Power recorded no additional ADITC amortization and no provision for sharing with customers, as its
Idaho ROE in both years was between 9.5 percent and 10.0 percent. Accordingly, at December 31,2017, the full $45 million of
additional ADITC remains available for future use under the terms of the settlement stipulation.
Fixed Cost Adjustment: The Idaho jurisdiction fixed cost adjustment (FCA) mechanism is designed to remove ldaho Power's
financial disincentive to invest in enerry efficiency programs by separating (or decoupling) the recovery of fixed costs from the
variable kilowatt-hour charge and linking it instead to a set amount per customer. The FCA mechanism is adjusted each year to
collect, or refund, the difference between the authorized fixed-cost recovery amount and the actual fixed costs recovered by Idaho
Power during the year. The annual change in the FCA recovery is capped at no more than 3 percent ofbase revenue, with any excess
deferred for collection in a subsequent year.
The following table summarizes FCA amounts approved for collection in the prior FCA years:
Annual Amount
FCA Year Period Rates in Effect (in millions)
20t6
2015
June l, 2017-May 31, 2018
June l, 2016-May 31, 2017
s35.0
$28. I
In July 2014, the IPUC opened a docket to allow ldaho Power, the IPUC Staff, and other interested parties to further evaluate the
IPUC Staffs concems regarding the application of the FCA mechanism (including weather-normalization, customer count
methodology, rate adjustment cap, and cross-subsidization issues) and whether the FCA is effectively removing Idaho Power's
disincentive to aggressively pursue energy efliciency programs. In May 2015, the IPUC approved a settlement stipulation that
modified the FCA mechanism by replacing weather-normalized billed sales with actual billed sales in the calculation of the FCA,
applicable for the entirety of calendar year 2015 and thereafter, and reflected in FCA rates effective June I , 201 6.
Hells Canyon Complex Relicensing Costs Settlement Stipulalion.' In December 2016,ldaho Power hled an application with the
IPUC requesting a determination that Idaho Power's expenditures of $220.8 million through year-end 2015 on relicensing of the HCC
were prudently incurred, and thus eligible for inclusion in retail rates in a future rate case. In December 2017, Idaho Power filed with
the IPUC a settlement stipulation signed by Idaho Power, the IPUC stalI, and a third party intervenor recognizing that a total of
$216.5 million in HCC relicensing expenditures and other related costs were reasonably incurred, and therefore should be eligible for
inclusion in customer rates at a later date. On April 13, 2018, the settlement stipulation was approved by the IPUC substantially as
filed. As a result of filing the settlement stipulation, Idaho Power recorded a $5.0 million pre-tax charge in 2017. For more
information relating to HCC relicensing costs, see Note l2 - "Property, Plant and Equipment and Jointly-Owned Projects."
FERC FORM NO.1 (ED. 12481 Page 123.15
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
ut't8t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Energt Elliciency Rider: On an annual basis, Idaho Power applies to the IPUC for an order designating Idaho Power's prior
calendaryear Idaho Enerry Efficiency Rider (ldaho Rider) funded expenses as prudently incurred. ln2012 and 2013, the IPUC
declined to decide the prudence of the increases in 201I and20l2ldaho Rider funded labor increases, while at the same time offering
Idaho Power another opportunity to provide sufficient evidence at a future time. In 2017, Idaho Power applied to the IPUC for an
order determining that the 201 | - 2016ldaho Rider funded labor increases of $1.9 million were prudently incurred and eligible for
collection through the Idaho Rider. On October 16,2017, the IPUC issued its order determining that the 201 I - 2016 incremental
Idaho Rider funded labor expenses of $l.9 million were prudently incurred. In its order, the IPUC also authorized actual Idaho Rider
funded wage increases after 2016. The IPUC determined that this process does not require pre-determination as to prudence (up to a 2
percent annual cap), no longer requires labor to be examined in Idaho Power's annual prudence cases, and that the base wage level
and annual cap will be reset in future general rate cases. The prudence order resulted in a $2.4 million increase in operating income in
2017.
Tax Cuts and Jobs Act
On December 22,2017, the Tax Cut and Jobs Act was signed into law. On January 17,2018, the IPUC issued an order requiring
utilities within its jurisdiction, including Idaho Power, to I ) record a deferred regulatory liability for the estimated Idaho-jurisdictional
share of financial benefits after January I , 201 8, from the changes in the federal income tax law and 2) to file a report with the IPUC
by March 30, 201 8, identifying and quantifying the income tax changes along with proposed tariff schedule changes. The IPUC order
requires Idaho Power to estimate the income tax changes by comparing acttal20lT federal income tax expense components with what
those federal income tax components would have been if the Tax Cuts and Jobs Act had been effective for the full year of 2017 .
In March 2018, Idaho Power made a filing with the IPUC providing the results of its pro forma analysis, on a system basis, indicating
pro forma annual income ta,\ expense reductions, comprised of a current income tax expense reduction and a deferred income tax
expense reduction. On April 12,2018,ldaho Power filed with the IPUC a settlement stipulation (April 2018 Settlement Stipulation)
signed by Idaho Power, the IPUC Staff, and a third-party intervenor which, ifapproved, provides for Idaho Power customers an
annual (a) direct $ I 8.7 million reduction of customer base rates and (b) non-cash offset of $7.4 million of regulatory deferrals that
would have otherwise been a future potential liability of Idaho customers, commencing June I , 201 8.
Additionally, a one-time benefit of $7.8 million will be provided to Idaho customers through Power Cost Adjustment (PCA)
mechanism rates for the period from June l, 2018 through May 31, 2019 for the income tax savings accrued from January l, 2018 to
May 31, 2018 and the income tax benefits related to the transmission tariff. On June 1,2019, the amount provided via the PCA will
decrease to 52.7 million and will cease on June l, 2020.
The April 2018 Settlement Stipulation also provides for the indefinite extension of the October 2014 Settlement Stipulation beyond
the initial termination date of December 31, 2019, with the following modified terms to become effective beginning January 1,2020:
Idaho Power will have available and may continue to use any unused portion of the $45 million ADITC from the October
2014 settlement.
If ldaho Power's annual Idaho ROE in any year is less than 9.4 percent, then Idaho Power may amortize up to $25 million of
additional ADITC to help achieve a 9.4 percent ldaho ROE for that year, so long as the cumulative amount of ADITC used
does not exceed $45 million; however, upon approval of the IPUC, Idaho Power may replenish the total amount of ADITC it
is permitted to amortize.
Ifldaho Power's annual Idaho ROE in any year exceeds 10.0 percent, the amount ofearnings exceeding a 10.0 percent Idaho
ROE and up to and including a 10.5 percent Idaho ROE will be allocated 80 percent to Idaho Power's Idaho customers as a
rate reduction to be effective at the time of the subsequent year's PCA, and 20 percent to Idaho Power.
FERC FORM NO.1 (ED.12€8)Page 123.16
a
a
a
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
ut18t20't8
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
a
a
Ifldaho Power's annual Idaho ROE in any year exceeds 10.5 percent, the amount ofearnings exceeding a 10.5 percent Idaho
ROE will be allocated 55 percent to Idaho Power's ldaho customers as a rate reduction to be effective at the time of the
subsequent year's PCA, 25 percent to ldaho Power's Idaho customers in the form of a reduction to the pension expense
deferral regulatory asset (to reduce the amount to be collected in the future from Idaho customers), and 20 percent to Idaho
Power.
In the event the IPUC approves a change to Idaho Power's allowed annual Idaho ROE as part ofa general rate case
proceeding effective on or after January 1,2020, the ROE thresholds will be adjusted on a prospective basis as follows: (a)
the Idaho ROE thresholds under which Idaho Power will be permitted to amortize an additional amount of ADITC will be set
at 95 percent of the newly authorized ROE, (b) sharing with customers on an 80 percent basis as a customer rate reduction
will begin at the newly authorized Idaho ROE, and (c) sharing with customers on an 80 percent basis but allocated 55 percent
to a rate reduction, and 25 percent to a pension expense deferral regulatory asset, will begin at 105 percent ofthe newly
authorized ROE.
Neither the October 2014 Settlement Stipulation nor the April 2018 Settlement Stipulation order impose a moratorium on Idaho
Power filing a general rate case or other form ofrate proceeding during the respective terms.
On December 29,2017,ldaho Power filed an application with the OPUC, requesting authority to defer for later ratemaking treatment
the Oregon jurisdictional earnings in excess of the currently authorized Oregon jurisdictional rate of return on equity that may result
from the Tax Cuts and Jobs Act, as measured from the Company's annual Oregon Results of Operations. On December 29,2017 ,
OPUC Staff also filed an application with the OPUC requesting authority to defer for later ratemaking treatment the difference
between Idaho Power's current retail rates and its current retail rates inclusive of the impact of the Tax Cuts and Jobs Act.
Idaho Power is working with the IPUC and OPUC to determine how potential income tax expense reductions from the changes in
federal income tax law may benefit Idaho Power customers and affect Idaho Power's financial condition and results of operations. The
method through which potential cost savings may be accrued for the benefit of customers, including potential reductions to customer
rates and to regulatory deferrals, will require approval from the IPUC and OPUC.
Valmy Base Rate Adjustment Settlement Stipulations
In May 2017,the IPUC approved a settlement stipulation allowing accelerated depreciation and cost recovery for Idaho Power's
jointly-owned North Valmy coal-fired power plant (Valmy Plant). The settlement stipulation provides for an increase in Idaho
jurisdictional revenues of$13.3 million per year, and (l) levelized collections and associated cost recovery through December 2028,
(2) accelerated depreciation on unit I through 2019 and unit 2 through 2025, (3) ldaho Power to use prudent and commercially
reasonable efforts to end its participation in the operation of unit I by the end of 2019 and unit 2 by the end of 2025, and (4) a filing
no later than December 31,2019 that would include actual and planned incremental investments in unit 2, including updated financial
analysis regarding the lowest costs options for unit 2. The costs intended to be recovered by the increasedjurisdictional revenues
include current investments as of May 31, 2017, in both units, forecasted unit I investments from 2017 through 2019, and forecasted
decommissioning costs for unit I and unit 2, offset by forecasted operation and maintenance costs savings. The settlement stipulation
also provides for the regulatory accrual or deferral ofthe difference between actual revenue requirements and levelized collections,
and provides for the regulatory accrual or deferral ofthe difference between actual costs incurred (including accelerated depreciation
expense on unit I through 2019 and unit 2 through 2025) compared with costs permitted to be recovered during the cost recovery
period specified in the settlement stipulation (including depreciation expense through 2028). lf actual costs incurred differ from
forecasted amounts included in the settlement stipulation, collection or refund ofany differences would be subject to regulatory
FERC FORM NO. I (ED.12-88)Page 123.17
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
ut18t20't8
Year/Period of Report
20,171Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
approval.
In June 2017,the OPUC also approved a settlement stipulation allowing for accelerated depreciation of units I and2 through
December 31,2025, cost recovery of incremental Valmy Plant investments through May 31, 2017, wrd forecasted decommissioning
costs. The settlement stipulation provides for an increase in the Oregon jurisdictional revenue requirement of $l.l million, effective
luly l, 2017 , with yearly adj ustments, if warranted.
Depreciation Rate Settlement Stipulations
In May 2017,the IPUC and OPUC approved settlement stipulations related to revised depreciation rates for Idaho Power's electric
plant in service other than the Valmy Plant, and adjusted base rates in Oregon to reflect the revised depreciation rates applied to
electric plant-in-service based on balances from the most recent general rate case. These settlement stipulations provided for new
depreciation rates to go into effect on June l, 2017 , with no significant resulting increase in revenue.
Western Energy Imbalance Market Costs
Idaho Power plans to participate in a new energy imbalance market implemented in the western United States (Western EIM). In
August 2016, Idaho Power filed an application with the IPUC requesting specified regulatory accounting treatment associated with its
participation in the Westem EIM. In January 2017, the IPUC issued an order authorizing Idaho Power's requested deferral accounting
treatment for costs associated with joining the Western EIM. Idaho Power can defer costs incurred until the earlier of when Idaho
Power begins recovery ofthe costs and the deferral balance or the end of20l8. Idaho Power anticipates that its participation in the
Westem EIM will commence in April 2018.
In November 2017 , Idaho Power filed an application with the IPUC requesting approval to establish an interim method of recovery
for costs associated with participation in the Westem EIM. Ifthe IPUC approves the application as filed, Idaho Power intends to
include S3.6 million in costs for recovery through the PCA, beginning June l, 2018.
Notable Oregon Regulatory Matters
Oregon Base Rate Changes: Oregon base rates were most recently established in a general rate case in20l2.In February 2012,the
OPUC issued an order approving a settlement stipulation that provided for a $ I .8 million base rate increase, a retum on equity of 9.9
percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. New rates in conformity with the settlement
stipulation were effective March I , 20 12. Subsequently, in September 2012, the OPUC issued an order approving an approximately
$3.0 million increase in annual Oregon jurisdiction base rates, effective October l, 2012, for inclusion of the Langley Gulch power
plant in Idaho Power's Oregon rate base.
FERC FORM NO. 1 (ED. 12481 Page'123.18
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2\ -A Resubmission
Date of Report
(Mo, Da, Yr)
ut18t2018
Year/Period of Report
2U7tA4
NOTES TO FINANCIAL STATEMENTS (Continued)
Federal Regulatory Maffers - Open Access Transmission Tariff Rates
Idaho Power uses a formula rate for transmission service provided under its OATT, which allows transmission rates to be updated
annually based primarily on financial and operational data Idaho Power files with the FERC. Idaho PowerJs OATT rates submitted to
the FERC in Idaho Power's four most recent annual OATT Final Informational Filings were as follows:
Applicable Period
OATT Rate
(per kW-year)
$
$
$
34.90
25.52
23.43
Idaho Power's current OATT rate is based on a net annual transmission revenue requirement of $130.4 million, which represents the
OATT formulaic determination of Idaho Power's net cost of providing OATT-based transmission service.
FERC FORM NO. I (ED. 12€8)Page 123.19
October 1,2017 to September 30, 2018
October 1,2016 to September 30,2017
October l, 2015 to September 30,2016
Name of Respondent
ldaho Power Companv
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
o4118t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table summarizes Idaho Power's long-term debt at December 3 I (in thousands of dollars):
2017 2016
First mortgage bonds:
4.50% Series due2020
3.40% Series due 2020
2.95% Series due2022
2.50% Series due2023
6.00% Series due2032
5.50% Series due 2033
5.50olo Series due 2034
5.875Yo Series due 2034
5.30% Series due 2035
6.30% Series due2037
6.25% Series due2037
4.85% Series due 2040
4.30% Series due2042
4.00% Series due2043
3.65% Series due2045
4.05% Series due2046
$130,000 $
100,000
75,000
75,000
100,000
70,000
50,000
55,000
60,000
140,000
100,000
100,000
75,000
75,000
250,000
120,000
130,000
100,000
75,000
75,000
100,000
70,000
50,000
55,000
60,000
140,000
100,000
100,000
75,000
75,000
250,000
120,000
Total first mortgage bonds r ,575,000 l,575,000
Pollution control revenue bonds:
5.15% Series due20240)
5.25% Series due 20260)
Variable Rate Series 2000 due 2027
49,800
l r6,300
4,360
49,800
r r 6,300
4,360
Total pollution control revenue bonds 170,460 170,460
American Falls bond guarantee
Milner Dam note guarantee
Unamortized issuance costs and discounts
19,885 r 9,885
1,064
(4,417)(4,125)
Total ldaho Power outstanding debt(2)1,761,220 1,761,992
(l ) Humboldt County and Sweetwater County Pollution Control Revenue Bonds are secured by the first mortgage, bringing the total first mortgage bonds outstanding at
December 31, 201 7, to $1.741 billion.
(2) At December 3 1,2017 and2016. the overall effective cost rate ofldaho Power's outstanding debt was 4.87 percent.
FERC FORM NO.1 (ED.12{8)Page 123.20
4. LONG-TERIVI DEBT
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
04t18t2018
Year/Period of Report
2017t44
NOTES TO FINANCIAL STATEMENTS (Continued)
At December 3l , 2017 , the maturities for the aggregate amount of Idaho Power long-term debt outstanding were as follows (in
thousands ofdollars):
2018 2019 2020 2021 2022 Thereafter
S $$ 230,000 $$ 75,000 s 1,460,345
Long-Term Debt Issuances, Maturities, and Availability
On March l0,20l6,Idaho Power issued $120 million in principal amount of 4.05o/o first mortgage bonds, secured medium-term
notes, Series J, maturing on March 1,2046. On April ll,20l6,ldaho Powerredeemed, priorto maturity, $100 million in principal
amount of 6.15%o first mortgage bonds, medium-term notes, Series H, due April 2019. In accordance with the redemption provisions
of the notes, the redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the
aggregate amount of approximately $14.0 million. Idaho Power used a portion of the net proceeds from the March 2016 sale of first
mortgage bonds, medium-term notes to effect the redemption.
On March 6,2015,ldaho Power issued $250.0 million in principal arnount of 3.650/o first mortgage bonds, secured medium-term
notes, Series J, maturing on March 1,2045. On April 23,2015,ldaho Power redeemed, prior to maturity, $120.0 million in principal
amount of 6.025Yo first mortgage bonds, secured medium-term notes, Series H, due July 2018. In accordance with the redemption
provisions of the notes, the redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed
notes in the aggregate amount of approximately $17.9 million. Idaho Power used a portion of the net proceeds from the March 2015
sale of first mortgage bonds, medium-term notes to effect the redemption.
In April and May 2016, Idaho Power received orders from the IPUC, OPUC, and Wyoming Public Service Commission (WPSC)
authorizing Idaho Power to issue and sell from time to time up to $500 million in aggregate principal amount of debt securities and
first mortgage bonds, subject to conditions specified in the orders. The order from the IPUC approved the issuance ofthe securities
through May 31, 2019, subject to extensions upon request to the IPUC. The OPUC's and WPSC's orders do not impose a time
limitation for issuances, but the OPUC order does impose a number of other conditions, including a requirement that the interest rates
for the debt securities or first mortgage bonds fall within either (a) designated spreads over comparable U.S. Treasury rates or (b) a
maximum all-in interest rate limit of 7.0 percent.
On May 20,2016,IDACORP and Idaho Power filed a joint shelf registration statement with the U.S. Securities and Exchange
Commission (SEC), which became effective upon filing, for the offer and sale of, in the case of Idaho Power, an unspecified principal
amount of its first mortgage bonds and debt securities. On September 27 , 2016, Idaho Power entered into a selling agency agreement
with seven banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million
aggregate principal amount offirst mortgage bonds, secured medium term notes, Series K (Series K Notes), under Idaho Power's
Indenture of Mortgage and Deed of Trust, dated as of October l, 1937 , as amended and supplemented (Indenture). At the same time,
Idaho Power entered into the Forty-eiglrth Supplemental Indenture, dated as ofSeptember 1,2016, to the Indenture. The Forty-eighth
Supplemental Indenture provides for, among other items, the issuance of up to $500 million in aggregate principal amount of Series K
Notes pursuant to the Indenture. As of December 31,2017, $500 million in principal amount of Series K Notes remained available for
issuance under the Indenture.
On March 16, 2018, Idaho Power issued $220 million in principal amount of 4.20o/o first mortgage bonds, secured medium-term
notes, Series K, maturing on March 1,2048. On April 17,2018,ldaho Power redeemed, prior to maturity, $130 million in principal
amount of 4.50o/o first mortgage bonds, medium-term notes, Series H due April 2020. ln accordance with the redemption provisions
FERC FORM NO.1 (ED.12A8l Page 123.21
Name of Respondent
ldaho Power Comoanv
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t18t2018
Year/Period of Report
2017to.4
NOTES TO FINANCIAL STATEMENTS (Continued)
of the notes, the redemption included Idaho Power's payment of a make-whole premium to the holders of the redeemed notes in the
aggregate amount of $5 million. Idaho Power used a portion of the net proceeds from the March 2018 sale of first mortgage bonds,
medium-term notes to effect the redemption.
Mortgage: As of December 3l,2017,ldaho Power could issue under its Indenture approximately $1.8 billion of additional first
mortgage bonds based on retired first mortgage bonds and total unfunded property additions. These amounts are further limited by the
maximum amount of first mortgage bonds set forth in the Indenture.
The mortgage ofthe Indenture secures all bonds issued under the Indenture equally and ratably, without preference, priority, or
distinction. First mortgage bonds issued in the future will also be secured by the mortgage of the Indenture. The lien constitutes a first
mortgage on all the properties of Idaho Power, subject only to certain limited exceptions including liens for taxes and assessments that
are not delinquent and minor excepted encumbrances. Certain ofthe properties ofldaho Power are subject to easements, leases,
contracts, covenants, workmen's compensation awards, and similar encumbrances and minor defects and clouds common to
properties. The mortgage ofthe Indenture does not create a lien on revenues or profits, or notes or accounts receivable, contracts or
choses in action, except as permitted by law during a completed default, securities, or cash, except when pledged, or merchandise or
equipment manufactured or acquired for resale. The mortgage of the Indenture creates a lien on the interest of Idaho Power in
property subsequently acquired, other than excepted property, subject to limitations in the case ofconsolidation, merger, or sale ofall
or substantially all of the assets of ldaho Power. The Indenture requires Idaho Power to spend or appropriate l5 percent of its annual
gross operating revenues for maintenance, retirement, or amortization of its properties. Idaho Power may, however, anticipate or make
up these expenditures or appropriations within the five years that immediately follow or precede a particular year.
The Forty-eighth Supplemental Indenture increased the maximum amount of first mortgage bonds issuable by Idaho Power under the
Indenture from $2.0 billion to $2.5 billion. The amount issuable is also restricted by property, eamings, and other provisions of the
Indenture and supplemental indentures to the Indenture. Idaho Power may amend the Indenture and increase this amount without
consent of the holders of the first mortgage bonds. The Indenture requires that Idaho Power's net eamings be at least twice the annual
interest requirements on all outstanding debt ofequal or prior rank, including the bonds that ldaho Power may propose to issue. Under
ceftain circumstances, the net earnings test does not apply, including the issuance ofrefunding bonds to retire outstanding bonds that
mature in less than two years or that are ofan equal or higher interest rate, or prior lien bonds.
5. NOTES PAYABLE
Credit Facilities
On November 6,2015,ldaho Power entered into a Credit Agreement replacing the existing Second Amended and Restated Credit
Agreements, dated October 26,201I , to provide credit facilities that may be used for general corporate purposes and commercial
paper backup. Idaho Power's credit facility consists ofa revolving line ofcredit, through the issuance ofloans and standby letters of
credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an
aggregate principal amount at any time outstanding not to exceed $30 million, and letters ofcredit in an aggregate principal amount at
any time outstanding not to exceed $100 million. Idaho Power has the right to request an increase in the aggregate principal amount of
the facilities to $450 million, subject to certain conditions.
The interest rate for any borrowings under the facility is based on either (l ) a floating rate that is equal to the highest ofthe prime rate,
federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin,
provided that the federal funds rate and LIBOR rate will not be less than 0.0 percent. The margin is based on ldaho Power's senior
FERC FORM NO. 1 (ED. 12{8)Page 123.22
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
ut1812018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch
Rating Services, Inc., as set forth on a schedule to the credit agreements. Under the credit facility, Idaho Power pays a facility fee on
the commitment based on the company's credit rating for senior unsecured long-term debt securities. While the credit facility provides
for an original maturity date of November 6,2020, the credit agreements grant Idaho Power the right to request up to two one-year
extensions, subject to certain conditions. On November 7,2017,ldaho Power executed the second extension agreement with the
consent of all the lenders, extending the maturity date under the credit agreement to November 4,2022. No other terms of the credit
facility, included the amount of permitted borrowing under the credit agreement, were affected by the extension.
At December 31, 2017 , no loans were outstanding under Idaho Power's facility. At December 3l , 2017 , Idaho Power had regulatory
authority to incur up to $450 million in principal amount of short-term indebtedness at any one time outstanding. Balances (in
thousands of dollars) and the interest rate of Idaho Power's short-term borrowings was as follows at December 3l , 2017 , and
December 31,2016:
2017 2016
Commercial paper balances:
At the end of year
Average during the year
Weighted-average interest rate
At the end ofthe year
1,800
438
o//o -o/o l.l3o/o
$
$
s
$
2
839
6. COMMON STOCK
Idaho Power Common Stock
No contributions were made to Idaho Power in 2017 or 2016 and no additional shares of Idaho Power common stock were issued.
Restrictions on Dividends
Idaho Power's ability to pay dividends on its common stock held by IDACORP is limited to the extent payment of such dividends
would violate the covenants in its credit facility or Idaho Power's Revised Code of Conduct. A covenant under Idaho Power's credit
facility requires Idaho Power to maintain leverage ratios ofconsolidated indebtedness to consolidated total capitalization, as defined
therein, ofno more than 65 percent at the end ofeach fiscal quarter. At December 31,2017, the leverage ratio for Idaho Power was 46
percent. Based on these restrictions, Idaho Power's dividends were limited to $l.l billion at December 31,2017. There are additional
facility covenants, subject to exceptions, that prohibit or restrict the sale or disposition ofproperty without consent and any
agreements restricting dividend payments to the company from any material subsidiary. At December 31, 2017 ,Idaho Power was in
compliance with those covenants.
Idaho Power's Revised Policy and Code of Conduct relating to transactions between and among Idaho Power, IDACORP, and other
affiliates, which was approved by the IPUC in April 2008, provides that Idaho Power will not pay any dividends to IDACORP that
will reduce Idaho Power's common equity capital below 35 percent of its total adjusted capital without IPUC approval. At
December 3l,2017,ldaho Power's common equity capital was 54 percent of its total adjusted capital. Further, Idaho Power must
obtain approval from the OPUC before it can directly or indirectly loan funds or issue notes or give credit on its books to IDACORP
FERC FORM NO.1 D.1 123.23
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t18t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Idaho Power's articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock
dividends are in arrears. As ofthe date ofthis report, Idaho Power has no preferred stock outstanding.
In addition to contractual restrictions on the amount and payment of dividends, the Federal Power Act (FPA) prohibits the payment of
dividends from "capital accounts." The term "capital account" is undefined in the FPA or its regulations, but Idaho Power does not
believe the restriction would limit Idaho PoweCs ability to pay dividends out of current year eamings or retained eamings.
In accordance with Section l0(d) of the Federal Power Act, Idaho Power has $13.3 million of amortization reserves established for
certain of its licensed hydroelectric facilities.
7. SHARE.BASED COMPENSATION
Through its parent company IDACORP, Idaho Power has one share-based compensation plan - the 2000 Long-Term Incentive and
Compensation Plan (LTICP). The 1994 Restricted Stock Plan was terminated effective February 9, 2017 . The LTICP (for officers,
key employees, and directors) permits the grant ofstock options, restricted stock and restricted stock units (together, Restricted
Stock), performance shares and performance-based units (together, Performance-Based Shares), and several other types of share-based
awards. At December 31,2017, the maximum number of shares available under the LTICP was 836,220.
Restricted Stock and Performance-Based Shares Awards
Restricted Stock awards have three-year vesting periods and entitle the recipients to dividends or dividend equivalents, as applicable,
and voting rights, except that holders ofrestricted stock units do not have voting rights until the units are vested and settled in shares.
Unvested awards are restricted as to disposition and subject to forfeiture under certain circumstances. The fair value of these awards is
based on the closing market price ofcommon stock on the grant date and is charged to compensation expense over the vesting period,
based on the number of shares expected to vest.
Performance-Based Shares awards have three-year vesting periods and entitle the recipients to voting rights, except that holders of
performance-based units do not have voting rights until the units are vested and settled in shares. Unvested awards are restricted as to
disposition, subject to forfeiture under certain circumstances, and subject to the attainment of specific performance conditions over
the three-year vesting period. The performance conditions are two equally-weighted metrics, cumulative eamings per share (CEPS)
and total shareholder retum (TSR) relative to a peer group. Depending on the level of attainment of the performance conditions and
the year issued, the final number ofshares awarded can ftmge from zero to 200 percent ofthe target award. Dividends or dividend
equivalents, as applicable, are accrued during the vesting period and paid out based on the final number ofshares awarded.
The grant-date fair value ofthe CEPS portion is based on the closing market value at the date ofgrant, reduced by the loss in
time-value of the estimated future dividend payments. The fair value of this portion of the awards is charged to compensation expense
over the requisite service period, based on the number ofshares expected to vest. The grant-date fair value ofthe TSR portion is
estimated using the market value at the date of grant and a statistical model that incorporates the probability of meeting performance
targets based on historical returns relative to the peergroup. The fair value ofthis portion ofthe awards is charged to compensation
expense over the requisite service period, provided the requisite service period is rendered, regardless ofthe level ofTSR metric
attained.
FERC FORM NO. 1 (ED. 12{8)Page 123.24
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, YD
0/.I1812018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
A summary of Restricted Stock and Performance-Based Shares award activity is presented below. Share amounts represent the shares
of IDACORP common stock:
]iumher of
Sharcs,(Jnitr
["ighted-
Average
Grart l)rte
Feir lhlue
Nodr.-ested shaf,esiuf,its at Jaauary l,201l
Shares;'units grated
Shares,"units forfeited
Shares"units r.ested
$199"526 $
95,568
(6, l 7e)
(89,263)
61-51
7i_40
75"i4
51.07
Noarested shaf,es;utrits at Deceuber J l. 20 I 7 $ 199,651 $ 72.39
The total fair value of shares vested was $7.5 million in 2017 and $8.3 million in 2016. At December 31,2017 ,ldaho Power had $5.4
million oftotal unrecogrized compensation cost related to nonvested share-based compensation that was expected to vest. These costs
are expected to be recognized over a weighted-average period of 1.7 years. Original issue and/or treasury shares ofIDACORP are
used for these awards.
ln 2017 , a total of I 2,050 shares of IDACORP common stock were awarded to directors of IDACORP and ldaho Power at a grant
date fair value of$82.93 per share. Directors elected to defer receipt of3,0l2 ofthese shares, which are being held as deferred stock
units with dividend equivalents reinvested in additional stock units.
Compensation Expense: The following table shows Idaho Power's share of the compensation cost recognized in income and the tax
benefits resulting from the LTICP (in thousands ofdollars):
2017 2016 2015
Compensation cost
Income tax benefit
$ 7,304 $
2,856
5,494 $
2,t48
5,221
2,042
No equity compensation costs have been capitalized. These costs are primarily reported within other operations and maintenance
expense in the consolidated statements of income.
FERC FORM NO.1 (ED.12{8)Page 123.25
Name of Respondent
ldaho Power Companv
This Report is:
(1)XAn Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t't8t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
8. COMMITMENTS
Purchase Obligations
At December 3l,2017,Idaho Power had the following long-term commitments relating to purchases of enerry, capacity. transmission
rights, and fuel (in thousands ofdollars):
20f8 2Ol9 2020 2O2l 2022 Thereafter
Cogeneration and power production
Fuel
$ 234,094
42,772
g 229,129 S 230,734 $ 236,644 S 242,380
29,450 27,671 27,861 8,389
s 2,951,425
92,588
As of December 3l,2017,ldaho Power had l,l l4 MW nameplate capacity of PURPA-related projects on-line, with an additional 5
MW nameplate capacity of projects projected to be on-line in 2018 and an additional 24 MW expected to be added in 2019. The
power purchase contracts for these projects have original contract terms ranging from one to 35 years. Idaho Power's expenses
associated with PURPA-related projects were approximately $170 million in2017 and $154 million in 2016.
Idaho Power also has the following long-term commitments (in thousands of dollars):
2018 2019 2020 2021 2022 Thereafter
operating leases(l )
Equipment, maintenance, and service
agreements(l )
FERC and other industry-related fees( I )
(l) Approximately $34 million, $20 million, and $60 million ofthe obligations included in operating leases; equipment, maintenance, and service agreements; and FERC
and other industry-related fees, respectively, have contractsthatdo not specifyterms related to expiration. Asthese contracts are presumed to continue indefinitely, ten
years ofinformation, estimated based on current contract terms, has been included in the table for presentation purposes.
Idaho Power's expense for operating leases was $5.6 million in2017 and $4.9 million in 2016.
Guarantees
Through a self-bonding mechanism, Idaho Power guarantees its portion of reclamation activities and obligations at BCC, of which
IERCo owns a one-third interest. This guarantee, which is renewed annually with the Wyoming Department of Environmental
Quality, was $56.7 million at December 3l ,2017 , representing IERCo's one-third share of BCC's total reclamation obligation of
$ I 70. I million. BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs. At
December 31,2017, the value of the reclamation trust fund was $103.4 million. During 2017,the reclamation trust fund made no
distributions for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the
reclamation trust fund and its estimate of future reclamation costs. To ensure that the reclamation trust fund maintains adequate
reseryes, BCC has the ability to, and does, add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger
plant. Because ofthe existence ofthe fund and the ability to apply a per-ton surcharge, the estimated fair value ofthis guarantee is
minimal.
Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating
to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements. Generally, a maximum
FERC FORM NO.1 (ED.12{8)Page 123.26
$ 3,s29 $
3s,867
4,434 g
10,378
4,538 $
I 1,828
4,s00 $
6,421
4,s07 $
10,322
30,052
53,572
12,940 12,836 10,145 10,145 10,145 50,729
Name of Respondent
ldaho Power Company
This Report is:
(1)XAn Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
ut18t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation
under such indemnification provisions cannot be reasonably estimated Idaho Power periodically evaluates the likelihood of incurring
costs under such indemnities based on its historical experience and the evaluation of the specific indemnities. As of December 3 I ,
2017, management believes the likelihood is remote that Idaho Power would be required to perform under such indemnification
provisions or otherwise incur any significant losses with respect to such indemnification obligations. Idaho Power has not recorded
any liability on its consolidated balance sheets with respect to these indemnification obligations.
9. CONTINGENCIES
Idaho Power has in the past and expects in the future to become involved in various claims, controversies, disputes, and other
contingent matters, some of which involve litigation and regulatory or other contested proceedings. The ultimate resolution and
outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties
sought are indeterminate, (b) thb proceedings are in the early stages or the substantive issues have not been well developed, or (c) the
matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance,
Idaho Power, as applicable, establishes an accrual for legal proceedings when those matters proceed to a stage where they present loss
contingencies that are both probable and reasonably estimable. Ifthe loss contingency at issue is not both probable and reasonably
estimable, Idaho Power does not establish an accrual and the matter will continue to be monitored for any developments that would
make the loss contingency both probable and reasonably estimable. As of the date of this report, Idaho Power's accruals for loss
contingencies are not material to its financial statements as a whole; however, future accruals could be material in a given period.
Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other
financial disclosures involve significant judgment and may be subject to significant uncertainty. For matters that affect Idaho Power's
operations, Idaho Power intends to seek, to the extent permissible and appropriate, recovery through the ratemaking process ofcosts
incurred, although there is no assuftmce that such recovery would be granted.
Idaho Power is party to legal claims and legal and regulatory actions and proceedings in the ordinary course ofbusiness that are in
addition to those discussed above and, as noted above, record an accrual for associated loss contingencies when they are probable and
reasonably estimable. As of the date of this report, Idaho Power believes that resolution of those matters will not have a material
adverse effect on its consolidated financial statements. Idaho Power is also actively monitoring various pending environmental
regulations and recently issued executive orders related to environmental matters that may have a significant impact on its future
operations. Given uncertainties regmding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is
unable to estimate the financial impact of these regulations.
FERC FORM NO. 1 (ED. 12€8)Page 123.27
Name of Respondent
ldaho Power Company
This Report is:
('l) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04118t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
IO. BENEFIT PLANS
Idaho Power sponsors defined benefit and other postretirement benefit plans that cover the majority ofits employees. Idaho Power
also sponsors a defined contribution 401(k) employee savings plan and provides certain post-employment benefits.
Pension Plans
Idaho Power has two pension plans-a noncontributory defined benefit pension plan (pension plan) and two nonqualified defined
benefit pension plans for certain senior management employees called the Security Plan for Senior Management Employees I and
Security Plan for Senior Management Employees II (together, SMSP). Idaho Power also has a nonqualified defined benefit pension
plan for directors that was frozen in 2002. Remaining vested benefits from that plan are included with the SMSP in the disclosures
below. The benefits under these plans are based on years of service and the employee's final average earnings.
Idaho Power's funding policy for the pension plan is to contribute at least the minimum required under the Employee Retirement
Income Security Act of 1974 (ERISA) but not more than the maximum amount deductible for income tax purposes. ln2017 and
2016, Idaho Power elected to contribute more than the minimum required amounts in order to bring the pension plan to a more funded
position, to reduce future required contributions, and to reduce Pension Benefit Guaranty Corporation premiums.
FERC FORM NO. 1 (ED. 12€8)Page 123.28
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
ut1812018
Year/Period of Report
20't7tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table summarizes the changes in benefit obligations and plan assets of these plans (in thousands of dollars):
Pension Plan SMSP
2017 2016 2017 2016
Change in projected benefit obligation:
Benefit obligation at January I
Service cost
Interest cost
Actuarial loss
Plan amendment
Benefits paid
s 895,060 $
33,742
38,957
67,758
(36,t73)
835,523 $
32,019
37,813
22,640
8l
(33,016)
99,570 $
759
4,315
10,635
(4,976)
95,389
1,228
4,275
2,933
t20
(4,375)
Projected benefit obligation at December 3l 999,344 895,060 110,303 99,570
Change in plan assets:
Fair value at January I
Actual return on plan assets
Employer contributions
Benefits paid
607,568
86,288
40,000
(36,173)
559,616
40,968
40,000
(33,016)
Fair value at December 3l 697,683 607,568
Funded status at end ofyear s (301,661) $ (287,492) $ (1r0,303) $ (99,570)
Amounts recognized in the statement of financial position
consist of:
Other current liabilities
Noncurrent liabilities - $ - $ (5,olo)$
(301,661) (287,492) (105,293)
$(4,733)
(94,837)
Net amount recognized $ (301,661) $ (287,492) $ (il0,303) $ (99,570)
Amounts recognized in accumulated other comprehensive
income consist of:
Net loss
Prior service cost
$ 277,0s2 S
68
263,634 g
96
41,333 $
498
33,660
625
Subtotal 277,120 263,730 4 r,831 34,285
Less amount recorded as regulatory asset (277,120) (263,730)
Net amount recognized in accumulated other comprehensive income $s $ 4r,83r S 34,285
Accumulated benefit obligation $ 850,763 S 766,367 S 100,222 $ 91,146
As a non-qualified plan, the SMSP has no plan assets. However, Idaho Power has a Rabbi trust designated to provide funding for
SMSP obligations. The Rabbi trust holds investments in marketable securities and corporate-owned life insurance. The recorded value
of these investments was approximately $85.7 million and $77.8 million at December 31,2017 and2016, respectively, and is
reflected in Investments and in Company-owned life insurance on the consolidated balance sheets.
FERC FORM NO. 1 (ED. 12{8)Page 123.29
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0r'.t18t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table shows the components ofnet periodic benefit cost for these plans (in thousands ofdollars). For purposes of
calculating the expected return on plan assets, the market-related value ofassets is equal to the fair value ofthe assets.
Pensior Plen S}'tSP
Sen ice cost
lnterest cost
Expected returir or ass€ts
Aoortizatoa of uet loss
Aaortizatioa of prio,r sefl.ice cost
2017 l0t6 l0r7 2016
$ 33,742 $ 3?,019 E 759 $ 1,228
38.957 3?.813 4,315 4,t75
(4J,r38) ({2,08r)
13.190 13.33t 2,963 3,i32
t8 i9 127 168
Net periodic pension coEt
Regulatorl'deferral of te{ periodic beaefit co#ll
.10,?79
(38,6ee)
l ?,1 54
41,141
(3e,335)
I i,15,{
8,164 9,203
Preriously deferred pension cost recoqnized{I)
Net pef,iodic beoefrt cost recoeaized for fira4ci4 [elqtincll]$--!g.rit- !--$.ef!- !_l,'g $-u!i
(l) Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization ofeach regularoryiunsdiction in which Idaho
Power operates. Under IPUC order, the Idaho portion ofnet periodic benefit cost is recorded as a regulatory asset and is recognized in the income statement as those
costs are recovered through rates.
The following table shows the components of other comprehensive income for the plans (in thousands of dollars):
PeuionPlan SMSP
Actuarisl (locs) .eaia durinE the vear
Plan amrndmeat sen'ice cost
Reclassigcatio! adjustmerts for:
A-nrortizatim of net loss
Aarortization of prior set-,(,ice cost
Adjusbreat for deferred tar effects
Adjustmetr due to tle eff,ects ofregulation
201? 1016
$ (?6,608) $ (23.?i3)
(81)
!017 t0t6
$ (10,635) $ (2,e33)
(1r0)
13.190
l8
l.l4,t
I I,646
13,33 I
59
.1.083
6-361
2.963
ll7
I,J i5
3,532
168
(253)
Other comp'rehensir-e iscome recogrized related
to oerrgiotr be!-efit p1afls $I 1--g4o)$39.1
In 201 8, Idaho Power expects to recognize as components of net periodic benefit cost $ I 7.5 million from amortizing amounts
recorded in accumulated other comprehensive income (or as a regulatory asset for the pension plan) as of December 3l , 2017 , relating
to the pension plan and SMSP. This amount consists of $13.6 million of amortization of net loss for the pension plan and $3.8 million
of amortization of net loss and $0.1 million of amortization of prior service cost forthe SMSP.
FERC FORM NO. 1 1 123.30
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t18t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table summarizes the expected future benefit payments of these plans (in thousands of dollars)
20r8 2019 2020 2021 2022 2023-2027
Pension Plan
SMSP
$ 3s,312 $
5,1 00
37,490 $
5,r6r
39,983 $
5,538
42,438 $
5,707
44,797 $
5,880
2s7,290
30,962
As of December 3l,2017,Idaho Power's minimum required contributions to the pension plan are estimated to be zero in 2018.
Depending on market conditions and cash flow considerations in 2018, Idaho Power could contribute up to $40 million to the pension
plan during 2018 in order to help balance the regulatory collection of these expenditures with the amount and timing of contributions
and to mitigate the cost of being in an underfunded position.
Postretirement Benefits
Idaho Power maintains a defined benefit postretirement benefit plan (consisting ofhealth care and death benefits) that covers all
employees who were enrolled in the active-employee group plan at the time of retirement as well as their spouses and qualiffing
dependents. Retirees hired on or after January l,1999, have access to the standard medical option at full cost, with no contribution by
Idaho Power. Benefits for employees who retire after December 31,2002, are limited to a fixed amount, which has limited the growth
of Idaho Power's future obligations under this plan.
The following table summarizes the changes in benefit obligation and plan assets (in thousands of dollars)
2017 2016
Change in accumulated benefit obligation:
Benefit obligation at January I
Service cost
Interest cost
Actuarial loss
Benefits paid(l)
Plan amendments
$63,876 $
973
2,783
5,769
(3,s62)
212
62,393
l,l l6
2,766
1,550
(3,949)
Benefit obligation at December 3l 70,051 63,876
Change in plan assets:
Fairvalue ofplan assets at January I
Actual retum on plan assets
Employer contributions( I )
Benefits paia(l)
34,999
5,112
1,745
(3,s62)
35,566
) a)\
957
(3,949)
Fair value of plan assets at December 3 I 38,294 34,999
Funded status at end ofyear (included in noncurrent liabilities)$ (31,757) $ (28,877)
(l) Contributions and benefits paid are each net of$3.4 million and $3.7 million ofplan participant contributions for 2017 and 2016, respectively.
FERC FORM NO.1 (ED. 12ASl Page 123.31
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411812018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Amounts recogrized in accumulated other comprehensive income consist of the following (in thousands of dollars):
2017 2016
Net gain
Prior service cost
s 2,777 $
269
(55)
r04
Subtotal
Less amount recognized in regulatory assets
3,046
(3,046)
49
(4e)
Net amount recognized in accumulated other comprehensive income $$
The net periodic postretirement benefit cost was as follows (in thousands of dollars):
2017
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
$973 $
2,783
(2,307)
47
l,l l6
zfl66
(2,474)
26
Net periodic postretirement benefit cost s 1,496 $ r,434
The following table shows the components of other comprehensive income for the plan (in thousands of dollars):
2017 2016
Actuarial (loss) gain during the year
Prior service cost arising during the year
Reclassification adjustments for amortization of prior service cost
Adjustment for deferred tax effects
Adjustment due to the effects of regulation
$(2,964) $
(2r2)
47
807
2,322
(1,600)
26
615
959
Other comprehensive income related to postretirement benefit plans $$
The following table summarizes the expected future benefit payments of the postretirement benefit plan (in thousands of dollars):
1 ,o,s-E, @l ,r, | ,r.| ,orrrurl
Expected benefit payments $ s,051 $ 4,667 $ 4,374 S 4,080 S 4,070 S 19,910
FERC FORM NO. 1 (ED. 12-88)Page 123.32
2016
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
ut18t2018
Year/Period of Report
2U7tA4
NOTES TO FINANCIAL STATEMENTS (Continued)
Plan Assumptions
The following table sets forth the weighted-average assumptions used at the end of each year to determine benefit obligations for all
Idaho Power-sponsored pension and postretirement benefits plans:
Pension Plan SMSP
Postretirement
Benefits
2017 2016 2017 2016 2017 2016
Discount rate
Rate of compensation increase( I )
Medical trend rate
Dental trend rate
Measurement date
3.95o/o
4-17 o/o
4.45o/o
4.llVo
3.95o/o
4.75Yo
4.45o/o
4.75o/o
3.95o/o 4.45o/o
6.8o/o
4.lo/o
t2/3t/2017
8.3o/o
5.0o/o
t2l3t/2016t2/3U2017 t2l3v20t6 t2/31120t7 t2/31/2016
( I ) fne ZO I Z rate of compensation increase assumption for the pension plan includes an inflation comFnnent of 2.50% plus a I .67% composite merit increase component
that is based on employeeJ years ofservice. Merit salary increases are assumed to be 8.0% for employees in their first year ofservice and scale down to 0% for
employees in their fortieth year ofservice and beyond.
The following table sets forth the weighted-average assumptions used to determine net periodic benefit cost for all Idaho
Power-sponsored pension and postretirement benefit plans:
Pension Plan SMSP
Postretirement
Benelits
2017 2016 2017 2016 2017 2016
Discount rate
Expected long-term rate ofretum on
assets
Rate of compensation increase
Medical trend rate
Dental trend rate
4.45o/o 4.600/o 4.45% 4.600/o 4.45o/o 4.600/o
7.50o/o
4.l7Yo
7.50o/o
4.llo/o
6.75o/o
6.8%
4.0%
7.25o/o
-%
8.30o/o
5.00%
4.75o/o 4.50o/o
The assumed health care cost trend rate used to measure the expected cost ofhealth benefits covered by the postretirement plan was
6.8 percent in2017 and is assumed to decrease to 6.4 percent in 2018, 5.9 percent in2019,5.4 percent in2020 and to gradually
decreaseto4.l percentby20T4.Theassumeddentalcosttrendrateusedtomeasuretheexpectedcostofdentalbenefitscoveredby
the plan was 4.0 percent, or equal to the medical trend rate iflower, for all years. A one percentage point change in the assumed
health care cost trend rate would have the following effects at December 31,2017 (in thousands of dollars):
One-Percentage-Point
Increase Decrease
Effect on total ofcost components
Effect on accumulated postretirement benefit obligation
$301 $
3,166
(223)
(2,459)
FERC FORM NO.1 D.1 123.33
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
Mt1812018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Plan Assets
Pension Asset Allocation Policy: The target allocation and actual allocations at December 31,2017, for the pension asset portfolio by
asset class is set forth below:
.{.rset Clr3r
Ierget
Allocatfoin
Actual
Allocrtion
December 31,
7fi11
Debt securities
Equin secmities
ReaI estate
olher plan assets
24o/o
i60/o
7%
13o/o
249iI
58s/o
6%
120,6
Assets are rebalanced as necessary to keep the portfolio close to target allocations.
The plan's principal investment objective is to maximize total return (defined as the sum of realized interest and dividend income and
realized and unrealized gain or loss in market price) consistent with prudent parameters of risk and the liability profile of the portfolio.
Emphasis is placed on preservation and growth ofcapital along with adequacy ofcash flow sufficient to fund current and future
payments to pensioners.
The three major goals in Idaho Power's asset allocation process are to:
o determine ifthe investments have the potential to earn the rate ofreturn assumed in the actuarial liability calculations;
o match the cash flow needs ofthe plan. Idaho Power sets bond allocations sufficient to cover at least five years ofbenefit
payments and cash allocations sufficient to cover the current year benefit payments. Idaho Power then utilizes growth
instruments (equities, real estate, venture capital) to fund the longer-term liabilities of the plan; and
e maintain a prudent risk profile consistent with ERISA fiduciary standards.
Allowable plan investments include stocks and stock funds, investment-grade bonds and bond funds, real estate funds, private equity
funds, and cash and cash equivalents. With the exception of real estate holdings and private equity, investments must be readily
marketable so that an entire holding can be disposed of quickly with only a minor effect upon market price.
Rate-of-retum projections for plan assets are based on historical risk/retum relationships among asset classes. The primary measure is
the historical risk premium each asset class has delivered versus the yield on the Moody's AA Corporate Bond Index. This historical
risk premium is then added to the current yield on the Moody's AA Corporate Bond Index. Additional analysis is performed to
measure the expected range of retums, as well as worst-case and best-case scenarios. Based on the current low interest rate
environment, current rate-of-retum expectations are lower than the nominal returns generated over the past 20 years when interest
rates were generally much higher.
Idaho Power's asset modeling process also utilizes historical market retums to measure the portfolio's exposure to a "worst-case"
market scenario, to determine how much performance could vary from the expected "average" performance over various time periods.
FERC FORM NO.1 (ED. 12-881 Page'123.34
--------------- --------------l@ir
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1812018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
This "worst-case" modeling, in addition to cash flow matching and diversification by asset class and investment style, provides the
basis for managing the risk associated with investing portfolio assets.
Fair Value of Plan Assets.' Idaho Power classifies its pension plan and postretirement benefit plan investments using the three-level
fair value hierarchy described in Note 15 - "Derivative Financial Instruments." The following table presents the fair value of the plans'
investments by asset category (in thousands ofdollars).
Level I Level 2 Iffi]-ill-rl-rAssets at December 31,2017
Cash and cash equivalents
Short-term bonds
Intermediate bonds
Long-term bonds
Equity Securities: Large-Cap
Equity Securities: Mid-Cap
Equity Securities: Small-Cap
Equity Securities: Micro-Cap
Equity Securities: Intemational
Equity Securities: Emerging Markets
Plan assets measured at NAV (not subject to hierarchy disclosure)
Equity Securities: Intemational
Equity Securities: Emerging Markets
Real estate
Private market investments
Commodities fund
Total
82,923
40,707
95,179
81,127
62,502
32,753
6,774
8,785
81,127
$ 349,146 $ 123,630 $ - $ 697,683
$ 20,852 $
20,475
20,699
s $ 20,8s2
20,475
103,622
40,707
95,179
62,502
32,753
6,774
8,785
83,589
36,2s5
38,435
31,618
35,010
E
-IIIII
Postretirement plan assets( I )$ 567 $ 37,727 $$ 38,294
FERC FORM NO.1 (ED. 12481 Page 123.35
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0/.t18t20't8
Year/Period of Report
2017tO4
NOTES TO FINANCIAL STATEMENTS (Continued)
Assets at December 31,2016
Cash and cash equivalents
Short-term bonds
Intermediate bonds
Long-term bonds
Equity Securities: Large-Cap
Equity Securities: Mid-Cap
Equity Securities: Small-Cap
Equity Securities: Micro-Cap
Equity Securities: Intemational
Equity Securities: Emerging Markets
Plan assets measured at NAV (not subject to hierarchy disclosure)
Equity Securities: International
Equity Securities: Emerging Markets
Real estate
Private market investments
Commodities fund
Levetl Levet2 I "-,.* I ,*"
$ 28,632 $
I 1,198
11,904
s g 28,632
88,734
20,573
80,582
68,634
53,766
29,671
7,782
9,204
3 1,895
I l,l 98
100,638
20,573
80,s82
68,634
53,766
29,671
7,782
9,204
64,930
24,443
41,907
33,713
IIIII
Total s 301,373 $ 109,307 $ - $ 607,568
Postretirement plan assets( I )$ 28 $ 34,971 $$ 34,999
(l ) The postretirement benefits assets are primarily life insurance contracts.
For the year ended December 3l ,2017 and December 31, 2016, there were no material transfers into or out of Levels l, 2, or 3
Fair Value Measurement of Level 2 Plan assets and Plan assets measured at NAV:
Level 2 Bonds: These investments represent U.S. govemment, agency bonds, and corporate bonds. The U.S. govemment and agency
bonds, as well as the corporate bonds, are not traded on an exchange and are valued utilizing market prices for similar assets or
liabilities in active markets.
Level 2 Postretirement Asset: This asset represents an investment in a life insurance contract and is recorded at fair value, which is the
cash surrender value, less any unpaid expenses. The cash surrender value ofthis insurance contract is contractually equal to the
insurance contract's proportionate share ofthe market value ofan associated investment account held by the insurer. The investments
held by the insurer's investment account are all instruments traded on exchanges with readily determinable market prices.
Commineled Funds: These funds, made up of the intemational, emerging markets equity securities, and commodities fund measured
FERC FORM NO. 1 (ED. t2{8)Page 123.36
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
ut18t2018
Year/Period of Report
2017tQ4
NOTES TO FtNANCIAL STATEMENTS (Continued)
at NAV, are not publicly traded, and therefore no publicly quoted market price is readily available. The value of the commingled
funds are presented at estimated fair value, which is determined based on the unit value of the fund. The values of these investments
are calculated by the custodian for the fund company on a monthly or more frequent basis, and are based on market prices of the
assets held by each of the commingled funds divided by the number of fund shares outstanding for the respective fund. The
investments in commingled funds have redemption limitations that permit monthly redemption following notice requirements of 5 to
7 days.
Real Estate: Real estate holdings represent investments in open-ended commingled real estate funds. As the property interests held in
these real estate funds are not frequently traded, establishing the market value ofthe property interests held by the fund, and the
resulting unit value of fund shareholders, is based on unobservable inputs including property appraisals by the fund companies,
property appraisals by independent appraisal firms, analysis ofthe replacement cost ofthe property, discounted cash flows generated
by property rents and changes in property values, and comparisons with sale prices of similar properties in similar markets. These
open-ended real estate funds also fumish annual audited financial statements that are also used to further validate the information
provided. Redemptions are generally available on a quarterly basis, with l0 to 35 days written notice, depending on the individual
fund. If the fund has sufficient liquidity, the redemption will be processed at the fund NAV or the fund's estimate of fair value at the
end of the quarter. If the fund does not have sufficient liquidity to honor the full redemption, the remainder will be set for redemption
the following quarter on a pro-rata basis with other redemption requests. This same process will repeat until the redemption request
has been completed. To protect other fund holders, real estate funds have no duty to liquidate or encumber funds to meet redemption
requests.
Private Market Investments: Private market investments represent two categories: fund of hedge funds and venture capital funds.
These funds are valued by the fund companies based on the estimated fair values of the underlying fund holdings divided by the fund
shares outstanding or multiplied by the ownership percentages of the holder. Some hedge fund strategies utilize securities with readily
available market prices, while others utilize less liquid investment vehicles that are valued based on unobservable inputs including
cost, operating results, recent funding activity, or comparisons with similar investment vehicles. Redemptions are available on a
quarterly basis with 70 days written notice. Redemptions will be processed at the quarterly NAV or fair value within 60 days
following quarter end. In the event of a full redemption, a reserve amount of 5%o to l0% of the redemption amount may be held in
reserve until the audited financial statements of the fund are published. This allows the fund to adjust the redemption so that other
fund holders are not adversely impacted. Venture capital fund investments are valued by the fund companies based on estimated fair
value of the underlying fund holdings divided by the fund shares outstanding. Some venture capital investrnents have progressed to
the point that they have readily available exchange-based market valuations. Early stage venture investments are valued based on
unobservable inputs including cost, operating results, discounted cash flows, the price ofrecent funding events, or pending offers
fiom other viable entities. These private market investments furnish annual audited financial statements that are also used to further
validate the information provided. These funds are formed for a stated life of l0 to l5 years. The general partner can extend the fund
life for 2 or 3 one-year periods. The fund can be futher extended with the approval of the limited partners. There are generally no
redemption rights associated with these funds. The limited partner must hold the fund for the life of the fund or find a third-party
buyer.
Employee Savings PIan
Idaho Power has a defined contribution plan designed to comply with Section 401(k) ofthe Internal Revenue Code and that covers
substantially all employees. Idaho Power matches specified percentages of employee contributions to the plan. Matching annual
contributions were approximately $7.4 million, $7.5 million, and $6.9 million in2017,2016, and 2015, respectively.
FERC FORM NO.1 (ED.12€8)Page 123.37
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t18t2018
Year/Period of Report
20'17tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Post-employment Benefits
Idaho Power provides certain benefits to former or inactive employees, their beneficiaries, and covered dependents after employment
but before retirement, in addition to the health care benefits required under the Consolidated Omnibus Budget Reconciliation Act.
These benefits include salary continuation, health care and life insurance for those employees found to be disabled under Idaho
Power's disability plans, and health care for surviving spouses and dependents. Idaho Power accrues a liability for such benefits. The
post employment benefits included in other deferred credits on ldaho Power's consolidated balance sheets at December 31,2017 and
2016, were approximately $2 million.
I1. PROPERTY, PLANT AND EQUIPMENT AND JOINTLY.OWNED PROJECTS
The following table presents the major classifications ofldaho Power's utility plant in service, annual depreciation provisions as a
percent of average depreciable balance, and accumulated provision for depreciation for the years ended December 31, 2017 and 20 I 6
(in thousands of dollars):
2017 2016
Balance Avg Rate Balance Avg Rate
Production
Transmission
Distribution
General and Other
s 2,598,940
1,163,240
1,710,126
433,856
3.07o/o $
1.94%
2.44o/o
6.01o/o
2,551,823
1,120,903
1,637,131
422,187
2.40Yo
2.02o/o
2.72o/o
5.49o/o
Total in service
Accumulated provision for depreciation
2.64%
In service - net $ 3,807,888 s 3,743,567
At December 3l,2017,ldaho Power's construction work in progress balance of $452.4 million included relicensing costs of $268.7
million for the HCC, Idaho Power's largest hydroelectric complex. ln 2017 ,201 6, and 201 5, the IPUC authorized Idaho Power to
include in its Idaho jurisdiction rates $6.5 million annually ($ 10.7 million when grossed-up for the effect of income taxes) of AFUDC
relating to the HCC relicensing project. Collecting these amounts will reduce the amount collected in the future once the HCC
relicensing costs are approved for recovery in base rates. At December 3l , 2017 ,ldaho Power's accumulated provision for rate
refunds for collection of AFUDC relating to the HCC was $l 19.7 million.
Idaho Power's ownership interest in threejointly-owned generating facilities is included in the table above. Under thejoint operating
agreements for these facilities, each participating utility is responsible for financing its share ofconstruction, operating, and leasing
costs. Idaho Powefs proportionate share ofoperating expenses for each facility is included in the Consolidated Statements oflncome.
FERC FORM NO.1 1 't23.38
5,906,162
(2,098,274)
2.87o/o 5,732,044
(1,988,477)
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
ut1812018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
These jointly-owned facilities, including balance sheet amounts and the extent of Idaho Power's participation, were as follows at
December 31,2017 (in thousands of dollars):
Name of Plart Location
Ltilit"t
PLant in
Sen-ice
Conrtruction
lf,ork in
Progrerr
Accumulated
Prorisionfsr OrrneruhipDepreciation q6 ME:Oi
Jim Bridger Urits 1-{
Boardman
Valm]'Uaits I asdl
Rock Springs, ltrY $ ?2?.440
Boardman, OR 83,193
lfrimeoucca. Nl' ,!09,836
$JJ
l0
50
6,935 $
55
r59
316,092
11,150
235,6?0
7?l
64
28,1
(l) Iaano Power's share ofnameplate capacity.
IERCo, Idaho Power's wholly-owned subsidiary, is a joint venturer in BCC. Idaho Power's coal purchases from the joint venture
were $86.4 million in2017 and $92.9 million in 2016.
Idaho Power has contracts to purchase the enerry from four PLIRPA qualified facilities that are 50 percent owned by lda-West. Idaho
Power's power purchases from these facilities were $9.8 million in2017 and $7.8 million in2016.
12. ASSET RETIREMENT OBLIGATIONS (ARO)
The guidance relating to accounting for AROs requires that legal obligations associated with the retirement of property, plant, and
equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can
be made. Under the guidance, when a liability is initially recorded, the entity inoeases the carrying amount ofthe related long-lived
asset to reflect the future retirement cost. Over time, the liability is accreted to its estimated settlement value and paid, and the
capitalized cost is depreciated over the useful life ofthe related asset. If, at the end ofthe asset's life, the recorded liability differs
from the actual obligations paid, a gain or loss would be recognized. As a rate-regulated entity, Idaho Power records regulatory assets
or liabilities instead ofaccretion, depreciation, and gains or losses, as approved by the IPUC. The regulatory assets recorded under
this order do not eam a retum on investment. Beginning June l, 2012, acuetion, depreciation, and gains or losses related to the
Boardman generating facility have been exempted from such regulatory treatment as Idaho Power is now collecting amounts related to
the decommissioning of Boardman in rates.
Idaho Power's recorded AROs relate to the removal of polychlorinated biphenyl-contaminated equipment at its distribution facilities
and the reclamation and removal costs at its jointly-owned coal-fired generation facilities.
Idaho Power also has additional AROs associated with its transmission system, hydroelectric facilities, natural gas-fired generation
facilities, and jointly owned coal-fired generation facilities; however, due to the indeterminate removal date, the fair value of the
associated liabilities currently cannot be estimated and no amounts are recognized in the consolidated financial statements.
The regulated operations ofldaho Power also collect removal costs in rates for ceftain assets that do not have associated AROs. Idaho
Power is required to redesignate these removal costs as regulatory liabilities. See Note 3 - "Regulatory Matters" for the removal costs
recorded as regulatory liabilities on Idaho Power's consolidated balance sheets as ofDecember 31,2017 and 2016.
The following table presents the changes in the carrying amount of AROs (in thousands of dollars):
FERC FORM NO.1 (ED.12{8)Page'123.39
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
ut18t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
2017 2016
Balance at beginning ofyear
Accretion expense
Revisions in estimated cash flows
Liability settled
s 26,257 s
l,0l 5
(7et)
(66)
26,153
1,031
1,759
(2,686)
Balance at end ofyear $26,415 S 26,2s7
13.INVESTMENTS
The table below summarizes Idaho Power's investments as of December 3l (in thousands of dollars):
2017
Idaho Power investments:
IERCO
Exchange traded short-term bond funds and cash equivalents
Executive deferred compensation plan investments
$72,213 S
30,249
t7
77,131
23,908
lll
Total Idaho Power investments 102,479 l0t,l50
Investments in securities classified as available-for-sale securities are reported at fair value. Any unrealized gains or losses on
available-for-sale securities are included in income, as the fair value option has been elected for these instruments. Unrealized gains
and losses on available-for-sale securities were immaterial at December 31,2017 and December 31,2016. The following table
summarizes sales of available-for-sale securities (in thousands of dollars):
2017 2016 2015
Proceeds from sales
Gross realized gains from sales
34,243
14. DERIVATIVE FINANCIAL INSTRUMENTS
Commodity Price Risk
Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily
influenced by supply and demand. Market risk may be influenced by market participants' nonperformance of their contractual
obligations and commitments, which affects the supply of or demand for the commodity. Idaho Power uses derivative instruments,
such as physical and financial forward contracts, for both electricity and fuel to manage the risks relating to these commodity price
exposures. The primary objectives of ldaho Power's energy purchase and sale activity are to meet the demand of retail electric
customers, maintain appropriate physical reseryes to ensure reliability, and make economic use of temporary surpluses that may
develop.
FERC FORM NO.1 (ED. 12ASl Page 123.40
$4,989 $r 5,693 $
54
2016
Investments in Equity Securities
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
04t18t20',t8
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and
sales, though none ofthese instruments have been designated as cash flow hedges. Idaho Power offsets fair value amounts recognized
on its balance sheet and applies collateral related to derivative instruments executed with the same counterparty under the same master
netting agreement. Idaho Power does not offset a counterparty's current derivative contracts with the counter?arty's long-term
derivative contracts, although Idaho Power's master netting arrangements would allow current and long-term positions to be offset in
the event of default. Also, in the event of default, Idaho Power's master netting arrangements would allow for the offsetting of all
transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments,
derivatives qualif,ing for scope exceptions, receivables and payables arising from settled positions, and other forms ofnon-cash
collateral (such as letters ofcredit). These types oftransactions are excluded from the offsetting presented in the derivative fair value
and offsetting table below.
The table below presents the gains and losses on derivatives not designated as hedging instruments for the years ended December 31,
2017 and 2016 (in thousands ofdollars):
Location of Realized Gain(Loss) on
Derivatives Recognized in Income
Gain(Loss) on Derivatives Recognized in Income(l)
2017 20t6
Financial swaps
Financial swaps
Financial swaps
Financial swaps
Forward contracts
Forward contracts
Forward contracts
Off-system sales
Purchased power
Fuel expense
Other operations and maintenance
Off-system sales
Purchased power
Fuel expense
$902 $
166
701
(84)
55
(6e)
4
1,405
586
(1,947)
(l6r)
(s4)
86
t39
(l) Excludes unrealized gains or losses on derivatives, which are recorded on the balance sheel as regulatory assets or regulatory liabilities.
Settlement gains and losses on electricity swap contracts are recorded on the income statement in off-system sales or purchased power
depending on the forecasted position being economically hedged by the derivative contract. Settlement gains and losses on contracts
for natural gas are reflected in fuel expense. Settlement gains and losses on diesel derivatives are recorded in other operations and
maintenance expense. See Note l5 - "Fair Value Measurements" for additional information conceming the determination of fair value
for Idaho Power's assets and liabilities from price risk management activities.
Derivative Instrument Summara
The table below presents the fair values and locations of derivative instruments not desigaated as hedging instruments recorded on the
balance sheets and reconciles the gross amounts ofderivatives recognized as assets and as liabilities to the net amounts presented in
the balance sheets at December3l, 2017 and 2016 (in thousands ofdollars):
FERC FORM NO.1 D.{'t23.41
Name of Respondent
ldaho Power Company
This Report is:
(1)XAn Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)
ut18t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Arset I)erh"ltives Liabilitv Derireth'er
Belaace Sheet Location
GrosrIrir
Velne
Anounts
Of&€t
Net
Asrets
Grolr
Feir
$rlue
A.uoolts
Of&€t
5rt
Liabilities
December 31, 201?
Curreat:
Financial srn'aps
Financial srn'aps
Forq'ard coabacts
Loug-tera:
Financial sr*'aps
Other currat ass€ts
Other currerrt liabilities
Other curreat liabilities
Other assets
$l8$
5r3
$ 18$$
l-971
2
,f
5
(553)(74S) (r)t,2t3
I
I
l__lE_Total
Deceaber 31, 2016
Currmt:
Financial sn'aps Otier crrrent assets
$____rE s____or} g____ir_$__L9t3_ l___rtl!)
Total
$ 8,134 $ (2,183)g)$ 5,951 $ 30?$ (301) $ -l___ji!'\ !_l---!J:l- L-elE) I-L9:l- l---:qi
(l) Cunent liability derivative amounts offset include $0.2 million ofcollateral receivable for the period ending December 31,2017.
(2) Cunent asset derivative amounts offset include $1.9 million ofcollateral payable for the period ending December 3 l, 2016.
The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at December 3l , 2017 and
2016 (in thousands ofunits):
December 31,
Commodity Units 2017 2016
Electricity purchases
Electricity sales
Natural gas purchases
Natural gas sales
Diesel purchases
MWh
MWh
MMBtu
MMBtu
Gallons
312
224
7,028
140
217
135
6,604
70
l,l 88
FERC FORM NO. 1 1 123.42
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04h8n018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Credit Risk
At December 31, 2017 ,ldaho Power did not have material credit risk exposure from financial instruments, including derivatives.
Idaho Power monitors credit risk exposure through reviews of countelparty credit quality, corporate-wide counterparty credit
exposure, and corporate-wide counterparty concentration levels. Idaho Power manages these risks by establishing credit and
concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters ofcredit from
counterparties or their affiliates, as deemed necessary. Idaho Power's physical power contracts are commonly under Western Systems
Power Pool agreements, physical gas contracts are usually underNorth American Energy Standards Board contracts, and financial
transactions are usually under International Swaps and Derivatives Association, Inc. contracts. These contracts contain adequate
assurance clauses requiring collateralization ifa counterparty has debt that is downgraded below investment grade by at least one
rating agency.
Credit-Contingent Features
Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an
investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services. If ldaho Powe/s unsecured
debt were to fall below investment grade, it would be in violation ofthese provisions, and the counterparties to the derivative
instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative
instruments in net liability positions. The aggregate fair value of all derivative instruments with credit-risk-related contingent features
that were in a liability position at December 31,2017, was $2.0 million. Idaho Power posted $0.9 million cash collateral related to
this amount. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 201 7, Idaho
Power would have been required to pay or post collateral to its counterparties up to an additional $4.5 million to cover open liability
positions as well as completed transactions that have not yet been paid.
15. FAIR VALUE MEASUREMENTS
Idaho Power has categorized its financial instruments into a three-level fair value hierarchy, based on the priority ofthe inputs to the
valuation technique. The fairvalue hierarchy gives the highest priority to quoted prices in active markets for identical assets or
liabilities (Level l) and the lowest priority to unobservable inputs (Level 3). If the inputs used to measure the financial instruments
fall within different levels ofthe hierarchy, the categorization is based on the lowest level input that is significant to the fair value
measurement of the instrument.
Financial assets and liabilities recorded on the consolidated balance sheets are categorized based on the inputs to the valuation
techniques as follows:
Level l: Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities
in an active market that ldaho Power has the ability to access.
Level 2: Financial assets and liabilities whose values are based on the following:
a) quoted prices for similar assets or liabilities in active markets;
b) quoted prices for identical or similar assets or liabilities in non-active markets;
c) pricing models whose inputs are observable for substantially the full term ofthe asset or liability; and
d) pricing models whose inputs are derived principally from or corroborated by observable market data through
FERC FORM NO. 1 (ED. 12-881 Page 123.43
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
04t18t2018
Year/Period of Report
20't7tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
correlation or other means for substantially the full term of the asset or liability
Idaho Power Level2 inputs are based on quoted market prices adjusted for location using corroborated, observable market
data.
Level 3: Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are
both unobservable and sigrificant to the overall fair value measurement. These inputs reflect management's own assumptions
about the assumptions a market participant would use in pricing the asset or liability.
Idaho Power's assessment of a particular input's significance 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. An item recorded at fair value is
reclassified among levels when changes in the nature of valuation inputs cause the item to no longer meet the criteria for the level in
which it was previously categorized. There were no transfers between levels or material changes in valuation techniques or inputs
during the years ended December 31,2017 and20l6.
The following table presents information about ldaho Power's assets and liabilities measured at fair value on a recurring basis as of
December 31,2017 and2016 (in thousands of dollars):
December 31, 2017 December 31, 2016
Level I Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets:
Money market funds
Derivatives
Trading securities: Equity securities
Available-for-sale securities: Equity securities
Liebilities:
Derivatives
$10,260
22
t7
30,249
s 1,223 $ 2 $$ 1,22s $$$
$-$-$-$10,260
22
17
30,249
s29,967
5,951
llt
23,908
$-s29,967
5,951
lll
23,908
$
Idaho Power's derivatives are contracts entered into as part ofits management ofloads and resources. Electricity derivatives are
valued on the Intercontinental Exchange (lCE) with quoted prices in an active market. Natural gas and diesel derivative valuations are
performed using New York Mercantile Exchange (NYMEX) and ICE pricing, adjusted for location basis, which are also quoted under
NYMEX and ICE pricing. Trading securities consist of employee-directed investments held in a Rabbi trust and are related to an
executive deferred compensation plan. Available-for-sale securities are related to the SMSP, are held in a Rabbi trust, and are actively
traded money market and exchange-traded funds with quoted prices in active markets.
FERC FORM NO. 1 (ED.12-88)Page 123.44
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)
04t1812018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of
December 31,2017 and 2016, using available market information and appropriate valuation methodologies (in thousands of dollars):
December 31,2017 December 31, 2016
Carrying
Amount
Estimated Fair
Value
Carrying
Amount
Estimated Fair
Value
(thousands of dollars)
Liabilities:
Long-term deb(l)s 1,746,123 $ 1,915,459 $ 1,745,678 $ 1,858,666
(l) Long+erm debt are categorized as Level 3 and Level 2, respectively, ofthe fair value hierarchy, as defined earlier in this Note l5 - "Fair Value Measurements."
Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. Carrying values for
cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes
accrued approximate fair value.
16. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
Comprehensive income includes net income and amounts related to the SMSP. The table below presents changes in components of
accumulated other comprehensive income (AOCI), net of tax, during the years ended December 31,2017,2016, and 2015 (in
thousands of dollars). Items in parentheses indicate reductions to AOCI.
Year Ended December 31,
2017 2016
Defined benefit pension items
Balance at beginning ofperiod $ (20,882) $ (21,276)
Other comprehensive income before reclassifications
Amounts reclassified out of AOCI to net income
(7,872)
1,882
( I ,859)
2,253
Net current-period other comprehensive income
Balance at end ofperiod
(5,eeO)394
$ (26,872) $ (20,882)
FERC FORM NO. { (ED. 12-881 Page 123.45
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0/.t't8t2018
Year/Period of Report
2017tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The table below presents the eflects on net income of amounts reclassified out of components of AOCI and the income statement
location of those amounts reclassified during the years ended December 31,2017 and 2016 (in thousands of dollars). Items in
parentheses indicate increases to net income.
Amount Reclassified from AOCI
Year Ended December 31,
2017 2016
Amortization of defined benefit pension items(l)
Prior service cost
Net loss
s 127 $
2,963
168
3,532
Total before tax
Tax benefit(2)
3,090
( 1,208)
3,700
(1,447)
Net of tax 1,882 ) )\1
Total reclassification for the period $ 1,882 $ 2,253
( I ) Amortization ofthese items is included in Idaho Power's consolidated income statements in other expense, net.
(2) The tax benefit is included in income tax expense in the consolidated income statements ofldaho Power.
17. RELATED PARTY TRANSACTIONS
IDACORP: Idaho Power performs corporate functions such as financial, legal, and management services for IDACORP and its
subsidiaries. Idaho Power charges IDACORP for the costs ofthese services based on service agreements and other specifically
identified costs. For these services, Idaho Power billed IDACORP $0.7 million in2017 and $0.8 million in2016.
At December 31, 2017 and 201 6, Idaho Power had a $57.3 million and $0.9 million payable to IDACORP, respectively, which was
included in its accounts payable to affiliates balance on its consolidated balance sheets.
Ida-West: Idaho Power purchases all of the power generated by four of lda-West's hydroelectric projects located in ldaho. Idaho
Power paid lda-West $9.8 million in2017 and $7.8 in 2016.
FERC FORM NO.1 (ED.12{8)Page 123.46
Name or Respono€ot
ldaho Power Company (2)Resubmission
DAla OI HEDON(Mo, Da, Yi)
04118,2018
Yearl,enoo or Repon
Endof 20171Q1-
SUMMARY OF UTILITY PI.AT.IT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) he amount br electic function, in mlumn (d) the amount for gas function, in column (e), (f), and (g) report oher (specit) and in
column (h) q)mmon function.
Line
No.
Clsssificatlon
(a)
Total Company br tle
Cunent Year/Quarter Ended
(b)
Electric
(c)
1 Utility Plant
2 ln SeMce
3 Plant in Service (Oassified)5,905,411,061 5,905,41't,061
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construcdon not Claesifled
7 Experimental Plant Undassified
8 Total (3 thru 7)5,905,411,061 5,905,41 1,061
I Leased to Others
10 Held for Futlre Use 8,074,933 8,074,933
1'.!Construction Work in Progress 452,424,340 452,424.340
12 Acquislton Mjustn€ntB 750,893 750,893
13 Total Utility Plant (8 thru 12)6,366.661,227 6,366,661,227
14 Acom Provfor Depr, Amort, & Depl 2,283,266,5$2,283,266,546
't5 Net Utility Plant ('l3less'14)4,083.394.681 4,083,394,681
16 Detail of Accum Prov br Depr, Amort & Depl
't7 ln Service:
18 D6preciation 2,256,354,154 2,256,354,154
19 Arnort & Depl of Producing Nat Cras Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility Plant 26,879,853 26,879,853
22 Total ln Service (18 thru 21)2,283,2U.007 2,283,2U,O07
23 Leased to Oherc
24 Depreciaffon
25 Amortization and Dopletion
26 Total Leased b Others (24 &251
27 Held for Future Use
28 Depreciation
29 Amorlization
30 Total Held tor Futuro Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj 32,53S 32,539
33 Total Accum Prov (equals 1 4) (22,26,30,31,32)2,283,266,546 2,283,266,546
FERC FORITI NO. I (ED. 12-89)Page 200
Name of Respondent
ldaho PowerCompany
This(1)
(2)
ls:
Original
A Resubmission
Date of Reoort(Mo, Da, Yi)Year/Period of Report
End of 20171Q4
04t18t2018
1. Repod below tre original cost of electrlc plant in seruice acording b he prescdbed ac@unts.
2. ln addition to Acaount 101, Elecffic Plant in Service (Clas.sifed), this page and the next include Account 102, Eleciric Plant Purcfiased or Sold;
Account 103, Experimental Electic Plant Unclassiffed; and Account 106, Completed Constuction Not Classiffed-Electric.
3. lnclude in column (c) or (d), a9 approp.iale, oorec,tions of additions and reliremenE for he cunent or procedlng year.
4. For revisions to the amount of initial ass6t r€drement costs capitalized, included by primary plant account, incroeses in column (c) additons and
rcductions in column (e) adjustmonts.
5. Enclose in parenheses credit adjustments of plant accounb to indicato the negative effec't of such accounb.
6. Classifu Account 106 according to presoibed accountE, on an estimat€d basis if necessary, and indude lho entrios in column (c), Also to be included
in column (c) are entrles for reversals of tentative disbibutions of prior year reported in column (b). Ukarise, if [re respondent has a significant amount
of plant retirements which have not been classified b prlmary accounts at the €nd of the year, include in column (d) a tefltative distribution of sudr
retirements, on an Gtimated basis, with apFopriate contra enfy b he account fur accumulated depreciaUon provision. lndude also in column (d)
Addltons
(c)
Line
No.
Ac@unt
(a)
tsalanoeBoginning of Y€ar
(b)
1 l.INTANGIBLE PI.ANT
2 (301) Orqanization 5.703
3 (302) Franchises and Consents 30,032,675 697,008
4 (303) Miscellaneous lntanaibl€ Plant 22,702,225 7,554,831
5 TOTAL lntanoible Plant {Enter Tohl of lines 2, 3. and 4)52,740,603 8,251,839
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Ricfitg 't,722,421
I 151,560.962 3.140,755(311) Structures and lmprovements
10 (312) Boiler Plant EouiDment 758,144,425 5,849,270
11 (313) Enqines and Enoine.Driven Generators
12 (314) Turbooenerator Unib 165,721.66S 5,012,328
13 (31 5) Accessorv Elec{ric Equipment 72,133,547 r,898,503
14 (316) Misc. Power Plant Equipment 17,503,532 3,927,182
't5 (317) Asset Retirement Costs br Steam Production 15,31 1 ,883 421,992
't6 TOTAL Steam Productlon Plant (Enter Total of lines 8 thru 15)1,182,098.439 19,406,046
'17 B. Nudear Production Plant
18 (320) Land and Land Ridrts
19 (321) Struchrres and lmprovemenb
20 (322) Reactor Plant Equipment
21 (323) Turbooenorator Unit3
22 (324) Accessorv Electric Equipment
23 (325) Misc. Power Plant EquiDment
24 (326) Asset Retirement Costs for Nuclear Produclion
25 TOTAL Nuclear ProducUon Plant (Enter Total of lines 18 thru 24)
26 C. Hvdraulic Produclion Plant
27 (330) Land and Land Riahts 31,,144,838 52,801
28 179,022,986 17,643,830(331) SttucfrJres and lmprovemenb
29 (332) Rssenoirs. Dams, and Waterways 271.762.159 1.936,554
30 241.657.U1 18.996,026(333) water wheels. Turbines, and Generators
31 60,377,085 2,145,40C(334) Accessory Electic Equipment
32 24,514,473 1.521 ,010(335) Misc. Power Plant Equipment
33 (336) Roads. Railroads. and Bridoes 10,842,584 39,099
34 (337) 6s"1 Retirement Costs br Hydraulic Produotion
35 819,621,.165 42,334,720TOTAL Hydraulic Production Plant (Enter Total of lines 27
'dr,ru34136D. Other Produclion Plant
37 (340) Land and Land Riohts 2,690,006
38 (341) Structures and lmorovernenb 143,'167,990 36/.,7U
39 (342) Fuel Hold€rs, Products, and Accossories 't0,452,*7 85,022
40 229,873,752 9,328,517(343) Prime lilovers
41 (344) Generators 66,531,876
42 (345) Accessorv Electric Equioment 91.146.851 331,510
43 6,240.366 148,347(346) Misc. Power Plant Equipment
44 (347) Asset Reurement Costs for Oher Production
45 TOTAL Other Prod. Plant (Enter Total of lin€s 37 thru 44)550,103,388 10,258,180
46 TOTAL Prod. Plant (Enter Total of lines '16, 25, 35, and 45)2,551,823,252 71,998,946
FERC FORr NO. I (REV. 12.05)Pags 2U
Name of Respondent
ldaho Power Company
This(1)
(2)
ls:
Original
Dat€ of Roport(Mo, Da, Yr)
Year/Period of Report
End of 2O17lQ4A Resubmission 04118t2018
distributions of these tentative classlffcations in columns (c) and (d), induding the reversals of he prlor years tonbtive account distributions ol these
amounts. Careful obsenranc€ of the above instuctions and the tdds of Accounts 101 and 106 will avoid serious omissions of the reporbd amount of
respondont's plant actually in service at end of year.
7. Show in column (0 r€classificetions or fansfors within utility plant accounts. lndude also in olumn (f) the additions or reduclions of primary account
classifications arising from disfibution of amounts initially r€cord€d in Account 102, include in column (e) tha amounts with respect to accumulated
provision for depreciation, acquisition adjusttnonts, etc., and show in column (0 onry he of6et to tre debi6 or credits distributed in column (0 to primary
account dassifi cations.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplemenbry statement strowlng
subaccount classification of such plant conforming to he requirement of these pages.
9. For each emount comprising the reported balance and changes in Account 102, state lhe pmperty purchased or sold, name of vendor or purchase,
and date of transaction. lf proposed joumal enfies haw beon filed with the Commission as r€quired by he Unibrm System of Accounb, give also date
Rotir€menb
(d)
Adiusunents
(e)
Transfers
(0
Balanca at
End fl,Year
Llne
f.lo.
1
5,703 2
60,000 30,669,683 3
3,640,095 26.616.961 4
3,700,095 57,292,347 5
6
7
1.722.421 I
237.952 154,463,765 9
6,322,569 757,671,126 10
't1
874,372 169,859,625 12
282,041 73.750.009 13
1,277.900 20,152,814 14
14,889,891 15
6.994.834 1,192,509,651 16
't7
18
19
20
21
22
23
24
25
26
31,497,639 27
424,174 191i,242,il2 28
153.429 273,545,283 29
343.954 260,309,413 30
57.618 62,464,867 31
43,775 25.991.708 32
10.881,683 33
34
1.022.950 860.933,235 35
36
2,690.006 37
200,018 143,332,7fi 38
10,537,569 39
14,664,440 224,537,829 40
66,531,876 41
91,478,361 42
6.388,713 43
44
14,864.458 545,497,1 1 0 45
24,882.242 2.598.939.996 46
FERC FORttl NO. r (REV. 12-05)Page 205
I
Name of R€spondent
ldaho Power Company
This(1)
(2')
ls:
Original
Date of Rooort(Mo, Da, Yi)Year/Pedod o, Report
End of 2O17lQ4A Resubmission 04n&2a18
Lrne
No.
6alanc€Beginning of Year
{b)
Ad6iuons
(c)
Accounl
(a)
47 3. TRANSMISSION PI-ANT
48 (350) Land and t-and Rishts 37.193.222 '! 1 5,120
4S (352) Struc.tures and lmprovements 79,539,883 849,041
50 (353) Station Equipment 411,289.120 20,101,853
51 (354) Towers and Fixtures 198.102.s99 8,760,019
52 (355) Poles and Fixtures 175,172,U3 9,490,063
53 (356) Overhead Conductors and Devices 219,214,808 8,705,363
54 (357) Undorground Conduit
55 (358) Undersround Conductors and Devices
56 (359) Roads and Trails 390,266
57 (359.1) Asset Retrement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)'t,'t20,902,541 48,021,459
59 4. OISTRIBUTION PI.ANT
60 (360) Land and Land Riqhte 5,947,971 104,648
61 (361) Struc{ures and lmprovements 36,984,366 577,575
62 (362) Station Equipment 222,356,864 17,225.163
63 (363) Storaqe Battery Eauipment
il (364) Poles, Towers. and Fixtures 256,158.912 1 1,240,685
65 (365) Overhead Condudors and Devices 131,275,U0 6.400.542
66 (366) Undeorcund Conduit 4S.794.768 1,439,022
67 (367) Underqround Conductors and Devices 243,650,263 16,625,202
68 (368) Line Transbrrners 536,550,475 30,689,434
69 (369) Services 59,471.367 1,720,471
70 (370) Meters 87,259,555 s,341.004
71 (371) lnstallations on Customer Premises 3,016,977 86,705
72 (372) Leased Prooerty on Customer Premises
73 (373) Street Liqhtina and Siqnal Systems 4,500,453 64,475
74 (374) Asset Relirement Costs for Distibution Plant 164,191 -21,561
75 TOTAL Distribution Plant (Enter Total of lines 60 hru 74)1,637,131,522 91,493,365
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380) Land and Land Riohte
78 (381) Structures and lmprovemen$
79 (382) Computer Hardware
80 (383) Computer Sofhrare
81 (384) Comm unication EouiDment
82 (385) Miscellaneous Regional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Regional Transmisslon and Market OperuTOTAL Transmission and Martet Operatlon Plant (Total lines 77 thru 83)
85 6. GENERAL PI.ANT
86 (389) Land and Land Rhhts 17,175,955 285.50S
87 (390) Struclures and lmpmvements 1 18.,149,353 3,055,224
88 (39'l ) Office Furniture and Equipmeflt 49,081,870 4,978,442
89 (392) Transportation Equ ipmont 81,429,700 10,945,622
90 (393) Stores EquiDment 2,619,997 365,494
91 (394) Tools. Shoo and Garaqe Equipment 8.666,166 r,827,995
92 (395) Laboratorv EouiDment 13,022,365 1,179,313
93 (396) Power Operated Equipment 15,085,037 1,248,738
94 (397) Communication Equipment 56,593,212 951,803
95 (398) Miscellaneous Eeuipment 6,571,337 713.1'.tz
96 SUBTOTAL (Enter Total of lines 86 thru 95)368,694.992 25,551,252
97 (399) Other Tansible Property
98 (399.1 ) Asset Relirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96. 97 and 98)368,694.992 25,551,252
100 TOTAL (Accounts 101 and 106)5,731,292,9!i0 245,316,861
101 (102) Electric Plant Purchased (Se6 lnstr. 8)
102 (Less) (102) Electric Plant Sold (Se€ lnslr. 8)
103 (1 03) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 hru 103)5,731,292,950 245,316,861
FERC FORII NO. t (REV.12-05'Page 206
Name of Respondent
ldaho Power Company
Thi$
(1)
(2',,
ls:
Original
Date of Report
(firlo, Da, Yr)
A Resubmission a4na2u8
Year/Period of Repo(
End of 20171Q4
and 1
Transfers
(f)
Ealance at
End 2rfear
Line
No.
Relirements
(d)
Adjustmentg
(e)
47
37.127.446180,896 48
80.263.617 4g125,307
502,441,N4 428,949,66S
246.552.729 51309,889
521,327.O49 't83,335,657
226.621.106 531,299,065
54
55
56390,266
57
585.683,510 1.163,240,490
59
6.052,619 60
6'l98,568 37,'163,373
2,249,918 237,332,109 62
63
642,018,2',t4 265.381,383
1.605,944 136,069,938 65
474,720 50,759,070 66
1.775.711 258,499,754 67
7.206,08'l 560,033,828 68
405,790 60,786,068 69
2.579,391 90,021,168 70
46,326 3,057,356 71
72
38,007 4,526,921 73
74142,630
18.498.670 1.714126.217 75
76
77
78
79
80
81
82
83
84
85
17,461,4U 86
850,457 120,654,124 87
9.147,780 44,912,532 88
88,148,894 894,A26,428
37.U4 2,947,647 90
55,997 '10,438,164 91
13,869,062 92332,616
68,496 16.265,279 93
3.409,266 54,135,749 94
95305,349 6,979,100
18.434.233 375,812,011 96
97
98
9918.434,233 375,812,O11
10071.1 98,750 5,905,41 1.061
101
102
103
10471.'t98,750 5,905,411,061
FERC FORm NO. r (REV.12-05)Page 207
'&
w%
ldaho Power Company (1)
(2)Resubmission
Date of Report
(Mo, Da, Yr)
04118t2018
Year/Period of R€port
End of 2O17lQ4
1. Roport s€paraGly eacfi property held br future use at 6nd of the year having an original oost of $250,000 or moro. Group other items of properly held
forfuture use.
2. For property having an odginal cost of $250,ff)0 or more previously used in utility operalions, now held br futrre u6€, givo in column (a), in addition b
othsr requlred inbmaton, lhe date that uulity use of such propery was discontinu€d, and the date he original co6t wes transfened b Ac@unt 105.
LineNo.
Descdpuon ano Locauonote6geo in in
Ealanoe at
End of Year(d)
1 Land and RighB:
2 Boise Operations Center 12t31t82 2018 763,161
3 Production 109,961
4 Transmission Stations 423,089
5 Transmission Lines 195,489
6 Distribution Stations 1,083,432
7 Beacon Light Subshtlon 12t30102 2024 465,662
I Homedale Substation 2t29t08 2035 109,453
I North River Operations Center 1t31n8 2019 2,630,4',12
10 Line #854 500 Kv 3/31/09 2024 308,066
11 General Plant 62.673
't2
13
14 Column B and C if no date listed it is various
't5
16
17
18
19
20
21 Olhor Prop€rty:
22 Boise Operations Center 71o112016 2018 437,243
23 Transmission Stations 199,069
24 Distribution Stations 69,941
25 Homedale Substation 2t29t08 2035 217,797
26 Beacon Light Substation 1A3UO2 2020 555.340
27 Underground Vault, Blaine County 8/30/16 2020 443,545
28
29
30
31 Column B and C if no date listed it is various
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Total 8,074,933
FERG FORt/i No.1 (ED. 12-96)Pagc 211
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:Date of Reoort(Mo, Oa, Yi)
Year/Period of Report
End of 2O17lQ4An Original
A Resubmission 04t18t2018
1. Report below descripUons and balances at end of year of projecls in process of construclion (107)
2. Show items relating to "researdr, development, and demonstration" projects last, under a caption Research, Development, and Oemonskating (see
Account 1 07 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line
No.
Description of Prolecl
(a)
Construction work in prwress -
Electric (Account 107)(b)
1 104,801,174ROLLUP RELIC COST BROWNLEE
2 71,364,431ROLLUP RELIC COST HELLS CANYON
3 GATEWAY WEST 5OO](/ LINE 35,041,686
4 ROLLUP RELIC COST OXBOW 33,'r96,024
5 HELLS CANYON RELICENSING OUTSI 29,075,023
6 B2H PERMITTING 1111/2011 & FOR 15,604,221
7 BOARDMAN - HEMINGWAY 5OO KVLI 8,635,201
I HCC WATERSHED ENHANCEMENT PROG 6,653,967
I BROWNLEE UNIT 4 TURBINE REFURB 5,851,982
10 BLISS UNIT 3 TURBINE REBURBISH 5,731,782
11 BROWNLEE UNIT 2 TURBINE REFURB 4,783,347
12 LEGAL DEPT. I,ABOR FOR RELICENS 4,68/',762
13 2.WAY RADIO. BVMT - BEAVER MO 4,510,345
14 BAYHA ISI.AND RESEARCH PROJECT 4,2@,758
15 WQ HCO4O.I CERTIFICATION OPS AN 4,022,081
16 EIM INTEGRATION 3,966,194
17 BUILD CADA SUBSTATION 3,806,807
18 UPPER MALAD FISH LAOOER 3,431,906
19 REL.HCC OREGON REAUTHORIZATION 3,381,049
20 NEV\O(I101OO STAR-LNSG NEW 138 K 3,232,240
21 B2H TLINE CONSTRUCTION COSTS 2,916,262
22 2,780,932LNSGOTO3 ADD LINE TERMINALS CO
23 BLISS UNIT 3 GENERATOR REWIND 2,780,593
24 METEOROLOGY MODEL FOR OPERATIO 2.512,135
25 FAREWELL BENO STATE PARK BANK 2,364,097
26 BULL TROUT PROGRAM . AOMINISTR 2,321,667
27 WDRI.KCHM NEW 138KV 2,223,012
28 TOOMHZ SPECTRUM PURCHASE 2,186,989
29 WQ HCC4O1 APPLICATION, REVISIO 2,109,063
30 FALL CHINOOK PROGRAM - REDD SU 2,025,573
31 GRAND VIEW IRRIGATION UPGRADE 1,832,077
32 LTP - HOT GAS PATH INSPECTION 1,830,306
33 HBND-041:ALT LINE ROUTE TO GAR 1,779,510
34 SHOSHONE FALLS UPGRADE - REPLA 1,718,930
35 THOUSAND SPRINGS UNIT 3 ROTOR 1,534,178
36 HCC RELICENSING WATER QUALITY 1,522,985
37 BUILD CADA-o11 1,343,748
38 2aOMHZ SPECTRU M PURCHASE 1,314,934
39 T4O4O1 . RECONSTRUCT/BUILD NEW 1,289,718
40 CHQ REMODEL 1,243,349
4'.!1,217,312HTSU1lOOOI . REPI-ACE MLNR.PAUL
42 1,157,638LANGLEY WATER AND WASTEWATER B
43 TOTAL 452,424,340
FERC FORIU NO. I (ED. l2-E7)Page 216
Name of Respondent
ldaho Power Company (2)Resubmission 04t1812018
I . Report below descriptions and balances at ond of year of projects in process of construction (107)
2. Show items relaffng to 'researdr, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Lane
No.
Description of Projec-t
(a)
Conslrudion wo* in orooress
Eleciric (66e6rr61 1671-
(b)
1 MAINSTEM FLOW AND TEM PERATURE 1,126,513
2 Ofi er Minor Projeds Under'1,000,000 53,2s7,839
3
4
5
6
7
8
9
10
1'.!
12
13
't4
15
16
't7
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43 TOTAL 452,424,340
End of
of Report
2017tQ4
FERC FORM NO. I (ED.12-E7)Page 216.1
Data of Rsoort(Mo, Da, Yi)
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:
Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
Year/Period of Report
End of 20l,7n4
0{,t1u2018
1. Explain in a footnote any important adjustrnents during year.
2. Explain in a footnote any difierence between the arnount for book cost of plant retired, Line 11, column (c), and that rcported fur
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable propefi.
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 ftom service. lf the respondent has a significant amount of plant retircd 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. ln addition, include all costs included in retirernent work in progress at year end in the appropriate functional
dassiflcatlons.
4. Show separately interest credits under a sinklng fund or similar method of depreciation accoundng.
Section A, Balances and Year
No.(a)(c)(e)
1 Balance Beginning of Year 2,150,749,270 2,150,749,270
a DepreciaUon Provisions for Year, Charged to
153,9s8,586 153,958,586(403) Depreciation Expense
4 (403.1) Deprecialion Expense br Aset
Retirement Costs
566,665 566.665
E (413) Exp- of Elec. Plt. Leas. b Others
6 Transportation Expenses-Clearing 4,298,853 4,298,853
7 Oher Clearing Accounts
I Other Accounts (Specify, details in botlote):
s Fu€l Stock 136,110 136,1 10
10 158,960,214 158,960,214TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
11 Net Gharges br Plant Retired:
't2 Book Cost of Plant Retired 67,498,655 67,498,655
13 Cost of Removal 17,94r'.,114 't7,944,114
3,',t13,45214Salvage (Credit)3,1',t3,452
15 TOTAL Net Chrgs. br Plant Ret. (Enter Total
of lines 12 thru 14)
82,329,317 82,329,317
1€Olher Debit or Cr. ltems (Desoibe, details in
bohote):
28,973,987 28,973.087
17
18 Book Cost or Asset Retirement Costs Retired
1g Balance End of Year (Enter Totals of linos 1,
10, 15, 16, and 18)
2,256,354,154 2,256,354,154
Soctlon B. Balances at End of Year According to Functional Clasglflcatlon
20 617,122,624 617,122,624Steam Production
2'.!Nuclear Production
22 Hydraulic Produclion-Conventional 424,8S0,849 424.890.84S
23 Hydraulic Production-Pumped Storage
24 105,656,778 '105,656,778Other Production
25 Transmission 364,308,753 364,308,753
26 Distribution 628,829,047 628,829,047
27 Regional Transrnission and Market Operation
2e 1 15,546,103 1 15,546,103General
29 2,256,354,154 2,zfi,354,154TOTAL (Enter Total of lines 20 thru 28)
FERC FORir NO. I (REV. 12-05)Page 219
Name of Respondent
ldaho Porver Comoany
This Report is:
(1) X An Original(21- A Resubmission
Date of Report
(Mo, Da, Yr)
0411u2018
Year/PerM of Report
20171Q4
FOOTNOTE DATA
Scladula Page:219 Line No.:16 Column: cIncludes: VaImy deprecj-ation adjustments (ID 337
Retirement Obligation activity.7r ind OR 17-235), CieC and
I
NO. 1 450.1|2-A7l
Name of Respondent
ldaho Porer Company
This
(1)
(z',,
ls:
Original
A Resubmission
Data of Report(Mo, Da, Yr)
o411u2018
Year/Perlod of Report
Endof 20171Qd.
1. Report belo,v invesbn€nts in Accounts 123.1, investnents in Subsidiary Companies.
2. Provide a subheading br each company and List therc under the informalion called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(0,(g) and (h)
(a) lnvestmont in Soqrritios - List and describe eacrr security owned. For bonds give also princ{pal amount, date of issue, mah.rity and intor€ot rate.
(b) lnvestment Advanc€s - Roport separately the amounts of loans or inv€stnent advances whicJr are subject to rcpayment, but whictr are not srbjod to
current s€tuement. With respec't to eadr advance show whether the advance is a note or open a@ount. List o6dr noto giving dato of issuance, maturity
date, and speclllng whether note is a renewal.
3. Report separately the equity in undlstibuted subsidiary eamings sinoe acquisiUon. The TOTAL in column (e) should equal the amount entorcd for
Aocount 41 8.1.
Line
No.
Date Acqulred
(b)
Date Of
'w.,
Amount ol lnvestrnent atBesinl[tp of YearDescription or lnvestrnent
(a)
1 ldaho Energy Resources Company
2 C,ommon Stock o2lo1t74
3 Capihl conhlbutions 2,462,554
74,667,8334Equity in eamings
5
o Subtotal ldaho Energy Resources Company 77,130,927
7
8
I
10
11
12
13
14
15
'16
17
'18
19
20
21
22
23
24
25
26
27
28
29
30
3'l
32
33
34
35
36
37
38
39
40
41
[Totral Cosl of Acoount 123.1 $TOTAL 771n,92742
FERC FORM NO.1 (ED. 12-89'Page 224
500
2,463,094|
Name ol Respondent
ldaho Power Company
lhls
(1)
ls:
Original
uato ol K600n(Mo, Da, Yi)YearrPenod ot Kepon
End of 2017n4(2)Resubmission 0411u2018
4. For any securities, notes, or accounb that were pledged designate such securities, not€s, or accounts in a foohote, and state the name of pledgee
and purpose of the pledge.
5. lf Commission approval was required for any advanoe made or security acquired, designate such fact in a foohote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investnents, including such revenues form securiiles disposed of during the year.
7. ln column (h) report for eadr investrnent disposed of during th6 year, he gain or loss represented by the difference between cost of the investrnent (or
the olher amount at whicfi carried in the books of account if difference trom cost) and the selling price hereof, not including interest adjustment includlble
in column (f),
8. Report on Line 42, column (a) the TOTAL cost of Account 123.1
Equity in suosEiary
Eaminlsrof Year
Kevenues lor Year
(0
Amounl ot lnvesunent at
End of Year(s)
(jarn or Loss rom lnvesunent
oisel;go or Line
No.
1
500 2
2,462,594 3
'12,000,000 69,749,884 47,082,05'l
5
7,082,051 12,000,000 72,212,978 6
7
8
9
10
11
12
13
14
'ts
't6
't7
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
4'l
12,000,000 72,212,978 427.082,051
FERC FORM NO. r (ED. 12.09,Page 225
Name ot Respond€nt
ldaho Power Company
lnrs Keoon ls:(1) fiAn Original
{U ffARosubmission
uate ot Hepon(Mo, Da, Yr)
0411812018
Yearronoo ot Kepon
End of 20171Q4
MATERIALS AND SUPPLIES
1. For Account 154, report the amount of plant matorials and operating supplies under he primary functional classifications as indicated in column (a);
estimates of amounF by functlon are acceptable. ln column (d), designate he d@artment or deparlm€nb which use the class of material.
2. Give an explanetion of imporhnt inventory adjust nenb during the year (ln a foottote) showing general classes of material and supplies and he
various ac@unts (opera0ng expenses, dearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits tc stores expons€
cleadng, if applicable.
Line
No.
(a)
Account Balance
Beginning of Year
(b)(c)
Balance
End of Year
Departnent or
Departments which
Use Material(d)
1 Fuel Stock (Account 151)53,700,442 56,638,459 Electric
2 Fuel Stock Expenses Undistributed (Account 152)-2,623 5 Electric
3 Residuals and E,ffacted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Conslruction (Estimated)
6 Assigned to - OperaUons end Maintenance
7 Produc'tion Plant (Estimated)17,442,U1 17,946,659
8 Transmission Plant (Estimated)13,353,307 10,01 1 ,948
I Distribution Plant (Estimated)21,236,2U 24,559.578
10 Regional Transmission and Market Operation Plant
(Eslimated)
11 Assigned to - Other (provide details in boftote)2,422,752 1.338,445
12 TOTAL Account 154 (Enter Total ol lines 5 thru 1 1)il,454,684 53,856,630 Electric
13 Merchandis€ (Account'l 55)
14 Other Materials and Supplies (Account 156)
15 Nudear Materials Held br Sale (Account 157) (Not
applicto Gas Util)
16 ElectricStores Expense Undistributed (Account 163)3,403,797 't,888,307
17
18
19
20 111,556,300 112,383,401TOTAL Materials and Supplles (Per Balance Sheet)
FERC FORir NO. r (REV.12-0s)Page 227
Name of Respondent
ldaho Power Company Original
Date of Reoort(Mo. Da, Yi)Year/Period of Report
gn6 qg 2017/Q4
(2)A Resubmission o4t1812014
Transmission Service and Generation lnterconnection Study Costs
1. Report the particulars (details) called ficr mncerning lhe costs incuned and the reimbursemenb received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. ln column (a) prcvide the name of the study.
4. ln column (b) report the cost inqrrred to perform the study at the end of period.
5. ln column (c) report the account charged with the cost of the study.
6. ln column (d) report the amounts received for reimbursement of the study costs at end of period.
7. ln column (e) report the account credited wilh the reimbursement received for perficrming the sfudy.
Line
No.Costs lncurred During
Period
(b)
Account Charged
(c)
RarmDursementsReceived Duringth6 Period
(d)
Account Credited
With Reimbursement
(e)
Description
(a)
1 Transmission Studies
2 BPAP NETWORK SIS 83177020 1,017 1 86623 2,908 186623
3
4
5
6
7
8
I
10
11
12
'13
14
15
16
17
18
19
20
21 Generation Studies
13.279 186623 634 18662322JACKPOT SOI-AR SOUTH #503
23 SOUTHERN IDAHO SOLID WASTE #501 186623 28,436 186623
24 BAKER CITY 1 SOLAR 4,627 186623 ( 30,000)186623
25 16,318 186623 ( 16,318)186623JACKPOT ANNEX SOLAR #523
17,861 186623 ( 10,000)'18662326CAT CREEK PUMP STORAGE #524
18662327IPCO COMMUNITY SOLAR #509 186623
28 ONTARIO SOLAR #525 1,445 186623 ( 10,000)186623
29 WARM SPRINGS HYORO #526 2,017 186623 ( 1,000)186623
186623 26,742 18662330BRUSH SOLAR #512
18662331CARTER SOI.AR #517 '114 186623 ( 1.382)
32 JACKPOT SOLAR EAST #514 186623 27,886 186623
33 9,528 1 86623JACKPOT SOLAR NORTH #502
186623 27,993 18662334JACKPOT SOLAR WEST #513
29,024 '18662335MORGAN SOLAR #510 976 186623
36 ONTARIO 1 SOLAR #520 2,460 186623 ( 2,460)186623
37 SHOSHONE FALLS HYDRO PROJECT IPCO 2,839 186623 186623
26,395 18662338VALE 1 SOI..AR #511
39
40
FERC FORM NO. 1/r-Fl3-Q (NEW.0!07)Page 231
186623
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
04t1u2018
Year/Period of Report
2017tQ4
FOOTNOTE OATA
s received (credit amounts)and re funds
Iback to the counterparties (debit amounts).
deposit exceeds the finaf expenses.
Refunds are initi-ated when the initia
NO.1FERC Pago 450.1
ldaho Power Company (1)
(2)
An Original
A Resubmission 0411u2018
Year/Period of Report
End of 2U!44
OTHER REGULATORY ASSETS (Account 182.3)
'l . Report below the particulars (details) called for conceming other r€gulatory assets, including rate order docket number, if applicable.
2. Minor items (5olo of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line
No.
Description and Purpose of
Other Regulabry Assets
(a)
Balance at Beginnirg
of Cunent
Ouarter/Year
(b)
Debits
(c)
CREDITS Balance at end of
CurcntQra.t€r/Year
(0
Winon ofi Dudng flo
ouadsr fYoar Account
Chased (d)
Wriuen off Du.hg
he Period Amount
(e)
1 Fixed Cost AdJustnent (FCA) (182302)34,867,487 15,542,127 100/1823 34,867,487 15,542,127
2 Oder #33527 (Arno{t perlrd 06/17 thru 05/18)
3
4 AOCI lmpact of Unfundod Post Rotircrnent Liablity 49,369 3,043,410 2283 4t,25E 3,M5,52'l
5 0rder#30256 (182306)
6
7 FCA Calender Mo Adiusfnent ( 3,393,382)3,393,382 400 704,075 -704,075
I Otder#33295 (182308)
I
10 Prio,Year FCA - 0rder#33527 (182309)12,971,026 35,012,042 400 31,965,224 16,0'17,844
11 (Amort period 06i16 thru 05/17) 0rder#33527
12 (Amort pedod 0017 thru 05/18) Order#33777
13
14 PCA Unbilled Amortizauon (182316)( 1,987,4s4)848,564 400/101 207,938 -1,346,828
15 (Amort pedod 06/'16 hru 05/17)
't6
17 AOC| lmpact of Unfunded Pension Lhbility 263,729,9s2 26,721,785 2283 13,331,245 277,124,492
18 ordu#302s8 (182320)
19
20 Defened Pension Expense Net of Contributions 22,X5,4X 39,250,908 Vafous 38,513,416 23,032,921
21 oder #30333 (182321 )
22
23 FAS 109 Unfunded (1823221 948,539,822 NA 626,279,537 322,260,28s
24 Accum Defered lncome Noncurent
25
26 PCA Deforal ldaho -Oder#33526 52,989J42 52,989,142
27 (Amort perlod 06/17 thru 05/'18) (182323)
28
29 PCA Prior Year Defenal ldaho - (182324)10,154,32S 3'f,089,967 Various 39,761,505 4,482/91
30 (Amort period 06/16 thru 05/17) Order#33526
31 (Arnort oeriod 06/17 thru 06i'18) 0rter#33775
32
33 PCA Unbilled Forccast- Order#32821 (182325)( 3,027,410)3,027,410
34
35 PCA SBA Unbilled AdiOrder#33307 (182326)( 4,685,781)4,685,781
36
37 ldaho Pension Cash - Orderr #32248 (182327j 83,056,919 38,913,1 76 401 17,281,662 104,688,433
38 (Amort period beginning 06/11 $ru hdefnitQ
39
4A ASC 815 t&rk b Mafiet (182330 & 182333)1,419,163 2U 't,4't9,163
41 Oder#28661
42
43 Orcgon Pensbn Expense Capiblized (182339)3,756,774 757,277 401/4073 1'16,445 4,397,606
FERC FORM NO. 1r3.Q (REV.02.04)Page 232
Date ot t{eport(Mo, Da, Yr)
ldaho Power Conrpany (1)
(2)
An Original
A Resubmission
Da,
0411812018
Ysa/Period oI Report
End of 20171Q4
OTHER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for conceming other regulatory assets, including rate order docket number, if applicable.
2. Minor items (57o of the Balanca in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line
No.
Doscription and Purpose of
Other Rogulatory Assets
(a)
Balance at Beginning
of Cunent
Quartsrffear
(b)
Debits
(c)
CREDITS BalarEe at end of
Cunent Qusrbr/Year
(0
Wrilten off During he
Quartor /Yoi Account
charsed (d)
Written off During
he Peilrd Amount
(e)
1 Order#lH)64
2
3 Asset Relircmenl Obligatlons (182311)13,970,846 1,658,624 401 15,629,470
4 IPUC Order #29414-OPUC Order #04-585
5
b PCAM Oregon 2008 (182346)739,466 3,396 402 742,862
7 Order#08-238 &#13439 (Amort0l/14 -0d17)
I
9 2008 PCAM Unbiled Amod (182356)( 195,193)196,036 402 843
10 (Amort perbd 01/'14 hru 06/17)
11
12 RA-Hells Canyon-Baker Cooder #33948 (182360)3,08s,321 NA 3,085,321
't3
14 Lidar Surveys - Order #32426 (18236,l )218,023 402 43,60s 174,4'.t8
15 (Amort poriod 01/1 2 ttu 1U211
16
17 PS&l Shoshone - Orde''#29904 (182368)400,'187 402 266,791 133,396
18 (Amort perbd 07/15 hru 06/18)
19
20 RA-ElM Deferal-Order #33706 (182370)786,074 1071999 786,074
21
22 RA-lnbruenor Fundlng-ldaho (1 82387)150,7s4 NA 150,754
23
24 RA-CONTRA-DEF rNC TAX (182389)262,069,r57 282 262,069,157
25
10 ldaho Boadman ARO - On er #29114 (182393)174,2m 403114110 43,557 130,669
27 (Amort period lhru 2020)
28
29 Langley Revenue Aogrual - Order *12-226 (182398)1,098,946 88,049 NA 1,'186,995
30
31 RAOR Langley Rev lnt Res (182399)( 9s,418)4210 30,252 -125,700
32
33 Siemens Long Term Defened Rate Base (182410)11,201,419 4073 431,488 10,769,931
34 0rder#33,020 (Amort perlod 01/16 hru 1242)
35
36 Siemens Lons Teflr Debried Rate Base (18241 1)16,114,77A 4073 643,866 16,070,904
37 Order#33420 (Amod period 01i16 thru 1?42)
38
39 Siornsns Long T€rm D,efered Rate Base(1824121 441,774 33,717 Various 48,843 426,648
40 Oidet#1$387 (Amo( period 01/16 hru l2136)
41
42 Siemens Long Term Defened Rah Base (1824'13)757,149 4073 49,465 707,684
43 Order#15-387 (Amortpedod 01/16 thru 12136)
FERC FORrrr NO- 1r3-Q (REV. 0244)Page 232.1
Name of RsEpondent
ldaho Poarer Company (1)
(2)A Resubmission
Date of Report(Mo, Da, Yr)
04t18t2018
Year/Period of Report
End of 2017tO4
OTHER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for conceming other regulatory assets, includirB rate order docket numbor, if applicable,
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line
No.
Description and Purpose of
O(her Regulatory Assets
(a)
Balarce at Beginning
otCumnt
Quarlerffear
(b)
Debits
(c)
CREDITS Bahnc,e atend of
Cun€ntOuaturffear
(D
Wdttar offDurhg ttn
ouartBr /Yoar Account
cha{€d (d)
Written otl During
the Period Amount
(e)
1
2 RA-Valmy O&M 1033771 (182432\400/1823 738,442 -738,M2
3
4 RA-Valrry OR DeprAdi 17-325 (182434)1,28r,969 NA 1,281.969
5 (Amort pedod 06/17 htu 1A251
6
7 RA-Valmy AccS Adi lD 33771 (182435)41,107,596 NA 44,107,596
8
I ldaho Boardman Decomissioning (182493)1,471,285 5,833,697 Various 7,3c/.,982
10 0rder#32549 & #32457
11
12 RA-OR BDMN DECOM 12 235 (182494)( 18,415)18,415
13
14 0regon DSM Rid6r (182405)5,552,141 2,329,344 1,608,956 6,272,529
15 Advise 05{3
16
17 Minor lhms (25)192,973 1,392,12'.1 Various 1,565,396 19,698
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
4 TOTAL 1,17't,940,401 529,739,262 869,583,469 1,132,096,'194
FERC FORM filO.1l&Q (REV. 02-04)Page 232.2
Name ol Kesponoent
ldaho Powe Company
I nrs(1)
(21
ls:
Original
A Resubmission
uat€ ot t{eoon(Mo. Da, Yi)
Yoa/t enoo ot Kepon
End of 20171Q4
o4,t18,t20'18
1. Report belo^, the particularc (details) called for conoeming miscellaneous defened debits.
2. For any defened debit being amortizsd, show period of amortization in column (a)
3. Minoritem(1%oftheBalanceatEndofYearforAccountlS6oramountslessthanSl00,000,whicfieverisless)maybegroupedby
classes.
CREDITSLine
No.
Description of Miscellaneous
Debrred Debits
(a)
Balance at
Beginning of Year
(b)
Debits
(c)
ACOOUntcnageo Amount
(e)
Balance at
End of Year
(f)
1 Prepaid Credit Facrl itv( 1 86025)1,023,246 431,232 14,284 1,008.962
2 (Amort period'l 1/16 thru 1 1/20)
3
4 Prepaid Service Contract 2,188,196 999,315 3,187.511
5 Lonq Term Porton (186052)
b
7 Lono Term (186121)1,O41,877 401.2282 21.813 1.020.064
8 Workers Compensalion
I
10 Preoaid ROW(186160)339.887 329,490 669,377
11 Rents/Easements Lono Term
12
13 Lone-Term Portfolio ( 1 86255),165,469 90,142 401 46s.469 90,142
14
15 Advance Preoaid (186709)1,088,440 151 81.052 1.007.388
16 Coal Rovalties
17
18 Stable Value Life (186719)41.422,ffi9 1,736.828 43.159,437
19
20 Security Plan (186720)12.376.573 143,4262 102,125 12,274,448
21 Net lnaurance Asset
22
23 American Falls Bond Ref(186722)1 18.843 401 14,552 104,291
24 (Amort Period 04100 hru A2f25\
25
26 3,753.976 135,081Retiree Medlcal€OLl (1 86726)3,889,0s7
27
28 American Falls Water Riohts 8.422.904 401 't,042,009 7,380,895
29 (Anort 01/06 - O2l25l686727\
30
31 Shelf Reoistation (186733)147,328 147.328
32
33 Milner Bond Guarantee (186734)1.063,636 253 1,063,636
34 (Artl.ofiO?O7 -21171
35
36 391,993American Falls - Bond Refinance 401 47.999 343.994
37 (Amort through O2l25l ('l,86770)
38
39 1.472.259Bridger Coal Study (186781 )1't2.971 1,58s,236
40
41 Miscellaneous Defened Debt Various 2.772.230 -2,772,230
42 Reoulatory Reserves (186800)
43
44 't5,421 207,246Minor ltems (3)Various 185,879 36,788
45
46
47 Mlsc. Work in Progress
48 Defen€d Regulatory Comm.
Expenses (See pages 350 - 351)
49 75,332,657TOTAL 73,132,688
FERC FORi' NO.1 (ED. 12-94)Psge 23:l
1. Report the information called for below conceming the respondent's accounting for defened income taxes.
2. At Other (Speciff), include defenals relating to other income and deductlons.
t aran?91 rcginrng
(b)
ualan@ at Enoof Year
(c)
Line
No.
gesfiption ano Locauon
(a)
1 Electric
I
1
4
,vrog, i6Other Electric (See bohote)92,773,039
6
1 168,030,701 $4.4@,703Oher (Soe foohote)
260,803,740 272,026,950ITOTAL Electric (Enter Total of lines 2 thru 7)
o Gas
10
't1
12
13
14
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15
17 Other Non Eleciric (See foohote)25,522,789 r2786,968
1€286,326,529 289,8't3,919TOTAL (Ac.t 190) (Total of lines 8, 16 and 17)
Notes
Name or x€sponoenr
ldaho Power Company
tnts
(1)
(21
IS:
An Original
A Resubmission
uate ot Keoon(Mo, Da, Yi)YearFerroo or Kepon
End of 20171Q4
04t1u20'18
FERC FORM ilO. r (ED- r2-E8)Page 24
I
a
Name of Respondent
ldaho Power Company
This Report is:
(1) XAn Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
0411u2018
Year/Period of Report
2017tQ4
FOOTNOTE DATA
Schedule Page: 234 L!79 N9.;5 Qelump;
Balance
Construction Advances
Postretirement Benefits
USBR-American Falls O&M Costs
Settlement
Non-VEBA Pension and Benefits
Executive Deferred Com pensation
Retention Pay Accrual
Stock Based Compensation
Pension Expense-Oregon
Bridger Revenue Deferral
Asset Retirement Obligation (ARO)
lncentive Deferral-Profit Sharing-Not in
Rates
OR Reconnect Fees Adv
Rate Case Disallowance
Prov for Rate Refund-HC Relicensing
(AFUDC)
Revenue Sharing
VEBA-Post Retirement Benefits
Deferred ldaho ITC
Deferred GBC Federal
TotalOther Electric
Balance
1,939,459
566,112
125,256
1,420,074
436,208
74,18
(179,4971
39,761
22,212
3,861,627
3,s23,081
442,426
1,il3,332
4,9s9,496
(238,s6s)
28,808
21,449
3,209,060
2,714,789
377,040
1,230,333
3,752,926
0
2,157,gO2
40,353,531
' 237
1,356,867
31,085,864
Schedule Page: 234 Line No.:7
Pension-FAS 158
Regulatory Liability-FAS 1 09
Minimum Pension Liability
Poslretirement Plan-FAS 1 58
TotalOther
0011,747,529 7,854,162
21,721,941 29,195,22869,872 7,038,619
92,773,039 89,557,247
Column: c
103,332,880 72,068,42151,326,330 98,743,759
13,403,940 10,866,388(32,449) 791,135
168,030,701 ',t82,469,703
Schdute Page: 231 Line No.:
Senior Management Security Plan
TotalNon Electric
17 Column: c
789 1 7
FERC FORM NO.1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This(1)
(2)
ls:
Orlglnal
Dat6 of Reoort(Mo. Da, Yi)
0411812018
Year/Period of R6port
End of 20171Q4A Resubmission
1. Report below the particulars (details) called for conceming common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and prefened stock. lf information to meet the stock exchange reporting
requirement outlined in column (a) is available ftom the SEC 10-K Report Form filing, a specifc reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line
No.
Class and S€ries of Stock end
Name of Stock Series
(a)(b)
Number of shares
Authorized by Charter
(c)
Par or Statd
Value per share
(d)
Call Prlce at
End of Year
1 Account 201
2 Common Stock all of which is held by 50,000,000 2.50
3 ldaCorp, lnc. and not traded
4 Total Common Stock 50,000,000 2.50
5
6 Account 204 - None
7
8
9
10
't1
12
13
14
15
't6
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33u
35
36
37
38
39
40
41
42
FERC FORM flO.1 (ED.12.9r)Page 250
Name of Respondent
ldaho Power Gompany
This
(1)
(2)
ls:
An Original Dalo of Report(Mo, Da, Yr)
Resubmission 04nu2a18
Year/Perlod of Report
End of z0'l7lQi
3. Give particulars (details) conceming shares of any class and series of stock authorized to be issued by a regulatory commisdon
which have not yet been issued.
4. The identification of each class of prefened stock should show the dividend rato and whether the dividends are cumulative or
non-cumulative
5. State in a foofrrote if any capital stock which has been nomlnally lssued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stoct, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
HELD BY RESPONDENTOUTSTANDING PER BALANCE SHEET(Total amount outstanding without reduc{ion
for amounts held by respondent)AS REACOUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS
t'nares(e)Amount(0 5nares(g)uost(h)tinares(i)Amount
0)
Line
No.
I
39,150,812 s7,877,030 2
3
39,150,812 s7,877,030 4
5
b
7
I
I
10
11
12
13
14
15
16
17
18
t9
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORI' NO.1 (EO. 12-88)Page 251
ls:
An Original
A Resubmission
Dato of Reoort
(Mo, Da, Yi)
Year/Period of Repod
End of 2O17lQ404t18t2018
Name
ldaho Power Company (1)
(2)
OTHER PAID-IN CAPITAL (Accounts 208-21 1, inc.)
Roport below the balance at the end of the year and the information specified below br the respective other paid-in capital accounte. Provide a
subheading for oach ac@unt and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 'l 12. Add more
columns for any account if deerned necessary. Explain changes made in any account during the year and give the accounting entries effading suclr
change.
(a) Donations Received ftom Stockholders (Account 208!State amount and give brief €xplanation of the origin and purpose of each donation.
(b) Reduction in Par or Strated value of Capital Stock (Account 209): State amount and give brief elqlanation of the capital change which gave rise b
amounts reported under lhis captlon including identification with the class and series of stock b whidr relabd.
(c) Gain on Resale or Gancellation of Reacquired Capltal Stock (Acconnt 210): Report balance at beginning of year, credits, debits, and balance at end
of year witr a designaUon of the nature of 6ach credit and debit identiffed by the class and series of stock to which relat€d.
(d) Miscellaneous Paid-in Capital (Account 21'l fClassify amounts included in his account according t capuons which, together with briel explanatons,
discloso ths general nafure of the transactions whidt gave rise tc the reported amounts.
LtneNo.It€m(a)Amount(b)
,|Account 208 - Donations receivd from stockholders - None
2
3 Account 209 - Reduclion in par or stated value of Capital Stock - None
4
5 Account 210 - @in on reaoquired Capital Stock - None
6
7
I Account 211 - Miscellaneous paiGin Capital - None
I
't0
11
12
13
14
15
16
17
't8
19
20
21
22
23
24
25
26
27
28
29
30
3'l
32
33
34
35
36
37
38
39
40 TOTAL
FERG FORil NO. I (ED.12-87)Page 253
tlame of Respondent
ldaho Power Company
This Roort ls:(1) ElRn Original
Date of Report(Mo, Da, Yr)
YearlPeriod of Report
End of 2O17lQ4
(2)A Resubmission 04t1812018
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. lf any change oocuned during the year in the balance in rcspect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specifu the account charged.
Llne
No.(a)
Glass and sefles of Stod(Balance at End ol Year
(b)
1 Common Stock 2,096,92s
2
3
4
5
6
7
8
I
10 Explanation of Changes during the year:
11
12
't3
14
15
16
't7
18
't9
20
21
22 TOTAL 2,096,925
FERC FORXT NO.1 (ED. 12-87)Page 2tfb
Name ot t(e9pon6ent
ldaho Power Company
I his
(1)
(2t
An
ls:
Original
A Resubmission
uat6 ot Report(Mo, Da, Yr)
YearlPenod ot Keport
End of 2O17lQ40411u2018
1. Report by balance sheet account the particulars (details) conceming long-term debt included in Accounts 221 ,Bonds.222,
Reacquired Bonds, 223, Advances from Associated Companios, and 224, Other long-Term Debt.
2. ln column (a), for new issuos, give Commission authorization numbeni and dates.
3. For bonds assurned by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. lnclude in column (a) names of associated companies ftom which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under whicfr such certificates were
issued.
6. !n column (b) show the principal amount of bonds or o0ter long-term debt originally issued.
7. ln column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
lndicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Fumish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Principal Amount
Of Debt issued
(b)
Total 6xpense,
Premium or Discount
(c)
Class and Series of Obligation, Coupon Rate
(For new issue, give @mmission Auhorization numbers and dates)
(a)
1 Account 22'l
2 First Mortgage Bonds:
3 4.50% Series due 2020 130,000,000 1,190,698
4 234,601 D
5
6 5.50o/o Series due 2033 70,000,000 728,701
7 36,,100 D
8
I 3.40% Series due 2O20 100,000,000 1,159,871
10 498,864 D
11
12 5.307o Series Due 2035 60,000,000 408,411 D
13 3,802,01S
't4
15 4.00% Series due 2043 75,000,000 742,017
16 193,836 D
17
18 6.000/o Series due2032 100,000,000 1,191,2',t6
19 543,2U O
20
21 5.8757o Series due 2034 55,000,000 -585,759
22 746,961 D
23
24 5.50% Series due 2034 50,000,000 524,419
25 383,322 D
26
27 4.85% Series Due 2040 100,000,000 1,2U,871
28 169,984 D
29
30 6.30o/o Series due 2037 140,000,000 1,495,799
31 278,367 0
32
33 TOTAL 1,777,045,000 29,952,899
FERC FORM ilO.1 (ED. 12-96)Pago 256
Name ot Kespondent
ldaho Power Gompany
ls:
Original
lhis
(1)
(2)
Uate ot ReDort(Mo. Da, Yi)Year/Period ot Regort
End of 20171Q4Resubmission04118,2018
10. ldentlf, separate undisposed amounts applicable to issues which were redeemed in prior years.
1 1. Explain any debits and credits other than debited to Account 428, Amortization and Exp€nse, or credited to Account 429, Premium
on Debt - Credit.
12. ln a footnote, give explanatory (details) for Accounts 223 and 224 of nel changes during the year. With resp€ct to long-torm
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. lf the respondenl has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose ofthe pledge.
14. lf the respondent has any long-term debt securities which have been nominally issued and are nomanblly outstanding at end of
year, describe such securities in a footnote,
15. lf interest expense was incurred during the year on any obligations relired or reacquired before end of year, include such interest
expense ln column (i). Explain in a footnote any difference between the total of column (i) and the total of Accou nt 427 , interest on
Long-Term Debt and Account 430, lnterost on Debt to Associated Companies.
16. Give particulars (details) conceming any long-term debt authorized by a regulatory commission but not yet lssued.
AMORTIZATION PERIODNominal Date
of lssue
(d)
Date of
Maturity
(e)
Oate From
(0
Date To
(s)
uuEilanolno(Totral amount out6hnAino without' reduclion llrr amounts hiH by
rese?fl\dent)
lnterest for Year
Amount
(t)
Line
No.
'l
2
11t20to9 3t'U20 11120109 311120 130,000,000 5,850.000 3
4
5
05/01/03 05/01/0304to1133 03/31/33 70,000,000 3,8s0,000 6
7
8
't111t10 511f2020 1111110 511120 100,000,000 93,400,000
10
11
08126105 0u26135 08r/26105 08/26/35 60,000,000 3,180,000 12
13
14
4t812013 41812013 411120434t1t2U3 75,000,000 3,000,000 15
16
17
11t15tO2 '11t15t32 11t15t02 11t15t32 100,000,000 6,000,000 18
19
20
08/16/04 08/1 6/34 08/16/04 _08/16/34 55,000,000 3,231,250 21
22
23
03l26to4 osllsly 03l2glo4 o3115134 50,000,000 2,750,000 24
25
26
2t15110 u15t40 2t15110 8t15140 100,0@,000 4,850,000 27
28
29
6t22107 6122107 6t15t376115t2037 140,000,000 8,820,000 30
31
32
1,765.345,000 81,198,430 33
FERC FORM NO. r (ED. 12-96)Page 257
Name ot Respondent
ldaho Power Cornpany
T his(1)
(2)
ls:
Original
A Resubmission
Uat€ ot Report(Mo, Da, Yr)
Year/Period ot Report
End of 20171Q4u|1812018
1. Report by balance sheet account the particulars (detalls) conceming long-term debt included in Accounts 22'l, Bonds,222,
Reacquired Bonds, 223, Advances fiom Associated Companies, and224, Other long-Term Debt.
2. ln column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. ElesQnate
demand notes as such. lnclude in column (a) names of associated companies fiom which advanc€s were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. ln column (b) show the principal amount of bonds or other long-term debt originally issued.
7. ln column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issuad.
8. For cplumn (c) the total expenses strould be listed first for each issuance, then the amount of premium (in parentheses) or discount.
lndicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Fumish in a footnote particulars (details) regarding the treatnent of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give In a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rato
(For new issue, give commission Authorization numbers and dates)
(a)
Prindpal Amount
Of Debt issuod
(b)
Total expense,
Premium or Discount
(c)
1 ,00,000,0006.25% Seri€sdue2O37 1.141.489
2 267,677 0
3
4 Port of Morow Variable due2027 4,360,0(x)188,545
5
6 Humboldt Variable due 2024 49,800,000 't,697,856
7
I Sweetwater Variable due 2026 1 1 6.300,000 3,026J22
I
10 2.50% Series due2023 75,000,000 648,267
11 371,854 D
12
13 4.30% Series Oue2042 7s,000,000 802,240
14 49,417 D
15
16 2.95% Series Due2022 75,000,000 708,490
17 127,607 A
18
't9 3.65% Series Due 2045 250.000,000 2,559,510
20 1,715,000 D
21
22 4.05% Series Due 2046 120,000,000 1,3't 1,383
23 309,600 D
24
25 1,745,,160,000 29,952.899Subtotal Acnunl221
26
27 Acrl,unl222 - Reaquired Bonds
28
29 Account 223: Advances for Associated Companies
30
31 Acmunl224'.
32 Bond Guarantee - American Falls 19,885,000
33 1,29,952,899TOTAL
FERC FORir NO. I (ED.
'2-96)
Page 258.1
Name of Respondent
ldaho Power Cornpany
This
(1)
(2)
ls:
An Original
A Resubmission
Dat6 of Report
(Mo. Da, Yr)
Year/Period of Report
End of 20171Q4
04t1u2018
110. ldentirys!€parateundisposedamountsapplicabletoissueswhichwereredeemedinprioryears.
111. Explain any debits and credits oth6r than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
lon Debt - Credit.
ItZ. ln
^footnote,
give explanatory (details) for Accounts 223 and224 of net changes during the year. With respect to longterm
advances, show for each oompany: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numb€Is and dates.
13. lf the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose ofthe pledge.
14. lf the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. lf interest expense was incuned during the year on any obligations retired or reaquired before end of year, include such interest
expense in column (i). Explain in a foohote any difference between the total of column (i) and the total of Account 427, interesfi on
Long-Term Debt and Account 430, lntersst on Debt to Associated Companies.
16. Give pedculars (details) conceming any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD
Dat6 From
(0
Date To
(s)
lnterest fcr Year
Amount
(i)
Line
No.Nominal Date
of lssue
(d)
Date of
Maturity
(e)
L'UISIANOINO(Total amount outstanilino wihout' reducton br amounts h;ld by
'o1fi0""0
1U18tA7 10t1512037 10l1uo7 10115t37 100,000,000 6,250,000 1
2
3
0210112705t17too021o1127051171o0 4,360,000 49,230 4
5
10122t03 12tO1124 11t01t03 12101124 49,800,000 2,564,700 6
7
'10/3/06 7n5n6 10/3/06 7n5n6 116,300,000 6,105,7s0 8
I
u812013 411t2023 418t2013 41112023 75,000,000 1,875,000 10
11
12
411142 75,0m,00c 3,225,0004113t12411t424t13t'.t2 13
14
't5
4113112 4t1t22 4t13112 411122 7s,000,00c 2,212,500 't6
17
18
3t6l't5 3t1t45 316115 3t1145 250,mo,00c 9,12s,000 19
20
2',1
4,860,000 223/10/16 311146 31'.!0116 3t1146 120,000,000
23
24
1,745,,t60,000 81,1 98,430 25
26
27
28
29
30
31
04t26t00 2t1t25 19,885,000 32
1,76s,345,000 81.1S8,430 33
FERC FORrrr NO. t (EO. 12.96)Page 257.1
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20'l7lQ4An Original
A Resubmission 04t'tu2018
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds,222,
Reacquired Bonds, 223, Advances from Associated Companies. and224, Other long-Term Debt.
2. ln column (a), for new issues, give Commission authorization numbers and dates.
3. For hnds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances frcm Associated Companies, repolt separalely advances on notes and advances on op€n accounts. Designate
demand notes as such. lnclude in column (a) names of associated companies firm which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certmcates were
issued.
6. ln column (b) show the principal amount of bonds or other long-term debt originally issued.
7. ln column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
lndicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Fumish in a footnote particulars (details) r€garding the treatment of unamortized debt expense, premium or discount associatad with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rate
(For nevv issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 Note Guarantee - Milner Dam 1 1,700,000
2 Subtotal Account 224 31,585,000
3
4
5
6
7
8
9
10
1',1
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33 1,777,045,000 29,952.899TOTAL
FERC FORtrl NO. I (ED. 12-96)Page 256.2
Name of Respondent
ldaho Power Company
ls:OriginalThis(1)
(2t
Date of Reoort(Mo. Da, Yi)Year/Period of R€port
End of 2O17lQ4Resubmission0411812018
10. ldentiff soparate undispossd amounts applicable to issues which were rede€med in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. ln a footnote, give explanatory (details) for Accounts 223 and 224 of nel changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. lf the respondent has pledged any of its long-term debt securities give parliculars (d€talls) in a footnote including name of pledgee
and purpose ofthe pledge.
14. lf the respondent has any long-term debt securites wtrich have been nominally issued and are nominally outstanding at end of
year, describe such securities in a foohote.
15. If interest expense was incuned during the year on any obligaUons retired or reacquired befure end of year, include such interast
oxpense in column (i). Explain in a footnote any difierence between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, lnterest on Debt to Associated Companies.
16. Give particulars (details) conceming any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD
Nominal Date
of lssue
(d)
Date of
Maturity
(e)
Date From
(0
Date To
(s)
uutsilanorno(Total amount outsEnAino wihout' reduction fur amounts htld byrosryfld6n0
lnterest br Year
Arnount
(i)
Line
No.
02t10t92 ,|
19,885,000 2
3
4
5
6
7
I
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
1,765,345,000 81,198,430 33
FERC FORM NO.1 (ED.12-96)Page 257.2
Name of Respondent
ldaho Power Company
This ReDort ls:(1) E]An orisinal Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 2O17lQ4(2t A Regubmission o4t18t2018
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
1. Report the reconciliation of roported not income for the year witt tiaxable income used in compuling Federal in@me tax accruals and show
compuhtion of such trax accruals. lndude in the reconciliation, as far as practicable, the sam6 detail as fumished on Schedule M-l of the tax refurn for
the year. Submit a reconciliation even though there is no taxable income for he year. lndicate clearly the nafure of each reconciling amount.
2. lf th€ utility is a member of a group which files a consolidated Federal tax retum, reconcile reported net income with taxable net income as if a
separate retum were to be field, indicating, however, intercompany amounts to be eliminated in such a mnsolidated refurn. State names of group
member, Ex assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among tre goup members.
3. A substihrte page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of
the above insfirdions. For 6l6c'tronic reporting purposes complete Line 27 and provide the erbstitute Page in the context of a footnote.
Ltne
No.
Partio.ilars (Detalls)
(a)
Amount
(b)
206,347,3',t71Net lncome for the Year (Page 117)
2
3
4 Taxable lncome Not Reported on Books
5 13,{.tN.'r80
6
7
8
o Deductions Recorded on Books Not Deducted for Return
10 22.660,09'
11
12
13
14 lncome Recorded on Books Not lncluded in Retum
15 17.46.4sr
't6
17
18
19 Deductions on Retum NotCharged Against Book lncome
83.5t0,92820
21
22
23
24
25
26
27 Federal Tax Net lncome 141,555,165
28 Show Computation of Tax:
29 49,509,308
30
31
32
33
34
35
36
?7
38
39
40
41
42
43
44
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(2) A Resubmission
Date of Report
(Mo, Da, Y0
04118t2018
Year/Period of Report
2017tQ4
FOOTNOTE OATA
4OOs-AVOIDED COST 4,322,425
4OO3-CONSTRUCTION ADVANCES 1,509,519
4013-C|AC - TAXABLE - ACCT 107 5,878,808
4021-ENGINEERING FEES - TAXABLE . ACCT 107 377,721
4o24-RENEWABLE ENERGY CERTIFICATES (REC) SALES 1,365,716
fotal 13,454,189
261 Line No.:
261 Line No.:10 Column: b
Schedule 261 Line No.: 15 Column: b
FERC FORM NO.1 1 450.1
fotal Federal and State taxes deducted on books 48,994,755
5OO1-BAD DEBT EXPENSE 1,060,493
(32,000,0005022.263A CAP ITALIZED OVE RH EADS
s00,0005o24-NON-DEDUCTIBLE MEALS
5O7O-INCENTIVE DEFERRAL-CRI &
RELIABILITY-INCLUDED IN RATES
(4,857,657)
501 O-POSTEMPLOYMENT BENEFITS 231,167
(22,846,28715023-PENSION EXPENSE
5025-MILNER FALLING WATER (855,6721
5035-PCA EXPENSE DEFERRAL 53,442,826
so47-EXECUTIVE DEFERRED COMP 0
sOs3.STOCK BASED COMPENSATION 2,306,851
5058-FIXED COST ADJ USTMENT 13,589,235
5O6O-OREGON - PCAM 467,920
5061-PENSION EXPENSE - OREGON 1,439,'t56
5O67.ASSET RETIREMENT OBLIGATION (ARO)788,594
5071.INCENTIVE DEFERRAL-PROFIT SHARING-NOT IN
RATES
1,825,137
5074-VALMY SETTLEMENT ADJ USTMENT (42,960,129)
5075.E1M DEFERRAL (806,365
5501-SMSP - INSURANCE COSTS (1,857,803
5503-EDC - UNREALIZED GAIN/LOSS FROM RABBITRUST 0
ssM-NON-DEDUCTIBLE POLITICAL EXPENSES 1,009,892
3,187,9675505-SMSP - NET
fota!22,660,080
7501-REVERSE EQUITY EARNINGS OF SUBSIDIARIES 7,082,051
7509-SMSP . INSURANCE PROCEEDS 96,911
75o2-ALLOWANCE FOR OFUDC 20,784,392
75o3-ALLOWANCE FOR BFUDC 8,694,285
7O1O-PROV FOR RATE REFUND - HC RELICENSING
(AFUDC)
(16,447,7141
7O12.REVENUE SHARING 0
701 3-LANGLEY REVENUE ACCRUAL (2,714,462'
fotal 17.495,493
Schedule Page: ,261 Line No.:20 Column: b
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
0411812018
Year/Period of Report
2017tQ4
FOOTNOTE DATA
5538-STOCK BASED COMP - STOCK 3,665,013
3702-STOCK BASED COMP. DIVIDENDS 573,294
3o25-MANUFACTURING DEDUCTION 7,478,875
3034-REMOVAL COSTS 17,944,114
8o42-GAIN/LOSS ON REACQUIRED DEBT ,|
8073-REPAIRS DEDUCTION 82,000,000
8O77.PREPAID INSURANCE & OTHER EXPENSES 1,447,880
8OO1.VEBA - POST RETIREMENT BENEFITS (624,614)
BO2O.CONSERVATION EXPENSES (680,287
8o59-SOFTWARE . LABOR COSTS DEDUCTED . ACCT 107 1,900,000
8o72-RELICENSING. LABOR COSTS DEDUCTED. ACCT
107
2,200,000
8OOg.DEPR TIMING DIFF - OPERATING - FEDERAL (42,501,323',)
STATE INCOME TA)( DEDUCTED ON FEDERAL RETURN 12,260,928
Total 83,si0,928
FERC FORM 1 1 450.2
This(1)
(2)
ls:
Original
Resubmission
- Date of Report(Mo, Da, Yr)End of
of Report
20171Q4ldaho Power Company 04t18t2018
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show he totral taxes drarged b operations and other acoounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts b which the tax€d material was cfiarged. lf the
actual, or estimated amounts of sudr taxes are know, show the amounts in a foohote and designate wheher estimated or actual amounts.
2. lnclude on this page, taxes paid during the year and charged direct to final accounts, (rrct charged b prepaid or accrued taxes.)
Enter tre amounts in both oolumns (d) and (e). The balancing of his page is not affec{ed by the inclusion of hese taxes.
3. lnclude in column (d) hxes cfiarged during 0le yoar, taxes charged tc opera[ons and oher accounb hrough (a) accruals credited to taxes eccrued,
(b)amounts credited to proportions of prepaid taxes cfiargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
han accrued and prepaid tax ac@unts.
4. List the aggregate of each kind of tax in such manner tlat the total tax for eacfi State and subdivision can readily be ascertained.
BALANCE AT BEGINNING OF YEARLine
No.
Kind of Tax
(See instruction 5)
(a)
Taxes Acdued(Account 236)(b)
Preoaid Tax6(lndude in ff*rn1 16s)
Adiust-
ments
(0
1 Federal:
2 -19,939,467 46.455,836 48,727,629lncome
3 Social Security - (FOAB)441,9't5 15,581,429 15,591 ,51 I
4 37,862 91,280 91,713Unemployment
5 Subtotral Federal -19,459,690 62,128,545 64,410,853
6
7 State of ldaho:
I lncome -3,1't4,901 9,883,487 1 1 ,101 ,390
s Unemployment 23,588 306,536 307,3,l8
10 Property 9,595,802 22,411,740 22,166,327
11 Non-Operating 9,597 18,246 18,799
12 kvvh 78.001 1.950,66S 1,923,636
13 2,665,9&2,665,764Regulatory Commission
14 Business License - Sho Ban 150 150
37,236,792 38,183,41415Subtotal ldaho 6,592,087
16
17 State of Oregon
't8 lncome -248,478 526,268 635,504
19 Unemployment 2,912 54,986 55,704
20 Property 1,591,161 3,288,877 3,393,s96
21 Non-Operating Property 973 't,975 2,005
22 Regulatory Commission 254,808 254,808
23 Franchise 194,412 859,928 857,183
24 -51,154 1 ,5S2,134 4.986,842 5,198,800Subtotral Oregon
25
26 State of Montana:
27 Property 161,088 359,207 340,839
28 Subtotal Montiana 161,088 359,207 340,839
29
30 State of Nevada:
31 487,522 907,U2 817,042Property
32 Subtotal Nevada 487.522 907,U2 817,042
33
34 State of Wyoming
35 796,727 1,508,456 1,550,956Prope0
36 Corporate License 4,429 4,429
37 796,727 1,512,885 1,555,385Subtotal Wyoming
38
39
40
-11,2.079,656 91 110,517,763 -6,30941TOTAL
FERC FORil NO. I (ED. t2-96)Page 262
l,lame of Respondent
ldaho Power Company
This(1)
(2t
ls:An Original
Date of Reoort(Mo, Da, Yi)
Resubmission 4q18/2018
Year/Period of Report
End of 2017lQ4
5. lf any tax (exclude Federal and State income taxes)- coverc moro th6n one year, show the required information separately icr eacfr tax year,
klentifring the year in column (a).
6. Enter all adjustmenE of the accrued and prepaid tiax accounts in column (0 and explain sach adjus[nent in a bot- note. Designate d€bit adiustments
by parentheses.
7. Do not include on this page entries with respect to defened income tiaxes or taxos collected through payroll deduclions or o0rerwise pending
transmittal of such taxes to tha taxing autrcrity.
8. Report in columns (i) through (l) how he taxes were distributed. Report in column (l) only tho amounts cfiarged b Accounb 40E.1 and 409.1
pertaining to €lectic operations. R€port in column (l) he amounts charged to Acoounts 408.1 and 109.1 pertiaining to other utility d€partr€nB and
amounts charged to Accounts ,108.2 and 409.2. Also shown in column (l) he taxes charged to utility planl or other balanc€ shoot accounts.
9. For any trax apportioned to more lhan one utility department or account, state ln a footnote the basis (necessity) of apportioning suctr tax.
BALANCE AT :ND OF YEAR DISTRIBUTION OF TAX]
(Taxes acanrednccoplza0)
Prepaid Taxes
(lncl. in Account 165)
Electric(Account 408.1. 409.1 )
Exhaordinary ltems
(Accounf 409.3)
AOiustments to K€t.
Eamlngs (Account 439)
(k)
Other
(t)
Line
No.
1
-22,211,260 44,701,501 t.754,335 2
431,833 15.581,42S 3
37,428 91,280 4
-21,741,W 60.374,210 1,754,335 5
6
7
4.332,804 9,880,304 3,1t 8
22,775 306,536 I
22,410,7209,841,215 r,020 10
9,0,14 18,2#11
105,033 1,950,669 12
2,665,964 13
150 14
5,645,263 37,214,U3 22,449 15
16
17
-357,714 526,162 106 18
54,9862,194 19
1,695,878 3,152,',162 130,71{20
1.002 t,975 21
254,808 22
197,157 859,928 23
-158,363 1,696,880 4,848,046 138,796 24
25
26
179,456 359,207 27
179,456 359,207 28
29
30
415,074 907,842 31
907,842415,O74 32
33
34
754,229 1,508,456 35
4,429 Jb
754,229 1,512,885 37
38
39
4A
-15,1s6,342 2,111,954 89,348,997 1,916,01 r 4',1
FERC FORM t{O. I (ED. 12.961 Page 203
Name of Respondent
ldaho Power Company
l6:
Orlginal
This
(1)
(2)
Date of Report
(Mo, Da, Yr)
04t18t2018
Year/Period of Report
End of 2O17lQ4
Resubmission
TAXES ACCRUED. PREPAID AND CHARGED DURING YEAR
1. Give partculars (details) of the combined prepaid and accrued tax accounts and show he total taxes charged b operaflons and other accounts during
the year. Do not include gasoline and other sales taxes whidt have been charged to h€ accounfs b nhidr the taxed material was charged. lf the
actual, or estimated amounts of such taxes are knorv, show the amounts in a footnote and designate whother estimated or actual amounts.
2. lnclude on this page, tiaxes paid during he year and drarged direct to final ac@unts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). Th€ balancing of this page is not affected by the inclusion of these taxes.
3. lnclude in column (d) taxes charged during lhe year, taxes charged b operatiofls and oher accounts through (a) accruals credited to bxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeaHe to current year, and (c) taxes paid and chaqed direct to operations or aocounts other
fian accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that fre total tax for eacfi Sbte and subdivision can readily be ascertained.
BALANCE AT BEGINNING OF YEARLtne
No.I axes Acqueo(Account 236)(b)
Kind of lax
(See instruction 5)
(a)
Preoa6 I itxos(lndude In
fficount
1 65)
Adjusl-
ments
(f)
1 State of Washington
2 Propefi 6,000 15.241 10,201
3 Subtotal Washington 6,000 15,201 'to,20'l
4
5 9,723Other States lncome 151,925 6,505
6 Canada GST Tax -38 -5,276 6,300
7 Payroll Tax Credit -16,034,231
8
I
10
11
12
't3
't4
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
4A
41 TOTAL -'t1 2,079,656 91 110,517,-6,309
FERC FORII ]tlo. I (ED. t2-96)Page 262.1
ldaho Power Company (1)
(2)
An
A Resubmission 04t1u2018
Year/Period o, Report
End of 20171Q4
5. lf any tax (exclude Federal and State income taxesf covers more then one year, show the required information separately for eacfi tax year,
identifying the y€ar in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (0 and explain each adiustment in a fuot- note. Designate debit adjustnents
by parentheses.
7. Do not indude on this page enties witt respec,t to deferred inoome taxes or taxes collected through payroll deduc-tions or othenvise p€nding
transmittal of such taxes to the taxing auhority.
8. Report in columns (i) through (l) how the taxes wer€ distibuted. Report in column (l) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 periaining to other u0lity departm€nls and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) he taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than ono utility depertnent or account, state in a fuourote tie basis (necessity) of apportioning sudr tax.
BALANCE AT :ND OF YEAR Line
No.(Taxes accrued
nccolnJ zso)
Prepaid Taxes
(lncl. in lgyunt 16s)Electric(Account 408.'1 , 409.1 )
Extraordinary ltems
(Acount 409.3)
Adiustments to Ret.
Eamings (Account €9)
(k)
Other
(t)
,|
1 1,000 15,201 2
1 't,000 't5,201 3
4
155,143 151,494 .|3l 5
-1,071 6
:B,A',',23a 7
8
I
10
't1
12
13
't4
15
16
't7
18
19
20
21
22
23
24
25
26
27
28
29
30
3'l
32
33
34
35
36
37
38
39
40
-15,1s6,342 2,111,954 89,348,997 I ,916,011 41
FERG FORM r{O.1 (ED. t2-96)Page 2Gl.l
Date of Remrt(Mo. Da, Yi)
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t18t2018
Year/Period of Report
20171Q4
FOOTNOTE DATA
Account
Account
Total
ount
Account
count
Account 4
409.1 1,733,485
262
1 154 335
B a1
I
It1
r4
4 I
UJ1 san L]S because o set account snota60 exDense
account
amount san et to ines 3,, 9, and 9 employer taxes flowinto vari-ous 408,1 accounts. In that same month these amounts are offset with a different
408.1- account. These payroll taxes are then allocated back to the balance sheet and O&M
accounts based on current month labor charges.
262 Line No.:
No.:10 Column: I
262 Line No; 18
No.:21
262.1
1 Line No.:
262.1 Line No.: 7
FERC 450_1
l,h2a-
2
$106
Column: I
D.12{7}
ldaho Powor Company (21 A Rasubmission
Date of Reoort(Mo, Da, Yi)
04t1812018
Year/Period of Report
End of 2O17lQ4
Report belour information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
nonutility operations. Explain by footnote any corToction adjustments to frie account balance shown in column (g).lnclude in column (i)
the average period over which the tax credits are amortizod.
Llne
No.Subd{$sions
Ea|anoe#rrogrnnrng
(b)
Defened for Year ACunen Adjustmenb
(s)ACOOUnT FaCr.(c)Alnoun((d)AGOOUNI NO.(e)Am((f unt
1 Elecbic Utility
I 3%
4o/o 323,927 46,347
4 7To
C 10o/o 16,941,112 1,694,96?
6 O(her-Federal 1,109,766 6,968,747 23,58C
7 Other-Shte 61,585,040 41'.t.4 3,537,615 411.4 't,316,575
I TOTAL 79,959,845 10,506,362 3,081,46€
c Oher (List soparately
and shor 3To, 4o/o, 7o/o,
10% and TOTAL)
1C 1|to 1,109,766 23,58C
11 30%411.4 6,968,747
12 Total Line No. 6 1,109,766 6,968,747 23,58C
't3
14
15 Sbte of ldaho 61,585,040 411.4 3,537,615 411.4 1,316,575
16
17
18
19
20
2'.1
22
23
24
25
26
27
28
3C
31
32
33
34
35
36
37
38
?o
4A
41
42
43
44
45
46
4t
48
FERC FORI' t{O.1 (ED. 12-89)Page 200
Name of Re$pondenl
ldaho Power Company
Oats of Report(Mo, Da, Yr)
oil1812018
Year/Period of Report
End of 2O17lQ4
Balance at Endof Year
(h)
Averaoe Pariod
of Allocaton
to lncome{i)
ADJUSTMENT EXPLANATION Line
No.
,|
2
277,580 6.99 3
4
15,246.145 9.99 5
8,0s4,933 6
63.806,080 46.78 7
87,384,738 I
I
1,086,186 47.06 10
6,968,747 11
8,054,933 't2
13
14
63,806,080 't5
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. r {ED. 12-89)Page 267
Thls R600rt Is:(1) frfiAn Orisinal(2) fiA Resubmission
ldaho Power Company (1)
(z',,
An Original
A Resubmission 0411812018
Year/Period of Report
End of 20171Q4
1. Report below the particulars (debils) called fcr conceming other defered credits.
2. For any deferred credit being amortized, show lhe period of amortization.
3. Minor it6ms (5olo of the Balance End of Year for Account 253 or amounts less than S100,000, whidrever is greater) may be grouped by classes.
Line
No.
Description and Other
Deforred Cr€dits
(a)
Balance at
Beginning of Year
(b)
OEBITS
Credits
(e)
Balance at
End of Year
(f)
Contra
Account(c)
Amount
(d)
1 Point to Point Trans Study(253201)1,U7,225 235 46,787 46,787 1,U7,225
2
3 FTV (2s3202)2.066,666 400 400,000 1,666,666
4 (Amort Period Mar 199&Feb 2023)
5
6 Sho Ban Trans ROW (253480)172,500 242 15,000 157,500
7 (Amort Period Jan 2005-D*2027)
8
I Operatlons Accrual (253550)524,456 232,401 134,922 48,750 438,284
10
11 Milner Falling Water (253953)855,672 186 1,063,636 207,9U
12 tunort Period (F€b 1992 - Feb 2017)
13
14 Postretirement Benefi ls (253960)1.448,043 253 231,187 1,216,876
15
16 Directors Defened Com pensation 3.560.669 40'l 468,695 327,745 3,419,719
17 (2s3e80-253999)
't8
19 Mlnor ltems (1) 253042 4,11'.!401 35,275 31,164
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
3s
36
37
38
39
40
41
42
43
M
45
46
47 TOTAL 10,479,342 2,395,482 662,410 8,7$,270
FERC FORM NO. I (EO. r2-S4)Page 269
End of
of Fieport
20171Q4
Name of Respondent
ldaho Power Company (21 A Resubmission 04118t2018
1. Report the information called for below ooncemlng the respondents accounting for debned income traxes rating to property not
subject to accelerated amortization
2. For other (Speciff),indude defenals ralating to other income and deductions.
Line
No-
Account
(a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
Amounts D€bated
to Account 41 0.1
(c)
Arnounts Credited
to Account 4'l'1.1
(d)
1 Account 282
2 Eleclric {95,355.S0'2.219,648 3,213,738
3 Gas
4 Other
5 TOTAL (Enter Total of lines 2 thru 4)4S5,355,902 2,219,648 3,213,738
6 Non0perating Proporty
7 O(her - Regulatory Asset 948,539,824
I Like Kind Exchange- Redass No 5,631,121
9 TOTAL Account 282 (Enter Tohl of lines 5 thru 1,M5,526,U1 2,219,648 3,213,738
10 Oassification of TOTAL
11 Federal lncome Tax 1,243,389,941 2,063,'.t42 3,210,502
't2 State lncome Tax 206,136,906 156,506 3,236
13 Local lncome Tax
NOTES
FERC FORM NO. r (EO. 12-90)Page 274
End of
of Report
2017tQ4ldaho Power Company Da,
l2',Resubmission 04118t2018
3. Use footnotes as required
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.Amounts DeUted
to Account 410.2
(e)
Amounts Crcdlted
to Account 411.2
(0
Debits Crcdits
Account
Cr6dited(s)
Amount
(h)
Account
Debit€d
(i)
Amount
(,)
1
254967 193,991,452 2821',t1 221.69t 300,592,05t 2
3
4
193,991,452 221,691 300,592,05t 5
o
182 364,210,382 5u,329,442 7
282100 -221,6*,5,409,42:8
558,201.83 890.330,92:I
10
182t254 526,123,79i 716,'t t8,78t 11
182 32,078,M'174,212,13.'t2
13
NOTES (Continued)
FERC FORM NO. r (ED. 12-96)Pago 275
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
0/.t18t2018
Year/Period of Report
2017tQ4
FOOTNOTE DATA
271 Llne No;2
Accourt
Depreciation Tim ing perati ng
tike Kin<l Exch€nqE -Reclass Nm-Rate Ba.se
Excese lletrred Tax on Depreciation {Reg U&}
CIIC-TEEblGdcd 1ffi
E n gineering Fees-Taxado{cct 107
Sotrgre-Lsbor Costs Dedrct6GAcct 107
1fi
b
?o17 Chanoes ilirino Yer Adiustments Debits Adustments Credits m17
Beginnirp
Balance
b
DR to
'410.1
c
CR to
411 1
d
Acct.
credted
d
E nding
Bdance
k
Amout
h
Acct
debted
i
Amount
I
'185,71a8{3(5,631, r211
0
(3,391,4591
$6q,142)
1,54q 08{
r7,599,697
5,810,998
2,182,516
2n,752
447.600
6.{9!},218
1,02q918
2,057,W.
1}?'ffi
251967 193,991, {52
2fp111 221,698
190,r$.923
(5,d09"123)
(1 93, 991 , 452)
{3,2S,s2s)
(416,6281
I,975.68,t
r1.2m..r9
495.3559(E 2.219.6t8 3.213.738 133.901.,r52 221.698 300.5p.058
FERC FORM NO.1 (ED, 12-871 Page 450.1
1. Report he information called for below concemirB the respondents accounting for defuned inoome taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include defenals relating to other income and deduclions.
CHANGES DURING YEARLine
No.
Account
(a)
Balance at
Eeginning of Year
(b)
Arounls ueDleo
to Account 410.1(c)
Anounts Grcdited
to Accoldt 41 1.1
I Acoount 283
2 Elecbic
3 Other Electric - See Note 36,638,5717S,550,000 64,494,466
4
5
6
7
8 Other - See Note 103.300,4ip
I TOTAL Elecfic (Total of lines 3 thru 8)182,856,4g2 36,638,571 64,494,466
10 Gas
11
12
13
14
't5
16
17 TOTAL Gas (ToEl of lines 11 lhru 16)
18 Other - See Note -06,258
19 TOTAL (Acct 283) (Entor Total of lines g, 1 7 and 18)182.761,234 36,638,571 64,494,466
20 Classification of TOTAL
21 Federal lncome Tax 153,310,006 32,269.243 59.843.,143
22 State lncome Tax 29,451,228 4,369,328 4,651,023
23 Local lncome Tax
NOTES
Name of Respondent
ldaho Porer Company
This(1)
(2t
ls:
Odginal
Dat€ of RoDort(Mo. Da, Yi)Year/Period of Report
End of 2O17lQ4A Resubmission 04t1812018
FERC FORil NO. ,l (ED. t2-96)?age 2?6
ldaho Power Company
This(1)
(2)
ls:Original Dato of Roport(Mo, Da, Yr)YearlPeriod of Report
End of 2O17lQ4
A Resubmission 041181201A
3. Provide in the space below explanations for Page 276 and 277. lnclude amounts relating to insignificant items listed under Other
4. Use footnotes as required.
(:HANGtrS T IFIING YFAFI
Del ,itsAmounts Dobited
to Account 410.2
(e)
Amounts Credited
to Account 41 '1.2
(o c'€l"d Amount
(h)
AC@UnIDebited(i)
Amounl
(i)
Balance at
End of Year
(k)
Line
No.
1
2
51,700,165 3
4
5
6
7
-30,,140,876 72,859,556 I
I-30,440,876 124,559,721
10
11
12
13
14
15
16
17
1894,385 2,381 -3,260
1994,385 2,387 -30,,140,876 124,556,461
20
-31,464,4A 94,348,750 2179,825 2,387
30,247,71',l 2214,560 1,023,618
23
NOTES (Continued)
FERC FORlrl NO. t (ED. 12.96)Page 2Tt
(;re
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
0411u2018
Year/Period of Report
2017tQ4
FOOTNOTE OATA
IVo..'3 Cdumn: b
Account
Emission Allowances
Renewable Energy Certificates (REC) Sales
Royalty lncome
Pension Expense
PCA Expense
lntervenor Funding Orders
Fixed Cost Adjustment
PS & lCosts
Oregon PCAM
2011 LIDAR Surveys Deferral
Boardman Decommission
Val my Settlement Adjustment
EIM Deferral
Langley Revenue Accrual
Conservation Expenses
Oregon Excess Porrer Costs
Siemens LTP Contract
Prepaid Credit Facility
Siemens OR DRB lnterest Reserve
Boardman RemovalCosts
TOTAL Line 3
276 Une No.: E Column: b
Pension-FAS 158
'158
TOTAL Line 8
276 Line No.: 18 Column: b
Account
EDC-Unrealized Gain/Loss From Rabbit Trust
SMSP-Unrealized Gain/Loss From Rabbi Trust
Tax
TOTAL Line 18
FORM NO.1 450.1
2017 Chanoes durino Year 2017
Beginning
Balance
DR to
410.1
CR to
411.1
Ending
Balance
2,001
52,633
361,616
36,782,759
20,893,473
160,438
17,375,925
260,755
247,953
102,284
554,697
0
0
370,974
2,145,392
(&1,691)
37,092
272,859
0
0
851,116
9,191,2U
7,010,630
1,782,635
102,200
,13,302
16,795,263
315,24
377AU
89,240
64,691
32,368
4,524
8,652
2,001
777,0*
124,276
15,426,204
27,904,103
84,138
11,143,024
156,798
552,533
45,m
190,587
5,635,510
105,779
1,192,862
985,826
0
23,{7
128,431
't3,482
2,903
0
126,691
237,U0
n,547,823
0
76,300
8,015,436
103,957
(202,380)
56,636
377,412
11,159,753
209,469
(44r',450)
1,248,806
0
46,153
144,428
(8,958)
5,749
79,556,060 36,638,571 64,494,466 51,700,165
2017 Adiustments Credits 20't7
Beginning
Balance
Acct.
debited Amount
Ending
Balance
103,332,881
$2.4491
190
190
(31,264,460)
823,584
72,068,421
791,135
103,300,432 (30,440,876)72,859,556
2017 2017
Beginning
Balance
4,420
(100,050)
372
DR to
410.2
2,311
92,064
10 129
CR to
4',11.2
2,259
Ending
Balance
4,473
(7,986)
253
(95,258 94,385 2,387 3,260,
Name of Respondent
ldaho Power Company (1)
(21
Original
Resubmission
Date of Report(Mo, Da, Yr)
44t1u2018
Year/Period of Report
End of 2O17lQ4
1. Report below the particulars (details) called for conceming other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Line
No.
Desoiption and Purpose of
Other Regulatory Liabilitis
(a)
Balance at Begining
of Current
Quarterlfear
(b)
DEBITS
Credits
(e)
Balance at End
of Current
Quarler/Year
(0
Account
Credited
(c)
Amount
(d)
1 lvlailet h Martet Short Term - (254001)7,831,41 7 171 7,813,262 '18,15s
2 IPUC Oder#2866'l
3
4 Oegon Solar Pilot t254005)3,762,081 Vdlous n,$7 836,34i 1,629,49,l
5 Oder#1G198
6
7 ldaho DSM Rider (254201)10,730,151 Various 51,962,111 4l,639,594 407.60,(
8 IPUC Order#29026
9
10 Oher Reg Liab-lD BRDMN Decomm (254393)947,24i 917,242
11
12 BPA Crcdit Residential ldaho (25440,l)1,848,994 Various 9,895,622 9,011,11 964,483
't3 Advice #'15-13
14
15 Oregon Geen Tags (254415)41,692 254 32,419 9E,r/1 't08,0,l4
16 Advice #11{86
17
18 Brkiger Deprcciatim (254800)1,151,436 i187,&3 1,938,83S
19 OPUC Oder#12-296
20
21 RL.WAQC CRYOVR (254901 )64,501 40,101 104.602
22 IPUC Order #29505
23
24 Unfunded Accum Def lncome Tax (254966)51,326,330 Various 213n,4s4 717,178 30,666,054
25
26 RL-DEF rNC TAX-ARAM (254967)193,991,452 1 93,991.45i
27
28 RL-DEF rNC TAX-AR M GROSS-UP (2s4968)68,077,705 68.077,705
29
30 RA-PCA Deleral]9 (254 4251 Various 50,060,n0 55,396,931 5,336,641
31
32 RA-OR BDMN Deconm Oder#'12-235 Various m6,686 354,59('t47,904
33
34 Mhor ltams (7)( 13,589)1,81 1,734 1,891,31:65,9S
35
36
37
38
39
40
41 TOTAL 77,013,0r3 't43,187,545 373,548,738 307,404,206
FERC FORM NO. 1/3-Q (REV 02-04)Page 278
Name
ldaho Power Company (1)
(2)
ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04118i2018
Year/Period of Report
End of 20171Q4
'1. Thc following instruclions generally apply to the annual verion of theso pagos. Do not report quartody data in columns (c), (e), (0, and (g). Unbilled rovanues and MWH
related to unbilled revenues n€ed not be reported s€parately as rEquired in lhe annusl v.rsion of thasc pagss.
2. Roport below operaling r6v6nu€s for €ach prescrib€d account, and manufactured gas revenues in totrl.
3. Roport number of customers, columns (f) and (g), on the basis of m6tors, in addition to the numbor of flat rate accounts; oxcopt that wh3l? separate m6l€r r€adings aro added
for billing purposes, one customer should b6 counted for each group of meters addsd. Th€ -average numb€r of customers means lhe averagB of trvclvo figurcs at lhe clos6 of
cach month.
4. lf increas€s or decreases from previrus period (colunns (c),(o), and (9)), are not derivcd ftom provirusly reporled liguras, axplain any inconsistencios in a footnote.
5. Oisdose amounts of $250,0fi) or greator in a footnoto for accounts 4.51 , 456, and 457.2.
Line
No.
Title of Acoount
(a)
Opereling Rovouas Y@r
b Dab Quarledy/Annual
(b)
Operaling Revenues
Previous year (no Quarterly)
(c)
1 Sales of Electricity
2 (440) Residential Sales 552,333,276 514,953,833
3 (442) Commercial and lndustrial Sales
4 465,145,591 455,158,518Small (or Comm.) (See lnsr. 4)
5 Large (or lnd.) (See lnstr. 4)195,124,244 182,590,036
6 (441) Public Street and Highway Lighting 4,079,095 3,996,825
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
I (448) lnterdepartmental Sales
10 1,216,682,206 1.156,699.212TOTAL Sal6s to Ultimate Consumers
11 (447) Sales br Resale 33.381.940 25,204.985
12 TOTAL Sales of Elecbicity 1,250,004,146 1,181,904,197
13 (Less) (449.1) Provision for Rate Retunds 10,706,040 10,706,040
't4 1,239,358,'106 1,171,198,157TOTAL Revenues Net of Prov. for Refunds
15 Other Operating Revsnues
16 (450) Forbited Discounts
17 (451 ) Miscdlaneous Service Revenues 4,089,6174,273,74
't8 (453) Sales of Wat6r and Water Power
19 15,236,098 14,260,349(454) Rent from Elecbic Property
20 (455) lnterdepartmental Rents
2l (456) Other Electric Revenues 39,92,t,003 u.?j,a,875
22 (456.1) Revenues from Transmission of Electricity of Others 42,071,453 31,4N,797
23 (457.1) Regional Conbol Ser',rice Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 101 ,502,298 84,100,642
27 TOTAL Eloctric Operating Revenues 1,340,860,404 1,2s5,298,799
FERC FORM NO.(REV.Page 300
Name or Ke3ponoent
ldaho PowerCompany
I nrs
(1)
(2)
ls:
Original
A Rosubmission
uate ot Keoon(Mo, Da, Yi)Yo8?renoo ol Kepon
End of 20171Q4
04t18t2018
in a foolnob.)
7. Sa6 paga6 108-109, lmportant Changes &ring Pcdod. for important n€ry toniby addcd and impodant rate ircraaso or d€crBas.e.
8. For Lines 2,4,5,and 6, s€. Pagc 304 for amountr r€latirq to unbill.d .rv.nu6 by accounl6.L lnclude unmetEr€d salos. Prcvk e doteils of such Sabs in a footnote.
MEGAWATT HOURS SOLD AVG.NO. CUSTOMERS PER MONTH
Year b Date Quarterly/Annual
(d)
Amount Previous year (n0 Quarterly)
(e)
Cunent Year (no Quarterly)
(0
Previous Year (no Quarterly)
(s)
Line
No.
I
5,004,352 448,800 440,362 25.354.568
3
5,838,862 5,916,649 87,675 86,621 4
3,345,712 3,243,3M 120 121 5
631,812 31,rt05 2,995 2,791
7
I
I
14,570,954 't4,195,750 539,s90 529,901 10
1,185,879 112,135,649
16,706,603 15,381,629 539,590 529,S01 12
13
16,706,603 15,381,62S 539,590 529,901 14
Line 12, column (b) includes $
Line 12, column (d) includes
4,243.250
-fit,190
of unbilled revenuea-
MWH relating to unbilled revenues
FERC FORrrr NO- rr&,Q (REV- r2-05)Page 301
Name of Respondent
ldaho Porver Company
This Report is:
(1) X An Original
(2) * A Resubmission
Date of Report
(Mo, Da, Yr)
04t18t2018
Year/Period of Report
20171Q4
FOOTNOTE DATA
_lThis amount consists of:
Service Establishment,/Connection Charges(lncLudes late and after hour charges)
Misc. Under $250,000
$4,079,244
194,504
TotaL Account 451 $ 4 ,273,1 44
s amount cons sts of:Alternate Di-stribution Service
DSM ActivltyMisc. Under $250,000
9 54 6,278
39 ,240 , 688
L34,037
Total Account 456 $ 39,921,003
3@ Line No.: 2l c
Th s amount cons stsA-Iternate Di-stribution Servi-ce
DSM Activi-tyMisc. Under $250,000
$ 321,995
33,754,060
183,824
Total Account 456 $ 34,259,8't9
300 Une No.: 27 Column: b
FERC FORM 1 Page 450.1ED.12€7)
Name of Respondent
ldaho Power Company
This
(1)
(2)
Reoort ls:
p(1An original
Date of Report(Mo. Da, Yr)
Year/Period of Report
EM of 20171Q4
A Resubmission 04t18t20't8
SALES OF ELECTRICTTY BY RATE SCHEDULES
1. Report below for each rat€ schedule in €ffect during the year the MWH of elefiicity sold, revenue, av€rage number of qJsbmer, average Kwh per
customer, and average revenue p€r Kwh, exduding date for Sales for Resale which is reported on Pages 310-31 1.
2. Provide a subheading and total for each presctibed operating r€venue ac@unt in lhe seguenoe followed in "Electric Operating Revenues,' Page
300-301. lf the sales und€r any rate schedule are da$ifi€d in mors than one rsvdlue ac@unt, List the rate sdredule and sales data under eacrr
applicable revenu€ account subheading.
3. Where the same customers are seryed und6r more than one rate schedule in lhe same rovgnue account classification (sudr as a general rosid€ntial
schedule and an off peak water heating schedule), the entries in column (d) for tho special schedule should denote he duplicalion in number of reported
customers.
4. The average number of q.rsliomers should be the number of bills rendered during tle year divkJed by the numbor of billlng periods during he year (12
if all billings are made monhly).
5. For any rate schedule having a fuel adjustment clause stiate in a footnote he estimated additional revenue billed pursuant ther€to.
6. Report amount of unhrilled revenue as of ond of year for each applicable revenue account subheading.
Line
No.
NUmOer ano I tue ot Hate scneoute
(a)
MWn 50to
(b)
Kevenue
(c)
Averaog Numoer
of ciflfmers KWn Ot l,alesPer tgstomer Tfr?fts%E*(0
1 440 - Residential Sales:
2 01 - Residential 5,371,991 557,376,181 447,534 12,004 0.1038
4,738 469,554303 - Residential Mastor Met€r 23 206,000 0.0991
4 05-Residential -TOO 22,175 2,216,437 1,243 17,840 0.1000
5 15 - Dusk to dawn lighting 2,631 651,818 o.2477
b Unbilled Revenues -46,967 -3,748,190 0.0798
7 Olher Revenues 4,632,524
8 Total 440 5,354,568 552,333,276 448,80C 11 ,931 0.1032
s
1C 442-Commerclal & lndustrial Sales
11 07 - General seMce 155,816 19,620,99€30,732 5,07C 0.125S
12 511,87309P - General service 33,863,636 227 2,254,947 0.0662
13 09S - General seMce 3,389,881 253,743,24',1 34,963 96,956 0.0749
14 6,6't 7 47J2a 1,654,25009T - General service 4 0.0712
15 15 - Dusk to Dawn Light 4,249 756,975 o.1782
16 19P - Uniform rat€ contracls 2,311,61C 135,931,12t 113 20,456,726 0.0588
17 19S - Uniform rate contracb 6,047 39s,41C 1 6,047,000 0.0654
18 19T - Uniform rate contracE 1 35,052 7,702.02C 7 45,017,333 0.0570
19 1,771,813 1$,213,125 20.824 85,101 0.082s24S - lnigation Pumping
20 40 - General service 10,43€918,425 929 11,234 0.0880
21 897,443 46,840,101 299,147,ffi1 0.0522Special Contracts a
22 Commercial & lndusfial Unbill -16,263 -501.763 0.0309
23 't4,315,42COther Revenues
24 fotal 442 9J84,574 660.269,835 87,795 104,6'14 0.0719
25
26 zl44 - Public Street Lighting:
27 40 - General service 784 69,294 461 1,701 0.0884
2e 28,195 3,787,0S7 1,u41 14,526 0.134341 - Street lighting
29 42 - Traffic control lighting 2,793 180,1 28 593 4,710 0.0645
30 40 6,703 0.1676Unbilled
31 Other Revenues 35,873
32 31,812 4,079,095 2,9S5 10,622 o.'t282Total 444
33
34
3s
36
31
38
20
40
41 14,634.144 1,220.925.45C 539,59(27.121 0.0834TOTAL Billed
42 Total Untilled Rev.(See lnst. 6)€3,19(4,243,2il ((o.0672
1,216,682,206 539,59(27,0U 0.083543TOTAL14,570,95/
FERC FORM NO. 1 (ED. 12-95)Page 304
ldaho Power Company (2)
An
A Resubmission
Date of Reoort(Mo. Da, Yi)
04118t2018
Year/Period of Report
End of 20171Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumerc) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-321).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or afiiliation the respondent has with the purchaser.
3. ln column (b), enter a Statistica! Classification Code based on the original contractual terms and conditions of the service as bllows:
RQ - for requiremenls service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this servios in its system resourco planning). ln addition, the reliability of requirements service must
be the same as, or second only to, the supplie/s service to its own ultimate consumers.
LF - for tong-term service. 'Long-term" means ftve years or Longer and 'firm' means that service cannot be intemrpted for economic
rsasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must aftempt to buy em€rgency energy
fom third parties to maintain deliveries of LF sewice). This category should not be used for Long-term firm service which meets the
definition of RQ seMce. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service except that'intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitrnent for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Longterm" means five years or Longer. The availability and reliabality of
service, aside from transmission constraints, must matcfi the availabili$ and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. fhe same as LU service except that "intermediate-term' means
Longer than one year but Less than flve years.
Line
No.
Name of Company or Public Authority
(Foohote Affliations)
(a)
Sbtistical
Classifi-
calion
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
MonthlyEilling
Demand (MW)
(d)
Actual Demand (MW)
,tveraqeMonthly NCP Demanr
(e)
Averaoa
Monthly CFrDemand
(0
1 3Phases Renewabies, lnc.SF WSPP
2 ADM lnvestor Services, lnc.OS
3 Arizona Public SeMce Co.SF VVSPP
4 Avangrid Renewables, LLC SF WSPP
5 Avangrid Renewables, LLC OS WSPP
b Avista Corp.os WSPP
7 Avista Corp.SF WSPP
8 Basin Elec{ric Power Cooperative OS WSPP
s Basin Electric Power Cooperative SF WSPP
't0 Blac* Hills Power lnc.OS WSPP
1'.!Black Hills Power lnc.SF WSPP
12 Black Hills Power lnc.OS WSPP
13 Bonneville Power Adminishation SF WSPP
14 Bonneville Power Administration OS WSPP
Subtotral RQ 0 0 0
Subbtal non-RQ 0 0 0
Total 0 0 0
FERC FORit NO. I (ED. 12-90)Page 310
SAL
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:Date of Reoort(Mo, Da, Yi)Year/Period of Report
End of 2O17lQ4An Original
A Resubmission 04t1u2018
' FOR RESALE (Account 447
OS - for other service. use this category only for those services wtrich cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this oode for any accounting adiustments or "true-ups" for s€wioe provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. Aftsr listing all RQ sales, enter'Subtotal - RQ'
in column (a). The remaining sales may then be listed in any oder. Enter "Subtotal-Non-RQ" in column (a) afler this Listing. fnter"Total" in column (a) as Orc Last Line of the schedule. Report subtotals and tota! for columns (9) through (k)
5. ln Column (c), identiff the FERC Rate Schedule or Tarifi Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges lmposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly nonroincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (0. For al! other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system rsaches its nlonthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawaft hours sho/vn on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see insfuction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ'amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The'Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
4O1,iine24.
'10. Footnote enlries as raquired and provide explanations folloring all required data.
REVENUEMegaWatt Hours
Sold
(s)
Demand Charges
($)
(h)
Energy Charges
($)
(i)
Line
No.Other Charges
($)
0)
Total ($)
(h+i+j)
(k)
54,925 1,',t32,719 1,132,719 1
951,740 951,740 2
'11,783 93,269 93,26S 3
7,978 116,711 116,711 4
18,382 18,382 5
I 1,000 67,020 67,020 b
266,625 4,577,653 4,577,653 7
34,532 34,532 I'r0,367
17,945 68,516 68,516 I
62,863 394,,16C 394,46C 10
35,817 236,166 236.16(11
12AOEC
44,641 886,927 886,92i 13
1 36 3€14
0 0 0 0 0
2,135,649 0 29,244,648 4,137,292 33,381,940
2,'.t35,ilg 0 29,214,U8 1,137,292 3:1,381,9rt0
FERC FORM NO. I (ED.12-90)Page 311
Name of Respondent
ldaho Power Company
I his
(1)
(2)
An
ls:
Original Dats of Regort(Mo, Da, Yr)
Year/Period of Report
End of 20171Q4
A Resubmission 0411812018
't. Report all sales for resale (i.e", sales to purchaserc other than ultimate consumerui) transacted on a setUament basas other than
power exchangos during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reporled on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier indudes projected load for this service in its system resource planning). ln addition, the reliability of requirements service must
be the same as, or second only to, the supplie/s service to its own ultimate consumeni.
LF - for toqg-term service. "Long-term' means five years or Longer and "firm" means that service cannot be Interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency energy
ftom third panies to maintain deliveries of LF seMce). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all lransactions identified as LF, provide in a footnote the termination date of the contracl defined as the
earliest date that either buyer or setter can unilaterally get out of the contrac{.
lF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm servico. Use this category for all firm services where the duration of each period of commitmenl for service is
one year or less.
LU - for Long-term service ftom a designated generating unit. "Long-term" means five years or Longer. The availability and reliabilig of
service, aside fiom transmission constraants, must match the availability and reliability of designated unit.
lU - for intermediate-term service ftom a designated generating unit. The same as LU seMce except that'intermediate-term'means
Longer than one year but Less than five years.
Actual Demand (MW)Line
No.
Name of Company or Public Auhority
(Footnoto Affi liations)
(a)
Sbtislical
Classifi-
calion
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
uonttriy tidF-Demanr
(e)
AveraoeMonthly CFrDemand
(0
I SF WSPPBrookefield Energy Marketing
2 SF WSPPCalpine Energy Services, L.P.
3 Cargill Power Markets LLC SF WSPP
4 Cargill Power Markets LLC os WSPP
5 Citigroup Energy lnc.SF WSPP
6 os WSPPCitigroup Energy lnc.
SF7City of Anaheim WSPP
I Clatskanie PUD SF WSPP
I SF WSPPCP Energy Marketing (US) lnc.
WSPPOS10EDF Trading North America, LLC
11 EDF Trading North America, LLC SF WSPP
12 Energy Keepers os WSPP
13 SF WSPPEnergy Keepers
14 Energy Keepers WSPPos
Subtotal RQ c 0 0
Subtotal non-RQ c 0 0
0 0 0Total
FERC FORM l{O.l (ED. 12-90)Page 310.1
5A
Name
ldaho Power Company (1)
(2)
An Original
Resubmission
Dat6 of Report
(Mo, Da, Yr)
a41812018
Year/Period of Report
End of 2O'l7lQ4
OS - for other service. use this category only for those servioes which cannot be placed in the above{efined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the naturo
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups'for service prcvided in prior reporting
years. Provide an explanation in a fuotnote for each adiustment.
4. Group requirements RQ sales together and report them starting at line number one. Afi6r listing all RQ sales, enter'Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. ln Column (c), identiff the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
wtrich service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monhly (or Longer) basis, enter he
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (0. For all other types of sarvice, enter NA in columns (O), (e) and (D. Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplie/s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawafr basis and explain.
7. Report in column (g) the megawaft hours shown on bills rendered to the purchaser.
8. Report demand charges ln column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of he amount shown in column (i). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ' amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
4O1,iine24.
10. Footnote entries as required and provide explanations following all requircd data.
Mogawatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+i)
(k)
Line
No.Oemand Charges
($)
(h)
Energy Charges
($)
(i)
Other Charges
($)
0)
4,400 106,068 106,068 1
721 17,138 17,138 2
542 3,084 3,m4 3
6,390 6,390 4
186 3,337 3,337 5
-49,81€-49,818 o
53,943 1,400,236 't.400.23€7
595 10,983 10,983 I
60 720 720 I
250 2,50C 2,s00 10
103,867 3,522,296 3,522,2!X 11
162 514 514 't2
336 3,351 3,351 13
1€16 14
0 0 0 0 0
2,135,il9 0 29,244,648 4,137,292 33,381,940
2,135,649 0 29,2U,U8 4,137,292 33,381,940
FERC FORM NO. r (ED. 12-90)Page 311.1
l,lame of Rsspondoflt
ldaho Power Company
(1)
(2)
An Original
A Resubmission a4h8t2018
1. Report all sales for resale (i.e., sales to purchasers oher than ultimate clnsumefti) tmnsacted on a seftlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlemsnts for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-3271.
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or afhliation the respondent has with the purchaser.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system nesouroe planning). ln addition, the reliability of requirements service must
be the same as, or s€cond only to, the supplie/s service to its own ultimate consurners.
LF - for tong-term service. "Long-term" means five years or Longer and "firm' means that seMce cannot be intenupted for economic
reasons and is intended to remain rsliable even under adverse conditions (e.9., the supplier must attempt to buy emergency energy
from trird parties to maintain deliveries of LF seMce). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earllest date that either buyer or setter can unilaterally get out of the contract.
lF - for intermediate-term flrm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm seMces where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. 'Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must matdr the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that 'intermediate-term" means
Longer than one year but Less than five years.
Line
No
Name of Company or Public Authority
(Foohote Afftliations)
(a)
StatisUcal
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Bllling
Demand (MW)
(d)
Actual Demand
Monthly
1 Eugene Eleclric Board SF WSPP
2 Exelon Generation Company. LLC SF WSPP
3 Macquarie Energy LLC SF WSPP
4 Macquarie Energy LLC os WSPP
5 Morgan Stanley Capital Group lnc,os ISDA
6 Morgan Stanley Capital Gmup lnc.SF ISDA
7 Morgan Stanley Capital Group lnc.OS WSPP
8 Municipal Energy Agency of Nebraska os WSPP
I Municipal Energy Agency of Nebraska SF WSPP
10 NV Energy OS WSPP
11 NV Energy SF WSPP
12 NV Energy os WSPP
13 NorthWestern Energy os WSPP
14 NorthWestern Energy SF WSPP
Subtotal RQ U 0 0
Subbtal non-RQ 0 0 0
Total 0 0 0
End of
of Report
2017tQ4
FERC FORM NO. 1 (ED. 12-90!Page 310.2
AVgrag{,
(f)(e)
Name
1)ldaho Power Company (2t Resubmission
Dato of Report
(Mo. Da, Yr)
04t18t2018
Year/Period of Report
End of 2O17lQ4
OS - for other servios. use tias category only for thos€ seMces which ciannot be placed in the above-defined categories, such as all
non-ftrm servic€ regardless of the Length of the contract and soruice ftom designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Us6 this code for any accounting adiustrnents or'tru€-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ' in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. ln Column (c), identifi the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identilied in column (b), is provided.
6. For requirementrs RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enterthe
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the meterad demand during the hour (60-minute
integration) in which the supplie/s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawafts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column fi). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ'amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
4A1,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(s)
REVENUE Total (S)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
Other Charges
($)
0)
4,786 155,200 155,20C 1
764 16,563 16,563 2
602 14,628 't4.628 3
10s 10s 4
28,236 130,713 130,713 5
239,584 2,617,265 2,617,265 6
1,338,642 1,338,642 7
126 630 630 8
410 4,133 4,'t39 9
2,172 22,O04 22,004 10
145,305 1,158,638 't,158,638 11
40 40 12
14,575 111,154 111,154 13
10,908 212,'.t89 212,189 14
0 0 0 0 0
2,135,649 0 29,244.648 4,137,292 33,381,9rO
2,135,649 0 29,2U,UE +137,n2 33,381,940
FERC FORtrt 1{O. I (ED. 12-90}Page 311.2
Da,End of
of Report
20171Q4
04t1812018
Name
(1)
(2)ldaho Power Company An Original
A Resubmission
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schsdule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate tho name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. ln column (b), enter a Statistical Classification Code based on the or(;inal contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes proiected load for this service in its system resource planning). ln addition, the reliability of requirements service must
be the same as, or second only to, the supplie/s service to its own ultimate consumem.
LF - for tong-term sorvice. "Long-term" means five years or Longer and "firm' means that service cannot be intemrpted for economic
reasons and is intended to rcmain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF servim). This category should not be used fur Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earllest date that either buyer or sefter can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service except that "intennediate-term' means longerthan one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term seMce from a designated generating unit. "Long-term" means five years or Longer. The availabili$ and reliability of
service, aside from transmission crnshints, must match the availability and reliability of designated unit.
lU - for intermediate-term servioa ftom a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line
No.
Name of Company or Public Auhority
(Footnote Affi lialions)
(a)
Statistical
Classifi-
calion
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVeraoe
Monthly NCF Demanr
(e)
AveraoeMonthly CPDemand
(0
1 NorthWestem Energy OS r-7
2 PacifiCorp lnc.os WSPP
3 PacifiCorp lnc.SF WSPP
4 PacifiCorp lnc.os T-7
5 Porfland General Elecfic Company OS WSPP
o Pordand General Electric Company SF WSPP
7 Portand General Electric C,ompany os T-7
8 Poriland General Electric Company OS WSPP
I Powerex Corp.os WSPP
't0 Powerex Corp.SF WSPP
1'.|Public Service of Colorado SF WSPP
12 Puget Sound Energy, lnc.os WSPP
13 Puget Sound Energy, lnc.SF WSPP
14 Pugel Sound Energy, lnc.OS T-7
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90)Page 310.3
Name Dalo of Report(Mo, Da, Yr)
Year/Period of Report
End of 2O17lQ4(1)
(21
Anldaho Power Company A Resubmission 04t18t2018
OS - for other servios. use this category only for tho6e services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adiustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After lis{ing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ' in column (a) after this'Listing. Enter
'Totial" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. ln Column (c), identifi the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which seMce, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincldent peak (CP)
demand in column (0. For all other types of sarvice, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplie/s system reaches its monthly peak. Demand reported in columns (e) ancl (f) must be in megawatts.
Footnote any demand not slated on a mElawatt basis and explaln.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), eneryy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The'Subtotal - RQ" amount ln column (g) must be repo(ed as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requlrements Sales For Resale on Page
4O'l,iine24.
10. Footnote entries as reguired and pmvide explanations fullowing all required data.
REVENUE
Energy Charges
($)
(i)
Olher Charges
($)
(i)
Totar($)
(h+i+j)
(k)
Line
No.
Megawatt Hours
Sold
(s)
Demand Charges
($)
(h)
7 204 204 1
1,100 1,100 2230
1,120,716 1,120,71e 382,2s1
920 920 439
155 900 900 5
2'r,889 323,031 323,O31 6
667 667 723
2,912 82,912
I10,580 28,963 28,963
41,773 193,026 1 93,026 10
10,569 10,563 11487
12,750 't21,275 't2,750
11 ,468 208,991 208,991 13
3,029 3,02S 14109
0 0 0 00
0 29,2U,648 4,137,292 33,381,9402,135,649
29,24,,,W 4,t37,292 33,38't,9402,135,6a9
FERC FORTU NO.1 (ED. t2-90)Page 311.3
0
Name ol Respondent
ldaho Power Company
This
(1)
F
I
I12)
ort ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4t1812A18
Year/Pedod of Report
End of 2O17lQ4
'1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a setflement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settements for imbalaneed exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. ln column (b), enter a Statistical Classification Code based on the or(7inal contractual t6rms and conditions of the service as follows:
RQ - for requirements servics. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., he
supplier includes projected load for this service in its system resource planning). ln addition, the reliability of requirements service must
be the same as, or second only to, the supplie/s service to its own ultimate consumers.
LF - for tong{erm service. "Long-term" means fivs years or Longer and *firm" means that service cannot be intemrpted for economic
reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency energy
from hird parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identlfled as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
lF - for intermedlate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm seMce. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term' means five years or Longer. The availability and reliability of
seMce, aside ftom transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term seMce fiom a designated generating unit. The same as LU service except that "intermediate-term'means
Longer than one year but Less than five years.
Line
No.
Name of Company or Public Authority
(Footnote Affliations)
(a)
Sta0sUcal
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
uonniy tiditbemanr
(e)
AveruroeMonthly Cfuemand
(f)
1 Rainbow Energy Marketing Corporatlon SF WSPP
2 Seatde City Light OS WSPP
3 Seatte City Ught SF WSPP
4 Shell Energy North America (US), L.P os WSPP
5 Shell Energy North America (US), L.P SF WSPP
6 Shell Energy North America (US), L.P os WSPP
7 Siena Pacific Powsr Co., dba NV Energy o8 T-7
I Snohomish County PUD SF WSPP
I Tacoma Power os WSPP
10 Tacoma Power SF WSPP
11 Talen Energy Markeffng, LLC.os WSPP
12 Talen Energy Marketing, LLC.SF WSPP
13 Tenaska Power Services Co.SF WSPP
't4 Tenaska Power Services Co.os WSPP
Subtotal RQ c 0 0
Subtotal non-RQ c 0 0
Total 0 0 0
Page 310.4FERC FORir r{O.1 (ED.12-90)
ldaho Power Company (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
o4t1u2018
YearlPeriod of R€port
End of 20171Q4
IOS - for other service. use this €tegory only for those s€rvices which cannot be placed in the above{efined categories, such as all
non-firm seruice regardless of the Length of the contract and service from designated units of Less than one year. Describe the naturs
of the service in a footnote.
AD - fur Out-of-period adjustment. Use this code for any accounting adjustments or'true-ups'for service provided in prior reporting
years. Provide an explanation in a footnote for each adlustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter 'Subtota! - RQ'
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
'Total" in column (a) as the Last Line of the schedule. Report subtotrals and total for columns (9) through (k)
5. ln Column (c), identiff the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
avemge monthly billing demand in column (d), the av€rage monthly noncoincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For al! otier types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shorn on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charg$ in column (i), and the total of any other types of chaqes, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in @lumn fi). Report in column (k)
the total charye shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non:RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The'Subtotral - RQ" amount in column (g) must be repoiled as Requirements Sales For Resale on Page
l()1 , line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
4A1,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges($)
(i)
Other Charges
($)
(i)
197,775 1,714,818 1,714,8le,1
1,880 29,465 29,465 2
10,063 241,791 241,791 3
48,506 407,937 407,937 4
254,163 4,287,302 4,287,302 5
492,241 462,241 6
19 5't6 51€7
2,413 83,670 83,670 I
50 s0c 500 I
3,13'l 67,390 67,390 10
5,200 29,565 29,565 11
7,541 66,1't3 66,1 13 12
15,932 69,s84 69,5B4 13
29,56S 29.56S 14
0 0 0 0
2,135,649 0 29,244,U8 4.137.292 33,381,940
2,135,649 0 25,24d,,U8 4,137,292 33,381,940
FERC FORM NO.1 (ED.12-90)Pagc 3{{.4
0
Name of Respondent
ldaho Power Company
I nts
(1)
(2)I
I
Dn 13:
An Original
A Resubmission
Date of Report(Mo, Oa. Yr)
0411812018
Year/Period of Report
End of 2O17lQ4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalancod oxchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain ln a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. ln column (b), enter a Statistical ClassificaUon Code based on the original contractual terms and conditions of the service as fullows:
RQ - for requirements servioe. Requirements seMce is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in ils system resource planning). ln addition, the reliability of reguirements seMce must
be the same as, or second only to, the supplier's service to its own ultimate oonsumers.
LF - for tong-term service. 'Long-term' means five years or Longer and "firm" means that service clnnot be intemrpted for economic
reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy ernergency energy
fom third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service except that "intermediate-term'means longer than one year but Less
than five years.
SF - for short-term firm servi@. Use this category for all firm services where the duration of eacfi period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availabilig and reliability of designated unit.
lU - br intermediate-term service from a designated generating unit. The same as LU service exceptthat'intermediate-term'means
Longer than one year but Less than five years.
No.
Line Name of Company or PublicArJthority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AvetaqeMonthly NCF Demanr
(e)
Av€raoe
Monthly CFrDemand
(0
1 The Energy Authority, lnc.SF WSPP
2 The Energy Authodty, lnc.os WSPP
3 TransAlta Energy Markeling (U.S.), lnc.SF WSPP
4 TransAlta Energy Marketing (U.S.), lnc.os WSPP
5 Utah Associated Municipal Power Systems SF WSPP
t)Prior Year Corrections os WSPP
7 Transmission Penalty Distribution OS
8
I
10
11
12
13
14
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORit NO. 1 (ED. 12-90)Page 310.5
An Original
A Resubmission
of Report
Da, Yr)
Year/Paiod of Report
End of 20171Q4
04118120',t8
Respondent (1)
(2)ldaho Power Company
OS - for other service. use this category only for those servioes which cannot be placed in the above{efined categories, such as all
non-firm service regatdless of the Length of the contract and service ftom designated units of Less than one year. Describe the nature
of the seMce in a footnote.
AD - for Out-ofaeriod adiustm€nt. Use this code for any aocounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter'Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) afier this Listing. Enter
'Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. ln Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provicled.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) dernand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of servlc€, enter NA in columns (d), (e) and (0. Monthly NCP demand is the maximum
metered hourly (6&minute integration) demand in a month. Monthly CP demand ls the metered demand during the hour (60-minute
integration) in which tha supplie/s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a msgawatt basis and explain.
7. Report in column (g) the megawaft hours shown on bills rendered lo the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adfustments, in column fi). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The'Subtotal - RQ'amounl in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
4Q1,iine24.
10. Footnote entries as required and provide explanations following all required data.
Megawatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges($)
(i)
Other Charges
($)
(i)
265,851 3,932,104 3,932,104 1
5,724 5,72Q 2
8,914 288.947 288,947 3
34,59e 34,59S 4
7,440 278,800 278,800 5
10 327 327 6
56,285 56,285 7
8
I
10
't1
12
13
14
0 0 0 0 0
0 29,244,648 4,137,292 33,381,940
2,'t35,649 0 29,2U,U8 1,'t3t,292 33.3E1,940
FERC FORM NO. 1 (ED. 12-90)Page 311.5
2,135,4r9
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t't812018
Year/Period of Report
20171Q4
FOOTNOTE DATA
Schedule Page: 310 Line No.: 2 Column: b
ADM Investor Futures, Inc Account Document,
Schedule Pagi: 310 Line No.: 5 Cotumn: bFinancial Transm,ission Losses
ichedule Page: 310 Line No.: 6 Column: b
dated May
dated March 7, 20lt
5f 20L5
Non-Firm
Sclredule Page:310 Line No.:8 Cdumn: b
Non-Firm
Schedule Page: 310 Line No.: 10 Cotumn: b
Non- Fi rm
Schedute Page: 310 Line No.: 12 Column: bEinanci-al Transm.ission Losses
Schedule Page:310 Line No.: 11 Column: b
Reserves
Sclredule iage: 310-1 Line No.: 4 Column: bFinancial Transmission Losses
Schedule Page: 310.1 Line No.:6 Column: b
ISDA tvl;rslei Agreemenr with Cir-igroup Energy Inc.
Schedule Page: 310.1 Line No.: 10 Column: b
Non-Firm
Schedute Page: 310.1 Line No-: 12 Column: b
Non-Firm
Schedute Page: 310.1 Line No.: 14 Column: bFlnancia1 Transmissi-on Losses
Schedute Page: 310.2 Line No.: I Cotumn: b
Financial Trarsmission Losses
Sclredule Page: 310.2 Line No.: 5 Cotumn: b
Non-Firm
Schedule Page:310.2 Line No.:7 Column: bFinancial Transmission Losses
Schedule Page:310.2 Line No.:8 Column: b
Non-Eirm
':schedule Page:310.2 Line No.:10
Non-Firm
Schedule Page: 310.2 Line No.: 12Iinancial Traasmission Losses
Schdule Page: 310.2 Line No.: 13
Non- Fi::m
Schedule Page: 310-3 Line No.: I
Reserves
Schedule Page:310.3 Line No.:2
Non-Firm
Schedute Page: 310.3 Line No.:4
Reserves
Sclredule Page:310.3 Line No.: 5
Non- !'irm
Schedule Page: 310.3 Line No.:7
Reserves
Schedule Page: 310-3 Line No.: IFinanciai Transmission Losses
Schedule Page: 310.3 Line No.:9
Non-f irm
Schedule Page: 310.3 Line No.: 12Non-Firn
Column: b
Column: b
Column: b
Column: b
Column: b
Aofumn: b
Column: b
Column: b
Column: b
Column: b
Column: b
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1u2018
Year/Period of Report
2017tQ4
FOOTNOTE DATA
310.1
Reserves
rm
Non-rm
sses
310.1 Line No.:7 Column: b
erves
Non-rm
on-rm
1 sion Losses
on se5
Line No.:1 Column: bssion Losses
310.5 Line No.: 6rcorrectNS
No.:7 Column: b
Tr ssion penalty t ts
FERC FORM NO.1 (ED. fl'87l Page 450.2
1 Column: b
310.1 Line No.:
Line No.: 11 b
Column: b
310.5 Line No.: 2 b
Schedule Page:310.3 Line No.:14 Column: b
Line No.: 9 Column: b
lf the amount for previous year is not derived fom previously reported figures, explain in foolnote.
Line
No.
Account
(a)
Amount brCun€nt Year
(b)
p*ffil3tf"L,
(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generalion
3 Operation
4 (500) Operation Supervision and Engineering 978,720 1,158,861
5 (501) Fuel 107.893,663 137,688,753
6 (502) Steam Expenses 8,501,434 8,97',t.192
7 (503) Steam from Other Sources
I (Less) (504) Steam Transfened-Cr.
9 (505) Elecfic Exoqrses 1,396,032 1,466,072
10 (506) Miscellaneous Steam Powsr Expenses 1 1,694,905 9,097,246
11 (507) Rents 328.946 206.742
12 (509) Allowances
13 TOTAL Op€ration (Enter Total of Lines 4 thru 12)130,793,700 1s8,588,866
14 Maintenance
15 (510) Maintenance Supervision and Enqineering 55.228 100,102
16 (51 1) Maintenance of Structures 440,434 528.121
17 (512) Maintenance of Boiler Plant 11,031,366 14.263,344
18 (513) Maintenance of Electric Plant 4.331.373 5,'t50,575
19 (514) Maintenance of Miscellaneous Steam Plant 5,S35,275 6.435,3.r8
20 TOTAL Maintenance (Enter Total of Lines 15 [lru 19)21,793,676 26,477,490
21 TOTAL Power Production Expenses-Steam Power (Entr Tot llnes 13 & 20)152,547376 185,066,356
22 B. Nudear Power Generation
23 Operation
24 (517) Operation Suoervision and Enqineerinq
25 (518) Fuel
26 (519) Coolants and Water
27 (520) Steam ExDenses
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transfened-Cr.
30 (523) Electric ExDenses
31 (524) Miscellaneous Nudoar Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
34 Maintenance
35 (528) Maintenance Suoervision and Enqineerinq
36 (529) Maintenanc6 of Structures
37 (530) Maintenance of Reactor Plant Equipment
38 (531) Maintenance of Electric Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 ftru 39)
41 TOTAL Power Produc{ion Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 5.699.366 5.676,404(535) Operation Supervision and Engineering
45 5,857,068 6.025.791(536) Water br Power
46 (537) Hvdraulic Exoenses 15,008,403 14,667,285
47 (538) Electic Exoenses 1,912,27E 1,696.943
48 (539) Miscellaneous Hydraulic Power Generation Expenses 8,270,822 5,699.628
49 (540) Rents 241,787 235,365
50 TOTAL Operation (Enter Tobl of Lines 44 thru 49)36,989,724 34,001,416
51 C. Hydraulic Power Generaton (Continued)
52 Maintenance
53 (541) Mainentance Suoervision and Enoineerino 94,013 116,729
54 (542) Maintenance of Structures 1,139,095 1,218,450
55 (543) Maintenance of Reservcirs, Dams, and Watemays 821,883 658,337
56 (5,t4) Maintenance of Electric Plant 1,877,280 2,197,930
57 (545) Maintenance of Miscellaneous Hydraulic Plant 2,819,560 2,345.337
58 TOTA Maintenance (Enter Total of lines 53 thru 57)6,751,831 6,536,783
59 TOTAL Power Production Expenses-Hydraulic Power {tot of lines 50 & 58)43,741.555 40,538.19€
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:
Original
Date of Reoort
(Mo, Da, Yi)Year/Period of Report
End of 20171Q4A Resubmission 04t18t2018
FERC FORri NO.1 (ED. 12-03)Page 320
Name of
ldaho Power Company
This
(1)
(2t
ls:
An Original
A Resubmlssion
Dat6 of Report(Mo, Da, Yr)
Year/Period of Report
End of 20171Q4
04t'tu2018
lf the amount for previous year is not derived from previously reported figures, explain in footnote
Line
No.
Account
(a)
Amount forCunent Year
(b)
-Aflpunt.brPreuous Year(c)
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering 687.916 738,44
63 (547) Fuel 37,935,165 41,&2,251
64 (548) Generation Expenses 4,171,670 4,155,511
65 (549) Miscellaneous Oher Power Generation Expenses 986,828 807,(E1
66 (550) Rents
67 TOTAL Operaton (Ent€r Total of lines 62 lhru 66)41,781,579 47.503.307
68 Maintenance
69 (551) Maintenance SuDervision and Engineering 226
70 (552) Maintenance of Structures 335.091 400,817
71 (553) Maintonance of Generatinq and Electric Plant 595,08s 126,988
72 (554) Maintenance of Miscellaneous Other Power Generalbn Plant 2,226,109 2,7U,692
73 TOTAL Maintenance (Enter Total of lines 69 ttru 72)3.156,5'11 3,292,497
74 TOTAL Polrrer Produciion Expenses-Other Power (Enter Tot of 67 & 73)46,938,090 50,795,804
75 E. Othsr Power Supply Expenses
76 (555) Purchased Power 244,381,204 240,248.728
77 (556) System Conkol and Load Disgatchino 2,885 2,678
78 (557) Other ExDenses 56,007,259 -1,206,336
79 TOTAL Other Power Supply Exp (Enter Tohl of lines 76 thru 78)300,391,348 239,005,070
80 TOTAL Power Producdon Expenses (Tobl of lines 21 , 41, 55,74 & 79)543,658.369 51s,405,42€
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Ooeration Suoervision and Enqineering 3,150,433 2,953,141
84
85 (561 .1 ) Load Dispatch-Reliability I 1.169 43,356
86 (561.2) Load Dispatctr-Monitor and Operate Transmission System 1,620,215 1,642,U4
87 (56 1 .3) Load Dispatcfr-Transmission Service and Scheduling 't,526,245 1,390,5s2
88 (561.4) Scheduaino, Syst€m Control and Oispatch Services
89 (561.5) Reliability, Plannins and Standards Development
90 (561.6) Transmission Service Studies
91 (561 .7) Generation lnterconnec{ion Strdies 32JA1 25,459
92 (561.8) Rdiability, Plannins and Standards Development Services 1,698,457 1,634,564
93 (562) Station Exoenses 2.887.872 2.637.946
94 (563) Overhead Lines Exoenses 1.070.029 953,376
95 (564) Underoround Lines Expenses
96 (565) Transmission of Elecffici& by Others 4,568.39S 5,555,121
97 (566) Miscellaneous Transmission Expenses 25 7,471
98 (56il RenE 4,782,018 4.'.139.757
99 TOTAL Operation (Enter Total of lines 83 hru 98)21,3$,967 20,943,387
100 Maintenance
't01 (568) Maintenance Suoervision and Enqineerinq 154,736 169,832
102 (569) Maintenance of Structures 2,882
't03 (569.1 ) Maintenance of Computer Hardware 31,344 27,821
104 (569.2) Maintenance of Computer Software 925,878 896,20€
105 (569.3) Maintenance of Communication Equipment 8,099 1 s.105
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equioment 1,925,172 2,220.242
108 (571) Mainlenance of Overhead Lines 883,265 1.132,781
109 (572) Maintenanco of Undorqround Lines
1't0 (573) Maintenance of Miscellaneous Transmisslon Plant 3,357
'111 TOTAL Maintenance (Total of lines 101 thru 110)3,931,851 4.464,875
112 TOTAL Transmission Expenses (Total of lines 99 and 1 1 'l )25,278,818 25,408,262
FERC FORI NO_ 1 (ED. 12-03)Pago321
I
End of
of Report
2017n4ldaho Power Company (1)
(2)
ls:
Original
Resubmission
Date of Reoort(Mo. Da, Yi)
04t'1u2018
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Acoount
(a)
Amount brCurrent Year
(b)
Amount forPrevious Year
(c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575. 1 ) Operation SupeMsion
116 (575.2) Day-Ahead and Real-Time Market Facilitation
117 575.3) Transmission Rights Market Facilitation
118 (575.4) Capacity Ma*et Facilitation
119 (575.5) Ancillary Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market FacilltaUon, Monitoring and Compliance SeMc6s
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)
124 Maintenance
125 (576.1) Maintenance of Structures and lmprovemenb
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Software
124 (576.4) Maintenance of Communication Equipment
't29 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Reqional Transmission and Market Op Expns (Total 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation SupeMsion and Engineetinq 4,208,616 4,226.O94
135 (581) Load Dispatchino 4,166,896 4,026,028
136 (582) Statlon Exoenses 1,555.734 1,544,740
137 (583) Overhead Line Expenses 4,916,620 3,606,076
138 (584) Underground Line Expensos 3.615,140 3.076.757
't39 (585) Street Liohting and Signal System Expenses 1 18,675 82,633
MA (586) Meter Expenses 4,904,919 4.717.443
141 (587) Customer lnstallations Expenses 't,276,3U 897,759
142 (588) Miscellaneous Expenses 6,886,864 7.518,466
143 (589) Rents 381,320 305,059
144 TOTAL Operaton (Enter Total of lines 134 thru '143)32,031,166 30,001,055
145 Maintenance
146 (590) Maintenance Supervision and Engineering -1,643,939 -1,554,525
147 (591) Maintenance of Structures
148 (592) Maintenance of Station Equipm6nt 3,887,158 3,870,899
149 (593) Maintenance of Overhead Lines 13,818,926 14,975.930
150 (594) Maintenance of Underground Lines 748,181 868,712
't5'l (595) Maintenance of Line Transbrmers 23,U3 28,581
152 (596) Maintenance of Streot Liqhting and Signal Systems 554,42',1 588.626
r53 (597) Maintenance of Meters 982,875 873,691
154 (598) Maintenance of Miscellanoous Oisfibution Plant 240,442 380,105
r55 TOTAL Maintenance (Total of lino6 146 thru 154)18.611,907 20,032,019
156 TOTAL Dlstribution Expenses (Total of lines '144 and 155)50.643.073 50.033.074
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 945,821 617,373
't60 (902) Meter Readins Expenses 1,544,7U 1,il9,267
161 (903) Customer Records and Colleclion Expenses 14,205,692 14,631,724
162 (904) Uncollectible Accounts 5.732,560 3,946,809
163 (905) Miscellaneous Customer AccounE Expenses -9M -551
164 TOTAL Customer Accounts Expenses (Total of lines 1 59 thru 1 63)22,427,893 20.8M.622
FERG FORil NO. r (ED. 12-93)Page322
lf the amount for previous year is not derived from preriously reported figures, explain in footnote.
Amount forCunsnt Year(b)
Amounl forPrevious Year(c)
Une
No"
Acoount
(a)
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
796.990167(907) Supervision 821,144
41.249.994168(908) Customer A,ssistanco Expenses M,'.t76,525
169 (909) lnformational and lnsauctonal Expens€s 444,538 427,793
449.522170(910) Miscellaneous Cusbmer Service and lnformaUonal Expenses 641,u1
171 TOTAL Customer Service and lnformation Expenses (Total 167 thru 170)46,084,048 42,924,299
172 7. SALES EXPENSES
173 Operation
174 (911) SupeMsion
175 (912) Demonstratlns and Selling Expenses 24
176 (9'l 3) Advertsins ExDenses
177 (91 6) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 1 74 firu 1 77)24
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries 79.079,418 81.422.856
182 (921 ) Office Supplies and Expenses 14,134,583 14,772,547
183 (Less) {922) Administrative Expenses Transfened-Credit 27,762,969 33,792,414
1U (923) Outside Services Employ€d 6,769,731 8,226,785
185 (924) Propsrtv lnsurance 3,1 17,561 3362,154
186 (925) lniuries and Damaqes 5,U7,112 5,991,970
187 (926) Emplovee Pensions and Benefrls 46.786,554 52,679,051
188 (927) Francfi ise Reeuiremenb
't89 (928) Regulatory Commission Expenses 4,260,709 3,818.396
190 (929) (Less) Duplicate Charqes-Cr
191 (930.1 ) General Advortisins Expenses 364,410 582,063
192 (930,2) Miscsllaneous General Expenses 3,556,441 3,552.222
193 (931) Rents -350
194 TOTAL Operation (Enter Total of lines 181 thru '193)135,953,200 140,616,030
195 Maintenance
't96 (935) Maintenance of General Plant 6,737.813 6,271,101
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196)142,691,013 146,887,131
198 TOTAL Elec OD and Maint Expns (Total 80.112,131,156,164,17'1,178,197)830,783,214 801.502.841
Respondent This
(1)
(2)
An
ls:
Original
DatB of Report(Mo, Da, Yr)
Year/Period of Report
End of 20171Q4ldaho Power Company A Resubmission 0411812018
FERG FORrrr NO.1 (ED. 12-93)Page 323
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:Date of Reoort(Mo, Da, Yi)Year/Period of Report
End of 2O17lQ4An Original
A Resubmission 0411812018
1. Report all power purchases made during the year. Also report exchanges of electricity (i,e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the nam€ of the seller or other party in an exchange transaction in column (a), Do not abbreviate or truncata the name or use
asonyms. Explain in a footnote any ownership interest or afriliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classilication Code based on the original contractual terms and conditions of the service as follows:
RQ - br requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resourc€ planning). ln addition, the reliability of requirement servica must
be the same as, or second only to, the supplier's service to its oryn ultlmate oonsumers.
LF - for long{erm firm seryice. 'Long-term'means five years or longer and "lirm' means that seMce cannot be intemrpted for
economic roasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
eneqy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets he definition of RQ seMce. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
!F - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term seruice. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for longr-term seMce from a designated generating unit. "Long-term" nreans fve years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term seMce fom a designated generating unit. The slame as LU service expect that'intermediate-tem" means
longer than one year but less than fve years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, 6tc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above{efined categories, such as all
non-firm service regardless of the Length of the contract and seMce from designated units of Less than one year. Describe flre nature
of the service in a footnote for each adjustment.
Actual Demand (MW)Line
No.
Statistical
Claesifi-
cation
(b)
FERC Rate
Schedule or
Tadff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Average
Monthly NCP Oeman(
(e)
Average
Monthly CP Demand
(0
Name of Company or Public Auhority
(Footnote Affi liations)
(a)
1 Cogeneration and Small Power Producers
LU N/A2American Falls Solar, LLC N/A N/A
3 American Falls Solar ll, LLC LU N/A N/A N/A
4 AgPower Jerome / Double A Digpster LU N/A N/A N/A
5 LU N/A N/A N/AAllan RavenscrofUMalad River
LU6Baker City Hydro N/A N/A tvA
7 Bannock County, ldaho LU N/A N/A f.UA
8 Bennett Creek lMnd Farm LU N/A N/A N/A
I Benson Creek Wind Farm LU N/A N/A N/A
LU N/A N/A N/A10Bettencourt DryCrcek Biofactory
11 Big Sky West Dairy DigeEter LU N/A NiA N/A
12 Big Wood Canal Company LU
13 Black Canyon #3 LU N/A NiA N/A
14 LU N/A N/A N/AJim Knight
Total
FERC FORM NO. 1 (ED. 12-90)Page 326
Name of Respondent
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Oate of Reoort(Mo, Da, Yi)
o4t18t2018
Year/Period of Report
End of 20171Q4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups' for service provided in prior reporting
years. Provide an explanation in a botnote for each adjustment.
4. ln column (c), identifu the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdic'tional sellers, include an appropriate
designation fur the contract. On separate lines, list all FERC rate schedules, tariffs or @ntract designations underwhiclt service, as
identiffed in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly averiage billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
avsrage monthly coincident peak (CP) demand in column (0. For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the upplie/s system neaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawathours shown on bills rendered to the respondent. Report in columns (h) and (l) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as sptilement by the respondent. For power exchanges, report in column (m) the settement
amount fur the net receipt of energy. lf more en€rgy was delivered than received, enter a negative amount. lf the settlemsnt amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credlts or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totialled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The totial amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.L Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Received(h)
Megawatt Hours
Delivered(i)
Demand Charges
($)
0)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (i+k+l)
of Settement (S)
(m)
1
3S,601 1,041,522 1,041,522 2
35,60t 860.271 860,271 3
26,421 2,360,837 2,360,837 4
2,86t 155,672 1 18.39€274,06t 5
68a 38,55C 38,55€6
11,Ezt 663,388 663,388 7
38,68i 2,482,454 2,482,4il I
25,09('t,337,O32 1,337,032 I
11,311 993,95€993,95€10
9,711 645,712 u5,712 11
12
38(26,053 26,053 13
1,082 76.075 76,075 14
4,293,616 228,34'l 259,185 2,559,008 234,522,471 6,899,725 2U.381.204
FERC FORM NO. I (ED.12-S0)Page 3127
rUF(UH'
of Respondent This
(1)
(2)
ls:Oato of Reoort(Mo, Da, Yi)Year/Period of Report
End of 2O17lQ4ldaho Power Company An Original
A Resubmission 0411812018
1. Report all power purchasos made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchang€s.
2. Enter the name of the sall€r or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classiftcation Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this servioe in its system resource planning). ln addition, he reliability of requirement service must
be the same as, or second only to, the zupplier's service to its own ultimate consumers.
LF - for long{erm firm service. 'Long-term" means five years or longer and "firm' means that service cannot be intemrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy ftom third parties to maintain deliveries of LF service). This category should not be used for longrterm firm service firm service
which meets the definition of RQ service. For all transaction identifled as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one ysar but less
than five years.
SF - for short-term servioa. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term servioe from a designated gsnerating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside fom bansmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU seMce expect that "intermediate-term" means
longer than one year but less than five yaars,
EX - For exchanges of electricity, Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any seftlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Actual Demand (MW)Line
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Stiatistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Av€rage
Monthly NCP Demanr
(e)
Average
Monthly CP Demanc
(f)
,|Sagebrush LU N/A N/A N/A
2 LU N/A N/A N/ABlack Canyon Bliss
LU3Blind Canyon Hydo N/A NI/A N/A
4 Branchfl ower/Trout Com pany LU N/A N/A N/A
5 Burley Butte Wind Park LU N/A N/A N/A
6 LUBypass Limited N/A N/A N/A
7 Camp Reed Wind Park LU N/A rvA N/A
8 Cargill lnc./B6 Anaerobic Digester LU N/A NiA N/A
I Cassia Wind Farm LU N/A N/A N/A
10 LU N/A T{/A N/ACCP OR Tenant 1, LLC - Gmve
LU N/A11CCP OR Tenant 1, LLC - Hyline N/A N/A
12 CCP OR Tenant 1, LLC - Open Range LU N/A N/A N/A
13 CCP OR T€nant'1, LLC - Railroad LU N/A TI/A N/A
14 LU N/A N/A N/ACCP OR Tenant 1, LLC - Vale Air
Total
FERC FORM NO.1{ED. 12-90)Page 326.1
Nsme of Respondent
ldaho Power C;ompany (1)
(2)
Original
Resubmission
Date of ReDort(Mo. Oa, Yi)
04t18t2018
Year/Period of Report
End of 2O17lQ4
AD - for out-of-period adiusfnent. Use this code for any accounting adiustments or 'true-ups" for service provided in prior reporting
ysars. Provade an explanation in a footnote for each adjustment.
4. ln column (c), identifr the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdic-tional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contrcct designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of seMce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly averrge billing demand in column (d), the average monthly nonroincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of servics, enter NA in columns (d), (e) and (Q. Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplie/s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for sattlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charyes, including
out-of{eriod adjustments, in column (l). Explain in a fmtnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settement by the respondent. For power exchanges, report in column (m) the settement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or charges other than incremental generation expsnses, or (2) excludes certain credits or charges covered by the
ageement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be rcported as Exchange Received on Page 40'l ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations folloring all required data.
MegaWatt Hours
Purdrased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Recelved
(h)
Mogawaft Hours
Delivered
(i)
Demand Charges
($)
0)
Energy Charges
ttI
Other Charges
($)
(t)
Total (i+k+l)
of SetUement ($)
(m)
944 65,14(65,1,10 ,|
74 2,231 2,239 2
4,312 187,921 187.921 3
857 60,034 60,034 4
48,17i 2,757,62C 2,757,620 5
25,63:1,410,31!1,410,3'1S o
60.73i 5,028,94€5,028,94S 7
13,24a 1,143,58r 1,143,588 I
22,11C 888,987 888,98i I
12,16t 700,762 700,762 10
17341 1,001,58€1,001 ,58S 11
20,76e I,193,558 1,193,558 12
9,35I s39,392 539,392 13
19,827 't,141,973 1,141,973 14
4,293,616 228,341 259,185 2,559,008 234,922,471 6,899,725 244,381,204
FERC FORM ilO. I (ED.12-90)Page 327,1
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Reoort(Mo, Oa, Yi)
0411812018
Yoar/Period of Report
End of 20171Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter thb name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownarship interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classiftcation Code based on the original contractual terms and conditions of the seMce as follows:
RQ - for requirements servica. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's ssrvice to its own ultimate consumers.
LF - for long-term firm service. "Long-term' means five ysars or longer and "firm" means that service cannot be intemrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediateterm firm service. The same as LF seMce oxpect that "lntermediate-term' means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for seMce is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term'means five years or longer. The availability and reliability of
service, aside fom transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU seMce expect that "intermediate-term" means
longerthan one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for onergy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only forhose services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service trom designated units of Less than one year. Describe the nature
of the service in a footnote for eaci adjustrnent.
Line
No.
Name of Company or Public Arthority
(Foohote Affliations)
(a)
Statistical
Ctassifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Bllling
Domand (MW)
(d)
Actual Demand (MW)
AVOrage
Monthly NCP Demanr
(e)
Average
Monthly CP Dernand
(f)
1 CCP OR Tenant '1, LLC - Thunderegg LU flUA N/A N/A
2 City of Cove, Oregon / Mill Creek LU N/A N/A N/A
3 CiV of Hailey LU f\,UA N/A N/A
4 City of Pocatello LU N/A N/A N/A
5 Clear Springs Food lnc.LU N/A N/A N/A
6 Clifton E. Jenson/Birch Creek LU lvA N/A N/A
7 Cold Springs Windfarm, LLC LU t{/A N/A N/A
8 Consolidated Hydro lnc. / Enel
I Barber Dam LU N/A N/A N/A
10 Dietrich Drop LU NI/A N/A N/A
1',!GeoBon #2 LU N/A N/A N/A
12 Lowline #2 LU N/A N/A N/A
13 Rock Creek #2 LU r{/A N/A N/A
14 Contractors Power Group lnc./Mile 28 LU t{/A N/A N/A
Total
FERC FORm NO. t (EO.12-S0)Page 326.2
Name of Respondent
ldaho Power Company (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
04t1u2018
Year/Period of Report
End of 2O17lQ4
AD - for out+f-fjeriod adjustment. Use this code for any accounting adjustments or'true.ups" for servi@ providod in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. ln column (c), identiff the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an apprcpriate
designation for the conhact. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly avsrage billing demand in column (d), the average monthly non-coincident poak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all othertypes of seMce, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (6&minute antegration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplie/s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchangos receaved and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustsnents, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchang€s, report in column (m) he settlernent
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or charges otherthan incremental generation €xpenses, or (2) excludes cartain credits or charges cover€d by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reporled as Exchange Delivered on Page 401, line 13.
9. Footnote entries as reguired and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES GOST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
Megawatt Hours
Delivered(i)
Demand chargos
($)
(i)
En€rgy Charges
($)
(k)
Other Charges
($)o
Total U+k+l)of Settlement ($)
(m)
20,31(1,166,492 1,166,492 1
2,19i 144,U5 144,Ua 2
141 9,943 9,943 3
1,37S 102,54€102,54C 4
3,4n 338,41t 338,4'18 5
321 17,500 13,492 30,9S4 6
46,57(3,357,56(3,357,56C 7
8
14,16:715,95t 715,958 I
7,141 390,891 390,891 't0
4,34t 314,52i 314,527 11
9,50:514,'t3t 514,138 12
8,89S 437,51t 437,516 13
6,04!423,241 423,241 14
4,293,616 228,341 259,185 2,559,008 234,922,47'.!6,899,725 244,381,204
FERC FORil NO. r (ED. 12-90)Page 327.2
Name of Respondent
ldaho Porer Company
This
(1)
(2)
ls:Date of Report(Mo, Da, Yr)Year/Period of Report
End of 20171Q4An Original
A Resubmission 0411812018
1. Report all power purchases made during the year. Also reporl exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classiftcation Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements servioe. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier inc{udes projects load for this servi@ in its system resource plannirq). ln addition, the reliability of r€quirement service must
be the same as, or second only to, the supplie/s sarvico to its own ultimate consumers.
LF - for long-term frm service. "Long-term' means five years or longer and "firm' means that service cannot be intamrpted for
economic neasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the eadiest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than ons year but less
than five years.
SF - for short-term service. Use this category for all firm serviccs, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. 'Long-term'means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for snergy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service fiom designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Actual Demand (MW)Line
No.
Name of Company or Public Authority
(Foohote Affliations)
(a)
Statisdcal
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(0
1 Crystal Springs Hydro LU N/A N/A N/A
2 Curry Cattle Company LU N/A N/A N/A
LU N/A N/A N/A3David McCollum lCanyon Springs
4 David R Snedigar LU N/A N/A N/A
5 Oeserl Meadow Windfarm tU N/A N/A N/A
6 LU N/A N/A N/ADurbin Creek Windhrm
LU N/A N/A N/A7Eightmile Hydro Corp
N/A N/AIFaulkner Brothers Hydro lnc.LU N/A
N/A9Fisheries Development LU N/A N/A
10 Fossil Gulch Wind LU N/A NiA N/A
11 LU N/A N/A N/AG2 Energy Hidden Hollow
LU N/A N/A N/A12Golden Valley Wind Park
13 Grand View PV Solar Two, LLC LU N/A N/A N/A
14 Hammett Hill lMndfarm, LLC LU N/A N/A N/A
Total
FERC FORM NO. r (ED. 12-90)Page 326.3
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)Year/Period of Report
End of 2O17lQ40411812018ldaho Power Company (1)
(2)
AD - for out-of-period adjustment. Use this code for any aocounting adjustments or'true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. ln column (c), identiff the FERC Rate Schedule Number orTariff, or, for non-FERC jurisdictional sell€rs, include an appropriate
designation for the contact. On separate lines, list all FERC rate schedules, tarifb or contract designations under which seMce, as
identified in column (b), is provided.
5. For requirements RQ purciases and any gpe of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of seMce, enter NA in columns (d). (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the srpplier's system reaches its monthly peak. Demand reported in columns (e) and (Q
must be in megawatts. Footnote any demand not stated on a m€gawaft basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand ctarges in column fi), energy charges in column (k), and the tota! of any other types of charges, induding
out-of-period adiustments, in column (l). Explain in a footnote all components of the amount shov,rn in column (l). Report in column (m)
he total chaqe shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, ent€r a negative amount. lf the settlement amount (l)
include crodits or charges other than incremental gensration expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an e:rplanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 1 3.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.MegaWaft Hours
Received(h)
Megawatt Hours
Delivered(i)
Demand Charges
($)
0)
Energy Charges
fi]
Other Charges
($)o
ToEl (i+k+l)
of Settlement ($)
(m)
11,964 813,16t 8't3,166 1
701 26.79€29,172 5s,968 2
44!6,802 6,802 3
'l,44i 99,85(99,856 4
53,83:3,898,82t 3,898,828 5
21,85i 1,171,921 1,171,921 6
1,58:97,421 97,421 7
3,331 261,733 261,731 I
83(12,O22 12,02Q I
23,35(1,368,539 1,368,53€10
20.602 '1.372.843 1,372,843 11
28,333 1,609,852 1,609,852 12
168,93?8,425,392 8,425,392 't3
53,1 6:3,U2,143 3,U2,143 14
4,293,616 228,341 259,185 2,559,008 234,922,471 6,89!t,725 244,381,201
FERC FORIU NO. 1 (ED. 12-90)Page 327.3
Report
ldaho Power Company (1)
(2)
An Original
A Resubmission 0/,t18t2018
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any setlements for lmbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or usa
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows;
RQ - for requirements service. Requirements seMce is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes proiects load for this service in its system resouros planning). ln addition, the reliabilig of requirement service must
be the same as, or second only to, the supplier's ssrvice to its own ultimate consumers.
LF - for long-term firm sorvioe. "Long-term' means five years or longer and "firm" means that service cannot be intemJpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the conEact.
lF - for intermediate-term firm servlce, The same as LF service expect that "intermediate-term' means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitrnent for service is one
year or less.
LU - for long-term sewice from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service ftom a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above{elined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the seMce in a foohote for each adjustment.
Line
No.
Name of Company or Public Authority
(Foolnote Affiliations)
(a)
Statistical
Classiff-
cation
(b)
FERC Rate
Sdledulo or
Tariff Number
(c)
Avarage
Monthly Bllling
Demand (MW)
(d)
Achral Demand (MW)
Average
I$onthly NCP Demanr
(e)
Average
Monthly CP Demand
(f)
1 Hazelton B Power Company LU N/A N/A N/A
2 Head of U Canal LU N/A N/A N/A
3 Hlgh Mesa Energy LU N/A N/A N/A
4 H.K. Hydro Mud Cred< S & S LU N/A N/A N/A
5 Horseshoe Bend Hydro LU N/A N/A N/A
6 Horseshoe Bend Wind/United Materials LU N/A N/A wA
7 Hot Springs Wind Farm LU N/A N/A N/A
8 lD Solar I, LLC LU N/A N/A N/A
9 ldaho Winds / Sawtooth Wind Projecl LU N/A N/A N/A
't0 J R Simplot Co.IU N/A N/A N/A
11 J.M. Miller/Sahko Hydro LU N/A N/A N/A
12 James B. Howell / CHI Elk Creek LU N/A N/A fl/A
13 Jett Creek Windfarm LU N/A N/A l,l/A
14 John R LeMoyne LU N/A N/A N/A
Total
FERC FORri NO.1 (ED. 12-90)Paga 326.1
End of 20171Q4
This
(1)
(2)
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)Year/Period of Report
End of 20171Q40411812018ldaho Power Company
AD - for out-ofaeriod adjustment. Use this code for any aocounting adjusitments or "tru€-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adiustment.
4. ln column (c), identifu the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional ssllers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or cpntract designations under which seMce, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NGP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (O), (e) and (fl. Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplie/s syslem reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawaft basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) fie megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column fi), energy charges in column (k), and the total of any other types of charges, induding
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total chaqe shown on bills received as settlement by the respondent. For porer exchang€s, roport in column (m) $e settlsment
amount br the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES COST/SETTLEMENT OF POWERMegaWatt Hours
Purchased
(s)
Megawatt Hours
Received(h)
MegaWatt Horrs
Delivered(i)
Demand Charges
(8
Energy Charges
(s)
(k)
Other Charges
($)
(t)
Total (j+k+l)
of SetUement ($)
(m)
Line
No-
21,46C 1,582,524 1,582,526 1
4,37(377,571 3?7,577 2
86,357 4,289,47t 4.289,476 3
1,67€92,50S 92,50S 4
36,99S 2,736,637 2,736,637 5
19,315 1,161,722 1,161,722 6
35,381 2,270,062 2,270,062 7
88,232 3,477,97{3,477,g7C I
51,36(4,208,852 4.208,852 I
68,343 3,404,449 3.404,449 10
1,37(109.651 109,651 11
4,94i 327,38t 327,38S 12
23,25e 1,234,521 1,234,524 13
61(34,921 34,922 14
4,293,6't6 259,185 2,559,008 234,922,47'.1228,34',1 6,899,725 244,381,204
FERC FORM NO. 1 (ED.12-90)Page 127.4
ldaho Power Company
This
(1)An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20171Q4
o4l'1812018
pow€r
1. Report all power purchases made during the year. Also repo( exchanges of electicity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchangos.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or afhliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classifcation Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resouroe planning). ln addition, the reliability of requirement seMce must
be the same as, or second only to, lhe supplier's service to its own ultimate consumers.
LF - for long-term firm servioe. 'Long-term'means tive yeans or longer and "firm" means that service cannot be intemrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy ftom third parties to maintain deliveries of LF service). This category should not be used for long-term ffrm service firm service
which meets the definitlon of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unllaterally get out of the contract.
lF - for intermediate-term flrm service. The same as LF service expect that'intermediate-torm" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. 'Long-term" means five years or longer. The availability and reliability of
ssrvioe, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for hansactions involving a balancing of debits and credits fur energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from des(Tnated units of Less than one year. Describe the nalure
of the service in a footnote for each adjusffnent.
Line
No.
Name of Company or Public Authority
(Foobote Affiliatlons)
(a)
Statistical
Classifr-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Arrerage
Monthly Billing
Demand (MW)
(d)(e)
Ac{ual Demand
Monthly
N/A1Kasel & Witherspoon LU N/A N/A
2 Kootenai Electric Cooperative / Fighti LU N/A N/A N/A
3 LU N/A N/A N/AKoyle Hydro lnc.
4 LU N/A N/A N/ALateral 10 Ventures
5 Lemhi Hydro Power Co./Schaffner LU N/A N/A N/A
6 Lime Wind LU N/A N/A N/A
7 LU N/A N/A N/ALitfle Mac Power Co./Codar Draw
LU N/A N/AILittle Wood River lrrigation Disbic't N/A
I LU N/A N/A N/AMagic Reservoir Hydro
10 Mainline Windfarm LU N/A N/A N/A
't1 Marco Rancher's lnigation lnc.LU N/A N/A N/A
't2 LU N/A NIA N/AMarysville Hydro Partners/Falls River
LU N/A N/A N/A13Milner Dam Wind Park
14 Mountain Home Solar l, LLC LU N/A N/A N/A
Total
FERC FORM NO.1 (ED. 12-90)Page 326.5
Av€rage
Monthly NCP Demar
(f)
Mme of Respondent
ldaho Power Company
This
(1)
(2)
ls:
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Pedod of Roport
End of 2O17lQ404118t2018
AD - for out-of-period adjustment. Use this code for any accounting adjustmsnts or lrue-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. ln column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or oontlact designations under which service, as
identified in column (b), is provided.
5. For requircments RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the aver.tge monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the *pplie/s system reaches its monthly peak. Demand reported in columns (e) and (0
must be in megawatts. Footnote any demand not stated on a meg€rwatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for setUernent. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total chaqe shown on bills received as settlemont by the respondent. For power exchanges, report in column (m) the s€ttlement
amount for the net receipt of energy. lf more eneey was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory foohote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGES COSTiSETTLEMENT OF POWERMegaWatl Hours
Purchased
(g)
MegaWatt Hours
Received
(h)
Megawatt Hours
Delivered(i)
Demand Charges
($)
0)
Energy ChargesI Other Charges
($)
(t)
Total (i+k+l)
of Settlement ($)
(m)
Line
No.
196,80(196,806 1219e
882,5471 1,49C 882,54i 2
4,01?379,69i 379,697 3
8,329 553,26!553,26S 4
95,977 95,977 51,26e
5,454 417,96(417,960 o
5,895 379,86{379,869 7
8,181 617,1U 617jU 8
I
50,837 3,678,022 3,678,022 10
3,442 236,474 236,474 11
64,811 4,358,98a 4,358,985 12
49.22t 2,816,092 2,816,092 13
901,31!901,313 1437,06(
4,293,61€228,341 259,185 2,559,008 234,922,471 6,899,725 244,38'.t,204
FERC FORM NO. r (ED. 12-90)Page 327.5
04118t2018
Year/Period of Report
End of 20171Q4ldaho Power Company (1)
(2)
An Original
A Resubmission
1. Report all power purchasss made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements ssrvice. Requirements servioe is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier indudes projects load for this service in its system resource planning). ln addition, the reliability of requirement servace must
be the same as, or second only to, the supplie/s service to its own ultimate consumers.
LF - for long-term firm service. "Long-tenn" means five years or longer and 'flrm" means that service cannot be intemrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy fom third parties to maintain deliveries of LF service). This category should not be used for longrterm firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term ffrm service. The same as LF servlce expect that "intermediate-term" msans longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service trom a designated generating unit. "Long-term' means five years or longer. The availability and reliabilig of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU seMce expect that'intermediate'term" means
longer than one year but less than five years.
EX - For exchanges of elecficity. Use this cat€gory for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any sattlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above.defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authorlty
(Foohote Affiliations)
(a)
Statistical
Classi'll-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Aclual Demand (MW)
Average
Monthly NCP Deman(
(e)
Averag€
Monthly CP Demand
(f)
1 Mud Creek White Hydro, lnc LU N/A N/A N/A
2 Murphy Flat Poewr, LLC LU N/A N/A N/A
3 Nerv Energy One / Rock Creek Dairy LU N/A NUA N/A
4 l,lorh Gooding Main, Hydo LU N/A NIA N/A
5 Orchard Ranch Solar, LLC LU N/A N/A N/A
6 Oregon Trail Wnd Park LU N/A lVA N/A
7 Owyhee lnigation Districl
8 Mitdrell Butte LU N/A N/A N/A
I Owyhee Dam LU N/A il/A N/A
10 Tunnel #1 LU N/A N/A N/A
11 Paynes Ferry Wind Park LU N/A N/A N/A
't2 Pigeon Cove Power LU N/A N/A N/A
13 Pilgrim Stage Station Wind Park LU N/A N/A N/A
14 Pristine Springs lnc #1 LU N/A NIA N/A
Total
FERC FORM NO. r (ED. 12-90)Page 326.6
An Original
A R6ubmission
Date of Report
(Mo. Da, Yr)
Year/Period of Report
End of 20171Q4
0411812018
Name
ldaho Power Company (1)
AD - for out-of-period adjustment. Use this code for any accounting adjustrnents or'true-ups" for servioe provided in prior r€porting
yeans. Provide an explanation in a footnote for each adjustment.
4. ln column (c), identiff the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand cfiarges impossd on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident p€ak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplie/s system reach€s its monthly peak. Oemand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawaft basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawetthours
of power exchanges received and delivered, used as the basis for settlemenl, Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (1). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the setdement amount (l)
include credits or charges other than incremental generation exp€nses, or (2) excludes certain credits or charges coverad by he
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 40'1, line 't 0. The total amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all raquired data.
Megawatt Hours
Purchased
(g)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received(h)
MegaWaft Hours
Delivered(i)
Demand Chargos
($)
(i)
Energy Charges
($)
(k)
Other Chargos
($)
(t)
Total (i+k+l)
of Settlement ($)
(m)
56t 38,697 38,697 I
35,92t 980,219 980,21e 2
10,321 480,617 480,61 7 3
4,31i 373,411 373,411 4
42,101 986,51S 986,51S 5
34,33t 1,994,74i 1,994,747 t)
7
7,36:222,29t 222,296 I
28,O12 690,212 690,212 I
22,861 2,617,74t 2,617,749 10
56,46'4,649,75i 4,649,752 't1
6,369 345,67€228,941 574,657 12
30,09€1,749,62i 1,745,627 13
774 48,61 48,611 14
4,293,616 228,341 259,185 2,559,008 234,922,471 6,899,725 244,381,204
FERC FORM NO. I {ED. 12.90)Page 327.6
Name of Respondent
ldaho Power Company
This
(1)
(2)I
I
ort ls:
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411812018
Year/Period of Report
End of 2O17lQ4
1. Report all p(lwer purchases made dufing the year. Also report Bxchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter tho name of the soller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a fuotnote any ownerchip interest or affiliation the respondent has wlth the seller.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements servi@. Requirements seMce is service which he supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resouros planning), ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm' means that servie Grnnot be intemlpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm servlce firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermedaate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where lhe duration of each period of commitment for service is one
year or less.
LU - for long-torm service from a designated generating unit. 'Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service ftom a designated generating unit. The same as LU service expect that 'intermediate-term' means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and crsdits for snergy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - br other service. Use this category only for those seMces which cannot be placed in the abovedefned categories, such as all
non-firm ssrvice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Aulhority
(Footnote Affiliations)
(a)
Statistical
Classifi-
caffon
(b)
FERC Rate
Schedule or
Tarifi Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVerage
Monthly NCP Demanr
(e)
Average
Monthly CP Domend
(0
1 Pfistine Springs lnc. #3 LU N/A N/A N/A
2 Prospec;tor Windfarm LU N/A N/A N/A
3 Reynolds lnlgation Distric{LU N/A N/A N/A
4 Richard Kaster
5 Box Canyon LU N/A N/A N/A
b Briggs Creek LU N/A N/A N/A
7 Riverside Hydro/Mora Drop LU N/A N/A N/A
I Riverside lnvestments
9 Arena Drop LU N/A N/A N/A
't0 Fargo Drop LU N/A N/A N/A
11 Rock Creek #1 Joint Venture LU N/A N/A N/A
12 Rockland Wind Project LU N/A N/A N/A
13 Rupert Cogeneration Partners/Magic Val LU N/A N/A N/A
14 Ryegrass Wndfarm LU N/A N/A N/A
Total
FERC FORIII NO.1 (ED.12-90)Page 326.7
Name of Recpondent
ldaho Power Gompany
(1)
(2t
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
04t18t2018
Year/Period of Report
End of 20171Q4
IRO - for out-of-period adjustment. Use this code for any aqcounting adjustments or "true-ups" for service provided in prior reporting
lyears. Provide an explanation in a footnote for each adjustment.
4. ln column (c), identiff the FERC Rate Schedule Number or Tarifi, or, for non-FERC iurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tarifrs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non+oincident peak (NCP) demand in column (e), and the
avemge monthly coincident peak (CP) demand in column (Q. For all other types of service, enter NA in columns (d), (e) and (0. Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplie/s system reaches its monthly peak. Demand reported in columns (e) and (0
must be in megawatts. Footnote any demand not stated on a megavvatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column fi), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Repod in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or cfiaryes other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory botnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amoupt in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Received(h)
M€gawatt Hours
Delivered
(i)
Demand Charges
($)
0)
Energy Charges
fi|
Other Charges
(s)
(t)
Total o+k+lof Setdement r
(m)
r)(s)
93t 43,98!43,989 1
22374 1,195,91t 1,195,916 2
1,141 85,45(85,450 3
4
1,83(123,668 123,668 5
3,,16(236,323 236,323 b
4,51[288,697 288,697 7
I
1,674 145,761 145,767 9
3,97S 227,AO1 227,001 't0
12,51t 552,508 517,268 1,069,77€'t1
23't,871 15,O57,294 15,057,294 12
13
48,207 3,481,719 3,481,71€14
4,293,616 228,341 259,'t85 2,559,008 234,522,471 6,899,725 244,381,201
FERC FORM NO.1 (ED. 12-90)Pago 327.7
|-UXUH,
Date of Report
(Mo, Da, Yr)Year/Period of Report
End of 20171Q4An Original
A Resubmission o4t18t2018
Name of Respondent
ldaho Power Company (1)
(2t
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate ths name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements servace is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this seMce in its system resource planning). ln addiUon, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm servicc. "Long-term" means five years or longer and 'firm' means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
deftned as the earliest date that either buyer or saller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five yearc.
SF - for short-term service. Use this category for all firm servioss, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term' means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliabilig of the designated unit.
lU - for intermediate-term service from a des(;nated generating unit. The same as LU service expect that "intermediate-term' means
longerthan one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other seMce. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No,
Name of Company or Public Authority
(Footnote Affliations)
(a)
Statistical
Classifi-
cation
(b)
FERC RatB
Sdredule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Acoal Demand (MW)
Av€rage
Monthly NCP Demant
(e)
Average
Monthly CP Demand
(0
1 Salmon Falls Wind Park LU N/A N/A N/A
2 SE Hazelton A LP LU N/A N/A N/A
3 Shorock Hydro lnc.
4 Shoshone CSPP LU N/A N/A N/A
5 Shoshone #2 LU N/A N/A N/A
6 Simcoe Solar. LLC LU N/A N/A N/A
7 Snake River Pottery LU N/A N/A N/A
8 South Forks Joint Venture/Lowline Cana LU N/A N/A N/A
I Tamarack Energy Partnership LU N/A N/A N/A
10 Tasco - Nampa os N/A N/A N/A
11 Tasm - Twin Falls OS N/A N/A N/A
12 Ted S. Sorenson/Tiber Dam LU N/A N/A N/A
13 Thousand Springs Wind Park LU N/A N/A N/A
14 Tuana Gulcfr Wind Park LU N/A N/A wA
Total
FERC FORM NO.1 (8D.12-90)Page 326.0
Name of Respondent
ldaho Power Company
This
(1)
(21
ls:
Original
Resubmission o411812018
Date of Report(Mo. Da, Yr)
YearlP€riod of R€port
End of 2O17lQ4
AD - for out-of-period adjustment. Use this code for any accounting adjusfnents or "true-ups" fur service provided in prior reporting
years. Provide an explonation in a footnote for each adlustment.
4. ln column (c), identifr the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdlctional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of seMce involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplie/s system reaches its monthly peak. Demand reported in columns (e) and (0
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawathours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charpes in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge sho,vn on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credlts or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12- The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
COST/SETTLEMENT OF POWERPOWER EXCHANGES
MegaWatt Hours
Delivered(i)
Demand Charges
,8
Energy Charges
fil
Other Charges
($)
(t)
Total 0+k+l)
ofSet0ement ($)
(m)
Line
No.
MegaWatt Hours
Purchased
(s)
MegaWatt Hours
R€caived(h)
54,485 3,169,591 3,169,591 1
21.94C 1,642,502 1,642,502 2
3
102,il(102,649 41,828
2,917 195,742 195,742 5
42,645 1,251,63(1,251,636 6
17,61t 17,618 7232
2,057,838 828,32!2,057,83t
22,262 1,460,85€1,054,39i 2,515,249 I
t 10
I 11
1,772,651 1,772,657 1230,03:
1,751 ,59t 1330,17:1,751,59€
26,415 1,536,068 1,536,06€14
4,293,616 259,185 2,559,008 234,922,471 6,899,725 244,381,201228,341
FERC FORIII NO. I (ED. r2-90)Page 327.0
End of 2O'l7lQ4
Name of Respondent
ldaho Porer Company
I nrs
(1)
(2)I
I
ort ls:
An Original
A Reqrbmission 0/.11812018
1. Report all poarer purchasos made during tho year. Also report exchangss of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a foohote any ownership interest or affliation the respondent has with the seller.
3. In column (b), enter a Statistical Classilication Code based on the original contractual terms and conditions of the seMce as follows:
RQ - for requirements service. Requirements seMce is seMce which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be intemrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm seMce
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or soller can unilaterally get out of the contract.
lF - for intermediate-term lirm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for ssrvice is one
year or less.
LU - for long-term service from a designated generating unit. "Longr-term" means five years or longer. The availability and reliability of
seMce, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that'intermediate-term" means
longerthan one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those seMces which cannot be placed in the abovedefined categories, such as all
non-firm service regardless of the Length of the contract and seMce fom designated units of Less than one year. Describe the nature
of the service in a fuohote fur each adjustment.
Line
No.
Name of Company or Public AulhoriU
(Footnote Affi lialions)
(a)
Stratistical
Classifi-
cation
(b)
FERC Rate
Sdredule or
Tarifi Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Avefage
Monthly NCP Demanr
(e)
Av6rag€
Monthly CP Demand
(f)
1 Tuana Springs Expansion LU N/A N/A N/A
2 Twin Falls Energy/Lowline Midway Hydro LU N/A N/A N/A
3 Two Ponds Wndfurm LU NiA N/A N/A
4 White Water Ranch LU N/A N/A N/A
5 William Arkoosh/Litfl ewood LU N/A N/A N/A
6 Littleurood River Ranch ll LU N/A N/A N/A
7 Willis and Betty Deveny/Shingle Creek LU N/A N/A N/A
I Willow Spring Windfarm LU N/A N/A N/A
I Wilson Power Company LU N/A N/A NIA
10 Yahoo Creek Wind Park LU N/A N/A N/A
1',!Scheduling Deviation os NIA N/A N/A
'12 Other Purchased Power
13 3 Phases Renewables lnc.SF WSPP N/A N/A wA
14 AOM lnvestor Services, lnc.os N/A N/A N/A
Total
FERC FORM NO. I (ED. 12.90)Page 326.0
End of
of Report
20171Q4
o411812018
Name of Respondent
ldaho Power Company (1)
(2)
Original
Resubmission
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. ln column (c), identiff the FERC Rate Schedule Number or Tarifi or, fior non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), Orc average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA ln columns (O), (e) and (f). Monthly
NCP demand is the maximum metered houdy (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplie/s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatlhours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column O, energy charges in column'(k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the totrl charge shown on bills received as settl€ment by the respondent. For power exchanges, report in column (m) the setflement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the seftlement amount (l)
include credits or chaqes other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The totral amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations fullowing all required data.
Megawatt Hours
Purdrased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Received
(h)
Megawatt Hours
Delivered(i)
Demand Charges
t?l
Energy Charges
fil
Other Charges
(9)
(t)
Total 0+k+lof Set{ement
(m)
r)
($)
68,29a 4,U1,362 4,341,362 1
8,85i 540,182 540,142 2
54,107 3,91 1 ,614 3,9'r 1,6'14 3
76t 52,'162 52,162 4
4,76t u4,512 344,512 5
5,441 294,232 294,232 6
999 72,192 72,'.t92 7
25,67C 1,374,715 1,374,7'15 I
24,794 1,826,90C 1,826,900 9
59,598 4,C26,146 4,926,146 10
3,59C 11
12
70€13,962 13,964 13
40,14(40,14S 14
4.293,616 228,341 259,185 2,559,008 234.922,471 6,899,725 244,381,204
FERC FORM NO. r (ED.12-S0)Page 327.9
ldaho Power Company (1)
(2')Resubmission
Dat6 of Report
(tt o. Da, Yr)
0411u2018
Year/Period of Report
End of 20171Q4
runt 555)es)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any s€tflements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. ln column (b), enter a Stratistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes pQects load for this service in its system resouroe plannang). ln addition, the reliability of requirement seMce must
be the same as, or second only to, the supplier's service to its own ultimate mnsumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm' m€ans that serviee cannot be intemrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that'intermediate-term" means longer than one year but less
than five years.
SF - for short-term seMce. Use this category for all firm services, where the duration of each period of commitment for seMce is one
year or less.
LU - for long-term servico from a designated generating unit. "Long-term" means five years or longer, The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU seMce expect that "intermediate-term" means
longerthan one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service trom designated units of Less than one year. Describe the nafure
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tarifr Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Avefa9e
Monthly NCP Demanr
(e)
Aveftry6
Monthly CP Demand
(0
,|Arizona Public Service Co.SF WSPP N/A N/A N/A
2 AVANGRID RENEWABLES, LLC SF WSPP N/A N/A N/A
3 Avista Corp.os r-12 N/A N/A N/A
4 Avista Corp.SF WSPP N/A N/A N/A
5 Avista Corp.os WSPP N/A N/A N/A
6 Black Hills Power lnc.SF WSPP N/A NiA N/A
7 Bonneville Power Administration OS WSPP N/A NiA N/A
8 Bonneville Pow6r Administration SF WSPP N/A N/A N/A
9 Bonneville Power Adminisbation OS WSPP NiA N/A N/A
10 BP Energy Company SF WSPP N/A N/A N/A
't1 Galpine Energy Services, L.P SF WSPP N/A N/A N/A
12 Cargill Power Markets LLC SF WSPP N/A N/A N/A
13 Chelan Co PUD os WSPP N/A N/A N/A
14 Chelan Co PUD SF WSPP N/A N/A N/A
Total
FERG FORM NO.1 (ED.12-90)Page 326.10
ort ls:
An Original
Name of Respondent
ldaho Power Company
(1)
(2)
Original
Resubmission
Dale of Rooort
(Mo, Da, Yi)
04118f2018
YearlPeriod of Report
End of 20171Q4
AD - for out-of-period adiustment. Use this code for any accounting adjustments or "true-ups'for service provided in prior raporting
years. Provide an explanation in a footnote for each adiustment.
4. ln column (c), identiff the FERC Rate Schedule Number orTariff, or, for non-FERC jurisdidional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identilied in column (b), ls provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the aveftrge monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (O), (e) and (Q. Monthly
NCP demand is the maximum metered hourly (6Gminute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (6G'minute integration) in which the supplie/s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not strated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) antl (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as seftlement by the respondent. For pourer exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was deliversd than received, enter a negative amount. lf the setUement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) throqh (m) must be totatled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Paga 401,
llne 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as requircd and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMETIT OF POWER Line
No.MegaWatt Hours
Received(h)
Megawatt Hours
Deliv€red(i)
Demand Charges
($J
U'
Energy Charges
fil
Other Charg€s
($)
(t)
Total (i+k+l)
of SetUement ($)
(m)
28,40C 879,60(879,600 1
63,661 1,346,4&1,346,484 2
28 607 607 3
40,04c ,,113,80r 1,1 13,805 4
68,83!68,839 5
1,829 13,20(13,200 6
192 4,224 4,224 7
63,207 't,465,753 1.465,753 8
304,157 304,'t57 9
400 u,4q 11,440 10
43,648 't,130,317 1,130,317 11
50 35C 35C 12
3C 3C 't3
4,40(121,5U 121,54 14
4,293,616 228,341 259,185 2,559,008 234,922,471 6,8S9,725 244,381.201
FERC FORM NO. r (Eo. 12.00)Page 327.10
Name of Respondent
ldaho Power Company
This(1)
(21
F
I
I
orl ls:
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
0/,11u2018
Year/Period of Report
Enct of 2O17lQ4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlem€nts for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchang€ transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliatlon the respondent has wi$ the seller.
3. ln column (b), enter a Statistical Classilication Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements seMce is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier indudes projeds load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. 'Long-term" msans live years or longer and "firm" means that ssrvice cannot be intenupted for
economic reasons and is intended to remain reliablo even under adverse conditions (e.9., tho supplier must attempt to buy emergency
energy fom third parties to maintain deliveries of LF seMce). This category should not be used for long-term ffrm service firm service
which meets the definition of RQ seMce. For all transaclion identified as LF, provide in a foohote the termination date of the contract
def ned as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that'intermediate-term'means longer than one year but less
than five years.
SF - for short-term service. Use this category for all frm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term servioe from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside ftom transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term'means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category fortransactions involving a balancing of debits and credits for eneey, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm seMce regardless of the Length of the contract and service ftom designated units of Less than one year. Describe the nafure
of the service ln a footnote for each adjustment.
Line
No.
Name of Company or Public Arhority
(Foohote Affliations)
(a)
Statistical
Classifi-
calion
(b)
FERC Rate
Schedule or
Tarifi Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Oemand (MW)
Average
Monthly NCP Deman(
(e)
Av€rage
Monthly CP Dernand
(0
1 CiUgroup Energy lnc.SF WSPP N/A N/A N/A
2 Citigroup Energy lnc.OS ISDA N/A NIA N/A
3 Clatskanie PUD SF WSPP N/A N/A N/A
4 Douglas County PUD OS WSPP N/A N/A NIA
5 EDF Trading North America, LLC SF WSPP N/A N/A N/A
6 Energy Keepers, lnc SF WSPP N/A N/A N/A
7 Eugene Electric Board SF WSPP N/A N/A N/A
I Exelon Generation Company, LLC SF WSPP N/A N/A NiA
I Grant CO Public Utility Districtf2 -os WSPP N/A NJ/A N/A
10 Gridforce Energy Management, LLC os NWPP N/A N/A N/A
11 Macquarie Energy LLC SF WSPP N/A N/A N/A
't2 Macquarie Energy LLC OS ISDA N/A N/A N/A
13 Morgan Stanley Capital Group lnc.SF ISDA N/A r{/A N/A
14 Nevada Power Company, dba NV Energy SF WSPP N/A N/A N/A
Total
FERC FORI| r{O. r (ED. 12-90)Page 326]11
Name of Respondent
ldaho Power Company )An
l2l Resubmission
Date of Reoort(Mo. Da, Yi)
o4118i2018
Year/Period of Report
End of 2O17lQ4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a fuotnote for each adjustment.
4. ln column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an apprcpriate
designation tor the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the averag€ monthly non-coincident poak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (0. For all other types of service, enter NA in columns (d), (e) and (Q. Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monhly CP demand is the metered demand
during the hour (60-minute integration) in which the supplie/s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a rnegawatt basls and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as he basis for setflement. Do not repo( net exchange.
7. Report demand charges in column (j), energy charges in column (k), and tho total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charye shown on bills received as seffement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the seftlement amount (l)
include credits or charges other than increm€ntal goneraton expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The tolal amount in column (h) must be reported as Exchange Received on Page 401 ,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
M€gawatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
MegaWatt Hours
Delivered(i)
Domand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
(s)
(t)
Total (i+k+l)
of Setllement ($)
(m)
78,40C 2,649,75i 2,649,753 1
1 1,988 11,988 2
908 3,09!3,094 3
1 't4 14 4
r03,201 2,642,158 2.642,155 5
5,469 147,19i 147.192 6
85C 21,2*21,258 7
23,817 618,53€618,536 I
11 174 't7l o
1 14 14 10
9,000 't62.45C 162,454 11
-2',17,764 -2'.17,7A 12
25,84(769,992 769,992 13
21,2U 518,354 518,354 14
4,293,616 228,341 2s9,'t85 2,559,008 234,922,471 6,899,725 244,381,204
FERC FORilr NO. I (ED. 12-90)Page t27.11
Name of Respondent
ldaho Power Company
This
(1)
(2)
ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 2O17lQ4
04118t2018
1 . Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacig, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements servioe. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement servico must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term' means five years or longer and "firm' means that service cannot be intemrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term frm service firm service
which meets the definition of RQ service. For all transaction identilied as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each perlod of commitment for servioe is one
year or less.
LU - for long-term service ftom a designatod generating unit. "Long-term" means five years or longer. Tho availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate.term" means
longer than one year but less than five years,
EX - For exchanges of electricig. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any setlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of he contract and service fom designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Monthly
(e)(0
Actual DemandName of Company or Public Authority
(Foohote Afliliations)
(a)
1 OS WSPP N/A N/A N/ANevada Power Company, dba NV Energy
.T-7OS N/A N/A N/A2NorlhWestern Energy
N/A3NorthWestern Energy SF WSPP N/A N/A
4 T-13OS NI/A N/A N/APacifiCorp lnc.
SF WSPP N/A N/A N/APaciffCorp lnc.
6 PacifiCorp lnc.OS IWSPP N/A N/A N/A
7 Pordand General Electric Company 6 T-14 wA N/A N/A
8 Portand General Eleckic Company SF WSPP N/A N/A N/A
s SF WSPP N/A N/A N/APowerex Corp.
SF WSPP N/A N/A N/A10Public SeMce Company of Colorado
NUA N/A11Puget Sound Energy, lnc,os r-9 N/A
12 Puget Sound Energy, lnc.SF WSPP N/A N/A N/A
13 SF WSPP N/A N/A N/ARainbow Energy Marketing Gorporation
OS ,WSPP tvA N/A N/A14Seatuo City Light
Total
FERC FORM NO.1 (ED.12-90)Page 324.12
AVOraga
Nlonthly CP Demanr
Name ol Respondent
ldaho Power Company (1)
(21
Original
A Resubmission
Da,
04t1812018
AD - for out-of-period adiustment. Use this code for any accounting adjustments or'true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adiustrnent.
4. ln column (c), identiff the FERC Rate Schedule Number or Tarlff, or, for non-FERC Jurisdlctional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, taffis or contract designations under which service, as
identifled in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (0. For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60<ninute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplie/s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawafthours shown on bills rendered to the respondent. Report in colurnns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column fl), energy charges in column (k), and the total of any other types of charges, includlng
out-of-period adjustrnents, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the nst receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes ce(ain credits or charyes covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all requircd data.
Mogawatt Hours
Purchased
(g)
POWER EXCHANGES COST/SETTLEMENT OF POWER Une
No.Mogawatt Hours
Received(h)
Megawatt Hours
Delivered
(i)
Demand Charges
($)
0)
Energy ChargesI Other Charges
(s)
(t)
Total U+k+l)of SetUement ($)
(m)
2,925 2,925 1
21 455 455 2
3,521 79,57€79,578 3
14t 3,264 3,264 4
75,292 2,149,505 2,149,505 5
22.686 22,ffia 6
37 934 934 7
31,241 747,367 747,367 I
33,83€1,063,781 1,063,78'1 9
54,94:1,426,03C 1.426.03C 10
44 1,055 1,055 11
26,144 565,789 565,78€12
3,39e 27,481 27,481 13
1€372 372 14
4,293,616 228,341 259,185 2,559,008 234,922,471 6,899,72s 244,381,204
End of 20171Q4
FERC FORM NO. I (ED.12-00)Page 327.12
Name of Respondent
ldaho Power Company
This
(1)
ls:
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 2O'l7lQ404t18t20't8
'1. Report all pot rer purchases made during the year. Also report exchanges of electricity (i.e., transactions involvlng a balancang of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an oxchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller,
3. ln column (b), enter a Statistical Classification Code based on the original contractual lerms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resouroe planning). ln addition, the reliability of requirement service must
be the same as, or second only to, he supplieis service to its own ultimate consumerc.
LF - for long-term firm service. "Long-term" means live years or longer and 'firm" means that service cannot be intemrpted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy fiom third parties to maintain deliveries of LF seMce). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all flrm servioes, where the duration of each period of commitment for service is one
year or less.
LU - for long-term seMce ftom a designated generating unit. "Long-term' m€ans five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service ftom a designated generating unit. The same as LU service expect that "intermediate-term" means
longerthan one year but less than five years.
EX - For exchanges of elec{ricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any setflements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and servlce from deslgnated units of Less than one year. Describe the nature
of the service in a foohote for each adlustment.
Actual Demand (MW)FERC Rate
Schedule or
Tarlff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Av6ra9e
Mon$ly NCP Demanr
(e)
Average
Monthly CP Demand
(f)
Line
No.
Name of Company or Public Authorlty
(Foohote Affiliations)
(a)
Statistical
Classiff-
cation
(b)
SF WSPP N/A N/A N/A1SeatUe City Light
2 Shell Energy North America (US), L.P SF WSPP N/A N/A N/A
3 T-55OS N/A N/A N/ASiena Pacific Power Co., dba NV Energ
SF WSPP N/A N/A N/A4Snohomish County PUD
N/A5Tacoma Power os wsPP N/A N/A
6 Tacoma Power SF WSPP N/A N/A NUA
SF WSPP N/A N/A t{/A7Talen Energy Marketing, LLC
WSPPos N/A N/A N/A8Talen Energy Marketing, LLC
SF WSPP N/A N/AoTenaska Power Services Co.N/A
10 The Energy Authority, lnc.SF WSPP N/A N/A N/A
11 TransAlta Energy Marketng (U.S.) lnc.SF WSPP NiA N/A N/A
os N/A N/A N/A12Portland General Electic
N)N/A N/A N/A13Prior Year Correction
14 Raft River Energy I LLC LU N/A N/A N/A
Total
FERC FORM ilO.1 (ED.12-90)Page 326.'13
(1)Original
Resubmission
of Report
Da, Yr)
Year/Period of Report
End of 2O17lQ404t192018ldaho Power Company
AD - for out-of-period adlustment. Use this code for any accounting adjustments or 'true-ups" for service providsd in prior raporting
years. Provide an explanation in a footnote for each adjustment.
4. ln column (c), identifu the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sell6rs, include an appropriate
designation for the contract, On separate lines, list all FERC rate schedules, tariffs or contract designations under which seMce, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the montrly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and ttre
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand repo(ed in columns (e) and (f)
must be in megawafts. Footnote any demand not stated on a megawaft basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) he megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net excftange.
7. Report demand charges in column fi), energy charges in column (k), and the tota! of any other types of charges, including
out-of-period adjustnents, in column (l). Explain in a footnote all components of the amount shorrn in column (l). Report in column (m)
Ithe total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the sefllement
lamount for the net receipt of energy. lf more energy was delivered than received, enter a negative amount. lf the settlement amount (l)
linclude credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (glthrough (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 40'1, line 10. The total amount in column (h) must be reported as Exchange Receiwd on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations fullowing all required data.
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Received(h)
Megawatt Hours
Delivered(i)
Demand Charges
8r
Energy Charges
tl]
Other Charges
($)
(t)
Total (i+k+l)
of Settlement ($)
(m)
39,261 824.652 824,652 1
16,2'.t7 307.25(307,2s0 2
78 1,898 1,898 3
2,05€18,08!18,085 4
,t 43 43 5
5,64t 119,69C 119,s)(6
55,53:1,430,48€1,430,48€7
9,261 255,081 255,081 I
2,17a s4,193 54,193 I
6,2tr 124,84 't24,U4 10
53,09t 1,820,771 1,820,771 11
78,742 78,742 12
1C 330 330 13
84,08€5,640,13'1 5,640.131 14
4,293,616 228,341 259,185 2,55S,008 2U,922,471 6,899,725 244,381,204
FERC FORil NO.1 (ED. t2-90)Page 327.13
Name of Respondent
ldaho Power Company
DIt 13:
An Original
A Resubmission
Dal€ of Reoort(Mo. Da, Yi)
04t1812018
Year/Period ot Report
End of 20'l7lQ4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or oth€r party in an exchange transaction in column (a). Do not abbreviate or truncate ths name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with lhe seller.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). ln addition, the reliability of requirement service must
be the same as, or second only to, the supplie/s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and 'firm" means that service @nnot be interupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency
energy from hird parties to maintain deliveries of LF service). This category should not be used for long-term lirm service ftrm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
deffned as the earliest date that either buyer or seller can unllaterally get out of the contract.
lF - for intermediate-term firm servic€. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use his category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service fom a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transrnission constraints, must match the availabili$ and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longerthan one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any setflements for imbalanced exchanges.
OS - for other seMce. Use this category only for those services which cannot be placed in the above{efined categories, such as all
non-firm servios regardless of the Length of the contract and service from designated units of Less than one y6ar. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-
caton
(b)
FERC Rate
Sdredule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand
Monthly
(e)(0
1 Telocaset Wind Power Parlners LLC LU APP-A N/A N/A N/A
2 Noal Hot Springs Unit #1 LU N/A N/A N/A
3 Oregon Solar Customers os N/A N/A N/A
4 Avista Corp.D(N/A N/A N/A
5 Bonneville Power Administation D(N/A N/A N/A
6 NorthWestem Energy EX N/A N/A N/A
7 PacifiCorp lnc.D(N/A N/A TUA
8 Sierra Pacific Power Co., dba NV Energ D(N/A N/A N/A
I Clatskanie PUD EX 't53 N/A N/A N/A
'10 Clark Canpn Hydro os0 N/A N/A N/A
11 Acctg Valuation of Clatskanie PUD os 0 N/A N/A N/A
12 Demand Response Avoided Energy os N/A N/A N/A
13
14
Total
FERC FORM NO. I (ED.12-90)Page 326.14
(1)
AVe e
Name (1)
(2)
An Originalldaho Power Company A Resubmission
Date of Report(Mo, Da, Yr)
04t1812018
Year/Period of Report
End of 2O17lQ4
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "tru€-ups" for seMce provided in prlor reporting
years. Provide an explanation in a footnote for each adiustmenl
4. ln column (c), identiff the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate llnes, list all FERC rate schedules, tariffs or contract designations under which servic€, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly oincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (0. Monthly
NCP demand is the maximum metered hourly (60+ninute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) ancl (0
must be in megawafts. Footnote any demand not stated on a megawatt basis and oxplain.
6. Report in column (g) the megawatthours shown on bills randered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column O, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (1). Eplain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondenl For power exchanges, r€port in column (m) the sefrlement
amount for the net receipt of energy. lf more energy was delivered than received, enter a negatve amount. lf the sefilement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or cfiarges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The totral amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
o)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Mogawat Hours
Received(h)
Megawatt Hours
Ddivered
(i)
Demand Charges
t?r
Energy Charges
($)
(k)
Other Gharges
($)
(t)
Total 0+k+l)of SetUement ($)
(m)
302,46(18,329,296 't8,329,29€1
172,90e 19,295,177 19,295,177 2
731 15,930 15,93C 3
815 4
84,499 5
6
62.106 125.382 7
1,228 I
80,921 132,575 I
-21 1,500 -21 1,500 10
-428,088 -428,088 11
6,983,314 6,983,3'14 't2
13
14
4,293,616 228,341 259,185 2,s59,008 234,922,471 6,899,725 244,*1,204
Page 327'11FERC FORrrr NO. r (ED.12.9,)
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
o4118t2018
YearlPeriod of Report
20171Q4
FOOTNOTE DATA
Sciedule Page: 326.4 Line No.: 1 Column: bIda West, a subsidiary of IDACORP (Idaho Power Company's parent company), has partial
ownership of this project.
Scfiedule Page:326.5 LineNo,: 12 Column: b
Ida West, I subsidiary of IDACORP (Idaho Power Company's parent company), has partial
9ry1eqsh,1p 9f tl1_19 projeg!
Scfiedule Page: 326.8 Line No.: I Column: b
1da Wes-:, a subsidiary of IDACORP (Idaho Power Company's parent company),
ownershio of th-s projecL.
Schedule Page; 3l-6,-8- Line No.: 10 Column: b
Non-firm purchases
Schedule Page: 326.8 Line No.: 11 Column: b
Non-firm purchases
Schedule Page: 326-9 Line No.: 9 Column: b
Tda Wesr, a subsidiary of IDACORP (Idaho Power Company's parent company),
ownership of thi-s project.
Schedule Page: 326.9 Line No.: 11 Column: b6rfference between booked and scheduled energy
Schedule Page: 326.9 Line No.: 11 Column: b
ADM Investor Services, Inc f'utures Account Document, dated May 5. 2015
Schedute Page:326.10 Line No.:3 Column: b
Spinning oi Ope.aling Reserves
'schedule Page: 326.10 Line No.: 5 Column: bFinancial Transmission Losses
Schedute Page:326-10 Line No.:7 Cotumn: bSpinning or Operating Reserves
'Schedute Page: 326.10 Line No.: 9 Column: bFinancial Transmission Losses
Scheduie iage: Si&lo Line No.: 13 Cotumn: b
Spinning or Operatlng Reserves
'Schedule Page: 326.11 Line No.: 2 Column: b
ISDA Master Agreement Wi-th CicigrouP, dated March 7, 2011
ScDedule Page: 326.11 Line No.: 4 Column: bSpinning or Operating Reserves
ScDoduls Page: 326.11 Line No.: 9 Column: b
Spinn:.ng or Operating Reserves
Schedule Page: 326.11 Line No.: 1O Column: bSpinning or OperaLLng Reserves
Schedule Page:326-11 Line No,: 12 Column: b
ISDA Master Agreement wiin Macquarie Energy, LLC dated AprrL 12, 2011
Schedule Page:326.12 Line No.:1 Column: bFinancial Transmission Losses
Echedule Page: 326.12 Line No.: 2 Column: b
Spinning or Operating Reserves
Schedula Page:326.12 Line No;4 Column: b
Spinning or Operating Reserves
Sc&edule Page: 326.12 Line- No.: 6 Column: b
Ei-nancial ?ransmission Losses
Sclredule Page:326.12 Line No.:7 Column: b
Spinnj.ng or Operating Reserves
Schedule Page: 326.12 Line No.: 11 Column: b
Spinninq. or Operaling Reserves
'Schedule Page: 326.12 Line No.: 11 Column: b
Spinninq or Operating Reserves
has pa:tial
has partial
FERC FORM NO.1 450.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) - A Resubmission
Date of Report
(Mo, Da, Yr)
0411u2018
Year/Period of Report
20171Q4
FOOTNOTE DATA
Schedule Page: 326,13 Line No.: 3
Spinni.ng or Operating Reserves
Schedule Page:326.13 Line ltlo..'5 Column: b
Sp,.nl or Q_perating Reserves
Schedule 326.13 Line No.:8 Column: b
Unit Continggnt Purchases
Operatlng aqreement with Portland General Electr
Power Plant offline - Boardman Assured
Schedule Page: 326.13 Line No; 13 Column: b
Correctlons from 2016
Schedule Page: 326.14 Line No.: 3
Schedule B8 Oregoa Solar
SchdulePage: 326.11 Line No.: 4Physical transmiqs,lon losses
Sciedulo Page:326.14 Line No.:5Physical transmission losses
Schedule Page: 326-11 Line No.: 6Physical transmission losses
Schedule Page: 326.14 Line No.: 7
Physical transrnission losses
Schedule Page:326.11 Line No.:8Physical transmission losses
Schedule Page:326.11 Line No.:9 Column: b
Energy exchange between Clatskanj-e PUD and Idaho
Schedule Page: 326.11 Llne No; 1O Column: b
CSPP liquidated da,mages
Scheduls Page:326.11 Llne No.: 11 Column: b
Energy exchange between Clatskanie PUD and Idano
Schedule Page: 326.11 Line No.: 12 Column: bIncentive program for customers to reduce demand
ic to still provj.de power if Boardman
Column: b
Column: b
Column: b
eotunii: t
Column: b
Column: b
Column: b
Po;ef e.g4rpeny at Eiiow;oAk
Power C*omp_any_ at Arrowrock
during pear nouis - --
Dam
Dam
FERC FORM NO.1 1 450.22-871
Name of Regondeot
ldaho Power Company
This
(1)
(2)
R€oort 18:
ffiAn originat
[lA Resubmission
Date of Report
(Mo, Da, Yr)
04118120'.t8
Year/Period of Report
End of 2O17lQ4
IRANS lo as
ccount 456.1)
1. Report all transmission of electricity, i.e., wheeling, provided for other elec'tric utilities, cooperatives, other public authoritios,
qualirying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the bansmission service. Report in column (b) the company or
public authority that the energy was receiv€d from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority, Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP -'Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transrnission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Servlce and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or'kue-ups'for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General lnstruc{ion for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affliation)
(a)
Energy Received From
(Company of Public Anthority)
(Footnote Affliation)
(b)
Energy Oelivered To
(Company of Public Authoilty)
(Footnote Affiliation)
(c)
Statistical
Classifl-
cation
(d)
1 Bonncvllle PowerAdnHrtatlon - OTEC Bonneville Power Administration Oregon Trails ElecUic Co-op FNO
2 Bonnodle PomrA&Ir{faton - USBR Bonneville Power Administration United States Bureau of Reclamati FNO
3 Bonnorllls Potir.rAdlrlnhta0on - PF Bonnoville Power Adminisbation Priorig Firm Customers FNO
4 Mllnorlrlgdlon Utiid United States Bureau of Reclamati Milner lrrigation District OLF
5 Morgan SEt!€y Crdbl Goup lnc Seatile City Ught Bonneville Power Administration OS
D PadfCoO PacifiCorp West PacifiCorp West FNO
7 Unltcd Shtcc Eunau of lndan Afhlrt Bonneville Power Administration United States Bureau of lndian Af OS
8 Cydc Florecchoe Ecnd Vlllnd, I-LC PacifiCorp East ldaho Power Company OS
I Cycle Horseshoe Bend Wind, LLC PacifiCorp East ldaho Power Company os
10 Cycle Horseshoe Bend Wnd, LLC PacifiCorp East ldaho Power Company OS
11 Cycle Horsoshoe Bend Wnd, LLC PacifiCorp East ldaho Power Company OS
12 United Materials of Great Falls PacifiCorp East ldaho Porver Company OS
13 United Materials of Great Falls PacifiCorp East ldaho Porver Company OS
14 Mountain Home Solar 1 OS
15
't6 PacifiCorp lnc.PacifiCorp East Bonneville Power Administration LFP
17 PaciffC.orp lnc.PaclffCorp East PacifiCorp West LFP
18 PacifiCorp lnc.PacifiCorp East PadfiCorp West LFP
19 Morgan Stanley Capital Group lnc.ldaho Power Company Bonneville Power Administration LFP
20 Bonneville Power Adminishation PacifiCorp West PacifiCorp East LFP
21 Bonneville Power Administration PacifiCorp West PacifiGorp East LFP
22
23 APS - Pinnacle West Capital Corp.Bonneville Power Administration PacifiCorp East NF
24 APS - Pinnacle West Capital Corp.Bonneville Power Administration PacifiCory East NF
25 Avangrid Renewables, LLC PacifiCorp East Bonneville Power Adminishation NF
26 Avangrid Renewables, LLC NorthWestem/Pacifi Corp East PacifiCorp East NF
27 Avangrid Renewables, LLC Norfi Westem/Pacifi Corp East Siena Pacific Power NF
28 Avangild Renewables, LLC Bonneville Power Administration PacifiCorp East NF
29 Avangrid Renewables, LLC Bonneville Power Administration Sierra Pacific Power NF
30 Avangrid Renewables, LLC Avista Siena Pacific Power NF
31 Avangrid Renewables, LLC Siena Pacific Power Bonneville Power Administration NF
32 Avangrid Renewables, LLC PacifiCorp West PacifiCorp East NF
33 Avangrid Reneurables, LLC PacifiCorp West PacifiCorp East NF
34 Avangild ReneYyables, LLC PacifiCorp West Siena Pacific Porer NF
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328
Name of Respondent
ldaho Porver Company
Date(Mo,
of
(1)
t2)
An Original
A Resubmission
Da,
ail1812018
Year/Period of Report
End of 20171Q4
to as t 4sOXUOntnUeO)
5. ln column (e), identiff the FERC Rate Schedule or Tarifr Number, On soparate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (f), report the
designation br the substration, or other appropriate identification for where energy was received as specified in the conlract. ln column
(g) report the designation for he substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specifled in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and fi) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designa0on)
(D
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(Mw)
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received(i)
Megawan Hours
Delivered
0)
I 346,83C 346,83(,|
I 301,394 30't,39,(2
I 1,287,721 't,287,727 3
togacy Minidoka. ldaho Various in ldaho 9,341 9,341 4
4 452,702 452,701 5
I 2,087 2,08i 6
Legacy LaGrande, Oregon Various in ldaho 13,788 13,78{7
5€BRDY tPco o (I
5/6 BRDY IPCOEAST 775 771 I
5t6 JEFF tPco 1,307 1.307 10
5/6 JEFF IPCOEAST 8,219 8,215 11
5/6 BRDY IPCO 2,711 2,7'.1'.|'t2
5/6 JEFF rPco 6.2U 6,294 13
11 14
15
IB BOFIA LAGRANDE 457,86€457,86(16
7t8 KPRT HURR 373,861 373,861 17
7t8 BORA HURR 495,862 495,862 18
7t8 LYPK I-AGRANDE 19,749 19,749 19
7t8 M500 KPRT 109,873 109,873 20
7t8 SMLK KPRT 208,974 208,974 21
22
7t8 LAGRANDE BORA 235 235 23
7t8 LAGRANDE BROY 50c 50(24
7t8 BORA LAGRANDE 6 (25
7t8 BPAT.NWMT BRDY 29 2(26
7t8 BPAT.NWMT M345 EO <(27
7t8 LAGRANDE BORA 6,693 6,69i 2A
7t8 LAGRANDE M345 5,242 5,242 29
7t8 LOLO M345 832 832 30
718 M345 LAGRANDE 325 32a 31
718 SMLK BORA 6,202 6,202 32
718 SMLK BRDY 8 t 33
7t8 SMLK M345 517 51?u
0 6,832,8E0 0,E32,68!
FERC FORM lrlO. I (ED. 12-90)Page 329
Name of Respondont
ldaho Power Company
This
(1)
(2',,
ReDort ls:lflAn Onginal
[lA Resubmission
Date of Reoort
(Mo, Da, Yi)
0411812018
Year/Period of Report
End of 20171Q4
I KANi
as
ccount 456.1 )
1. Report all transmission of electricity, i.e., wheeling, provided br other electric utilities, cooperatives, other public authorities,
qualiffing facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separat€ line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or publlc authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or u6o acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Selt LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - OtherTransmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or 1rue-ups" for service provided in prior reporting periods. Provide an explanation in a foohote for
each adjustment. See General lnstruction for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Foohote Affiliation)
(a)
Energy Received From
(Company of Public Auhority)
(Footnote Affliation)
(b)
Energy Delivered To
(Company of Public Auhority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Blad Hills Power lnc.Bonneville Power Administation PacifiCorp East NF
2 Black Hills Power lnc.Bonneville Power Administation PacifiCorp East NF
3 Bonneville Power Administration Northwestem/Pacifi Corp East PadftCorp East SFP
4 Bonnevilla Power Adm inistration NorthwostomlPadfi Corp East Siena Pacific Power NF
5 Bonneville Power Administration PacifiCorp East Bonneville Power Administration NF
o Bonneville Power Administration PacifiCop East Sierra Pacific Power NF
7 Bonneville Power Administration PacifiCorp East Bonneville Power Administration NF
I Bonneville Power Adminisfation PacifiCorp East Bonneville Power Administration NF
I Bonneville Power Administration Bonneville Power Administration PacifiCorp East NF
10 Bonneville Power Administration Bonneville Power Administration PacifiCorp East NF
11 Bonneville Power Administration Bonneville Pow€r Adminiskation Bonneville Pow€r Administration NF
12 Bonneville Power AdminisFation Bonneville Power Administation Sierra Pacific Power NF
13 Bonneville Power Adminislration Bonneville Power Adminishation Bonneville Power Adminisbation NF
14 Bonneville Power Administration Avista PacifiCorp East NF
15 Bonneville Power Adminisfation Avista Bonneville Power Administration NF
16 Bonneville Power Administration Avista Bonneville Power Administration NF
17 Bonneville Power Adminisfation Avisla Siena Pacifc Power NF
18 Bonneville Power Administration Siena Pacific Power PaciflCorp East NF
19 Bonneville Power Administration PacifiCorp West Siena Pacific Power NF
2A Bonneville Powor Administration PacifiCorp West PacifiCorp East NF
21 Bonneville Power Administration PacifiCorp West PaciftCorp East SFP
22 Bonneville Power Administration PacifiCorp West Siena Paciflc Power NF
23 Bonneville Power Administation PacifiCorp West Sierra Pacific Power SFP
24 Cargill-Alliant ldaho Power Company PacifiCorp East NF
25 Cargill-Alliant PaclffCorp East PacifiCorp East NF
26 Cargill-Alliant PacifiCorp East PaciliOorp East NF
27 Energy Keepers, lnc.Bonneville Power Administration Sierra Pacific Power NF
28 Macquarie Energy, LLC PacifiCorp East Bonneville Power Administation NF
29 Morgan Stanley Capital Group lnc,Northwestom/Pacifi Corp East PacifiCorp East NF
30 Morgan Stanley Capital Group lnc.NorthWestemlPaoillCorp East Bonneville Power Adminisfation NF
31 Morgao Stanley Capital Group lnc.NorlhWestem/Pacifi Corp East Sierra Pacific Power NF
32 Morgan Stranley Capital Group lnc.NorthWestern/PacillCorp East Siena Pacific Power SFP
33 Morgan Stanley Cagital Group lnc.PacifiCorp East NorthWestern/Pacifi Corp East NF
34 Moryan Stanley Capital Group lnc.PaciffCorp East PacifiCorp East NF
TOTAL
FERC FORm NO.1 (ED. r2-s0)Page 328-1
ldaho Power Company
(1)
(2)A Resubmission
Date of Reoort(Mo, Da, Yi)
04t18t2018
Year/Period of Report
End of 2O17lQ4
as t 456,XConUnu€d)
5. ln column (e), identifr the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, 'point to point'transmission s€rvlce. ln column (f), report the
designation for the substation, or other appropriate identification for where €nergy was received as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identilication for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the lirm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the tota! megawatthours received and delivered.
FERC Rate
Sdredule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Olher
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(Mw)
(h)
TRANSFER OF ENERGY Line
No.M€gawan Houni
Received(i)
Megawan Hours
Ddivered(i)
7t8 I-AGRANDE BORA s63 s6i 1
7t8 ISGRANDE JBSN 2A 2(2
7t8 BPAT.NWMT BORA 7,000 7,00(3
7t8 BPAT.NWMT M345 46 4t 4
7t8 BRDY BPASIO 57 5;5
718 BRDY M345 1,330 't,33(6
7t8 KPRT BPASID 975 97a 7
7t8 KPRT OTEC 4 I I
7t8 LAGRANDE BORA 1,022 1,O22 9
7t8 I.AGRANDE KPRT 37 3?10
7lB TAGRANDE LAGRANDE 1,910 1,91(11
7ta LAGRANDE M345 23,723 23,723 12
7t8 LAGRANDE OTEC 7 1 13
718 LOLO BORA 193 193 14
7t8 LOLO BPASID 5 T 15
7t8 LOLO LAGRANDE 901 901 't6
7t8 LOLO M345 593 59:17
718 M345 EORA 270 27(18
718 M500 M345 203 201 19
7t8 SMLK BORA 72 7i 20
7t8 SMLK BORA 1 1 1,907 111,90]21
718 SMLK M345 862 86i 22
7t8 SMLK M345 43,594 43,59r 23
7t8 IPCOGEN BORA 400 40(24
7t8 JBSN BORA 1,970 1,97(25
7t8 JEFF BORA 2,687 2,ffi1 26
7t8 LAGRANDE M345 100 10(27
7t8 BORA I-AGRANDE 100 10(28
7t8 AVAT.NWMT BORA 2,455 2,451 29
718 AVAT.NWMT LAGRANDE 874 874 30
7t8 AVAT.NWMT M345 6.323 6,323 31
7t8 AVAT.NWMT M345 64,524 64,524 32
718 BORA BPAT.NWMT 128 12t 33
718 BORA BRDY 10 1(34
0 6,832,880 6,E32,88(
FERC FORI'I NO. I (ED. 12-90)Page 329.1
ldaho Power Company (1)
t2)
An OrEinal
A Resubmission
Date of Report(Mo, Da, Yr)
04t1812015
Year/Period of Report
End of 2O17lQ4
TRANS as ccount 4co.1 )
1. Regort all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives. other public authorities,
qualifiing facilities, non-traditaonal utility suppliers and ultimate customeni for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authorig. Do not abbreviate or truncate name or use acrcnyms. Explain in a footnote
any ownership interest in or affiliatlon the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service tor Others, FNS - Firm Network Transrnission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or'true-ups'for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General lnstruction for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote ffiliation)
(a)
Energy Received From
(Company of Public Authority)
(Foohote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote ffiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Morgan Slanley Capital Group lnc.PacifiCorp East Bonneville Power Administration NF
2 Morgan Stanley Capital Group lnc.NorthWestem/Pacifi Corp East PacifiCorp East NF
3 Morgan Stanley Capital Group lnc.NorthWestem/Pacifi Corp East PaciliCorp East SFP
4 Morgan Stanley Capital Group lnc.NorhWestem/Pacifi Corp East PacifiCorp East NF
5 Morgan Stanley Capital Group lnc.Norfi Westem/Pacifi Corp East PactfiCorp East SFP
6 Morgan Stanley Capital Group lnc.Norft Westem/Pacifi Corp East Bonnovill€ Power Administration NF
7 Morgan Stanley Capital Group lnc.NorthWestem/Pacifi Corp East Sierra Pacific Power NF
8 Morgan Stanley Capital Group lnc.NorhWestem/Pacifi Corp East Sierra Pacific Power SFP
9 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
10 Morgan Stanley Capital Goup lnc.PaciliCorp East PacifiCorp East SFP
11 Morgan Stanley Capital Group lnc.PacifiCorp East Bonneville Power Adminisbation NF
12 Morgan Sbnley Capital Group lnc.PacifiCorp East Sierra Pacific Power NF
13 Morgan Stanley Capital Group lnc.PacifiCorp East Siena Pacific Power SFP
14 Morgan Stanley Capital Group lnc.PacifiCorp W6st Pacificorp East NF
15 Morgan Stanley Capital Group lnc.PacifiCorp West PacifiCorp East SFP
16 Morgan Stanley Capital Group lnc.PacifiCorp West Siena Pacific Power NF
17 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
18 Morgan Stanley Capital Group lnc.PacifiCorp East PacifiCorp East NF
19 Morgan Stanley Capital Group lnc.PacifCorp East Bonneville Power Administration NF
20 Morgan Sbnley Capital Grcup lnc.PacifiCorp East Sierra Pacific Power NF
21 l\ilorgan Stanley Capital Group lnc"PacifiCorp East PacifiCorp East NF
22 Morgan Sbnley Capital Group lnc.PacifiCorp East PacifiCorp East SFP
23 Morgan Stanley Capital Group lnc,PacifiCorp East PacifiCorp East NF
24 Morgan Stanley Capital Group lnc.PacifiCorp East Bonneville Power Administration NF
25 Morgan Stanley Capital Group lnc.PacifiCorp East Sierra Pacific Power NF
26 Morgan Stanley Capital Group lnc.Bonneville Power Administration PacifiCorp East NF
27 Morgan Stanley Capiial Group lnc.Bonneville Power Administration PacifiCorp East NF
2A Morgan Stanley Capital Goup lnc.Bonneville Power Administration PacifiCorp East NF
29 Morgan Stanley Capital Group lnc.Bonneville Power Administration Sierra Pacific Power NF
30 Morgan Stanley Capital Group lnc.Avista PacifiCorp East NF
31 Morgan Stanley Capital Grup lnc.Avista PacifiCorp East SFP
32 Morgan Stanley Capital Goup lnc.Avista PacifiCorp East NF
33 Morgan Stanley Capital Group lnc.Avista PacifiCorp East SFP
34 Morgan Stranley Capitral Group lnc,Avista Siena Pacific Power NF
TOTAL
?age 32E'2FERC FORM NO. 1 (ED. 12-90)
End of 2O17lQ4ldaho Power Company (1)Original
Resubmission o4116t2018
as I 4COXUOnOnUeO'
5. ln column (e), identi$ the FERC Rate Schedule or Tarifi Number, On separate lines, list all FERC rate schedules or contract
designalions under which service, as id€ntified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, 'point to point' transmission servic6. ln column (0, report the
designation for the substiation, or other appropriate identification for where energy was received as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and O the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Oher
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.M€gswatt Hours
Received(i)
Megawan Hours
Delivered(i)
7t8 BORA I-AGRANDE 232 23'1
7t8 BPAT.NWMT BORA 1,447 1,447 2
7t8 BPAT.NWMT BORA 3,62S 3,62(3
7t8 BPAT.NWMT BRDY 494 49t 4
7t8 BPAT.NWIT4T BRDY 26,5s(5
7t8 BPAT.NWMT I-AGRANDE 4,548 4,54(6
7t8 BPAT.NWMT M345 12J34 12,'.t3t 7
7t8 BPAT.NWMT M345 129,191 I
7t8 BRDY BORA 2,561 2,561 I
7t8 BRDY BORA 5,403 5,40:10
7t8 BRDY TAGRANDE 7,258 7,25t 11
7t8 BRDY M345 24.560 24.fiC 12
7t8 BRDY M345 41,93?13
7t8 H500 BORA 19,090 19,09(14
7t8 H500 BORA 't,027 1,Oz't 15
7t8 H500 M345 204 204 16
7t8 JBSN BORA 1,895 17
718 JBSN BRDY 2 I 18
718 JBSN LAGRANDE 345 34{19
7t8 JBSN M345 110 1',1(2A
7t8 JEFF BORA 57,424 57,42t 21
7t8 JEFF BORA 't 5€15t 22
718 JEFF BRDY 830 83(23
7t8 JEFF LAGRANDE 2,431 2,431 24
718 JEFF M345 83,364 83,3&25
7t8 LAGRANDE BORA 41,432 41,43i 26
7t8 LAGRANDE BRDY 't0,230 10,23{27
7t8 LAGRANDE JBSN 50 5(28
718 LAGRANDE M345 59,338 59,33t 29
718 LOLO BORA 91,418 9't,41t 30
718 LOLO BORA 't4,026 14,021 31
7t8 LOLO BRDY 3,619 3,61!32
7!8 LOLO BRDY 1,7't8 1,7'.t8 33
7t8 LOLO M345 171,686 171,ffi 34
0 0,832,88{
FERC FORii NO. r (ED. 12-90)Pago 329.2
26,5501
129,191J
41,934
1,8951
6,832,SS61
Namo of Respondent
ldaho Power Company
Ihis F(eooft lB:(1) ffiRnoriginat(2) f-lA Resubmission 0411812018
ll(ANi as ccount 456.1 )
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distlnct type of transrnission sewice involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid forthe transrnission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or afiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or'true-ups" br service provided in prior reporting periods. Provide an explanation in a footnote for
each adlustment. See General Instruction for defnitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affliation)
(a)
Energy Received From
(Company of Public Authority)
(Foohote Affiliation)
(b)
Energy Delivered To
(Company of Public Auftority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Morgan Sbnley Capital Grcup lnc.Avistia Siena Pacific Power SFP
2 Morgan Stanley Capital Group lnc.ldaho Power Company NorthWestem/Pacif Corp East NF
3 Morgan Stianley Capital Group lnc.ldaho Power Company PaciliCorp East NF
4 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East SFP
5 Morgan Stanley Capital Group lnc.ldaho Power Company NorthWestem/Pacifi Corp East NF
6 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East NF
7 Morgan Shnley Capital Group lnc.ldaho Power Company PacifiCorp East SFP
I Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East NF
I Mo.g€n Stanley Capital Group lnc.ldaho Power Company Avista NF
10 Morgan Stsnley Capitial Group lnc.ldaho Power Company Siena Pacific Power NF
11 Morgan Stanley Capital Group lnc.Siena Pacific Power PacifiCorp East NF
12 Morgan Stanley Capital Group lnc.Sierra Pacific Power NorthWestern/Pacifi Corp East NF
13 Morgan Stanley Capital Grcup lnc.Sierra Pacific Power PacifiCorp East NF
14 Morgan Stanley Capital Group lnc.Sierra Pacific Power Bonnevillo Power Administration NF
't5 Morgan Stranley Capital Group lnc.PacifrCorp West Pacific,orp East NF
16 Morgan Stanley Capital Group lnc.PacifiCorp West Siena Pacific Power NF
17 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East NF
18 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East SFP
19 Morgan Stanley Capital Group lnc.ldaho Power Company PacifiCorp East NF
20 Morgan Stanley Capitral Group lnc.ldaho Power Company Siena Pacific Power NF
21 Nevada Power Co.PacifiCorp East Siena Pacific Power NF
22 Nor$westem Energy PacifiCorp East Bonneville Pow6r Administration NF
23 PacifiCorp lnc.PacifiCorp East Avista NF
24 PaciffCorp lnc.PacifiCorp East NorthWestem/Pacifi Corp East NF
25 PaciffCorp lnc.PaciliCorp East PacifiCorp East NF
26 PacifiCorp lnc.PacifiCorp East PaciliCorp East SFP
27 PacifiCorp lnc.PacifiCorp East Bonneville Power Adminisbation NF
28 PacifiCorp lnc.PacifiCorp West PacifiCorp East NF
29 PacifiCorp lnc.PacifCorp West PacifiCorp East NF
30 PacifiCorp lnc.PacifiCorp West Bonneville Pow€r AdminisbaUon NF
31 PacifiCorp lnc.Bonneville Power Administration PacifiCorp East NF
32 PacifiCorp lnc.Bonneville Power Administration PacifiCorp East NF
33 PaciffCorp lnc.Avista Pacificorp East NF
34 PacifiCorp lnc.Avista PacifiCorp East NF
TOTAL
End of 20171Q4
FERC FORm NO. 1 (ED. 12-90)Page 328.3
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo. Da, Yr)
04t18t2018
Year/Period of R€port
End of 20171Q4
as
t 456Xgontnuod)
5. ln column (e), identiff the FERG Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point'transmission service. ln column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specllied in the
contract.
7. Report in column (h) the number of megawatB of billing demand that is specified in the firm tansmission servie contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and 0) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Deli\r€ry
(SubsEtion or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawa[ Hours
Received(i)
Megewa[ Hours
Dellv€red
0)
7t8 LOLO M34s 1 16,499 1 16,49S I
7t8 LYPK AVAT.NWMT 378 378 2
7t8 LYPK BORA 24,751 24,751 3
7t8 LYPK BORA 32,S88 32,98t 4
718 LYPK BPAT.NWMT 3.29?3,297 5
718 LYPK BRDY 8,383 8,383 6
718 LYPK BRDY 4,654 4,654 7
718 LYPK JBSN 31 31 8
7t8 LYPK LOLO 538 538 I
7t8 LYPK M345 361,352 361,352 10
7t8 M345 BORA 1,062 1,062 11
7t8 M345 BPAT.NWMT 1,041 't,o4'12
7t8 M345 BRDY 't,348 1,34t 13
7t8 M345 LAGRANDE 469 46(14
718 SMLK BORA 58,628 58,62t '15
7t8 SMLK M345 716 71(16
718 WALLAWALLA BORA r4,383 14,38:17
7t8 WALLAWALLA BORA 5,1 92 5,19i 18
7t8 WALLAWALLA BRDY 100 10('t9
7t8 WALLAWALLA M345 't23 124 20
7t8 BRDY M345 144 14t 21
7t8 BRDY LAGRANDE 150 15(22
718 BORA LOLO 61 61 23
718 BRDY BPAT.NWMT 640 6,4(24
7t8 BRDY BRDY 196 19€25
7t8 BRDY BRDY 1,773 1,773 26
7t8 BRDY LAGRANDE 2,087 2,087 27
7t8 HURR BORA 3,107 3,107 28
7t8 HURR BRDY 890 890 29
7t8 HURR LAGRANDE 2,954 2,954 30
7t8 ISGRANDE BORA u,476 34,471 31
718 LAGRANDE BRDY 13,504 13,50r 32
7t8 LOLO BORA 2,190 2,1S(33
7t8 LOLO BRDY 1,976 1,97(34
0 6,832,886 6,832,8E(
FERC FORM NO. r (ED. 12-90)Page 329.3
ldaho Power Company (1)
(2)
An Original
A Resubmission
Oat€ of Report(Mo, Da, Yr)
o411812018
YearlPeriod of Report
End of 20171Q4
It{ANt
AS
ccount 450,1 )
1. Report all transrnission of el6c{ricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualiffing facilities, non-traditional utility snppliers and ultimate customeni for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) he company or
public authority that the energy was received ftom and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Polnt to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservatlon, NF - non-firm transrnission service, OS - Other Transmission Service and AD - Out-of-Period AdjustsnenB. Use this code
fur any accounting adjustments or "true-ups' for service provided in prior reporting periods. Provide an explanation in a foohote for
each adjustment. See General lnstruction for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Foohote Affliation)
(b)
Energy Delivered To
(Company of Public Anthorlty)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 PacifiCorp lnc.Avista PacffiCorp West NF
2 PacifiCorp lnc.Avista Bonneville Power AdminisUation NF
3 PacifrCorp lnc.PacifiCorp West PacifiCorp East NF
4 PacifiCorp lnc.PacifiCorp West PacifiCorp East SFP
5 PacifiCorp lnc.PaciffCorp West PaciflCorp East NF
6 Portand General Electric PacifiCorp East Bonneville Power Adminisbation NF
7 Powerex Corporation PaciftCorp East Bonneville Power Administration NF
8 Powerex Corporation NorthWestem/Pacifi Corp East PacifiCorp East NF
I Porerex Corporation Northwestem/Pacifi Corp East Siena Pacific Power NF
10 Powerex Corporation PaciffCorp East PacifiCorp East NF
11 Powerex Gorporation PacifiCorp East Siena Pacific Power NF
12 Powerex Corporation PacifiCorp East Bonneville Power AdministaUon NF
13 Powerex Corporation PacifiCorp West PacifiCorp East NF
14 Powerox Corporaton PacifiCorp West PacifiCorp East NF
15 Powerex Corporation PacifiCorp East PacifiCorp East NF
16 Powerex Corporalion PacifiCorp East Bonneville Power Administration NF
17 Powerex Corporation PacifiCorp East PacifiGorp East NF
18 Powerex Corporation PacifiCorp East PacifiCorp East NF
19 Powerex Corporation PaciffCorp East Bonneville Power Administration NF
20 Powerex Corporation PacifiCorp East Sierra Pacillc Power NF
21 Powerex Corporation Bonneville Power Administration PacifiCorp East NF
22 Powerex Corporation Bonneville Power Administration PaciliCorp East NF
23 Powerex Corporation Bonneville Power Administration Siera Pacific Power NF
24 Powerex Corporation Avista PaclfiCorp East NF
25 Powerex Corporation Avista PacifiCorp East NF
26 Powerex Corporation Siena Pacific Power PacifiCorp East NF
27 Powerex Corporation PacifiCorp West PacjfiCorp East NF
28 Powerex Corporation PacifiCorp West PacifiCorp East NF
29 Powerex Corporation PacifiCorp West Sierra Pacific Power NF
30 Powerex Corporation ldaho Power Company PaciltCorp East NF
31 Shell Energy North America (US), L.P PacifiCorp East Sierra Pacific Power NF
32 Shell Energy North America (US), L.P NorthWestern/Pacifi Corp East PacifiCorp East NF
33 Shell Energy Norfr America (US), L.P NorlhWestem/Pacifi Corp East Bonneville Power Administration NF
34 Shell Energy North America (US), L.P NorlhWestem/Pacifi Corp East Siena Pacific Power NF
TOTAL
FERC FORM NO. r (ED.12-90)Page 328.1
Name of Respondent
ldaho Power Company (1)
12)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
0411812018
Year/Period of Report
End of 20171Q4
as t 4coxuontnued)
5. ln column (e), identiff the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or @ntract
designations under which service, as adentmed in column (d), is provided.
6. Report receipt and dellvery locatlons for all single contract path, "point to point" transmission service. ln column (0, report the
designation for the substialion, or other appropriate identification for where energy was raceivod as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identificatlon for where energy was delivercd as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawafts basis and explain.
8. Report in column (i) and O the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatstlon or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Mogawan Frours
Received(i)
Megawac Hours
Dellvered(i)
7t8 LOLO HURR 157 157 I
7t8 LOLO ljcRANOE 947 941 2
718 SMLK BORA 265,277 269,271 3
7t8 SMLK BORA 1,220 1,22t 4
7t8 SMLK BRDY 17,204 '17,204 5
7t8 JEFF LAGRANDE 788 78€6
7t8 BORA LAGRANDE 12 12 7
7t8 BPAT.NWMT BRDY 7 7 8
7t8 BPAT.NWMT M345 2N 2t I
7t8 BRDY BORA 125 121 10
718 BRDY M345 624 62t 11
718 GSHN LAGRANDE 100 10(12
7t8 HURR BORA 15 1t t3
7t8 HURR BRDY 12 'ti 14
7t8 JBSN BORA 114 11t 15
7t8 JBSN LAGRANDE 44 44 16
718 JEFF BORA 587 58?17
718 JEFF BRDY 411 411 18
7t8 JEFF LAGRANDE 31 31 19
7t8 JEFF M345 233 233 20
7t8 ljcRANDE BORA 6,875 6,875 21
718 LAGRANDE BRDY 3,7't0 3,71C 22
7t8 LAGRANDE M345 804 804 23
7t8 LOLO BORA 706 701 24
7t8 LOLO BRDY 481 48'25
7t8 M345 BORA 20c 20(26
7t8 SMLK BORA 9,017 9,0'r:27
7t8 SMLK BRDY 1,761 1,761 28
7t8 SMLK M345 1 ,01S 1,01!29
7t8 WALLAWALLA BORA 30s 30(30
7t8 BORA M345 1,564 1,56r 31
7t8 BPAT.NWMT BRDY 383 38:32
7t8 BPAT.NVVt\,lT LAGRANDE 95 OE 33
7t8 BPAT.NVI ,lT M345 '1,786 1,78Q 34
0 6,832,886 6,832,88t
FERC FORM NO.1 (EO. 12.90)Page 329.4
ldaho Power Company (1)
(2)
Original
Resubmission
Date of Report(Mo. Da, Yr)
04/18/201.8
Year/Period of Report
End of 2O17lQ4
I KANI as ccount 45tt.1 )
1. Report all bansmission of elecblcity, i.e., wheeling, provided for other electric utilities, cooporatives, other public authorities,
qualiffing facilities, non-traditional utility suppliers and ultimato customers for the quarter.
2. Use a sepaft*e line of data for each distinct type of transrnission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received fiom and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of eaci company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any orunership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the servico as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Tmnsmission Service for Self, LFP - "LongrTerm Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission SeMce, SFP - Short-Term Farm Point to Point Transmission
ReservaUon, NF - non-firm transmission service, OS - Other Transrnission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or'trrrs-ups" for seMoe provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General lnstruction for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Gompany of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Anhodty)
(Foohote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Shell Energy North America (US), L.P PacifiCorp East PadfiCorp East NF
2 Shell Energy North America (US), L.P PacifiCorp East Northwestem/Pacifi Corp East NF
3 Shell Energy North America (US), L.P.PacifiCorp East Bonneville Power Administration NF
4 Shell Energy North America (US), L.P PacifiCorp East Siena Pacific Power NF
5 Shell Energy Norfi America (US), L.P PaciflCorp East Siena Pacific Power SFP
6 Shell Enegy North America (US), L.P ldaho Porver Company Bonneville Power Adminisbation NF
7 Shell Energy North America (US), L.P ldaho Porer Company Northwestem/Pacifi Corp East NF
8 Shell Energy Nor$ America (US), L.P.ldaho Power Company Bonneville Power Administation NF
I Shell Energy Nortr America (US), L.P PacifiCorp East Northwestem/Pacifi Corp East NF
10 Shell Energy Nor0r America (US), L.P PacifiCorp East PaciliCorp East NF
11 Shell Energy North America (US), L.P PacifiCorp East NorthWestern/Pacifi Corp East NF
12 Shell Energy North America (US), L.P.PacifCorp East Bonneville Power Administration NF
13 Shell Energy North America (US), L.P PacifiCorp East Sierra Pacific Power NF
14 Shell Energy Norfi America (US), L.P PacifiCorp East PacifiCorp East NF
't5 Shell Energy Norh America (US), L.P PacifiCorp East PacifiCorp East NF
16 Shell Energy North America (US), L.P.PacifiCorp East Siena Pacific Power NF
17 Shell Energy North America (US), L.P Bonneville Power Adminisbation PacifiCorp East NF
18 Shell Energy North Am€rica (US), L.P Bonneville Power Administration PacifiCorp East NF
19 Shell Energy North America {US), L.P.Bonneville Power Administration Siera Pacific Power NF
20 Shell Energy Norh America (US), L.P Avista PacifiCorp East NF
21 Shell Energy North America (US), L.P Avista PacifiCorp East NF
22 Shell Energy North America (US), L.P Avista Sierra Pacific Power NF
23 Shell Energy llorth America (US), L.P Avista Sierra Pacific Power SFP
24 Shell Energy North America (US), L.P.Siena Pacific Power Bonnet/lle Power Administration NF
25 Shell Energy Nortlr America (US), L.P ldaho Power Company PacifiCorp East NF
26 Shell Energy North America (US), L.P ldaho Power Company Bonneville Power Administration NF
27 Shell Energy North America (US), L.P ldaho Power Company Siena Pacific Power NF
28 Shell Energy Norfi America (US), L.P.PacifiCorp West PacifiCorp East NF
29 Shell Energy Norfi America (US), L.P PacifiCorp West PacffiCorp East NF
30 Shell Energy North America (US), L.P.PacifiCorp West Sierra Pacifc Power NF
31 Shell Energy North America (US), L.P.PacifiCorp W€6t Sierra Pacific Power SFP
32 Shell Energy North America (US), L.P.ldaho Power Company PacifiCorp East NF
33 Shell Energy North America (US), L.P ldaho Power Company PadfiCorp East SFP
34 Shell Energy North America (US), L.P ldaho Power Company PacifiCorp East NF
TOTAL
FERC FORM ilO. r {ED. 12-90)Pagc 328.5
Name of Respondont
ldaho Power Company (1)
(2)
Original
Resubmission
Dat€ of Reoort
(Mo. Da, \t)
04t1u2018
Year/Period of Report
End of 2O17lQ4
to as
t 45OXUOn(nUeO'
5. ln column (e), identi$ the FERC Rate Schedule or Tariff Numb6r, On separate lines, list all FERC rate schedules or contracl
designations under whach seruice, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was roc€ived as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identification for where eneryy was delivered as specified in the
conlract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in colurnn (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tadff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Oelivery
(Substation or Olher
Designation)
(s)
Elilling
Domend
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Recelved(i)
M€awatt Hours
Delivered
0)
7t8 BRDY BORA 848 84€1
7t8 BRDY BPAT.NWMT 338 338 2
7t8 BRDY LAGRANDE 49S 49(3
7t8 BRDY M345 6,271 6,271 4
7t8 BRDY M345 2,016 2,01(5
718 HCPR LAGRANDE 96 9(6
7t8 IPCOGEN BPAT.NWMT 104 1At 7
7t8 IPCOGEN LAGRANDE 300 30(8
7t8 JBSN AVAT.NWMT 't40 14(I
718 JBSN BORA 't04 101 10
718 JBSN BPAT.NWMT 30 3(11
7t8 JBSN LAGRANDE 2,422 2,422 12
7t8 JBSN M345 618 61t 13
7t8 JEFF BORA 128 't2Q 14
7t8 JEFF BRDY 330 33(15
7t8 JEFF M345 135 135 16
718 LAGRANOE SORA 4,36'l 4,361 17
7t8 LAGRANDE BRDY 't6.254 16,254 18
7t8 LAGRANDE M345 78.079 78,07S '19
718 LOLO BORA 241 241 20
7t8 LOLO BRDY 76 7G 21
7t8 LOLO M345 1 55,586 't55,586 22
718 LOLO M345 53,90€53,90G 23
7t8 M345 LAGRANDE 614 614 24
7t8 OBBLPR BORA 12 'ti 25
7t8 OBBLPR LAGRANOE 100 10(26
718 OBBLPR M345 116 11(27
7t8 SMLK BORA 1,248 1,24t 28
7t8 SMLK BRDY 6,654 6,65t 29
7t8 SMLK M345 6,799 6,7SI 30
718 SMLK M345 2,396 2,39t 31
718 WALLAWALLA BORA 120,005 120,00!32
7t8 WALLAWALI-A BORA 7.948 7,94t 33
7t8 WALLAWALLA BRDY 6,887 6,887 34
0 6,E32,E86 6,832,886
FERC FOR| NO. r (ED.12-90)Page 329.5
ldaho Power Company
Date of Report(Mo. Da. Yr)
o4t1u2018
YearlPeriod of Report
End of 20171Q4
I F(ANI as ccount 456.1 )
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualirying hcilities, non-traditional utillty suppliers and ultimate customers fur the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authorig that the energy was rec€i\red from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or buncate name or use acronyms. Explain in a footnote
any ownership interest in or affliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service ficr Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission SeMce and AD - Out-of-Period Adlustments. Use this code
for any accounting adjustments or'true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General lnstruction for deffnltions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Foohote Affiliation)
(b)
Eneqy Delivered To
(Company of Publlc Authority)
(Footnote Affiliation)
(c)
Statistical
Oassifi-
cation
(d)
,|Sholl Energy North America (US), L.P ldaho Power Company Sierra Pacific Power NF
2 Shell Energy North America (US), L.P ldaho Power Company Siena Pacific Power SFP
3 Tenaska Power Services Co.PaclffCorp East Siona Pacific Power SFP
4 The Energy Authority, lnc.PacifiCorp East Bonneville Power Administration NF
5 The Energy Authority, lnc.Bonneville Power Administration PacifiCorp East NF
D The Energy Authoilty, lnc.Bonneville Power Adminiskation Sierra Pacific Power NF
7 The Energy Authority, lnc.Sierra Pacific Power Bonneville Power Administration NF
8 The Energy Authority, lnc.PacifiCorp West PacifiCorp East NF
I The Energy Authority, lnc.PacifiCorp West PacifiCorp East NF
10 Transalta Eneqy Marketing (U.S.) lnc.PaciffCorp East Bonneville Power Administration NF
11 Transalta Energy Marketing (U.S.) lnc.NorhWestem/Pacifi Corp East Siena Pacific Power NF
12 Transalta Energy Marketing (U.S.) lnc.Bonneville Power Administration PacillCorp East NF
13 Transaltra Energy Marketing (U.S.) lnc.Bonneville Power Administration Sierra Pacific Power NF
14 Transalta Energy Marketing (U.S.) lnc.Avistia PacifiCorp East NF
15 Transalta Energy Marketing (U.S.) lnc.Sierra Pacific Power Bonneville Power Adminisbalion NF
16 Transalta Energy Marketing (U.S.) lnc.PacifiCorp West PacifiCorp East NF
17 Utah Associated Municipal Power Systems PacillCorp East Siena Pacific Power NF
18 Utah Associated Municipal Power Systems PacifiCorp East Sierra Pacific Power SFP
19
2A
21
22
23
24
25
26
27
28
29
30
31
32
33
34
TOTAL
FERC FORtrl NO. 1 (EO. 12-90)Page 328.6
I hrs Kaoon ls:(1) [flRn Orisinat(a [eaesubmlsslon
Name of Respondont
ldaho Power Company (1)
(21
An Giginal
A Resubmission
Date of Report
(Mo, Da, Yr)
04t18t2018
YearlPefiod of Report
End of 2O17lQ4
to as
Ir 4co)(uononueo)
I
5. ln column (e), identif, the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which sorvice, as identified in column (d), is provided.
6. Report receipt and d€livery locations for all single contract path, 'point to point' fansmlssion service. ln column (f), report the
designation for the substation, or other appropriate identification for where onergy was received as specified in the contract. ln column
(g) report the designation for the substation, or othsr appropriate identification for where energy was delivered as specified in th6
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
repoiled in column (h) must be in megawatts. Footnot€ any demand not stated on a megawatts basis and explain.
8. Report in column (i) and [) the total megawatthours received and delivered.
FERC Rate
Scfiedule of
Tariff Number
(e)
Point of Reoeipt
(Subsataton or Olher
Designation)
(0
Point of Delivery
(Substefon or Other
Oesignation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawatt t{ours
Received(i)
Megawatt Hours
Delivered
0)
7t8 WALLAWALLA M345 16,214 16,21t 1
7t8 WALLAWALLA M345 410 41(2
718 BRDY M345 45,457 45,451 3
718 BRDY LAGRANOE 153 15:4
7t8 LAGRANDE BRDY 1,117 1,111 5
7t8 LAGRANDE M345 1,707 1,701 6
7t8 M345 LAGRANDE 124 12(7
7t8 SMLK BORA 3,432 3,432 8
718 SMLK BRDY 440 44(9
7t8 BORA LAGRANDE 412 412 10
7t8 BPAT.NWMT M345 1j4A 1,14C 11
7t8 LAGRANDE BORA 17,292 17,292 't2
7t8 LAGRANDE M345 5,530 5,53C 13
718 LOLO BORA 1,474 1,47Q 14
718 M345 LAGRANDE 105 105 15
7t8 SMLK BORA 23,816 23,U4 16
7t8 BORA M34s 234 234 17
7t8 BORA M345 2,212 2,212 18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
0 6,E32,EE8 0,832,88G
FERC FORM NO. r GD. r2-9O)Page 329.6
Name of Respondent
ldaho Power Company (1)
(2)
Original
Resubmission
Date of ReDort(Mo, Da, Yi)
04t18t2018
Year/Period of Report
End of 2O17lQ4
I 9F tsLEU I KIUI I Y FQ,udino transactions rofit{otttEKs(Aolr€d b as \flhee
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revonues ftom demand
chargos related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of onergy transfened. ln column (m), provide the total revsnues from all other charges on bills or vouchers r€ndered, including
out of period adiustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1101 1) in column
(n). Provide a foohote explaining Ure nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The totral amounts in columns (i) and (i) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(l)
(Oher Chargos)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
1,888,449 215,642 2,104,091 1
1,553,654 139,011 1,692,665 2
6,883,736 886,694 7.770,430 3
15,132 15,132 4
197,499 197,499 5
12,208 926 13,'t34 6
54,759 s4,759 7
6 6 8
s30 s30 I
894 894 10
5,622 5,622 11
2,654 2,654 12
6,162 6,1 62 13
82 82 14
15
4,040,454 4,0/,0,454 16
3,455,285 3,455,28s 17
6,715,513 6,715,513 18
2,8'14,385 2,814,385 't9
2,7ffi,520 2,786,520 2A
2,786,520 2,786,52A 21
22
2,318 2,318 23
4.932 4,932 24
38 38 25
185 185 26
377 377 27
42,747 42,747 28
33,480 33,480 29
5,314 5,314 30
2,O76 2,076 31
39,611 39,611 32
51 5'l 33
3,302 3,302 34
10,338,047 31,733,.f06 0 12,471,453
FERC FORM r{O. r (ED. 12.00)Page 330
Name of Respondenl
ldaho Power Company
This
(1)
t2)
ls:
An Original
A Resubmission
Dete of Reoort(Mo, Da, Yi)YearlPeriod of Report
End of 2017lQ404t18t2018
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide rovenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues ftom energy charges related to the
amount of snergy transfened. ln column (m), provide the total revenues fiom all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report ln column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary setUement was made, enter zero (1101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transrnission Delivered for annual rcport
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Otter Charges)
(s)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
1,638 1,638 1
25858
6,574 6,574 3
43 43 4
54 54 5
1,249 61,249
916 916 7
4 4 8
960 960 9
35 1035
't.7u 1,794 1'.!
22,281 22,281 12
7 7 13
181 1418'l
5 5 15
846 846 16
557 557 17
254 18254
19191191
68 68 20
105,103 105.103 21
22810810
40,943 40,943 23
1,706 I,706 24
8,402 8,402 25
11,460 26I 1,460
29'.1 2729',!
917 917 28
5.667 5,667 29
2,018 302,018
14,596 3114,596
148.,944 't48,944 32
,OE 295 33
23 23 34
31,733,/O0 0 12,071,15310,338,047
FERC FORIll ilO. ' (ED.12.90)Page 330.1
Name of Respondent
ldaho Porer Company (1)
(2)
An Original
A Resubmission
Dato of ReDort(Mo, Da, Yi)
0411wo18
Year/Period of Report
End of 20171Q4
as
9. ln column (k) through (n), report the r€venue amounts as shown on bills or voucheni. ln column (k), provide revenues ftom demand
charges related to the billing demand repo(ed in column (h). ln column (l), provide revenues from energy charges relatsd to the
amount of energy transfened. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of eneryy or seMce
rendered.
10. The total amounts in columns (i) and fi) must be reported as Transmission Received and Transmission Delivered for annual report
purposss only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provida explanations following all reguired data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
0)
(Oher Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
s36 536 1
3,340 3,340 2
8,377 8,377 3
1,140 1,140 4
61,287 61,287 5
10,498 't0,498 6
28,019 28,019 7
298,219 298,219 I
5,S12 5,912 I
12,472 12,472 10
16,754 16,754 11
56.693 56,693 12
96,806 96,806 13
44,067 44,067 14
2,371 2,371 15
47',|471 16
4,374 4,374 17
5 5 't8
796 796 19
254 254 20
1 32,564 132,564 21
365 365 22
1,916 1,916 23
5,612 5,612 24
192,434 192,434 25
95,640 95,640 26
23,614 23,614 27
115 115 28
't36,973 136,973 N
2't1,025 211,O25 30
32,377 32,377 31
8,354 8,354 32
3,966 3,966 33
396,312 396,312 34
10,338,047 31,733,406 0 42,071,45t
FERG FORilr NO. I (ED. 12-00)Page 3i10.2
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission 04118t2018
K (J rFrE,t(s (Ao
tred to as \i,fia€
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revonues from demand
charges related to the billing demand reported in column (h). ln column (l), provide rsv6nu6s from energy chargos relded to the
amount of energy transfened. ln column (m), provide the total rsv€nues fom all oth€r charges on bills or vouchers rendered, includiqg
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the enti$ Listed in column (a). lf no monetary s€ttlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and O must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
o
(Ofier Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
269,921 268,921 1
873 873 2
57,134 57JU 3
76,148 76,18 4
7,611 7,611 5
19,351 't9,351 6
14,743 10,743 7
72 72 I
1,242 1,242 9
834,129 834,129 10
2,451 2,451 1',!
2,403 2,443 12
3,112 3,112 13
1,083 1,083 14
135,334 135,334 15
1,653 1,653 16
33,201 33,201 17
I 1,985 1 1,985 18
231 231 19
284 2U 20
419 419 21
782 782 22
108 108 23
1,129 1,129 24
346 346 25
3,'t28 3,128 26
3,682 3,682 27
5,482 5,482 28
1,570 1.570 29
5,212 5,212 30
60,€83 60,833 31
23,828 23,828 32
3,844 3,864 33
3,487 3,487 34
10,33E,047 3't,733,406 0 42,0?1,453
YearlPeriod of Report
End of 20171Q4
FERC FORM NO. r (ED.
'2-00)
Page 330.3
ldaho Power Company Original Date of Reoorl(Mo, Oa, Yi)Year/Period of Report
End of 2O17lQ4Resubmission0411812018
(1)
to as
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the bilting demand reported in column (h). ln column (l), provide revanues from energy chaqes related to the
amount of energy transfuned. ln column (m), provide the total revenues ftom all other charges on bills or vouchers rendered, including
out of period adlusEnents. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the ertity Listed in column (a). lf no monetary settlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining the nature of th6 non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and fi) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 40'l , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
(s)
(k)
Energy Chargos
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
277 1
1,671 1,671 2
475,137 475,\37 3
2.153 2,153 4
30,356 5
4,105 4,'t05 6
76 76 7
44 44 8
126 I
790 790 10
3,943 3,943 11
632 12632
95 13
76 76 14
720 720 15
278 278 16
3,709 't7
2,597 2,597 18
196 196 19
1,472 't,472 20
43,446 21
23,445 23,445 22
5,081 5,081 23
4,461 4,461 24
3,040 3,040 25
1,264 1,2U 26
s6,982 56,982 27
1'.!,'t28 2811,128
6,439 29
1,953 1,953 30
7,915 7,S15 31
't,938 1,S38 32
481 48'l 33
9,038 9,038 34
10,330,047 0 42,071,153
FERC FORrrr NO. I (ED. 12-90)Page 330.4
2771
30,3561
1261
e5l
3,7091
43,4461
6,43s1
3r,733,403 |
ldaho Power Company
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0E,I18t2018
Year/Period of Report
End of 20171Q4
as
9. ln column (k) through (n), report the r€venue amounts as shown on bills or vouchers. ln column (k), provide revenuss fom demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues tom energy charges related to the
amount of eneryy transbrred. !n column (m), provide the total revenues from all other charges on bilts or vouchers renderod, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary ssttlement was made, cnter zero (1 1011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rcndered.
10. The total amounts in columns (i) and fi) must be reportod as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Oher Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
4,291 4,291 1
1,710 1,7'.t0 2
2,525 2,525 3
31,735 31,735 4
't0,202 10,202 5
486 486 6
526 526 7
1 ,518 't,518 I
708 708 I
526 526 10
152 't52 11
12,257 12,257 't2
3,127 3,127 13
M8 648 14
1.670 't,670 15
683 683 16
22,069 22.069 17
82,256 82,256 18
sgs,1 30 395,'t30 19
1,220 1,220 20
385 38s 2'l
787,366 787,366 22
272,799 272,7*23
3,107 3,107 24
61 61 25
506 506 26
587 587 27
6,316 6,316 28
33,674 33,674 29
34,407 34,47 30
12,135 't2,135 31
607,303 607,303 32
44,222 40,222 33
34,853 34,853 34
10,33E,047 31,733,{6 0 12,071,453
FERC FORm ilO.1 (ED.12-90)Page 330.5
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Dat€ of Reoort(Mo, Da, Yi)
o4t1812018
Year/Period of Report
End of 20171Q4
as
9. ln column (k) through (n), report the rc,v6nue amounts eB shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billlng demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transfened. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). lf no monetary seftlement was made, enter zero (1 101 1) in column
(n). Provide a footnote explaining he nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and fi) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
82,053 82,053 1
2,075 2,475 2
159,503 159,503 3
722 722 4
5,269 5,269 5
8.052 8,052 6
594 594 7
16,189 16,189 I
2,076 2,076 I
1,80s 1,805 10
4,993 4,993 11
75,739 75,739 12
24,221 24,221 13
6,465 6,465 14
'160 460 15
104,314 104,3'.t4 16
't,296 1,2S6 17
12,256 12,256 18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
10,338,047 31,733,406 0 42,07't,153
Page 330.6FERC FORil NO. r (EO.12-90)
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) - A Resubmission
Date of Report
(Mo, Da, Yr)
04t1u2018
Year/Period of Report
20't7lQ4
FOOTNOTE DATA
Schedule Page:328 Line No.:1 Column: a
The network service agreement between Idaho Power and the Bonneville Power Administrationfor the Oregon Trail Electric Cooperative expires September 30, 2A28.
Schedule Page:328 Line No.: I Column: h
The billing demand for network service is the customer's demand at the time of ldaho Power
Company transmission system peak and varies by monlh.
Schedule Page: 328 Line No.: 2 Column: a
The network service agreement between Idaho Power and the Bonnevj-lLe Power Administrationfor ,!,he USBR expires December 31, 2023.
Schedule Page: 328 Line No.: 2 Column: e9, Open Access Transmission Tariff, Schedule 9 Network Integration Transmlssion Servi-ce
ff3{i'ir?ffit;ll1outLiJl;:,"::':yI!"e ii the cui-tomer,s demand ar the rj.me or rdaho Fower
Com,pany transmission system peak and varies by month.
Schedule Page: 328 Line No.: 3 Column: a
The network service agreement between ldaho Power and the Bonnevili.e Power Administrationfor the Pri-ority Firm Customers expr,res September 30, 2028.
Schedule Page:328 Line No.:3 Column: h
The billing demand for network service is the customer's demand at the tlme of ldaho Power
Company transmission system peak and vari,es by month.
Schedula Page: 328 Llne No.: I Column: a
The contract between ldaho Power and t-he Mj-l-ner Irrigation District expired December 31,
2011 -
Schedule Page:328 Line No.:4 Column: e
Legacy, contracE prior to the Open Access Transmission Tariff
Schdule Page: 328 Line No.: 5 Column: a
The agreement between Idaho Power and the City of Seattle expired December 3L, 20L7. Cityof Seattfe has re-sold this transmi-ssion service request to Morgan Stanley and MorganStanley is now responsible for payment.
Schedule Page: 328 Line No.: 5 Column: e4, Open Access Transmission Tariff, Schedule 4 Energy fmbalance Service
Schdule Page: 328 Llne No.: 6 Column: a
The contract bet*een ldaho ?ower and PacifiCorp - Imnaha expires on Yarch 31, 202---
Schedute Page:328 Line No.:6 Column: h
The billing demand for network service is the customer's demand ac the time of fdaho Power
Company transmission sy-,stem peak and varies by month.
Schedule Page: 328 Line No.:7 Column: a
The agreement between Idaho Power aed the United States Department of the Interior, Bureauof Indian Affairs is subject to termj-nati-on upon 90 days written notice by the Bureau"
Sctredule Page:328 Line No.:8 Column: a
The agreement be:ween Idaho Power a:rd CycIe Hcrseshoe Bend Wind, LLC has no expiraLiondate and can be terminated by either party at any time.
Schedule Page:328 Line No.:8 Column: e5/6, Open Access Transmission Tariff, Schedule 5,/6 Operating Reserves
tchedule Page:328 Llne No.:11 Colum-n: e11, Open Access Transmission ?ariff, Schedule l1 Unreserved Use Penal-ty
Schdule Page: 328 Line No.: 16 Column: e7/8. Open Access Transmission Tari-ff, Schedule 7/B Firm/Non-Firm Point-to-Point
Transmission Service
FERC FORM NO.1 (ED. 12-871 Page 450.1
ldaho Power Company Resubmission 04t18t2018
Y€Br/Period of Report
End of 2O17lQ4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(lncluding transactions refened to as "wheeling")
1. Report all transmission, i.e. wheeling or €lectricity provided by other electric utilities, cq)peratives, municipalities, oher public
authorities, qualirying facilities, and othec for the quarter.
2. ln column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any oirnership interest in or affillation with the
transmission service provider. Use additional columns as necessiary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. ln column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the seMce as follows:
FNS - Firm Network Transmission Service for Selt LFP - Long-Term Firm Point{o-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General lnstructions for definitions of $ati$ical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivercd by the provider of the transmission seMce.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. ln column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transfened. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Repoil in column (h) the total charge shown on bills rendered to the respondent. lf no
monetary seftlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-mon€tary settlement,
including the anrount and type of energy or seMce rendered.
6. Enter'TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line
No.Name of Company or Public
Authority (Footnote Affi liations)(a)
Statistical
Classification(b)
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BYOTHERS
rvftlgawatt-nourSReceived(c)
MqgawatI-nouni
Delivered
(d)
u9rnafloc$yes
(e)
En6r(Wcttgy-ris
(0
cn6yes
b)
Total Cost of
Tranffission
1 Avangrid Renewables o8 -.l00,671 -100,671
2 Avish CorlWWP Div NF 4,551 4,551 29,421 25,421
3 Avista Cqp-WWP Div SFP 61,983 61,983 199,955 199,S55
4 Avista CoD-WWP Div SFP 1,800 1,800
5 Bonneville Power Admin ttP 426,711 426,711 2,810,869 2,810,869
o Bonneville PowerAdmin SFP 8,695 8,695 40,348 40,348
7 Bonneville Power Admin NF 882 882 4,767 4,767
I Bonneville Pourer Admin 12,932 12,932
I Bonneville PowerAdmin 569,186 s69,186
10 Bmneville PowerAdmin 3,621 3,621
't1 Bonneville PorerAdmin 08 58,775 58,775
't2 Bonneville Power Admin 08 26,280 26,280
13 Bonneville PoflerAdmin OB 6,282 6,282
14 Bonneville PorerAdmin 0e 700 700
15 Bonneville PowerAdmin os 3,560 3,560
16 Bonneville PowerAdmin OG 3n 320
TOTAL 630,14:630,143 4,371,439 196,960 4,568,399
FERC FORM NO. 1/3-O (REV. 02.04)Page 332
This Reoo(1) E^(21 r-ln
08
08
0s
ldaho Power Company (1)
(2)
An Original
A Resubmission
Da,
04t1812018
Year/Period of Report
End of 2O17lQ4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(l ncluding transactions referred to as'kheeling')
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, coopeftilives, munacipaliti€s, other public
authorities, qua[rying facilities, and oth€rs for the quarter.
2. ln column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or afiiliation with the
transmission servioe provid€r. Use additional columns as neosssary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. ln column (b) enter a Statistical Classification code based on he original contactual terms and conditions of the service as follows:
FNS - Flrm Network Transmission Service for Selt LFP - Long-Term Firm Point-to-Point Transmissioo Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- PointTransrnission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See Goneral lnstructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (0 and (g) expenses as shown on bills or vouchers rendered to the respondent. ln column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transfened. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondenl, including any out of period adjuslments. Explain in a footnote all
components of the amount shown in column (g). Repod in column (h) the total charge shown on bills rendered to the respondent- lf no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-rnonetary setflement,
including the amount and type of energy or servic€ rendered.
6. Enter'TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations follodng all required data.
Line
No.Name of Company or Public
Authority (Footnote Affi liations)(a)
Statislical
Classification(b)
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERT
Magawan-hoursReceived(c)
MqgawaE-
nourslDelivered
(d)
ch6yes
(e)
Enerovctr6y:*'
(0
ctr,a6yes
(o)
Total cost of
rransf$ission
I Bonneville Polrrer Admin 08 601 601 2,400 2,400
I Exelon Generatbn Co 06 -32,522 -32,522
3 NV Eneryy SFP '1,0'11 1,01,|12,990 12,990
4 NV Energy NF 3,709 3,709 m,235 20,235
5 NV Eneryy 06 4,581 4,s81
6 NorhWestem Enegy SFP 2,334 2,334 16,832 16,832
7 NoffWesbm Eneqy NF 61 6'l 264 2U
8 NorthWestem Eneqy os 824 824
I NorhWestsm Eneqy AI)42 -32
10 PacifCog lnc.LFP 14,622 14,622 1,045,452 1,045,452
1'l PacifiCory lnc.SFP 5,435 5,435 47,713 47,713
12 PacfiCop lnc.NF 10 10 746 746
13 PacifiCorp lnc.0s 46,174 46,174
14 Pacili0orp lnc,AD -285 -28s
15 PaciliCorp lnc.AD 87,366 87,366
16 PaciliCorp lnc.AD 2,112 2,112
TOTAL 630,143 630,143 4,371,439 196,960 4,568,399
FERC FORM NO. r/3-Q (REV.02-04)Page 332.1
ls:
ldaho Porer Company (1)
(2)
An Original
A Reeubmission
Date of Report
(Mo, Da, Yr)
04t1u2018
YearlPeriod of Report
End of 2O17lQ4
TRANSMISSION OF ELECTRIGITY BY OTHERS (Account 565)
( l nctuding bansactions refened to as'wheeling')
1. Report all transmission, i.e. wheoling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifuing facilities, and others for the quarter.
2. ln column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. ln column (b) enter a Statistical Classification code based on the original contractual terms and c-onditions of the service as follows:
FNS - Firm Network Transmission Servics fur Self, LFP - Long-Term Firm Point{o-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Pointto- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General lnstructions for definitions of statistical classifications.
4. Report in column (c) and (d) the tota! megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (Q anrl (g) expenses as sho^rn on bills or vouchers rendered to the respondent. ln column (e) report the
demand charges and in column (0 energy charyes related to the amount of energy transfened. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. lf no
monetary settlement was mad€, enter zero in column (h). Provide a foohote explaining the nature of the non-monetary settlement,
including the amount and type of energy or servioe rendered.
6. Enter'TOTAL" in column (a) asthe last line.
7. Footnote entries and provide explanations following all required datra.
Line
No.Name of Company or Public
tulhority (Footnote Affi liations)
Statislical
Classification(b)
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Magawan-houniRecer'ved
(c)
MaoaYYaII-lfrurc
Delivered
(d)
Ensrov
Charo-6s(sr
(0
.W""
(o)
Total Cost of
rranslgission
1 Powerex Cory.os -313,9s0 -313,950
2 Puget Sound Eneqy, lnc srP 34,325 y,325
3 SeaUe Clty Light SFP 075 875
4 Shell Eneqy N. Amerix SFP 7,36E 7,368
5 Shell Energy N. Amerie 08 ,1,057 -1,057
6 Snohombh County PUD 8FP 91,631 91,631
7 Tacoma Power SFP 5,400 s,400
I The Eneqy Aufiority SFP 448 448
I TransAlla Energy U.S.08 {0,095 {0,095
10
11
12
13
't4
15
't6
TOIAL 630,143 630,143 4,371,139 196,960 4,568,399
FERC FORM NO. 1/&Q (REV.02-04)Pago 332.2
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) - A Resubmission
Date of Report
(Mo, Da, Yr)
04t18,t2018
Year/Period of Report
20't7tQ4
FOOTNOTE DATA
Schedule Page: 332 Line No.: 1 Column: b
Resale Transmission
Schedute Page: 332 Line No.: 4 Column: b
BPAT is provider for capacity reassignment settled r,vlth Avis-;a.
Scledule Page:332 Line No.:5 Column: bContract Expiration Date 1213a/202I
Schedule Page:332 Line No.:8 Cotumn: b
Sp j-nning /s.upplementaf reserves
Schedule Page:332 Line No.:9 Column: bAncillary Services
Schedule Pagg:332 Line No.: 1_0 Column: b
BPAT is provider for capacity reassignment sett__l,ed with Shell.
Schedule Page:332 Line No.: 11 Cotumn: b
BPAT is provi-der for capacity reassignment set:led wlth Snohomish County PUD.
Sclredule Page:332 Ltne No.:12 Column: b
BPAT is provicler for capacity reasgignment setLtecl with Puget Sound Energy.
Schedule Page:332 Llne No.: 13 Column: b
BPAT is provider for capacity reassignment settled wj-th Avis-.a.
Schedule Page: 332 Line No.: 11 Cotumn: b
BPAT is provider for capacity reassignment setEfed with Seac:Ie Clty Light.
Schedule Page: 332 Line No.: 15 Column: b
BPAT is provider for capacity reassignmenc settled wirh Tacoma Power.
Schedute Page: 332 Line No.: 16 Column: b
BPAT is prcvider for capacity reassignment settied wi-th The Energy Authority.
Schedule Page: 332,1 Line No.: 1 Column: bTrar:smission Resale
Schdute Page: 332.1 Line No.: 2 Column: b
Resale Transmission
Schedule Page: 332.1 Line No.: 5 Column: bAncillary Services
Schedule Page: 332.1 Line No.: 8 Column: bAncillary Services
Schedule Page: 332.1 Line No.: 9 Column: b
Refunded PTP from July 2014
Schedute Page: 332.1 Line No.: 10 Column: b
Cor.tract ExpiraLion ldl-e 05,/31 /2079
Schedule Page:332.1 Line No.:13 Column: bAncilJ-ary Services
Schedule Page: 332.1 Line No.: 14 Column: b
PTP 201 5 True-Up
Schedule Page:332.1 Line No.:15 Column: b
2016 PTP lrue-Up
Schedule Page:332-1 Line No.: 16 Column: b
December 2aL5 correction
Schedute Page: 332.2 Line No.: I Column: bAncillary Servicgs
Scftadule Page: 332.2 Line No.: 2 Column: b
BPAT is provider for capacrty, reassignment settled with Puget Sound Ener:gy
Schedule Page:332.2 Line No.:3 Column: b
BPAT rs provider for capacity reassignment settled with Seattle City Liqht
Schedule Page: 332.2 Line No.: I Column: b
BPAT is provider for capacity reassignment settl-ed with Shel-i Energy
Schedule Page:332.2 Llne No.:5 Column: bAnciilary Services
FERC FORM NO.1 1 450.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) - A Resubmission
Date of Report
(Mo, Da, Yr)
04t1u2018
Year/Period of Report
20171Q4
FOOTNOTE DATA
Schedule Page: 332.2 Llne No.: 6 Column: b settled with Snohomish County PUD
settled with Tacoma Power
FERC FORm NO. 1 (ED. 12-871 Page 450.2
BPAT
BPAT
Name ot Respondent
ldaho Power Company
his Be9ort ls:(1)lxl An Original
(2) E A Resubmission
Date of FleDort(tAo, Da, Yi)
o4t1u2a18
Year/Period of Report
End of 20171Q4
MISCELLAI{EOUS GENERAL EXPENSES (Account 930.2) {ELECTRIC)
Line
No.
Amount
(b)
1 lndustry f,5ss63licn Dues 515,878
2 Nuclear Power Researctr Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist lnfo to Stkhldrs...expn se,vicing outstanding Securities t,@5,574
5 Oth Expn >=5,0(X) show pu,po6e, recipient, amount, Group if < $5,000 I
b
7 Director Fees and Expenses:
8 Annette Elg 66,907
I Christine King 87,96'r
't0 Dennis Johnson 70,290
11 J Lamont Keen 64,350
12 Judih Johansen 78,358
13 Richard Dahl 91,575
14 Richard Navano 76,230
15 Robert Tintsman 't70,703
16 Ronald Jibson 72,359
17 Thomas Carlile 76,230
18 Director travel and lodging 34,158
19
20 Corporate Memberships and Subscriplions:
21 Arizona Strate Unlversaty 41,666
22 Associated Taxpayers of ldaho 26,000
23 Assocation of ldaho Cities 5,000
24 Boise Valley Eco 20,000
25 Business Plus 5,000
26 Chartwell lnc.34,888
27 ldaho Association of Commerce & lndustry 't5,000
28 ldaho Mining Association 6,s00
29 National Association of Directors 8,075
30 National Hydropower Association 36,935
31 Pacific NW Utilites 42,747
32 S&P Global 29,261
33 Wester Energy lnstitute 30,962
34 Misc Memberships under $2,000 7,444
35
36 Chambers of Commerce & Other Civic Organizations 85,547
37
38
39
40
41
42
43
44
45
/t6 TOTAL 3,556,441
FERC FORir NO.1 (EO. t2-94)Page 335
Name of Respondent
ldaho Power Gompany
This Report is:
(1) X An Original
(21_ A Resubmission
Date of Report
(Mo, Da, Yr)
o4l'1812018
Year/Period of Report
20171Q4
FOOTNOTE OATA
Schedule Page:335Racipient
No.:1 Column: b
American Stock ?ransfer & Trust
Bloomberg Finance LPBroadridge Financj-a.l- Solutions
Deutsche BankE SourceMarket fntelligence Group
Moody's Analytics
NASDAQ Corp Solutions
New York Stock ExchangePayroll Related Expenses
PR NewswireRivel Research GroupStock Based CompensationWells Fargo Shareowner Services
Schedule Llne No.: 5 Column: b
Rccipient
Bank of New Yorkfnvestis, Inc.Payroll Related ExpenseMiscellaneous under S5, 000
Purpos€
Mgmt Services
Misc Expense
Misc Expense
Broker Fees
Mg-mt Services
Mgmt Services
Mgmt Services
Mgmt Services
Listi-ng ServicesMisc Expense
Misc Expense
Mgmt ServicesMisc Expense
Mgmt Services
)
$ L, 665,57 4
Amount$ L2,925
37 ,457
16,651
23, B]-0
ADount
60 | 40'7
22,591
50,438
30, 000
2'7 ,1 43
20,691
35.590
51, 157
58,929
L68,061
16, 57 5
15,840
98 9, 313
118 ,22'7
hrrpose
Revenue Bonds
lfebsite Design
Misc ExpenseMisc Expense
FERC FORM NO.1 450.1
$ 90,843
iD.12{7}
ls:
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report
(Mo. Da, Yr)
0{,t18t2018
Yeer/Period of Report
End of 2O17lQ4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PI-ANT (Account403, 404, 405)
(Except amortization of aquisition adjustments)
1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account ,103; (c) Depreclation Expense for Asset
Retirement Costs (Account 403.'l; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis us€d to
compute charges and whether any changes have been made in the basis or rates used fiom the preceding report year.
3. Report all available information called for in Section C every fifih year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. ldentiff at the bottom of Section C the type of plant
included in any sub-account used.
ln column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. lndicate at the bottom of section C the manner in which column balanc€s are obtained. lf average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classifica$on Listed in column
(a). lf plant mortality studies are prepared to assist in estimating average service Lives, shory in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining lift of surviving plant. lf
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. lf provisions for depreciation were made during the ysar in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and naturs of the provisions and the plant items to which related.
A. Summary of Deprociation and Amortization Charges
Line
No.Functional Classifi cation
(a)
Dgoredalion
Expenso(Account 403)
(b)
Depreciation
Expense br Asset
Retirement Costs(Account 403.1 )(c)
Amortization of
Limited Term
Electric Plant(Account 404)(d)
Amortization ofOther ElectricPlant (Acc 405)(e)
Total
(0
1 lntangible Plant 6,243,722 6,243,722
2 Steam Production Plant 45,281,481 566,665 45,848,146
3 Nudear Production Plant
4 Hydraulic Production Plant-Conventional 15,551,612 15,551,612
5 Hydraulic Produc-tion Plant-Pumped Storage
6 Oher Production Plant 16.450,729 16,450,729
7 Transmission Plant 22,154,895 22,154,895
I Distribution Plant 40,727,549 40.727,549
s Regional Transmission and Ma*et Operation
10 General Plant 13,792,320 13.792.320
't'l
12
Common Plant-Electric
TOTAL 153,958,586 566,665 6,243,722 r60,768,973
B. Basis brAmortization Charges
Acct 404 Balance 11112017 2017 Amortization Balance '1213'll2o17 Remaining Months(1) 12,000 12,000(21 9,257,436 52A,449 8,736,987(3) 4,873,436 185,257 4,684,179 296(4) 9,768,866 5,183,488 12,134,210(5) 3,172,199 287,899 2,884,300 120(6) 18s,769 16.112 169,657 36(7) 1,128,967 28,517 1,797,458Total 28,398,673 6,243,722 30,406,791
('l) Shoshone-BannockTribeLicense&UseAgreement.(NewfiveyearadvancepaymentstartingJanuary20lS,witha
Decembr 31, 2022 termination date.)
(2) Middle Snake Relicensing Costs (Amortized over a 30 year license p€riod; licenses expire 07131134 and 02128135).
(3) Swan Falls Relicensing Costs (Amortized over a 30 year license period, license expires August 31,20421.
(4) Computer Software packages (Amortized over a 62 month period).
(5) ShoshonrBannock Right of Way (Tennination dale 12131127).
(6) Boardman Relroflt Tech Analysis (Scheduled decommisskrn date 121311201.
(7) FERC License Compliancr Costs (Termination date will be expiration date of the applicable FERC Licenses)
FERC FORi' ilO. r GEV.12-03)Page 336
Name of Respondent
ldaho Power Company
This
(1)
(2)
Reoort
EIen
ls:
Original
fiA Resubmission
Date of Reoort
(Mo. Da, Yi)
04118t2018
YearlPeriod of Report
End of 2O17lQ4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C, Factors Used in Estimating Oepreciation Charges
Line
No.Account No.
{a}
uepreGlaoro
Plant Base(ln Thousands)(b)
Avs us;;ice(c)
NAI
Salvaoe
(Perc€-nt)
{d)
Appr60
Depr. rates
(Percent)(e)
MOnarIIy
Curvet[r"
Avera9e
Remaining
(o)
'12 310.20 649 75.00 s.60 R4.0 17.90
13 311.00 154,64 100.00 -9.00 3-09 s0.5 17.90
14 312.10 193,745 70.00 -5.00 2.79 sI.0 18.10
15 312.20 559,584 53.00 -8.00 4.25 R1.5 17.00
16 312.30 4,U1 35.00 10.00 2.65 R3.0 13.50
17 314.00 169,860 45.00 -7.00 4.80 s0.5 16.50
18 315"00 73,750 60.00 -3.00 3.19 s1.5 16.80
19 316.00 't3,727 35.00 2.00 5.36 s0.0 14.60
20 316,10 32S 13.00 15.00 7.92 L2.0 5.40
2',1 316.40 25C 't3.00 15.00 0.92 L2.0
22 316.50 1,36€13.00 15,00 4.12 L2.0 t1.80
23 316.60 387 3.24
24 316.70 144 21.00 't5.00 0.8't sl.0 12.20
25 316.80 3,936 20.00 25.00 4.54 01.0 17.80
26 316.90 14 35.00 15.0C 2.44 s1.0 30.60
27 317.00 14,890
?8 Subbbl Sbem 1,191,436
29 331.00 1S6,243 120.0c -25.00 2.08 R2.5 35.80
30 332.10 19,461 120.0c -20.00 0.98 s1.5 46.24
31 332.20 248,612 120.00 -20.00 1.80 s1.5 31.20
32 332.30 5.472 1.15 Square 55.1 0
33 333.00 260,30S 100.00 -10.00 't.92 R2.5 30.60
34 334.00 62,465 65.00 -r0.00 2.82 R1.5 27.80
35 33s.00 25,106 90.00 -5.00 2.18 R2.0 31.20
36 335.10 88 15.00 7.C2 Square 7.90
37 33s.20 398 20.(x)0.80 Square 9.20
38 335.30 40c 5.00 '14.42 Square 2.50
39 336.00 10,882 't00.00 2.58 R3.0 22.70
40 Subtotal Hydro 829,436
4',1 34'1.00 143,333 2.72 Square 32.80
42 342.00 1 0,538 50.00 2.81 s2.5 28.70
43 343.00 224,538 40.00 3.18 R2.0 26.00
44 344.00 66,532 50.00 2.45 s2.0 28.40
45 34s.00 91,478 55.00 2.91 R2.0 29.30
46 346.00 6,389 35.00 3.24 R2.5 24.40
47 Subtotal Other 542,808
48 350.20 32,501 100.0c 0.8s R4.0 85.20
49 350.22 193 30.00 3.33
50 352.00 80,2U 65.00 -33.00 1.88 R3.0 53.20
FERC FORm NO. I (REV.12-03)Page 337
Name of Respondent
ldaho Power Company
This
(1)
(2)
Reoort ls:
E:Itu orisinal
1'1A Resubmission
Oats of Reporl(Mo, Da, Yr)
0411u2018
Year/Period of Report
End of 20171Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Deprecialion Chargos
Line
No.Account No.
(a)
ueprectaole
Plant Base(ln Thousands)
nvo.ftgvtce
(c)
NEI
Salvaoe(Percfr0
(d)
Apprleo
Dspr. ral€s
(Percent)(e)
Morrarlty
Curve
'ffiu
Average
RefiEining
(o)
12 353.00 428,949 52.00 -10.00 '1.97 s0.5 42.00
13 354.00 206,553 80.00 -10.00 1.07 R4.0 71.10
14 355.00 182,124 65.00 -80.0c 2.64 Rl.5 53.90
15 3ss.10 1,212 10.00 10.00
16 356.00 226,621 74.O0 -50.m 1.87 R1.5 62.30
17 359.00 390 65.00 0.91 R2.5 33.30
18 Subtotal Transmission 1,158,813
19 360.22 853 30.00 3.33
20 361.00 37,463 70.00 -50.00 2.',t7 R3.0 54.40
21 362.00 237,332 55.0C -6.00 1.85 R1.5 42.90
22 364.00 261,432 s8.0c -s0.00 2.17 R1.5 44.14
23 364.10 3,950 12.04 8.34
24 365.00 136,070 49.00 -30.0{2.65 Rl.0 34.40
25 366.00 50,759 65.00 -25.00 1.83 R2.5 49.10
26 367.00 258,500 50.00 -1't.00 1.90 R1.5 39.40
27 368.00 560,034 42.44 -7.00 2.17 R0.5 34.80
28 369.00 60,78€55.00 -40.00 1.58 R1.5 43.40
29 370"00 16,413 30.00 -5.00 2.05 01.0 25.70
30 370.10 73,608 18.00 -5.00 5.39 R1.5 14.00
31 371.20 3,057 2',t.oo -5.00 2.88 R1.0 14.70
32 373.20 4,527 40.00 -30.00 1.73 R1.0 29.00
33 374.00 143
34 Subtotal Distribution 1,744,927
35 390.1 1 30,902 90.00 -3.00 2.O8 s1.0 33.20
36 390.12 89,751 55.00 -3.00 2.11 R2.0 38.80
37 391.10 15,370 20.00 4.00 Square 12.30
38 391.20 24,169 5.00 20.00 Square 2.70
39 391.21 5,374 8.00 12.50 Square 3.50
40 392.10 804 13.00 15.00 7.O7 12.0 9.30
41 392.30 4,563 15.0C 40.0c 4.13 s2.5 9.70
42 392-40 24,592 13.00 15.00 6.20 t2.0 8.50
43 392.50 1,355 13.00 15.00 6.34 L2.0 8.90
44 392.60 42,974 21.OA 15.00 3.95 s1.0 14.00
45 392.70 8,515 21.04 15.00 4.16 s1.0 12.30
46 392.90 5,346 35.00 15.00 2.24 s1.0 24.30
47 393.00 2,948 25.00 4.00 Sguare 17.40
48 394.00 10,438 20.00 5.00 Square 12.40
4g 395.00 13,86!20.00 5.00 Square 10.60
50 396.00 16,265 20.00 25.00 2.97 01.0 16.70
FERC FORM NO. I (REV. 12-03)Pagc 337.1
Name of Respondent
ldaho Power Company
This Reoort ls:(1) E:]An Orisinal(2) nA Resubmission
Date of ReDort(Mo. Da, Yi)
0411u2018
Year/Period of Report
End of 20171Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Eslimating Depreciation Charges
Line
No.Account No.
(a)
uspnBqaDl€
Plant Base(ln Thousands)
Avg.Sgrvice
lc)
Net
Salvaoe(Perce-nt)(d)
Appneq
Depr. rates(Percsnt)
(e)
MOrIarrry
Curve
'ffi"
Av€rage
Remajning
(o)
12 397.1 0 2,947 15.00 6.67 Square 4.70
13 397.20 28,280 1s.00 6.67 Square 8.'10
14 397.30 3,530 15.00 6.67 Square 9.70
't5 397.40 19.379 15.00 6.02 Square 13.'t 0
'16 398.00 6,97S 15.00 6.67 Square 8.60
17 Subtotral General 3s8,350
18 Total Phnl 5,785,770
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
4'.!
42
43
44
45
46
47
48
49
50
FERC FORM NO.1 (REv. 12-03)Page 337.2
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
0411E|201E
Year/Period of Report
20171Q4
FOOTNOTE DATA
Schedute Page:336 Line No.: 28 Column: a
(Column: e) An average plant balance was used in computing these rates by plant account.
Schedule Page: 336.2 Line No.: 18 Column:a
Steam, hydro, and other production depreciation and amortization of certain electric plant is maintained by plant
location. Effective April 1,1993 the forecast life span method of life analysis using an interim retirement rate was
utilized to develop all production plant rates. Rates, service lives, net salvage and remaining lives indicated are on a
composite basis. Effective April 1, 1993 alldepreciable plant is being depreciated using the straight-line remaining life
method.
FERC FORM NO. 1 450.1
(Column: cd,t, gl Plant accounts 31020 through 31650 and 31670 through 31690 are presented for Jim Bridger facility
only. This data is provided by the most recent depreciation study; Jim Bridger was the only thermal production facility
included in the depreciation study. Plant account 31560 is associated with Valmy facility only. Valmy was not part of
the 2016 depreciation study, as Valmy has been reviewed for decommissioning within regulatory order *33771. There
is no data for estimated service life, net salvage percentage, or mortality curve.
Name of Respondent
ldaho Power Company
This(1)
(2)
F
t
t
ort ls:An Original
A Resubmission
Data of Reoort(Mo, Da, Yi)
o411812018
Year/Period of Report
End of 20171Q4
REGULATORY COMMI SSION EXPENSES
1. Report particulars (details) of regulatory commission expens€s incuned during the curent year (or incuned in previous years, if
being amortized) relaUng to brmat cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the cunent yea/s expenses that ar€ not defened and the curent yeat's amortization of amounts
defuned in previous years.
Line
No.
Description
(Fumish name of reoulatorv commission or bodv the
dbd<et or case numbEr and'a description of Sre case)
(a)
Assessed bv
Resulatory
Commission
(b)
Expenses
of
Utility
(c)
Total
Exoense forCuirent Year(b) + (c)
(d)
D€ten€o
in Account
a"gilffiirBlv"".
(e)
1 Federal Energy Regulatory Commission:
2 Annual admin charges assessed by FERC 3,585,160 3,585,160
3
4 General Regulatory Expenses and
5 Various other Dockets 644 il4
6
7 Oregon Hydro - Fees Amorlization 158,501 158,501
I
I Regulatory Commission Exponses - ldaho
10 Rate Case - Misc expanses 146,746 u6,744 80,210
11
12 Regulatory Commission Erpenses - Oregon
13 Rate Cas€ - Misc expenses 7,093 7,093
14 General Regulatory 352,760 352,760
15 Other OPUC expenses 9,805 9,805
16
17
18
't9
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 3,743,661 517,048 4,260,705 80,210
FERC FORfrr NO. r (ED. 12-96)Page 350
Name of Respondent
ldaho Power Company
This Reoort ls:(1) [lnn orlsinal(21 nA Resubmissbn
Dats of Rooort(Mo, Da, Yi)
0411u2018
YearlPeriod of Report
End of 2O17lQ4
3. Show in column (k) any expens€,s incuned in prior years which are being amortized. List in column (a) the period of amortizailon.
4. List in column (0, (S), and (h) expenses incuned durlng year which were charged cunen{y to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Defened to
Account 182.3
(i)
Conha
Account
(i)
Amount
(k)
Line
No.uepartment
(0
,\ftooulrr
(s)
Amount
(h)
1
Electric 928 3,585,160 2
3
4
El€ctric 928 644 5
6
Electric 928 1 58,s01 7
8
I
Electric 928 1,200 113,171 928203 145,546 47,835 10
11
12
Electric 924 7,093 't3
Elec{ric 928 352,760 't4
Electic 924 9,805 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
4,1 1 5,163 113,171 145.546 47,835 6
FERC FORM NO. I (ED. 12-S6)Page 351
Name of Respondent
ldaho Power Company (2t Resubmission
Date of Report(Mo, Da, Y0
0411a12018
Year/Period of Report
End of 2017lQ4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
1. Descdbe and show below costs incunad and accounts charged during the year for technological researctr, development, and domonstration (R, D &
D) project ini0ated, continued or concluded during the year. Report also support given to others during the year for joinUy-sponsored projects.(ldentfu
recipient regardless of affliaUon.) For any R, D & D work canied with others, shorv separably he respondenfs cost for the year and cost chargeabl€ to
others (See definition of researdr, development, and demonstration in Uniform System of Accounts).
2. lndlcate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, O & D Performed lntemally:
(1) Generation
a. hydroelecbic
i. Recreation fish and wildlife
ii Other hydroelectric
b. Fossil-fuel steam
c. lntemal combustion or gas turbine
d. Nudear
€, Unoonv€ntional generaton
f. Siting and heat rejection
(2) Transmission
a. Overhead
b. Underground
(3) Distribution
(4) Regional Transmission and Market Operation
(5) Environment (other than equipment)
(6) Other (Classify and indude items in excess of $50,000.)
(7) Total Cost lncuned
B. Elecbic, R, D & D Performed Extemally:
(1) Researdr Support to the electrical Research Council or the Eleclric
Power Researdr lnstitute
Line
No.
Classification
(a)
Descripton
(b)
1 ldaho Power did not incur any Research and
2 Development expenditures in 2017
3
4
5
6
7
8
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
FERC FORM NO. t (ED. 12-87)Page 352
Name of Respondent
ldaho Porrver Company (2)Resubmission
Date of Reoort(Mo, Da, Yi)
0411812018
Year/Period of Report
End of 2O17lQ4
(2) Research Support to Edison Elechic lnstitute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (ClassiS)
(5) Total Cost lncured
3. lnclude in oolumn (c) all R, D & D items perbrmed intemally and in column (d) hose items performed outside the company cosling $50,000 or more,
briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.).
Group items under $50,000 by dassifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) dassify items by type of R, D &
D activity.
4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year,
lasting Account '107, Construclion Work in Prcgress, first. Show in column (f) the amounts rdated to he acoount charged in column (e)
5. Show in column (g) he total unamortized acormulating of costs of pro.iects. This total must equal the balance in Account 188, Researdr,
Development, and Demonstration Expendifures, Outstanding at the end of the year.
6. lf cosb have not b€en segregated for R, D &D ac{ivities or pmjects, submit estimates for columns (c), (d), and (0 with such amounts identified by
"Est.'
7. Report separately resoarch and related testing facilitios operated by the respondent.
Costs lncuned lnternally
Curre6jYear
Costs lncuned Extemally
Current Year
(d)
AMOUNTS CHARGED IN CURRENT YEAR Unamortized
Accumulation
(g)
Line
No.Account
(e)
Amount
(n
1
2
3
4
5
6
7
8
I
10
't1
12
13
14
15
16
't7
18
't9
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
FERC FORrl NO. I (ED. 12-87)Page 353
ldaho Power Company )
(2)A Resubmission
Dale of Report(Mo. Da, Yr)
04t18t2018
Year/P€riod of Report
End of 2O17lQ4
DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate anrounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amountrs in the appropriate lines and columns
provided. ln determining this segregation of salarios and wages originally charged to clearing accounts, a method of approximation
giving substantially conect results may be used.
Line
No.
Classification
(a)
Dired Pavroll
Distribution
(b)
Total
(d)
1 Electric
2 Operation
3 Production 20,s27,127
4 Transmission 6,658,812
5 Regional Market
6 Distribution 18,7@,177
7 Customer Accounts 8,817,654
I Customer SeMce and lnbrmational 4,665,208
I Sales
10 Administative and General 68,823,822
11 TOTAL Operation (Enter Total of lines 3 thru 10)128,652,800
12 Maintenance
13 Production 4,274,947
14 Transmission 2,892,129
15 Regional Market
16 Distribution 7,267,021
17 AdminisUative and General 1124,057
18 TOTAL Maintenance (Total of lines 13 thru 17)15,558,154
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)25,202,074
21 Transmission (Enter Total of lines 4 and 14)9,550,941
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)26,027,198
24 Customer Accounts (Transcribe fom line 7)8,817,654
25 Customer Service and lnbrmatlonal (Transcribe from line 8)4,665,208
26 Sales (Transcribe from line 9)
27 Adminisfative and G€noral (Enter Total of lines 10 and '17)69,947,879
28 TOTAL Oper. and Maint. (Total of lines 20 hru 271 144,210,954 144,210,954
29 Gas
30 Operation
31 Produclion-Manufu ctured Gas
32 Produclion-Nat. Gas (lncluding Expl. and Dev.)
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42 Maintenance
43 Produc;tion-Manufactu red Gas
44 Production-Natural Gas (lnduding Bploration and Development)
45 Othar Gas Supply
46 Storage, LNG Terminaling and Proc€ssing
47 Transmission
FERC FORM NO. 1 (ED.12-EE)Page 3!i4
ldaho Power Company (1)
(2)
ls:
Original
Resubmission
Dato of R€port(Mo. Da, Yr)
0411u2018
YearlPeriod of Report
End of 20'l7lQ4
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Line
No.
Classification
(a)
Direa PawollDislribution
(b)
for Total
(d)
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 hru 49)
51 Total Operalion and Maintenance
52 Production-Manufachrred Gas (Enter Total of lines 31 and 43)
53 Production-Nalural Gas (lncluding Expl. and Dev.) (Total lines 32,
54 O&er Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru
56 Transmission (Lines 35 and 471
57 Distribution (Lines 36 and 48)
58 Customer Accounts (Line 37)
59 Customer Service and lnformational (Line 38)
60 Sales (Line 39)
61 Adminisbative and General (Lines,(l and 49)
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)
63 Olher UUlity DepartmentsgOperalion and Maintenanoe
65 TOTAL All Utility Dept. (Total of lines 28, 62, ard 04)1M,210j#4 144,210,954
66 Utility Plant
67 Constsuc-tion (By Utility Departments)
68 Electic Plant
63 Gas Plant
70 Other (provide details in foohote):
71 TOTAL ConsEuction (fotal of lines 68 thru 70)
72 Plant Removal (By Utility Departments)
73 Electric Plant
74 Gas Plant
75 Other (provide details in foobrote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)
77 Other Accounts (Spedry. provide details in foobote):
78 Store Expense 4,772,395 4,772,395
79 Other Clearing Accounts 3,424,312 3,424.312
80 Consfuction Wor* in Prcgress 58,547,235 58,547,235
81 Other Work in Progress 3,903,156 3,903,156
82 Other Accounts 5,191,679 5,191,679
83 lndirect Loading 48,797,728 48,797,728
M
85
86
87
88
89
90
91
92
s3
94
95 TOTAL Other Aooounts 75,838,7n 48,797.728 124,636,505
96 TOTAL SALARIES AND WAGES 220,0/9,731 48.797,728 268,847,459
FERC FORM ilO.1 (ED.12.E8)Page 355
Name of Respondent
ldaho Porver Company
This Report is:
(1) X An Original
(2) _ A Reubmission
Date of Report
(Mo, Da, Yr)
od,t18t2018
Year/Period of Report
2A17n4
FOOTNOTE DATA
I
departments based on labor charges.
NO. I 1 450.1
Sclredule Page:351 Line No.:83 Column: a
Amount reported is total- amount of indirect loading. The loading is all-ocated to
ldaho Power Company An
(2)A Resubmission 04t18t2018
Year/Period of Report
End of 2O'l7lQ4
PURCHASES AND SALES OF ANCILLARY SERVICES
lReport the amounts for each type of ancillary seryice shown in column (a) for the year as specified in Order No. 888 and defined in the
lrespondents Open Access Transrnission Tariff.
I
lln columns for usage, report usage-related billing determinant and the unit of measure.
I('t) On line 1 columns (U), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year,
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (0, and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f). and (g) report the amount of energy imbalance services purchased and sold during the year.
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary servicrs purchased or sold during
the year. lnclude in a footnote and specify the amount for each type of other ancillary service provided.
Amount Purchased for he Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant
Line
hlo,
Type of Ancillary Service
(a)
Number of Units
(b)
Unit of
Measure
(c)
Dollars
(d)
Number of Units
(e)
Unit of
Measure
(0
Dollars
(s)
1 Scheduling, System Control and DBpatch 598,161
2 Reactve Supply and Vollage 22,605
3 Regulation and Frequ€ncy Responso 3,051,238 KW 298,869
4 Ensrgy lmbalance 5,470 KWH 703,539
5 Operallng Reserue - Spinning 7,46S 4,233,1 36 KW 416,636
€Operating Reserue - Supplement 5,463 4,274,576 KW 418,695
7 Other
I Total (Lines t hru 7)633,698 11,564,420 1,837,739
FERC FORM NO.1 (New 2.04)Page 398
Name of Respondent
ldaho Power Company
This Report is:
(1)XAn Original(21- A Resubmission
Date of Report
(Mo, Da, Yr)
04t18/2018
Year/Period of Report
20171Q4
FOOTNOTE DATA
Schedute Page: 398 Line No.: 1 Column: bfnformation not availabl-e - fdaho Power does not systematically :ecord tre number of unj-tsrelated to ancillary services purchased.
NO. 1 450.1
Name ol Respondent
ldaho Power Coorpany (2)A Resubmission
Date of Report(Mo, Da, Yr)
041192018
Year/Period of Report
End of 20171Q4
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
(1) Report the monthly peak load on the respondent's transmission syctom. lf the respondent has two or more power systems whidr are not physic€lly
integrated, fumish the required information fur each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Repofi on Columns (c ) and (d) he specifrod infomatpn for each monhly Eansmission - system peak load reported on Column (b).
(4) Report on Columns (e) through O by month the system' monhly maximum megawatt load by statistcal classifications. See General lnstruc,tion for
the definilion of each sta$stical dassification.
NAME OF SYSTEM: ldaho Power Company
Lina
No.Month
(a)
Monthly Peak
MW-Total
(b)
Day of
Monhly
Peak
(c)
Hour of
['lon$ly
Peak
(d)
Fim Neturork
Service for Self
(6)
Flrm Notuork
Seruhebr
Ofien
(D
Long-Term Fim
Pdnt-h-point
Reserualbns
(s)
OherLong-
Term Fim
Sswha
(h)
Short-Term Firm
Pdnthglint
Reserualion
(i)
Oher
Service
0)
1 Januay 3,73(17 800 2,1n 261 973 325
2 Februay 3,28{14 800 1,598 219 973 498
I March 2,89(3C 2100 1,30!185 973 423
4 Total for ouertar 1 5,08{665 2,91S 1,246
F Apnl 2,81i 28 80c 1,066 178 973 s96
6 Ma,3,84(31 I 70C 2,031 287 973 54S
7 June 4,46t 26 1 60C 2,724 357 973 414
I Totd br Quartor 2 5,821 822 2,919 1,559
o July 4,713 8 1900 3,'t63 352 973 225
10 Argust 4,161 I 1900 2,934 339 973 218
11 SAhn$er 3,918 1800 2,445 28:973 217
12 Total br Quarter 3 8,542 974 2,91!660
13 October 2,886 900 1,442 185 973 286
14 Nouomber 3,011 t 800 1,555 19S 973 2U
15 D6cemb€r 3,288 1t 900 1,506 218 973 591
16 Totalbr Quetur 4 4,503 602 2,91S 't,161
't7 Total Year to
Datoffea 23,9s0 3,063 1 1,676 4,626
FERC FORM NO. 1r3-O (NEW 07-04)Page tOO
ldaho Power Company (1)
(21 A Resubmission
Dste of Reoort(Mo, Da, Yi)
o411812018
Year/Period of Report
End of 20171Q4
ELECTRIC ENERGY ACCOUNT
Report below tr€ information called fur concerning lhe disposition of electric energy generated, purchased, excfianged and wheeled during the year.
Line
No.
Item
(a)
MegaWatt Hours
(b)
Line
No.
Item
(a)
MegaWatt Hours
(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Stration Use):22 Sales to Ultimate Consumers (lncluding
I nterdepartmental Sales)
14,570,954
3 Steam 3,284,013
4 Nuclear 23 Requiremenb Sales for Resale (See
instuction 4, page 31 1.)5 Hydro-Conventlonal 8,900,05s
6 Hydro-Pumped Stcrage 24 Non-Requirements Sales for Resale (See
insbuc{ion 4, page 311.)
2,'t35,649
7 Other 1,503,3 t C
8 Less Energy for Pumping 25 Energy Fumished Without Charge
I Net Generation (Enter Tobl of lines 3
through 8)
13,687,382 26 Energy Used by the Company (Eledric
Dept Only, Exduding Statlon Use)
10 Purchases 4,293,616 27 Total Energy Losses 1,256,411
11 Power Exchanges:28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EOUAL L|NE 20)
17,963,014
12 Received 228,341
13 Delivered 259,185
't4 Net Excfianges (Line 12 minus line 13)-30,844
15 Transmission For Other (Wheeling)
16 Received 6,832,886
17 Dolivered 6,820,02(
18 Net Transmission for Other (Line 16 minus
lin€'17)
12,W
19 Transmission By Others Losses
20 TOTAL (Enter Tobl of lines 9, 10, 14, 18
and 19)
17,963,014
FERG FORM NO. I (ED. 12-90)Page 401a
Name of Respondent
ldaho Power Company
This Report is:
(1)XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
ut18t2018
Year/Period of Report
2017tQ4
FOOTNOTE OATA
Line No.:18 Column: b
Page I ffers from page 401 by 72,860 MWH, reported for L Pea var tand BPA energy j-mbalance schedules on page 401. The numbers that are shown on pages
328-330 are for account 456 wheeling onIy, the numbers on page 401 have to be adjusted for
account 447 transmission.
FERC FORM NO. I (ED.12A7l Page 450.1
ldaho Power Company (1)
(2)
Original
Resubmission
Dat6 of ReDort(Mo, Da, Yi)
04118t2018
Yer/Period of Report
End of 2O17lA4
MONTHLY PEAKS ANO OUTPUT
1. Report the monthly peak load and energy ougut. lf lhe rospondent has two or more power whidt are rrct physically integoted, fumish the rcquircd
inbnnation fur eacfi non- integratd system.
2. Report in column (b) by month lhe system's output in Megawatt hou6 br each month.
3. Report in column (c) by month he non-requirernents sales fcr resale. lndude in he monhly amounb any energy losses associated with the sales.
4. Report in column (d) by month tho system's monthly maximum megEwatt load (60 minuta integration) associatod with the system.
5. Report in column (e) and (f) tre specified inbrmation for each monhly peak bad reported in oolumn (d).
NAME OF SYSTEM: IDAHO PoWER COMPAT.IY
Une
No.Month
(a)
Total Monthly Energy
(b)
Monthly Non-RequirmenE
Sales fur Resale &
Assodated Losses
(c)
MONTHLY PEAK
Megawatts (See lnsf.4)
(d)
Day of Month
(e)
Hour
(D
oc January 1,479,401 22,381 2.527 6 9AM
3C February 1,390,680 258,738 2,203 2 7PM
31 Marctr 1,ffi4,423 472,711 1,985 2 8AM
32 April 1,48,6,012 467,608 1,791 4 8AM
33 May 1,512,091 228,398 2,631 30 6PM
u June 1,665,666 139,852 3,139 26 4PM
35 July 1 ,91 1,08i 20,673 3,422 7 5PM
36 August 1,712,283 44,397 3,153 2 6PM
37 September 1,390,726 150,917 2,812 1 6PM
38 October 1,20',t,145 116,726 1,774 16 8AM
39 November 1,160,6s5 70,683 1.964 30 8AM
40 Decemb€r 1,,185,411 142,565 2,181 13 7PM
41 TOTAL 17,963,580 2,135,649
FERC FORITI NO. t (Eo. 12-90)Page 401b
Name of Respondent
ldaho Power Company
This RaDort ls:(1) ElAn Original(2) !A Resubmission
Date of Report
(Mo, Da, Yr)
o4t't8t2018
YearlPeriod of Report
Enct of 20171Q4
STEAM-ELECTRIC GENERATING PI-ANT STATISTICS (Larse Plants)
1. Report datia for plant in Service only. 2. Large planh are steam planh with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas.turbine and intemal combustion plants of 10,000 Kw or more. and nuclear plants. 3. lndicate by a footnote any plant leased or opemt6d
as a joint facility. 4. lf net peak domand for 60 minutes is not available, give data whicfi is a€ilable, speciffing period. 5. lf any employees attend
more than one plant. report on line 1 I the approximate avorage number of employees assignable b each plant. 6. ll gas is used and purchased on a
th€rm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fud bumed (Line 38) and avsftrge coet
per unit of fuel bumed (Line 41) must be consistent with charges to expense ac@unts 501 and 547 (Line 42) as show on Line 20. 8. lf more than one
fuel is bumed in a plant furnish only the composito heat rete ficr all fuels burned.
Line
No.
Item
(a)
Plant
Name: Jim Ertdger
(b)
Plant
Name: Boardman
(c)
1 Kind of Plant (lntemal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Semi-0utdoor Boiler Conventional
3 Year Originally Conslructed 1980
4 Year Last Unit was lnstalled 1 979 1980
5 Total lnstalled Cap (Max Gen Name Plate Ratings-MW)
o Net Peak Demand on Plant - MW (60 minutes)712 60
7 Plant Hours Connected to Load 8760 3905
I Net Continuous Plant Capability (Megawatts)0 0
I When Not Limited by Condenser Water 0 I
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 0 0
12 Net Generation, Exclusive of Plant Use - Kvvtl 2893201000 162076000
13 Cost of Plant: Land and Land Rights 509671 106610
14 Structures and lmprovements 70169218 12607486
15 Equipment Costs 627633929 63810772
16 Asset Retirement Costs 9832782 50.+6008
17 Total Cost 708145600 81570876
18 Cost per KW of lnstalled Capacity (line 17l5) lncluding 91 9.0728 1270.5744
19 Production Expenses: Oper, Supv, & Engr 166605 375778
20 Fuel 92007202 4156501
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses ss31 1 61 677945
23 Steam From Other Sources 0 0
24 Steam Transfened (Cr)0 0
25 Electric Expenses 0 0
26 Misc Steam (or Nuclear) Power Expenses 8747253 806543
27 Rents 328946 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 23/.30 31798
30 Maintenance of Struc'tures 94 40380
31 Maintenanc6 of Boiler (or reactor) Plant 7074749 188557
32 Maintenance of Electric Plant 2340314 1519055
33 Maintenance of Misc Steam (or Nuclear) Plant 5766079 56782
34 Total Production Expensos 121985833 7853339
35 Expenses p€r Net KWh 0.0422 0.0485
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal oit Coal oit
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclearindicate)Tons Barrels Tons Banels
38 Quantity (Units) of Fuel Bumed 1634369 6603 0 97989 1824 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nucleaO s183 't40000 0 8596 't38800 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 54.681 82.111 0.000 36_966 79.O25 0.000
41 Average Cost of Fuel per Unit Bum€d 55.903 65-932 0.000 40.864 76.359 0.000
42 Average Cost of Fuel Burned per Million BTU 3.015 't1.213 0.000 2.353 13.098 0.000
43 Average Cost of Fuel Burned per KWh Net C,€n 0.032 0.000 0.000 0.026 0.000 0.000
44 Average BTU per KWh Net Generation 10487.000 0.000 0.000 10567.000 0.000 0.000
Page rO2
197/
no.6t u.2(
FERC FORilr NO. 1 (REV.12-03)
Oate
ldaho Power Company (1)
{2)
tur Original
A Resubmission
(Mo, Da,
04t18t2018
Year/Period of Report
End of 20171Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Planb) (Continued)
9. ltems under Cost of Plant are based on U. S. of A. Accounts. Production exp€nsos do not include Purchased Power, System Control and Load
Dispatching, and Other Expsnses Classified as Other Power Supply Expenses. 1 0. For lC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 'Electric Expenses,'and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant.' lndicate plants
designed br peak load service. Designate automatically operated plants. 11. Fot a plent equipped with combinalions of fossil fuel steam, nudear
steam, hydro, internal combustion or gas-hrrbino equipm€nL report each as a separate plant. However, if a gas-furbine unit funcdions in a combined
cycle operation with a conventional steam unit, include the gas{urbine with tho 6team plant. 12. lf a nuclear power gonorating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any exoess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data conceming plant type fuel used, fuel enrichment type and quantlty for the
report period and olher physical and operating characterislics of plant.
Plant
Name: Valrny
(d)
Plant
Name: Danskia
(e)
Plant
Name: Eennelf Wuntain
(0
Line
tlo.
Steam Gas Turbine Gas Turbine 1
Outdoor Conventional Conventional 2
t981 2001 2005 3
1985 2008 2005 4
283.50 270.90 172.80 5
260 247 193 b
2771 431 605 7
0 261 1U I
o 0 0 I
0 0 0 10
0 6 5 11
228736000 661 91 000 86409000 12
1 106140 402745 0 13
71687061 6088861 I 830493 14
329988873 100556351 61237796 't5
1't102 0 0 16
402793176 10704755?63068289 17
1420.7872 395.1567 364.9785 18
430337 144745 7567 19
1 1 729960 3976764 3409554 20
0 0 0 21
2292329 0 0 22
0 0 0 23
0 0 0 24
1 396032 395123 3101 16 25
2141109 281259 134/.3'.1 26
0 0 0 27
0 0 0 28
0 0 0 29
399960 909s9 't44995 30
3768059 4581 254770 31
472004 219946 1178277 32
112414 0 0 33
22748204 5113377 5439710 34
0.0995 0.0773 0.0630 35
Coal oir Gas GAS 36
Tons Banels MCF MCF 37
131541 5815 0 826814 0 0 891124 0 0 3B
8937 1 38778 0 1027 0 0 1027 0 0 39
0.000 79.177 0.000 4.810 0.000 3.826 0.000 0.000 40
85.711 75j24 0.000 4.810 0.000 0.000 3.826 0.000 0.000 41
4.771 12.889 0.000 4.500 0.000 0.000 3.650 0.000 0.000 42
0.051 0.000 0.000 0.060 0.000 0.000 0.039 0.000 0.000 43
10479.000 0.000 0.000 't2829.000 0.000 0.000 10591.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12.03)Page 403
0.000
of
ldaho Power Company (1)
t2)
An Original
A Resubmission
(Mo,
04t18t2018
Year/Perlod of Report
End of 20171Q4
STEAM-ELECTRI C GENERATI NG PI-ANT STATISTICS (Large Plantsl (Continued)
'1. Report data for plant in Service only. 2. Large plants are steam plants witr installed capaclry (name plate ratlng) of 25,000 Kw or more. Report ln
his page gas-turbine and intemal combustion planB of 10,000 Kw or more, and nuclear plants. 3. lndicete by a footnote any plant leased or operated
as a joint facility. 4. lf net peak demand fur 60 minutes is not available, give data which is available, specirying period. 5. lf any employees attend
more than one plant, raport on line I 1 the appnoximate average number of employees assignable b each planl. 6. lf gas is used and purchased on a
lherm basis report th6 Btu content or the gas and the quantity of fud bumed converted to Mct. 7. Quantities of fuel bumed (Line 38) and average cost
per unit of fud bumed (Line 41) must be consietent with charges to expense accounb 501 and 547 (Line 42) as show on Lin€ 20. 8. lf more than ono
fuel is burned in a plant fumish only the composite heat rale br all fuels burned.
Line
No.
Item
(a)
Plant
Name: Langley Gulch
(b)
Plant
Name:
(c)
1 Kind of Plant (lntemal Comb, Gas Turb, Nudear Gas Tudine
2 Type of Consf (Convenlional, Outdoor, Boiler, etc)Conventional
3 Year Originally C,onstructed 2012
4 Year Last Unit was lnstalled 2012
5 Total lnstalled Cap (Max C;en Name Plate Ratings.MW)318.45 0.00
6 Net Peak Demand on Plant - MW (60 minutes)310 0
7 Plant Hours Connecled to Load 5079 0
8 Net Continuous Plant Capability (Megawatts)300 0
I When Not Limited by Condenser Water 0 0
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 23 0
12 Net Generation, Exclusive of Plant Use - K\A/h 13s0692000 0
13 Cost of Plant Land and Land Rights 2287261 0
14 Slru ctrres and lmprovements 135401444 0
15 Equipment Casts 236782901 0
16 Asset Retirement Costs 0 0
17 Total Cost 37447',t606 0
18 Cost per KW of lnstalled Capacity (line 1715) lncluding 1 1 7s.9196 0
19 Produc{ion Expenses: Oper, Supv, & Engr 500902 0
20 Fuel 305,14960 0
2'.1 Coolanb and Water (Nudear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Souroes 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 3466431 0
26 Misc Steam (or Nuclear) Power Expenses 451791 0
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintonance of Struc{ures 99137 0
31 Maintenance of Boiler (or r6actor) Plant 290325 0
32 Maintenance of Electric Plant 827886 0
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 36',t81432 0
35 Expenses per Net KWh 0.0268 0.0000
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas
37 Unit (Coal-tonsy'Oil-barrel/Gas+nc'f/Nuclear-indicate)MCF
38 Quantity (Units) of Fuel Bumed 9101138 0 0 0 0 0
39 Avg Heat Cont - Fuel Bumed (btu/indicate if nucloar)1027 0 0 0 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 3.356 0.000 0.000 0.000 0.000 0.000
41 Average Cost of Fuel per Unit Burned 3.356 0.000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Bumed per Million BTU 3.310 0.000 0.000 0.000 0.000 0.000
43 Average Cost of Fuel Bumed per K\A/h Net Gen 0.023 0.000 0.000 0.000 0.000 0.000
44 Average BTU per KWh Net Generation 6920.000 0.000 0.000 0.000 0.000 0.000
FERC FORfrl NO. 1 (REV. 12-03)Page 402.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) - A Resubmission
Date of Repoil
(Mo, Da, Yr)
0411u2018
Year/Period of Report
2017tQ4
FOOTNOTE DATA
Schedu/e Page:102 Line No.:3 Column: bThis footnote applies to lj-nes 3 and 4. The Jim Bridger PowerPlant consists of four equal- units constructed lointly by Idaho
Power Company and Paeific Power and Light Company. with Idaho
ownj-ng 1/3 and PaciflCorp owning 2/3. Untt #1 was placed in
commercial operation November 30, L914, Unit *2 December 1, L915,uni-r #3 L91 6!and Unit *4 November 29, 1919.1
Schedule
September
Page:102 Llne No.:3 Column: cThis footnote applies to lines 3 and 4. The Boardman plantconsists of one unit constructed jointly by Portland GeneralElectric Company, Idaho Power Company, and Pacific NorthwestGenerating Company, with Idaho Power Company owning 108. Theunrt was placed in commercial operation Auqust 3, 1980.
r$clredule Page:4,03 Li1t9 No.: .3 Column: d
Th.is footnote applles to lines 3 and 4. The Valmy plant consistsof two units constructed jointly by Sierra Pacific Power Companyand ldaho Power Company, with Sierra owning 7/2 and Idaho owni-ngL/2. UniL #1 was placed in commercial operation December 11, 1981and Unj-t #2 May 2l , 1985.
Schedule Page: 4)2 _ Une No; ! Column: bThis footnote applies to lj-ne 5 and lines 12 through 43.Information reflects ldaho Power Company's share as explainedin note for Lj-ne 3 page 402 column B.
Schedule Page:102 Line No.: 5 Column: c
This footnote applles to iine 5 and l-ines
Information reflects Idaho Pcwer Company'sin note on fine 3 page 402 ccfumn C
Scheduta Page:4)J Line No.:5 Column: dThj-s footnote appiies to line 5 and linesInformaiion refl-ects Idaho Power Company'sin note for line 3 page 403 columa D.
Schedule Page: 4O2 Line No-: g Column: b
This footnote applies to lines 9, 70, and 11. PacifiCorp
as operator of the plant will report this
information.
Schedule Page:402 Line No.:This footnote applies to clines 9,10, a
12 through 43.share as explained
12 through 43.share as explained
nd i1. Portfand GeneralFlectric Company, as operator will report this inforrnation,
Schedule Page: tl03 Line No.:9 Column: d
Th-is footnote appli-es to lines 9, 10, and 11. Sierra Pacifj-c
Power, as operator of the p1ant, will report this information.
FERC FORM NO. 1 (ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company (1 Original Da,
(2)Resubmission 04118t2018
Year/Period of Report
End of 2O17lQ4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1 . Large plants are hydm plants of 10,000 Kw or more of insblled capacity (name plate ratings)
2. ll any plant is leased. operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
e foolnote. lf licensed project, giv6 project number.
3. lf net peak demand for 60 minutes is not available, give that whictt is available specifiing period.
4. lf a group of employees att€nds mor€ than one generating plant, report on llne 11 the approximate av€rage number of employees assignable to eadr
plant.
Line
No,
Item
(a)
FERC Licensed Projec*No. 2736
Plant Name: American Falls
(b)
FERC Licensed Project No. 1975
Plant Name: Bliss
(c)
1 Kind of Plant (Run-of-River or Storage)Runof-Rlver Run-of-River
2 Plant Constuction type (Conventional or Outdoor)Outdoor Outdoor
3 Year Originally Constructed 1978 1949
4 Year Last Unit was lnstalled 1978 1950
5 Total installed cap (Gen name plate Rating in MW)92.30 75.00
o Net Peak Demand on Plant-Megawatts (60 minutes)106 52
7 Plant Hours Connect to Load 7,357 8,693
8 Net Plant Capability (in megawatb)
I (a) Under Most Favorable Oper Conditions 110 76
10 (b) Under the Most Adverse Oper Conditions 0 1
11 Average Number of Employees 4 4
12 N€t Generation, Exclusive of Plant Use - Kwh 482,999,000 343,369,000
13 Cost of Plant
't4 Land and Land Rights 875,318 768,366
15 Sbucfu res and lmprovements 1 1,970,406 1,739,818
16 Reservoirs, Dams, and Waterways 4,293,075 9,254,107
't7 Equipment Costs 32,33/.,221 9,989,731
18 Roads, Railroads, and Bridges 839,276 486,477
19 Assst Retiremeflt Costs 0 0
20 TOTAL cost (Total of 14 thru 19)50,312,296 22,238,499
2'.!Cost per KW of lnstalled Capacity (line 20 / 5)545"0953 296.5133
22 Production Expenses
23 Operation SupeMsion and Engineering 226,549 686,656
24 Water fur Power 1,648,928 492,979
25 Hydraulic Expenses 't49,495 890,584
26 Electric Expenses 54,746 74,476
27 Misc Hydraulic Power Generation Expenses 428,735 673,894
28 Rents 183 4.699
29 Maintenance Supervision and Engineering 6,825 3,787
30 Maintenance of Strucfu r€s 1 75,185 42,259
31 Maintenance of Reservoirs, Dams, and Waterways 92,288 3,576
32 Maintenance of Elecbic Plant 104,761 7,978
33 Maintenance of Misc Hydraulic Plant 85,690 200,241
34 Total Production Expenses (total 23 thru 33)2,973,385 3,081,129
35 Expenses per net KWh 0.0062 0.0090
FERC FORM NO. I (REV.12-03)Page tl06
Name of Respondent
ldaho Power Company
This Raoort ls:(1) 5l1Rn orisinat(2) -A Resubmission
Date of Raport(!rio, Da, Yr)
0411812018
Year/Period of Report
End of 2O17lQ4
HYDROELECTRIC GENERATI NG PLANT STATISTICS (Large Plants) (Continued )
5. The ltems under Cost of Plent represent a@ounts or combinations of accounts prescribed by the Unibrm System of Accounb. Produc{ion Expenses
do not include Purctrased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate dant any plant equipped with combinations of steam, hydro, intemal comh.rstion engine, or gas turbine equipment
FERG Licensed Project No. ,1971
Plant Name: Brownlee
(d)
FERC Licensed Projec{ No. 2g4B
Plant Name: Cascade
(e)
FERC Licensed Project l.lo. 1971
Plant Name: Oxbow (f)
Line
No.
Storage 1
Outdoor O.rtdoor Outdoor 2
't958 1983 196'l 3
1980 198/.1961 4
585.40 12.42 190.m 5
602 13 211 6
8,736 8,640 8,735 7
I
747 15 221 I
220 1 202 't0
I 2 7 't1
2,394,269,000 47,655,000 1,195,770,m0 12
13
18,253.689 82,142 1,212,767 14
37.211.286 7,328,252 13,188,581 15
67,618,611 3,145,630 31,343,667 16
100,361,290 13,394,6'10 21 ,1 10,964 17
518,444 122,ffi 585,876 18
0 0 0 19
223,963,320 24,O73,302 67,,141,855 20
382.5817 1,938.2691 354.9571 21
22
838,421 225,980 455,424 23
307,620 132,783 164,549 24
1,124,545 416,853 624,4s7 25
396,973 133,916 243,966 26
1,162,291 406,405 647,621 27
116,098 72 19,035 28
17,638 2,964 7,542 29
96,195 17,624 146,10S 30
179,495 0 12,925 31
355,442 82,836 115,037 32
569,018 101,873 238,025 33
5,167,736 1,521,306 2,674,690 34
0.0022 0.0319 0.0022 35
FERC FORm NO.1 (REV.12-03)Page 407
Run of.filvsr
Name of Respondent
ldaho Power Company
This Reoort ls:(1) 5]An orisinat(2) 3A Resubmission
Dat€ of Reoort(Mo, Da, Yi)
04118t2018
Year/Period of Report
End of 2O17lQ4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Planb)
1. Large dants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. lf any plant is leased, operated under a license from the Federal Energy Regulatory Commlssion, or operated as a joint facility, indicate such facb in
a foohote. lf licensed project, give project numb€r.
3. lf net peak demand for 60 minutos is not available. give that which is available specifuing period.
4. lf a group of employees attends more than one generating plant, report on line 1 1 the approximate average number of omployees assignable lo each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 1971
Plant Name: Hells Canyon
(b)
FERC Licensed Projec't No. 2726
Plant Name: Malad
(c)
I Kind of Plant (Run-of-River or Sbrage)
2 Plant Construction type (Conventional or Outdoor)Outdoor Outdoor
3 Year Originally Consfucted 1967 1948
4 Year Last Unit was lnstalled 1967 1948
5 Totral installed cap (Gen name plate Rating in MW)391.s0 21.77
6 Net Peak Oemand on Plant-Megawafts (60 minutes)435 23
7 Plant Hours Connect to Load 8,736 8,736
8 Net Plant Capability (in megawatts)
I (a) Under Most Favorable Oper Conditions 445 25
10 (b) Under the Most Adverse Oper Conditions 137 21
11 Average Number of Employees 3 ,|
12 Net Generation, Exclusive of Plant Use - Kwh 2,514,407,000 129,521,000
13 Cost of Plant
14 Land and Land Rights 1,880,381 205,376
15 Stuc{ures and I mprovem ents 2,869,602 3,964,636
16 Reservoirs, Dams, and Waterways 53,033.657 6,302,917
17 Equipment Costs 20,175,733 15,429,822
18 Roads, Railroads, and Bridges 922,781 1,507,442
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)78,882,154 27,410,',t93
21 Cost per KW of lnstalled Capacity (line 20 / 5)201.4870 1,259.0810
22 Production Expenses
23 Operation Supervision and Engineering 360,562 180,900
24 Water fcr Power 1s5,096 737,587
25 Hydraulic Expenses 563,083 207,155
26 Electric Expenses 208,908 51,891
27 Misc Hydraulic Power Generation Expenses 651,717 272,6U
28 Rents 31,663 0
29 Maintenance Supervision and Engineering 13,567 4,351
30 Maintenance of Struclures 27,903 44,586
31 Maintenance of Reservoirs, Dams, and Wateruays 110,508 85,771
32 Maintenance of Electric Plant 138,470 86,142
33 Maintenance of Misc Hydraulic Plant 649,298 75,452
34 Totral Production Expenses (total 23 hru 33)2,910,775 1,746,563
35 Expenses per net KWh 0.0012 0.0135
FERC FORM NO.'t (REV.12.03)
SbnEc Runol-River
Page 406.1
ldaho Power Company (1)
(2)
Original Date(Mo,
Resubmisslon 0411812018
Year/Period of Report
End of 2O17lQ4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounB or combinations of accounts prescribed by he Uniform System of Acoounts, Producdon Expenses
do not indude Purchased Power, System control and Load Dispatching, and Oher E&enses classified as "Othe Porer Supply Expenses.'
6. Report as a separate plant any plant equipped with combinations of steam, hydro, inbmal combustion englno, or gas furbine equipment
FERC Licensed POec{ No. 2055
PlantName: CJStriko
(d)
FERC Licensed Profirct No. S03
Plant Name: Swan Falls
(e)
FERC Licensed Projed No.
Plant l',lame: Twin Falls(f)
18 Line
No.
Run-of-River Run-of-River Runof-River 1
Outdoor Conventircnal Convontional 2
1952 1910 1 935 3
1952 1994 1 995 4
82.80 25.00 52.74 5
92 24 51 b
8,722 8,727 7,529 7
I
91 24 53 9
u 14 50 't0
4 4 3 11
550,191,000 I 30,191,000 214,318,000 12
13
5,725,987 263,249 255,49S 14
9,943,913 27,491,203 1 1,139,603 15
11,225,224 15,989,465 9,072,436 16
14,229,579 31,599.687 22,177,128 17
1,602,868 835,946 1,917,603 18
0 0 0 19
42,727,571 76,179,550 44,562,265 20
516.0335 3,047.1820 844.9425 2'.1
22
878,408 425,670 327,W 23
431,627 221,330 123,488 24
1,278,795 604.587 196,332 25
76,520 s6,260 79,136 26
1,'t60,238 683,537 387,962 27
50,456 7,ffi4 3,538 2A
9,546 4,675 4,436 29
't27,633 76,681 76,583 30
2't8,513 17,026 9,723 31
196,413 96,159 112,228 32
97,940 123,809 100,066 33
4,526,089 2,317,598 1,420,292 34
0.0082 0.0178 0.0066 35
FERC FORM NO. r (REV.12-03)Page 407.1
ldaho Porer Company (1)
(2)
An Original
A Resubmission
Oa,
ut18t2018
Year/Period of Report
End of 2O17n4
HYDROELECTRI C GENERATING PI-ANT STATISTICS ( Large Plants)
1. Large planb ar€ hydro plants of 10,000 Kw or more of ingtalled capacity (name plate ratings)
2. 1l any plant is leased, oporabd under a liconse fuom the Federal Energy Regulabry Commi66ion, or operated as a joint facility, indicat€ such facb in
a fuohote. lf liconsed project, givo proj€ot number.
3. lf net peak demand for 60 minutes is not awilable, give that which is available specifying period.
4. lf a group of employees attonds mora than one goneratlng plant, report on llne '11 lhe approximate average number ot employoes asslgnable to eacfr
plant
Line
No.
Item
(a)
FERC Lioensed Project No. 2777
Plant Name: Upper Salmon
(b)
FERC Licensod Project No. 2778
Plaot Name: Shoshone Falls
(c)
1 Kind of Plant (Run-of-River or Storage)Run-of-River Run-of-River
2 Plant Construc{on type (Conventional or Outdoor)Outdoor Conventional
3 Year Originally Constructed 1937 1907
4 Year Last Unit was lnstalled 1947 1921
5 Total installed cap (Gen name plate Rating in MW)34.50 12.50
6 Net P€ak Demand on Plant{Vlegawatts (60 minutes)35 13
7 Plant Hours Connec-t to Load 8,736 8,710
8 Net Plant Capatility (in mogawatts)
9 (a) Under Most Favorable Oper Conditions 39 14
10 (b) Under he Most Adverse Oper Conditions 32 11
11 Average Number of Employees 3 3
12 Net Generatlon, Exclusive of Plant Use - Kwh 241,735,000 93,460,000
13 Cost of Plant
14 Land and Land Rights 202,399 313.328
15 Struc'trres and lmprovements 2,729,832 1,593,707
16 Reservoirs, Dams, and Wateuays 6,181,301 10,o13,741
17 Equipment Costs 9,023,589 4,832,072
18 Ro8ds, Railroads, and Bddges 29,359 51,383
19 A,sset Retiremeot Costs 0 0
20 TOTAL cost flotal ot 1 4 thru 19)18,166,480 16,804,231
2',1 Cost per KW of lnstalled Capacity (line 20 / 5)526.5646 1,3'14.3385
22 Production Expens€s
23 Operation SupeMsion and Engineorirp 22s,097 177,233
24 Water br Poler 122,390 86,622
25 Hydraulic Expenses 35't,345 131,457
26 Electoic Expenses 141,232 36J22
27 Misc Hydraulic Power Generation Exponses 365,584 342,08',|
28 Rents 0 225
29 Maintonance Supervision and Engineering 6,80'l 1.937
30 Maintenance of Structures 95,487 27,853
31 Maintenance of Reservoirs, Dams, and Watomays 32,244 4,025
32 Maintenance of Electric Plant 206,321 28,62
33 Maintenance of Misc Hydraullc Plant 't22,225 78,470uTotal Production Expenses (total 23 thru 33)1,668,746 905,637
35 Elgenses per net KWh 0.0069 0.0097
FERC FORrU XO. r (REV.12-03)Page 'O6.2
ldaho Porver Company (1)
(2)A Resubmission
Date of R€port(Mo. Da, Yr)
o4t1u2018
Year/Psriod of Report
End of 2O17lQ4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinaliom of accounts prescribed by the Uniform System of Accounb. Production Expsnses
do not indude Purchased Power, System contol and Load Dbpatching, and Othor Expenses dassilled as'Other Power Supply Expenses.'
6. Report as a separate plant any plant equipped with combinations of steam, hydro, intemal combustion engine, or gas furbine oquipment.
FERC Licensed Proje<{ No. 1971
Plant Name: Common Facilities
(d)
FERC Licensed Project No. 20f31
Plant Name: Lower Salmon
(e)
FERC Licensed ProjectNo. 2899
Plant Name: Milner
(n
Line
No.
Runof-River Run-of-Rlver 1
Outdoor Conventional 2
1949 1992 3
1949 1992 4
0.00 60.00 59.45 5
0 63 59 6
0 8,709 6.748 7
8
0 a4 61 9
0 60 1 10
0 6 2 11
0 308,425,000 237,491,000 12
13
I 14,368 424,428 138,100 14
50,375,798 3,445,687 't0,696,551 15
13,556,785 7,881.414 17,767,N2 16
2,369,851 17,7fi,441 29,255.240 17
146,581 88,693 501,877 18
0 0 0 19
66,563,383 29,598,663 58,358,770 20
0.0000 493.311 1 981.6.146 21
22
0 383,936 221.',t58 23
0 18/.,325 1,004,611 24
7,603,075 584,176 1s9,386 25
0 186,112 53,898 26
182 336,528 27
0 4,234 3,720 28
0 5,234 3,269 29
0 87,396 48,344 30
0 10,667 14,068 31
0 173,036 101,148 32
163,605 80,082 55,750 33
7,7ffi,862 2,269,815 2,001,880 u
0.0000 0.0074 0.0084 35
FERC FORM NO. 1 (REv.12-03)Page 4{17.2
590,61
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2\ -A Resubmission
Date of Report
(Mo, Da, Yr)
M,11812018
Year/Period of Report
20171Q,4
FOOTNOTE DATA
$6 Line
Amer
USBR
ud5
Lower MaI
r s generat
$6 Line No.:7
stor
st
1
.v upon wa er eases controlled by the
et water releases contro the USBR.
r:1 Column: c
demand 15r000 Kw, Upper Malad maximum demand 91000 Kw non-colncident-
Re r
I
106
406.1 LlneNo.:1 Column: b
NO.1 1 450.1
1S
r-871
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yi)
0/.t18t2018
YearlPeriod of Report
End of 2O17lQ4
GENI
1. Small gonoraling plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbin+.plants, conventional hydro plante and pumped
storage plants of less than '10,000 Kw installed capacity (name phte rating). 2. Designate any plant leased frrom others, operated under a licens€ ftom
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a foolnote. lf licensed projed,
give prcj€c,t number in foolnote.
Line
No.
Name of Plant
(a)
Year
Orio.Con-st.
(b)
tnsutleo (ioaow
Name Plab RaUnj
(ln Mw)
(c)
Net FoaxDemand
MW(60,91in.)
Net Cieneration
ExdudinoPlant UsE
(e)
Cost of Plant
(f)
I Hydro:
2 Clear Lakes 1937 2.50 ac 16,514 3.544.451
3 Thousand Springs '1912 8.80 -25e 10,106,248
4
5
6 lnternal Combustion
7 1 5.00 3.7 1t 909,25S
8
I
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
4
45
46
FERC FORM NO.1 (REV. 12-03)Page 410
Salmon Dlcal
ldaho Power Company (1)
(2',)
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
o4t18t2018
Year/Period of R€port
End of 2O17lQ4
3. List plants appropriately undor subhoadings br steam, hydro, nuclear, intemal combustion and gas turbine plants. For nuclear, se€ instruclion 11.
Page 403. 4. lf net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. lf any plant is equipped with
combinations of steam, hydro intemal combustion or gas turbine equipment, reporl each as a separate plant. However, if the exhaust heat from the gas
trrbine is utilized in a steam turbine regenerative feed water c)rde, or fur preheated combustion air in a boiler, report as one plant.
Plant Cost (lncl Asset
Retire. Costs) Per MW
(s)
Operation
Exc'|. Fuel
(h)
Prooucuon Expenses
Kind of Fuel
(k)
Fuel Costs (in cents
(per Million Btu)
0)
Line
No.FUet
(i)
Marntenancoo
1
1,417.7N 314,282 120,895 2
1,148,437 236,307 117,575 3
4
5
6
181,852 Oiesel 7
I
I
10
11
12
't3
14
15
16
17
18
19
20
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
3S
40
41
42
43
44
45
46
FERC FORM r{O. I {REV.12-03)Page 411
2'.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04118t2018
Year/Period of Report
20171o1.
FOOTNOTE DATA
Schedute Page: 4lO Llne No.:
Sal-mon un-it.s are classifi
FERC FORM 1 1 450.1
Name of Respondent
ldaho Power Company (1)
(2t
(Mo. Da,
Resubmission 04118t2018
Year/Period of Report
Enct of 20171Q4
TRANSMISSION LI NE STATISTICS
1. Report information concerning bansmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below ftese voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounb. Do not report
substation costs and expenses on his page.
3. Report data by individual lines for all voltages if so required by a Stiate commisslon.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. lndicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) towor;
or (4) underground construction lf a transmission line has more than one type of supporting struclure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission lins of a diffurent type of construction need not be distinguished from he
remainder of the line.
6. Report in @lumns (0 and (g) the total pole miles of each bansmission line. Show in column (f) the pole miles of line on structures he cost of whicft is
reported for the line designated; conversely, show in column (g) the pole miles of line on sfuclures he cost of which is reported for another line. Report
pole miles of line on leased or parily owned strucfures in column (g). ln a footnote, oxplain the basis of sucfi occupancy and state whelher exp€nses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION Type of
Supporting
Struclure
(e)
YGTH (Pole miles)'lo he Dase.ofldorofDund Irnes
rcrt Erarit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
OperaUng
(c)
Designed
(d)
un i'trucruresof AnotherLlne
(s)
1 Borah Mldpolnt 345.0(500.00 S To$rer 62.35 1
2 Boardman Slatt 500.0(500.00 S Tower 1.79 1
3 Summer lake Hanlnsway 500.0(500.00 S Tower 0.08 1
4 Hemingway Mldpolnt s00.0(500.00 S Tower 0.15 '1
5 Summer Lake Hemlngway 500.0(s00.00 S Tower 53,08 1
6 Hemingway Mldpoint 500.0(500.00 S Tower 47,76 1
7
I Jim Bridger Godten 345.0(34s.00 S Tower 66.1a 1
9 State Line Midpoint 345.0(345.00 S Tower 76.0€2
't0 Kinport Borah 345.0(345.00 S Tower '19.81 1
11 Jim Bridger 'opulus 345.0(345.00 S Tower 60.93 1
12 Populus Klnport 345.0(345.00 S Tower 7.42 I
13 Jim Bridgar Populus 345.0(345.00 S Tower 61.12 1
14 Populus Borah 345.0(345.00 S Tower 9.05 1
15 Goshen Klnport 345.0(345.00 S Tower 7.48 1
16 Midpoint Borah #1 345.0(34s.00 H Wood 51.07 1
17 Midpoint Borah f2 34s.0(345.00 H Wood 49.98 z.
'18 Adelaide Tap Melaide 345.0(345.00 H Wood 1.72 2
19
20 Quart LaGrande 230.0(230.00 H Wood 45.9i 1
2',1 Midpoint Hunt 230.0(230.00 S Tower 0.70 2
22 Brady Antelope 230.0(230.00 H Wood 56.38 1
23 Brady Treasureton 230.0[230.00 H Wood 0.08 1
24 Brady#1 &#2 Kinport 230.0(230,00 S Towar 17.94 2
25 Brownlee Ontario 230.0(230.00 S fower 72.67 1
26 Mora Bowmont 138.0(230.00 S P Wood 9.98 1
27 Mora Bowmont 138.0(230.00 H Wood 8.75 ,t
28 Caldwell 710 Loorst 230.0c 230.00 SP Sleel 18.49 1
29 Boise Bench Caldwell 230.0c 230.00 S Tower 7.70 1
30 Boise Bench Caldwell 230.0c 230.00 H Wood 33.49 1
31 Boise Bench Cloverdale 230.0c 230.00 S Tower 15.91 2
32 Boardman Dalreed Sub 230.0(230.00 H Wood 1.67 1
33 Brownlee 714 Oxbow 230.0(230.00 SP Steel 11.04 2
34 Caldwell Ontario 230.0(230.00 H Wood 30.06 I
35 Caldwell Ontario 230.0(230.00 S Tower 3.14 1
36 TOTAL 4,769.8!11.02 203
FERC FORil NO. 1 (ED.12-87)Page 422
o3;
rvturgnerated
ldaho Power Company (1)
(2)
An Original
A Resubrnission
Dato of R€port(Mo. Da, Y0
0411u2018
Year/Period of Report
End of 2O17lQ4
7, Do not r€port the same transmission lin€ struclure twice. Report Lower voltage Lines and higher volbge lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of he same voltage, report the
pole miles of the primary sfucture in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any fansmission line or portion hereof for whictr the respondent is not the sole owner. lf sucfr property is leas€d ftom anoher company,
glve name of lessor, date and terms of Leas€. and amount of rent for year. For any transmission line olher than a leased line, or portion lhereof, for
which the respondent is not th6 sole owner but which the respondent operates or shares in he operation of, furnish a succinct sEternent explaining he
arrangement and giung parliculars (details) of such matteGi as peroent ownership by respondent in the line, name of co-orvner, basis of sharing
€xponses of the Line, and how the expenses bome by lhE respondent arc accounM for, and accounts affected. Speciff whether lessor, co-owner, or
other party is an associated company.
9. Designate any tEnsmission line leased to another company and give name of Lesse€, date and torms of lease, annual rent br year, and how
determined. Specify whether lesses is an associated company.
10. Base the plant cost frgures called for in columns (i) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
u(,)s I ()F LlNts (lnduoe rn uorumn u) Lano,
Land rights, and clearing rightd-way)
EXPENSES, EXCEPT DEPRECIATION ANO TAXES
No.
Land
U)
Construction and
Other Costs(k)
Total C.ost
(t)
Operation
='tli"'
Maintenance
Expenses(n)
Rents
(o)
Total
Exo,e;ses
1272 ACSR 256,381 15,976,932 'r6,233,s13 1
2X1780 ACSR 446,708 446,700 2
1272 ACSR 3
1272 ACSR 4
3X1272 ACSR 18,83't,753 1 8,831,753 5
3Xt272 ACSR 17,078,061 '17,078,061 o
1272 ACSR 483,30S 5,302,117 5,785/fr I
/95 ACSR 57't,97€11,223,151 11,795,130 I
r272 ACSR 344,22t,4,397,073 4,741,n3 JO
1272 ACSR 9,530,707 9,530,707 11
1272 ACSR 12
t272 ACSR 9,253,816 9,253,81t 13
t272 ACSR 14
Ix1272 ACSR 583,947 583,94i 15
/,l5.5 ACSR 2S3,1ti 8,551,189 8,834,33i 16
715.5 ACSR 64,851 16,447,655 r6,512,50t 17
715.5 ACSR 51,44i 224,244 275,697 18
19
795 ACSR 62,211 7,010,64:7,072,ffi1 20
715.5 ACSR 9,14!998,45i 1,007,59i 21
1272 ACSR '108,301 3,399,'t2:3,507,424 22
79s ACSR 6,186 6,186 IJ
715.5 ACSR 18,82!1,09't,655 1,110,4U 24
2X954 ACSR 1,676,83[20,541,79C 22,218,628 25
715,5 ACSR 413,79:2,336,84S 2,750.642 26
7'15.5 ACSR 27
ts90 AcsR 2,378,436 8,775,086 11,153,522 28
t272 ACSR 1,748,214 7]22,452 9,470,666 29
/15.5 ACSR 30
1272 ACSR 3,062,81i 6,653,374 9,716,186 3'l
295 AAC 89,089 89,089 32
}54 ACSR u,174 16,026,470 16,060,644 33
2X954 ACSR 236,15'9,384,090 9,620,242 34
t272 ACSR 35
33,039,40i 616,900,179 649,939,586 7,410,221 1,041,35!4,782,UA 13,233,59t 36
FERC FORM NO.1 (ED. 12-87)Page 123
Narne of Respondent
ldaho Power Company
This Reoort ls:(1) 5]en Orisinat
(21 fiA Resubmission
Date of Report(Mo. Da, Yr)
0411u2018
Year/Period of Report
End of 2O17lQ4
TRANSMISSION LINE STATISTICS
1. Report information concrming Eansmission lines, cost of lines, and expenses fur year. List each tansmission line having nominal ,roltage of 132
kilovolb or greater. Report transmission linee below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the delinition of transmission system plant as given in the Uniform System of Accounts. Do not r€port
substatlon msE and expenses on this page.
3. Report data by individual lines for all voltrages if so required by a State commission.
4. Exdude from this page any transmission lines br whictr plant cosb are included in Account 121, Nonutility Property.
5. lndicate whether the type of supporting structure roported in column (e) is: (1) single pole wood or steel; (2) H-fiame wood, or steel poles; (3) tower;
or (4) underground @nskuction lf a transmission line has more than one type of supporting strucfi.rre, inclicato the mileage of each type of construction
by lhe use of brackeB and exfa lines. Minor portions of a transmission line of a diffurent type of construction need not be distlnguished fiom the
remainder of he line.
6. Roport in columns (f) and (g) the total pole miles of each Uansmission line. Show in column (f) the pole miles of line on stuctures the cost of whicfi is
reported for the line designated; conversely, show in column (g) the pole miles of line on struc.tures he cost of which is reported for another llne. Report
pole miles of line on leased or party orvned strucfures in column (g). ln a fooUlote, explain the basis of sucfi occupancy and state whe0rer expenses with
respecl to s{rch slructures are included in he expenses reporled for the line designated,
Line
No.
DESIGNATION Typo of
Supporting
Structure
(e)
Number
of
Cirorits
(h)
From
(a)
To
(b)
OperaIng
(c)
Oesign6d
(d)D"9Ji
JctuTElnerated
I
un Smicluresof 4notherLrne(g)
1 Bennett Mtn PP Rattesnake TS 230.0t 230.00 SP Steel 4.43 1
2 Borah Hunt 230.0(230.00 H Steel 68.12 1
?Danskin Hubbard 230.0(230.00 H Steel 36.25 1
4 Danskin Hubbard 230.0(230.00 SP Sbd 1.U 1
5 Danskin Hubbard 230.0(230.00 SP Steel 1.30 2
6 Danskin Bennott Mtn 230.0(230.00 SP Steel 5.39 I
7 Hemingway Bowmont 230.0(230.00 SP Steel 12.94 1
I Langley Gulch Galloway Rd 138.0(230.00 SP Steel 14,19 I
I Galloway Rd Wllis Tap 138.0[230.00 SP Steel 2.09 I
10 Walla Walla Hurlcanc 230.0c 230.00 H Wood 31.66 1
11 Bclise Bench Midpoint #1 230.0c 230,00 S Tower 0,68 ,|
12 Boise Bench Midpoint #1 230.0c 230.00 HWmd 108.68 1
13 Brownlee QuarE Jct 230.0(230.00 STorer 1.51 1
14 Brownlee QuarE Jct 230.00 230.00 H Wood 41,fl)I
15 Brownlee Boise Bench #1 &#2 230.0(230.00 S Tower 99.76 I
16 Oxbow Brownlee 230.0(230.00 S Toser 10.40 2
17 Boise Benctr Midpoint #2 230.0(230.00 S Tower 3.49 t1
18 Boise Bench Midpoint #2 230.0(230.00 H Wood 102,17 1
19 Oxbow Pallette Jct 230.0(230.00 S Tower 20.11 2
20 Pallette Jc-t lmnaha 230.0(230.00 H Wood 24.42 2
21 Hells Canyon Palefte Jct 230.0(230.00 S Tovver 9.0t 2
22 Brownlee Boise Bench 230.0(230.00 S Tower 102.0€2
23 Boise Benctr Midpoint #3 230.0(230.00 H Wood 106.2!,|
24 Palette Jct Enterprise 230.0(230.00 H Wood 29.6(1
25 Borah Brady{2 230-0(230.00 S Tower 0.42 1
26 Borah Brady#2 230.0(230.00 H Wood 3.52 I
27 Borah Brady #1 230.0(230.00 H Wood 3.84 1
28
29 Goshen Sbte Une 161.0(161.00 H Wood 40.8S 1
30 Don Goshen 161.0(161.00 S Tower 2.37 2
31 Don Goshen 161.0(161.00 H Wood 48.42 2
32 Antelope Goehar 161.0(161.00 H Wood 5.67 1
33 Goshen Slrb Llnc 16'1.0(161.00 H Wood 10.93 1
34 Goshen Strtc Llne 't61.0(161.00 H Wood 7.84 1
35
36 TOTAL 4,769.89 11.02 203
FERC FORI, tlo. 1 (ED.12-87)Page 422.1
LI
t,
{e
'IGTH (Pole miles)ln the Lase.ofrOOrOrOund llnASnrtErorit miles)
,1
ldaho Power Company (1)
(2)
Original
Resubmission
Date ol R€oort
(Mo, Da, Yi)
04t18t2015
Year/Period of Report
End of 2O17lQ4
7. Do not report the same transmission line structurc twice. Report Lower voltage Lines and higher voltage lin€s as ono lino. D€signato in a foohote if
you do not include Lorrer voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structuro in column (f) and the pole miles of lhe oher line(s) in column (g)
8. Designate any fansrnission line or portion thereof for which the respondent is not the sole owner. lf sudr property is leased ftom anofier company,
giv6 name of lessor, date and terms of Lease, and amount of rent for year. For any tranvniesion line other than a leased line, or portion thereol for
which tre respondent is not the sole owner but whicfr lhe respondent operates or shares in tre operalion of, furnish a succinc.t statement explaining he
arangernent and giving particillars (details) of sudr matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses bome by the respondent are accounted for, and accounts affected. Spedfu whether lessor, cr-ownor, or
oher party is an assodbted company.
9. Denignate any bansmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether less€e is an associated company.
10. Base the plant oost figures call€d for in columns O to (l) on he book cost at end of year.
Size of
Conductor
and Mat6rial
(i)
COST OF LINE (lnclude in Column (j) Land,
Land rights, and clearing righhof.way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
0)
Constuc'tion and
Ofter Costs(k)
Total Cost
(t)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Tobl
Exnglses
t272 ACSR 01,701 1,666,351 1,748,055 1
t590 ACSR 624,917 22,467,321 23,092,23A 2
1590 ACSR 15,210,s61 15,210,561 2
1590 ACSR 1
r590 ACSR 5
1590 ACSR 3,s28,033 3,528,033 6
r590 ACSR 1,854,99(9,277,980 1 1,132,976
t590 ACSR 948,16t 9,067,609 10,015,775 8
t272 ACSR 9
1272 ACSR 6,264,553 6.264,553 10
7'15,5 ACSR 38s,28',i 11,912,816 12,298,103 11
7't5.5 ACSR 12
795 ACSR 53,06(4,794,561 4,U7,629 13
795 ACSR 14
VARIOUS 289,93 8,966,987 9,256,921 15
1272 ACSR 14,81(1,273,328 1,288,138 r6
715.5 ACSR 227,82!16,013,02{18,240,849 17
VARIOUS 18
t272 ACSR 87,46t 3,906,027 3,993,495 t9
1272 ACSR 171,081 2,054,803 2,225,881 20
1272 ACSR 44,6E7 1,252,84 1,296,E17 21
954 ACSR 184,81i 6,257,154 6,441,971 22
/15.5 ACSR 247,851 8,037,33'l 8,285,188 23
t272 ACSR 84,01,4 1,903,192 't,987,206 ?4
1272 ACSR 3,06€531,106 s34,174 25
7'15.5 ACSR m
'272
ACSR 7,242 421,273 428,521 27
28
250C@PER 375,57€3,208,82S 3,584,405 29
T15.5 ACSR 88,204 2,544,302 2,632,506 30
397.5 ACSR 31
397.5 ACSR 784,659 784,659 32
250 COPPER 1'18,0s€1,202,360 1,320,418 33
250 COPPER 75,951 190,295 266,246 34
3s
33,039,407 616,900,179 649,939,586 7,410,221 1,041,35€4,782,018 13,233,591 36
FERC FORM NO. r (ED. 12-87)Page 423.1
ldaho Power Company (2)Resubmission
Oate of Report(Mo. Oa, Yr)
04t18120't8
Year/Period of Roport
End of 20171Q4
TRANSMISSION LINE STATISTICS
1. Report information conceming transmission lines, cost of lines. and expenses ior year. List each bansrnission line having nominal wltage of 132
kilovolts or greater. Report transmission lines belor these voltages in group totals only for oach voltage.
2. Transmission llnes include all lines covered by the dellnition of transmlsslon system plant as given ln the Unlform System of Accounts. Do not repo(
substation costs and expense.i on this page.
3. Report data by individual lines br all t/oltages if so required by a State commission.
4. Exclude fuom this page eny transmission lines for which plant costs are included in Account 12'l , Nonutility Property.
5, lndicate whether the type of supporting structrre reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or stod poles; (3) towor;
or (4) underground @nstrucrtion lf a transmission line has more than one type of supporting sfudure, indicate the mileage of each type of construclion
by the use of brackets and exka lines. Minor portions of a transmission line of a differant type of construction need not b€ distinguished fiom the
rernainder of the line.
6. Report in columns (f) and (g) the total pole miles of eadt transmission line. Show in column (0 the pole miles of line on sbuc;tures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of llne on structures the cost of which is reported fur another line. Report
pole miles of lino on leasod or party owned strucfrrres in column (g). ln a footnote, explain th€ basis of such occupancy and state wh€h€r expenses with
respect to sucfi slrucfi.ires are indr.rded in the expeflses reported for the line designated.
Line
No.
DESIGNATION VULIAGE (KV)(lndicata wherebth6r than
60 cvde. 3 ohase)
Type of
Supporting
Structure
(e)
LENGTH (Pole mllesl(ln th€ aa8s.ofundelorouno lrnes
rsport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d):l,'j#ff i.JII StruCtUreSof AnothorLln6(s)
1 American Falls Polrer Plant Adelaide 138.0C 't38.00 H Wood 14.07 2
2 American Falls Power Plant Adelaide '138.0(138.00 S P Wood 0.12 2
3 Minidoka Loop Adelaide 138.0(138.00 S Tmer 1.14 2
4 Nampa Caldwell 138.0C 138.00 S P Wood 9,59 2
5 Upper Salmon Mountiain Home Jct 138.0C 138.00 H Wood 54,36 I
6 Upper Salmon criff 138.0C 138.00 H Wood 30,81 ,1
7 Eastgate Russet 138.0C 138.00 S P Wood 2.06 1
I Brady Fromont 138.0(138,00 S Tower 1.00
9 Brady Fremont 138.0(138.00 H Wood 24.38 I
10 Brady Fremont 138.0(138.00 S P Wood 24.33 I
11 King Lower Malad 138.0('t3E.00 H Wmd u.73 2
12 Emmett Jct Payefte 138.0(138.00 H Wood 66.46 2
13 Mountain Home AFB Tap 138.0(r38.00 H Wood 6.20 1
14 Ontario Quarh 138.0(138.00 H Wood n.m 1
15 King American Falls PP 138.0(138.00 S Tower 0.93 2
't6 King American Falls PP 138.0(138.00 HWod 142.16 1
17 King American Falls PP 138.0(138.00 S P Wood 3.71 I
18 Duffin Clawson 138.0(138.00 H Wood 6.19 1
'19 American Falls Brady Tie r3{,.0(138.00 H Wood 0.3:1
20 Upper Salmon A-B King r38.0(138.00 H Wood 5.6€1
21 Upper Salmon B Wells 138.0('t38.00 H Wood 1 25.54 1
22 King Wood River 138.0(138.00 H Wood 64.13 1
23 Toponis Pocket 130.0(138.00 S Pwood 9,8{1
24 Boise Bench Grove 138.0(138.00 S Pwood '10,37 2
25 QuarE John Day 138,0(138.00 H Wood 67. t:1
26 Sinker Creek Tap 138.0(138.00 H Wood 2.79 1
27 Mora Cloverdale 138.0(138.00 H Wood 2.51 ,l
2A Mora Cloverdale 138.0('t38.00 S PWood 22.28 I
29 Mora Cloverdale 138.0(138.00 S P Sbel 0.9€I
30 Stoddard Jct Stoddard Sub 138.0(138.00 S P Steel 3.80 I
31 Fossil Gulch Tap 138.0(,l38.00 H Wood 1.9€1
32 Wood River Midpoint 138.0('t38.00 H Wood 53.08 2
33 Wood River Midpoint 138.0('138.00 S PWood 16.69
34 Oxbow McCall 138.0(138.00 H Wood 37.15 1
35 Oxbow McCall 138.0(138.00 S P Wood 2.32 1
36 TOTAL 4,769.8S 11,02 203
FERC FORM NO. r (ED. 12-87)Page 422.2
Name of Respondent
ldaho Porer Company
This
(1)
(2)Reeubmlssion
Oats of Report(Mo, Da. Yr)
04t18t2018
Year/Period of Report
End of 2O17lQ4
7. Do not report the same bansmission line structure twice. Report Lower voltage Lines and high€r \roltage lines as one lino. Designate in a foohote if
you do not indude Lower voltage lines with higher voltage lines. lf two or more hansmission line strucfures support lines of the same voltage, report he
pole miles of the primary str.rc-ture in cdumn (0 and the pole miles of the other line(s) in column (g)
8. D*ignate any fansmission llne or portion thereof for whidt the respondent is not the sole owner. lf such property is leased from anolher company,
givo name of lessor, date and terms of Loase, and amount of rent for y6ar. For any transmission llne othsr than a leased line, or portion thereof, for
which the respond€nt is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement explaining lhe
arrang€ment and giving partiqjlars (details) of such matteF as per@nt ownorshlp by respondent in he line, name of oo-orvner, basis o, sharing
expenses of the Line, and how the expenses borne by the rsripondent are accounted 6r, and accounts affeded. Specily whethor lessor, co-o,vner, or
other party is an associated company.
9. Designate any tansmission line leased to another company and give name of Less6€, date and terms of lease, annual rent br year, and how
determined. Specifo whether lessee is an associated oompany.
10. Base the plant cost ffgures called fur in columns O to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
cosT oF LINE (lndude in uotumn 0) Lano,
Land rights, and clearing right-of-way)
EXPENSES. EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
(i)
Constuction and
Oher Costs(k)
Total Cost
(t)
Operaton
Expenses
(m)
Maintenance
Expenses(n)
Rents
(o)
TotalEx6yes
250 COPPER 26,507 415,412 441,919 1
250 COPPER 2
/15.5 ACSR 21,327 249,232 270,559 3
/95 AAC 719,163 3,301,089 4,020,552 4
r95 ACSR 78,07t s,065,961 5,144,039 5
r95 ACSR 43,s6t 3,066,31 1 3,109,879 6
795 AAC 210,823 561,561 832,38,(7
|/ARIOUS 564,93'4,f93,392 5,058,324 I
YARIOUS 9
TARIOUS 10
YARIOUS 76,82:3,735,604 3,8',t2,421 t1
YARIOUS 55,52',3,233,47a 3,288,99€12
]97,5 ACSR 5,00(83,131 88,211 13
/ARIOUS u,421 6,718,46,(6,752,892 14
r1s.5 ACSR 216,91(10,418,013 10,634,962 15
T15.5 ACSR 16
r15.5 ACSR 17
t\0 4,19',467,90S 472J04 18
)54 ACSR 96,921 96,921 19
Z5() COPPER 2,74',753,525 756,666 20
/ARIOUS 28,49 3,541,534 3,570,024 21
/ARIOUS 173,681 26,237,U9 26,410,732 22
197.5 ACSR 23
/ARIOUS 225,60i 1,648,079 1,873,681 24
397.5 ACSR 96,58'2,554,371 2,650,956 25
/ARIOUS 11,08:133,317 144,430 26
r15.5 ACSR 3,1 23,38(8,875,271 1 1,998,651 27
/ARIOUS n
r9sAAC 29
t272 ACSR 30
I5O COPPER 4s(187,848 188,298 31
,97,5 ACSR 349,712 7,122,8W 7,472,611 32
,97.s ACSR 33
t97.s ACSR 141,534 2,715,214 2,086,748 34
397.s ACSR 35
33,039,407 6'16,900,179 649,939,586 7,410,221 1,041,358 4,782,018 13,233,59?36
FERC FORM NO. 1 (ED. 12.87)Page 423.2
Name of Respondent
ldaho Power Company (2')A Resubmission
Date of Report(Mo, Da, Yr)
0/,I1812018
Year/Period of Report
End of 20171Q4
TRANSMISSION LINE STATISTICS
'1. Report information conceming transmission lines, cost of lines, and expenses for year. List €ach transmission line having nominal voltage of 132
kilovolts or great6r. Report transrnission lines below these voltages in group totals only for each voltage.
2. Transmission lines indude all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on his page.
3. Report data by individual lines br all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant oosts are induded in Account 121, Nonutility Prop6rty.
5. lndicate whether the type of supporting sbucture reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground constuclion lf a transmission line has more than one type of supporting structure, indicate the mileage of each type of construclion
by the use of brackeb and exka lines. Minor poriions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (0 and (g) the total pole miles of each transmission line. Show in column (0 the pole miles of line on structures the cost of whictr is
reported br the line designated; conversely, sttow in column (g) the pole miles of line on strucfures ttre cost of which is reported for another line. Report
pole miles of line on leasod or pardy owned structures in column (g). ln a footnote, explain the basis of suctt occupancy and state whether expenses with
respect to suclr structures are included in the expenses reported lor the line designated.
Line
No.
DESIGNATION Type of
Suppoilng
Strucfure
(e)
LENGTH (Pole miles)(ln the aase.ofu,ldaforound llnesreport flrcuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
L'N DIolDesl
tclure
nerated
UN SITSUTASof AnoherLine
{s)
1 Lowell Jct Nampa 138.0('138,00 S P Wood 7.50 2
2 Hunt Milner 138.0(138,00 S P Wood 19.42 1
3 Strike Bruneau Bridge 138,0(138,00 H Wood 13.49 1
4 American Falls Kramer Sub 138.0(138.00 S P Wood 18.46 2
5 Pingree Haven 138.0(138.00 S P Wood 11.72 1
6 Midpoint Twin Falls 138.0(138.00 S P Wood 25.2C 2
7 Twin Falls Russett 138.0(138.00 S P Wood 1.71 1
I Blackfoot Aiken 46.0(138.00 S P Wood 6.22 2
9 Peterson Tendoy 69.0(138.00 H Wood 57.02 I
10 Eastgate Tap Eastgate 138.0('t38.00 S P Wood 6.36 1
11 Kimberly Tap Kimberly 138.0('t38.00 S P Steel 1.84 2
12 Boise Bench Mora 138.0(138,00 H Wood 13.1 1 2
13 Bowmont-Caldwell Smplot Sub '138.0(138,00 S P Wood 0.51 ,|
14 Gary Lane Eagle 138.0(138,00 S P Wood 6.66 1
15 Locusl Grove Blackcat Sub 138.0(138 00 S P Steel 9.25 2.98 I
16 Boise Bench Butler 138,0(138.00 S P Wood 0.14 4.02 1
17 Eagle Sbr r38.0(r38.00 S P Wood 6.72 1
18 Karcher Sub Zilog Tap 138,0(138.00 S P Steel 3.59 1
19 Clovsrdale - 7'12 712-!{vy.e 138.0C r38.00 S P Steel 0.42 4.02 1
20 Mctory Jct Victory 138.0C 1 38.00 S P Steel 1.09 1
21 BuUer vwe 138.0C 138.00 S P Steel 2.94 1
22 Horseflat Starkey 138.0[138.00 H Wood 33.97 1
23 Starkey Mccall 138.0C 138.00 S P Steel 2.23 I
24 Starkey Mccall 138.0(138.00 H Wood 3.80 1
25 Starkey Mccall 138.0C 138.00 S P Steel 1.50 I
26 Starkey Mccall 138.0(138.00 S P Wood 17.61 1
27 Chestnut Happy Valley 138.0C 13E.00 S P Steel 2.78 1
28 Garnet Ward 138.00
29 McCall Lake Fork 138.q 138.00 S P Wood 8.89 I
30 McGall Lake Fork 138.0(138.00 S Steol 2.90
31 Caldwell Wllis 138.0{138.00 S P Ste€l 1.30 1
32 Caldwell Wllis 138.fr 138.00 S P Sted 1.59 1
33 Caldwell Wllis 138.0(138.00 S P Wood 0.87 ,l
34 Valivue Tap 138.0(138,00 S P Steel 0.79 2
35 Bowmont Happy Valley 138.0(138,00 S P Steel 8,65 1
36 TOTAL 4,769,8!11,02 203
FERC FORITI NO. I (ED. 12-87)Page 422.3
ldaho Power Company (1)
(2)A Resubmission
Oate of Roport(Mo, Da, Yr)
0411u2018
Year/Period of Report
End of 20171Q4
7. Do not report the same bansmission line strucfure twica, Report Lower voltage Lin€s and higher voltrage lines as one line. Designat€ in a foohote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line strucfures support lines of the same voltage, report the
pole mlles of the primary sbuc'ture in column (f) and the pole miles of the oher line(s) in column (g)
8. Designate any transmission llne or porton lhereof for whidr the respondent is not the sole owner. lf such property is leased from another company,
give name of lessor, datB and terms of Lease, and amount of rent br year. For any transmission llne other ftan a leased line, or portion lhereof, for
whidr the respond*rt is not the sole owner but which the respondent operetes or shares in the operation of furnish a succinct stat€ment explaining the
anang€ment and giving particulaG (details) of such mattens as percent ownership by respondent in he line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses bome by he respondent ar€ accounted for, and accounts affected. Spectfo whether lessor, co-owner, or
othsr party is an associated company.
9. Designate any tansmission line leased to another company and give name of Lessee, date and brms of lease, annual rent br year, and how
determined. Spedfo whether lessee is an associatd @mpany.
10. Base he plant cost figures called for in columns 0) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
GUSl OF LrNt (rnduoe rn uorumn u) Lano,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
No.
Land
0)
Construc{ion and
Other Costs(k)
Total Cost
0)
Operation
Expenses(m)
Maintenanca
Exgenses(n)
Rents
(o)
Total
Expenses
/15.5 ACSR 211,131 1,454,87!1,666,010 1
/15.5 ACSR 3,32A 1,457,336 1,460/m 2
!97.5 ACSR 14,921 7'.t|,454 725,381 3
r15.5 ACSR 13,734 1,072,2U 1,086,028 4
,97.5 ACSR 18,223 1.281,344 1,299,567 5
/ARIOUS 66,28(3,2U,778 3,351,061 6
115.5 ACSR 16,79(213,033 n9,823 7
115.5 ACSR 13,6r6 s29,756 543.372 8
t97.5 ACSR 395,696 3,504,326 3,900,022 I
715.5 ACSR 343,953 2jU,427 2,528,362 10
795 ACSR 11
715.5 ACSR 14,697 736,867 751,564 12
795 AAC 50,31S 50,31!13
/95 AAC 308,14',2,'t65,954 2,474,095 l4
1272 ACSR 935,8'1(3,444,679 4,380,48!15
,272 ACSR v,68;838,605 873,29i 16
T15.5 ACSR 179,811 2,932,783 3,112,60(17
I95 AAC 43,031 434,y1 477.371 18
1 272 ACSR 140,41i 2,5np75 2,717,481 19
1 272 ACSR 20
/95 ACSR 1y,171 1,40s,436 1,539,907 21
115.5 ACSR 2,473,83i 18,903,593 2't,377,42 22
115.5 ACSR 23
TI5.5 ACSR 24
r1s.5 ACSR 25
r15.5 ACSR 26
t272 ACSR 78,57!2,219,508 2,n8,081 27
40,58t 40,580 28
/15.5 ACSR 331,53!4,682,87S 5,014,418 29
30
t272 ACSR 272,231 2,141,2'.t8 2,413,44S 31
I95 ACSR 32
I95 ACSR J5
I95 ACSR 351,49i 351,497 34
ACSR 691,728 6,045,286 6,737,014 35
33,039,407 616,900,179 649,939,s86 7,410,221 1,04't,358 4,782,018 r3,233,59i 36
FERC FORM t{O.1 (EO.12-87}Page 421.3
ldaho Power Company (1)
(2)
An Original
A Rosubmission 04t18t2018
Year/Poriod of Report
Enct of 2O17lQ4
TRANSMISSION LINE STATISTICS
1. Report information conceming transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines indude all lines covered by the definition of lransrnission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on his page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any kansmission lines for whidt plant costs are included in Account 121, Nonutility Property,
5. lndicate whether the type of supporting structure reporled in column (e) is: (1) single pole wood or steel: (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction lf a transmission line has more than one type of supporting structure, indicate the mileage of each type of construdion
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construc{ion need not be distinguished ftom the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (0 the pole miles of line on structures the cost of which is
reported for tre line designated; conversely, sltow in column (g) the pole miles of line on strucfures he cost of which is reported for another line. Report
pole miles of line on leased or pardy own6d skuctures in column (g). ln a footnote, explain the basis of sncfr occ,upancy and state whether expenses wilh
resp€ct to such structures are included in lhe expenses reported ficr the line designated.
Line
No.
DESIGNATION Type of
Supporting
Struc'ture
(e)
LENGTH (Pole miles)(lB the aase.otund€mround lln6sreportEranlt miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operatng
(c)
Designed
(d)
un ilofDesi
rqure
inelal€d
I
\Jn ulruguresof ttoth€r(s)
1 Antelope Sotfl€138.0(138.00 H Wood 0.12 1
2 American Falls [at/h.don 138.0(138.00 H Wood 1.05 1
3 Kinport Don #1 138.0(138.00 S Torer 1.27 2
4 Donn HOKU 138.0C 138.00 S P Steel 2.69 1
5 HOKU Alamed 138.0C 138,00 S P Steel 0.22 2
6 HOKU Alamed 138.0C '138.00 S P Steel 0.23 I
7 HOKU Alamed 138.fr '138.00 S P Steel 2.85 ,t
I Rockland Jct Rockland Wind Farm 138.0(138.m S P Steel 5,18 I
I King Justice 138.0(138.m S P Wood 0.07 1
't0 NorthView Tap 138.0(138.00 S P Wood 6.17 1
11 Twin Falls PP Tap 't38.0(138.00 H Wood 0.99 1
12 American Falls PP Amercian Falls Trans ST 138.0(138.00 S P Sted 0.38 1
13 Lower Salmon King Tie 138.0(138.m H Wood 0.11 1
14 C J Strike Strike Jct 138.0(138.00 S Torer 4.30 2
15 Sfike Jct Mountrain Home Jct 138.0(138.00 H Wood 23.42 I
16 Sfike Jct Bowmont 138.00 H Wood 0,05 1
17 Strike Jct Bowmont 138.0(138.00 S Tower 0.36 ,1
18 Strike Jct Bowmont 138.0(138.00 H Wood 67.87 I
19 Lucky Peak Lucky Peak Jct 138.0(138.00 H Wood 4.4t 2
20 Bliss King 138.0(138.00 H Wood 10.41 1
21 Milner Deadend Milner PP 138.0(138.00 S P Wood 1.3C I
22 Swan Falls Tap 138.0(138.00 H Wood 0.95 1
23
24
25
26 Hines BPA (Hamey)115.0(1'15.00 H Wood 3.35 1
27
28
29 69 Kv Lines 69.0(69.00 H Wood 210.65 1
30 69 Kv Lines 69.0(69.00 S P Wood 880.6i I
31
32
33 46 Kv Lines 46,0(46.00 S P Wood 396.08 1
34
35 Total all lines 4,769.8!11.02 203
36 TOTAL 4,769.89 11.02 203
FERC FORM NO. 1 (ED.12-87)Page 422.4
ldaho Power Company (2)A Resubmission
Date of Reoort(Mo, Da. Yi)
0/.I18t2018
Year/Period of Report
End of 2O'l7lQ4
7. Do not report the same bansmission line sbucfure twice. Report Lorver voltage Lines and higher voltage lines as one line. Designate in a boUlote if
llou do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structres support lines of the same voltage, report the
pole miles of the primary structurs in column (f) and the pole miles of tha other line{s) in column (g)
8. Designate any bansmission line or porton thereof for which the respondent is not the solo owner. lf such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for ye8r. For any transmission line other than a leased line, or portion thereol frcr
which the respondent is not tho sole owner but which he respondent oporates or shares in fie operation of, fumish a succinct statement explaining the
arang€m€nt and giving particulars (detrails) of such mattsrs as porcent ownertrhip by respondent in he line, name of co-oirner, baCs of sharing
expenses of the Line, and how the expenses bome by he respondent are accounted for, and accounts affectod. Specify wheher lessor, @-owner, or
other party is an associated company.
9. Designate any bansmission line leased to another company and give name of Less€e, date and terns of lease, annual rent for year. and how
determlned. Specify whether lessee ls an associated company.
10. Base the plant cost ligures called for in columns (i) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
cusl oF LlNts (lncluoe rn uolumn u) Lano,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
No.
Land
0)
Constuction and
Other Costs(k)
Totral Cost
(t)
Operation
Expenses
(m)
Maintenance
Expenses(n)
Rents
(o)
Total
ExnTlses
397.5 ACSR 71,018 71,018 1
250 COPPER $5,721 105,721 2
715.5 ACSR 1,174 206,258 n7,4X2 3
1272 ACSR 19C 4,59{4,784 4
r272 ACSR 5
795 ACSR 6
/95 ACSR 7
T95 ACSR -'16,973 -16,973 8
1590 ACSR 60,659 60,65 o
/15.5 ACSR 105,93:4,'t25,054 4,230,98i 10
2s0 0@PER 5t 63,264 63,322 11
I.I5.5 ACSR 176,736 't76,736 12
197.5 ACSR 4,106 4,406 13
r15.5 ACSR 1,074 636,545 637,61S 14
!97.5 ACSR 6,332 2,566,261 2,s72,593 't5
/15.5 ACSR 86,651 3,956,640 4,043,291 16
r15.5 ACSR 17
18
7't5.5 ACSR 1 285,10(285,1 13 19
715.5 ACSR 5,62t 1,387 ,171 1,392,791 20
7'15.5 ACSR 14,968 183,60f 198,574 2t
397.5 ACSR 17,207 261,512 278,719 22
23
24
25
397.5 ACSR 1,978 63,40{65,382 26
27
28
YARIOUS 1,782,s3t 76,422.96Q 78,205,198 n
YARIOUS 30
31
32
YARIOUS '194,53(19,387,660 19,582,196 33
7,410,221 1,041,358 4,782,018 13,233,597 u
33,039,40'616,900,173 649,939,586 7,4',t0,221 1,041,358 4,782,018 13,233,59i 35
33,039,407 616,900,179 649,939,586 7,410,221 1,041,358 4,782,018 ,3,233,59;36
FERC FORM NO. I (ED. t2-87)Pag€ 123.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1812018
Year/Period of Report
2017tO4
FOOTNOTE OATA
Schedule Page:122 Line No.:1Thj-s line is jointly owneC
11ne.
Schedule Page:122 Line No.:2This line is jointly ownedr.his 17. B mil-e line.
Schgdule Page:122 Line No.:3This J-ine is jointly ownedline.
Schedule Page:122 Line No.:4Thls l-ine is jointly owned
Column: bwitn paCifi-orp and Idaho Power owns 73.23 of this 85.4 mile
Column: bwitfr iortfind General Electric and Idaho Power owns l-0.08 of
Column: b
with PacifrCorp and Idaho Power owns 22.08 of Lh,Ls 241.3 mile
Column: bwiLh PacifrCorp and Idaho Power owns 37.0t of this 129.3 miLeIine.
Schdule Page: 422 Line No.: 5 Column: b
This line i-s jointly owned with PacifiCorp and
,l-ine .
Schedule Page:422 Line No.:6 Cotumn: bThis line is jointly owned with PacifiCorp and1ine.
Sclredule Page:122 Line No.:8 Gotumn: b?his line is jointly owned with PacifiCorp andline.
Schedule Page:122 Line No-:10 Column: bThis fine is jo-int1y owned with PacifiCorp and1ine.
Sehedule Page:422 Line No.: 11 Column: bThis li-ne j-s jol-ntly owned with Pacif iCorp and
approxrmately 193 mj-l-e 1ine.
Schedule Page:122 Ltne No.:12 Column: bThis line is jointly owned w-ith PacifiCorp andIi-ne.
Schedute Page:122 Line No.:13 Column: bThis l-ine is jointly cwned with PacifiCorp and
apprcximal-eLy 193 mil-e Line.
Scftedule Page:122 Line No.:11 Column: b
Thj"s line is jointly owned with PacifiCorp and
Schedule Page:122 Line No.:15 Cotumn: bThis line is jointly owned with PacifiCorp and
l-ine.
Schedute Page: 122 Line No.:16 Column: bThis line is jointly owned with PacifiCorp and
Schedule Page:122 Line No.: 17 Column: bThis line is jorntly owned with PaeifiCorp andline.
Schedute Page:422 Line No.:18 Column: bThis ]ine is lol-ntiy owned with PacifiCorp andline.
Idaho
idalio
'fa;ho
-rarho
-ra;ho
rdaho
ra;ho
rd;ho
f aarro
fdaho
Idaho
Idaho
Power
Power
POWET
Power
Fo;ei
Power
Power
Power
Powei
Power
Power
Power
owns
owns
owns
owns
owns
owns
owns
owni
owns
owns
owns
owns
) ) .jo-
3"1 . Oea
29 .2\
29 .22
29 .22
29.22
29.22
18.3?
Ozt-4-o
64 .4s.
64 .42
oi"tnli-'2{i 3 rllts"
of .'rhls"-iz9 :'3-mila
of this 226.5 nile
of this 27.1 mile
of this
of thls 4L.2 mile
or [nis
of thi-s 47.3 mile
of this 40.9 mile
of thls 79.5 mile
of this 0.9 mile
Schedule Page:122 Line No.:32 Column: bThis line is 1oj-ntly owned with Portland Generai- Electric and Idaho Power owns 10.0% ofthis 16.7 mile Iine.
Schedule Page:122.1 Line No.:10 Cotumn: bThis line is jointly owned wich PacifiCorp and Idaho Power owns 40.8? of this 77.6 mileline.
Schedute Page: 422.1 Line No.:29 Column: b
FERC FORM NO.1(ED. 12-871 Page 450.1
Name of Respondent
ldaho Power Company
This Report is:
(1)XAn Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
0411u2018
Year/Period of Report
2017tQ4
FOOTNOTE DATA
This line is jointly owned with Pacj-fiCorp. Idaho Power owns 37.88 of Goshen- Jefferson28.9 mile segment, 37.8t of the Jefferson- Big Grassy 20.8 mile segment and 1008 of theBiGras s State Line 40.9 mile se
o t v ower owns eIine.
s o t v with PacifiCorp. Idaho Power owns erson28.9 mile segment, 37.88 of the Jefferson- Big Grassy 20.8 mile segment and 100? of the
B Grass State Line 40.9 mile s t
S ne o t v Power owns Je erson28.9 mile segment, 37.89 of the Jefferson- Big Grassy 20.8 mj-Ie segment and 100? of the
Grass State Line 40.9 mile t
Line I Column: bslslIy owned w th Pac f Corp and Idaho Power owns 1l-.5t of 1 le line
sI trv t Pac I Power owns 7.a mile
Iine.
122.1 Line
33 Column: b
422.1 Line No.:b
122.4 Llne No.: 2 Column: b
FERC FORM NO.1 1 Page 450.2I
Name of Respondent
ldaho Power Company (z',)Resubmission
Date of Reoort(Mo. Da, Yi)
04t'tu2018
Year/Period of Report
End of 2A17lQ4
TRANSMISSION LINES ADDED DURING YEAR
1. Report below the information callod for conceming Transrnission llnes added or alter€d during the yoar. lt is not necessary to report
minor revisions of lines.
2. Provide s€parat€ subheadings for overhead and under- ground construction and show each transmission line separately. lf actual
costs of competed construction are not raadily available for reporting columns (l) to (o), it is permissible to report in these columns the
Line
No.
LINE DESIGNAIION LtnoLength
tn
Miles
(c)
SUPP(,RTING I CIRCUITS PER STRUCTUR
From
(a)
To
(b)
Type
(d)
,\veraoeNumbeiper
Miles
(e)
Present
(0
Ultimate
(g)
1 No nelr lines br 2017
2
3
4
5
6
7
I
s
1C
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL
FERC FORI/I NO.1 (REV. r2-03)Page 421
ldaho Power Company An Original
A Resubmission 04t1u2018
Year/Period of Report
End of 20171Q1.
costs. D€signate, however, if estimated amounts are reported. lnclude costs of Clearing Land and Rlghts-of-Way, and Roads and
Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
3. lf design voltage differs from operating voltage, indicate such hct by footnote; also where line is other than 60 cycl6, 3 phase,
indicate such other characteristic.
u(JNUU(; | (Jr{l'VolEge
KV
(ope63ung)
LINE GOS]Line
No.Size
(h)
Specification
(i)
Confiouralionand Spacing
U)
Land and
Land,Rights
Poles, Towers
and Fixfures(m)
Conductors
and Devices(n)
Asset
Retire. Costs(o)
Total
(o)
1
2
3
4
5
6
7
I
I
10
11
't2
13
14
15
16
't7
18
't9
20
21
22
23
24
25
2a
27
28
29
30
3',!
32
JJ
34
35
36
37
38
39
40
41
42
43
44
FERC FORM }{O.1 (REV. 12-03]Page 425
I his
(1)
(2)
Name of Reepondenl
ldaho Porer Company (1)
{2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
04118t2018
Year/Period of Report
End of 2O17lQ4
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or str€et railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those seMng customers with energy for resale, may be grouped according
to functional character, but the number of such substatons must be shown.4. lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (0.
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
I Adelaldc bansmission 138.00 13.80
2 Aiken diskibution 46.00 13.00
3 Alameda distribution 't3.00
4 Alameda distribution 13.0S
5 American Falls PP - attended transmission 13.80
6 American Falls transmission 138.00 46.00 12-47
7 Andopc tansmission 230.00 161.00 13,80
8 Artesian distribuUon 13.00
9 Bannock Creek dislribution 46.0C 13.00
10 Bennett Mountain Power Plant- attended transmission 230.0c 18.00
11 Bennett Mounliain Power Plant- attended distribution 18.00 4.16
't2 Bethel Court distribution 't38.00 13.00
13 8lg Grassy bansmission 161.00
14 Black Cat distribution 138.00 13.09
15 Blackfoot distribuUon 13.00
16 Blackfoot transmission 161 46.00 12.47
17 Blackfoot distribution 161 138.00 12.98
18 Bllss - attended transmission 138.00 13.80
19 Blue Gulch distribution 1 35.00
20 Boise Bench transrnission 230.00 138.00 13.20
21 Boise Bench distribution 138.00 35.00
22 Boise Bench transmission 138.0C 69.00 12.S8
23 Boise Bench transmission 230.00 138.00 13.80
24 Boise Bench distribution 35.00 13.00
25 Boise distribution 138.00 13.00
26 Borah lfansrnission 345.00 230.00 13.80
27 Border distribution 138.00 13.00
28 Border diskibution 3s.00
29 Bowmont distribution 69.00 46.00 6.90
30 Bowmont distribution 138.00 35.00
31 Bowmont bansmission 138.00 69.00 12.98
32 Bowmont hansmission 69.00 12.47
33 Bowmont fansrnission 138.00 13.80
34 Brady fansmission 230.00 138.00 13.80
35 Brady transmission 46.00 12.47
36 Brady distribution 13.00
37 Brownlee - attended bansmission 13.80
38 Bruneau Bridge distribution 138.00 35.00
39 Bruneau Bridge distribution 138.00 36.20
40 Buckhom distribution 69.00 3s.00
FERC FORM r{O.1 (EO. 12.90)Page 426
345.01
138.0r
138.0r
138.0r
46.0(
46.01
138.0(
230.0(
138.q
46.(x
230.0r
ldaho Power Company (1)
(2)Resubmission
Date of Report(Mo. Da, Yr)
04t1u2018
Year/Period of Report
End of 2O17lQ4
5. Show in columns (l), fi), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated othenflise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and slate amounts and accounts
affected in respondent's books of account. SpecifiT in each case whether lessor, co-owner, or other par$ is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(f)
Number of
Transbrmers
ln SeMce
b)
Number of
Spare
Transfrrrmers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
fi)
Total Capacity
(ln MVa)
(k)
2 1
27 2 2
30 1 3
30 1 4
120 I 5
47 1 6
250 1 7
14 1 8
14 1 I
225 1 10
5 1 11
2A I 12
13
90 2 14
56 2 15
93 3 1 16
135 I 17
86 3 18
48 2 19
448 2 20
70 2 2',!
125 3 22
448 2 23
1 24
117 3 25
750 3 ,|26
11 1 27
5 3 28
8 3 29
30 1 30
46 1 31
47 1 32
600 2 33
312 3 34
1 35
28 't 4 36
752 5 I 37
30 1 38
45 1 39
37 1 40
FERC FORM NO. r (ED.12-0€)Page 427
50(
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4t18t2018
Year/Period of Report
End of 2O17lQ4
SUBSTATIONS
1 . Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrlal or sheet railway customer should not be listed below.
3. Substations with capacities of Less ftan 10 MVa except those serving customers with energy for resale, may be grouped accoding
to functional character, but the number of such substations must be shown.
4. lndicate in column (b) the functional character of each substation, des(Tnating whether transmission or distibution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individua! stations in
column (f).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tert!ary
(e)
I Bucyrus distribution 46.00 7.20
2 Buhl distribution 46.00 13.20
3 Burley Rural distribution 69.00 13.00
4 Bufler distribution 138.00 13.09
5 Caldwell distribution 138.00 13.00
6 Caldwell ttansmission 230.00 138.00
7 Caldwell distribution 138.00 13.09
8 Caldwell transmission 138.00 69.00 12.47
I Caldwell transmission 230.00 138.00 12.47
10 Camas distribution 35.00
11 Camas distribution 35.00 14.40
12 Canyon Creek distribution 138.00 36.20
13 Canyon Creek transrnission 138.0C 69.00 't2.98
14 Cartwright distribution 138.0C 13.00
15 Cascade Power Plant - attended transmission 69.00 4.60
16 Cascade diskibution 6S.00 13.00
17 Cascade distribution 69.00 13.10
18 Cascade distribution 25.00
't9 Chestnut distribution 138.00 13.00
20 Chestnut distribution 138.00 13.0€
2'l Clnder distribution 46.00 13.00
22 Clear Lake - attended tansmission 46.00 2.40
23 criff transmission 138.00 46.00 12.50
24 criff transmission 138.00 46.00 12.95
25 Cloverdale distribution 138.00 13.00
26 Cloverdale distribution 138.00 13.09
27 Council distribution 69.00 13.00
28 Crane Creek distribution 69.00 13.00
29 Crater distribution 46-00 13.00
30 Dale distribution 46.00 4.60
31 Dale distribution 46.00 13.00
32 Dale distribution 69.0C 13.00
33 Dale distribution 138.0C 36.20
34 Dale transmission 138.0C 46.00 12.47
35 Oanskin- attended transmission 230.00 18.00
36 Oanskin- attended transmission 230.00 138.00 13.80
37 Danskin- attend€d distibution 18.00 4.16
38 Danskin- attended transmlssion 138.00 12.00
39 Danskin- attended distribution 35.00 1 3.80
40 Deen distributon 46.00 13.00
FERC FORM NO. 1 (ED.12-901 Page 426.1
Name of Respondent
ldaho Power Company (1)
(2)
Original
Resubmission
Dale oI RoDort(Mo, Da, Yi)
04t1812018
Year/Period of Report
End of 2i17lq4
5. Show in columns (l), (j), and (k) special equipment such as rotary convertenr, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate subslations or major items of equipment leased from others, jointly owned with others, or operated othenrise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or eguipment operated other than by reason of sole ovvnership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and s(ate amounts and accounts
affected in respondent's books of account. Speciry in each case whether lessor, co-owner, or other pafl is an associated company.
Capacity of Substalion
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transfuiners
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
U)
Total Capacity
(ln MVa)(k)
7 1 1 1
1 2
20 I 3
90 2 4
28 1 5
200 1 6
45 1 7
140 I 6
200 1 I
5 3 1 10
't0 3 I 11
45 1 12
20 1 13
11 1 14
16 1 15
7 1 16
14 1 17
5 ,|18
45 I 19
45 1 zo
't1 1 21
5 1 22
21 2 1 23
10 1 24
45 1 25
45 1 to
14 1 27
11 1 2E
11 1 29
1 30
7 31
1 32
45 1 33
47 1 v
233 1 35
300 1 36
6 1 37
'160 2 38
5 1 39
11 1 40
FERC FORM ilO.1 (ED. 12.90)Page 427.1
Name of Respondent
ldaho Power Company (1)
(2)A Resubmission
Date of Reoort(Mo, Da, Yi)
04118t2018
YeariPeriod of Report
End of 20171Q4
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customerc with energy for resale, may be grouped according
to functional character. but the numbor of such substations must be shown.
4. lndicate in column (b) the functional character of each substation, designating whether hansmission or distribution and whether
aftended or unattended. At the end of the page, summarize according to function the capacities reported for the individual statlons in
column (f).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Dietricfi distribution 46.00 13.00
2 Don distribution 1 7.60
3 Don distribution 138.00 13"20
4 Don distribution 138-00 't 3.00
5 DRAM disfibution 138.00 13.0S
6 DRAM kansmission 138.00 13.80
7 DRAM distribution 138.00 12.47
8 DRAM distribution 138.00 13.00
I Duffin distribution 138.00 35.00
10 Eagle distribution 138.00 13.09
11 Eastgate distribution '138.00
12 Eastgate diskibuUon 138.00 13.00
13 Eckert distribution 138.00 36.20
14 Eden distribution 138.00 36.20
15 Eden transmission 138.00 46.00 12.98
16 Elkhom distribution 138.00 12.47
17 Elkhom distribution 138.00 13.00
18 EImore distilbution 138.00 35.00
19 Elmore fansmission 138.00 69.00 12.50
20 Elmore transmission 138.00 69.00 12.98
21 Emmett distribution 138.00
22 Emmett bansmission 138.00 69.00 12.47
23 Falls dishibution 46.0C 13_00
24 Filer distribution 46.0C 13.00
25 Flat Top distribution 46.00 13.00
26 Flying H distribution 69.00 2.40
27 Fort Hall distribution 46.00 13.00
28 Fossil Gulctr distribution 138.00 35.00
29 Fremont lIansmission 138.00 46.00 12.50
30 Gary distribution 138.00 13.09
31 Gary dislribution 138.00 13.00
32 Gem distribution 69.00 13.00
33 Gem distribution 69.00
34 Glenns Ferry distribution 138.00 13.00
35 Gooding Rural distribution 46.00 13.00
36 Golden Valley distribution 69.00 13.00
37 C{8h€o tansmission 345.00 161.00 69.00
38 Gowen Substation distribution 138.00 3s.00
39 Grindstone distribution 35.00
40 Grindstone distribution 35.00 2.40
FERC FORM NO. I (ED. 12-96)Page 426.2
230.0(
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o4t1u2018
Year/P€riod of Report
End of 20171Q4
5. Show in columns (l), (j), and (k) special equipment such as rotary convarters, rectifiers, condenseni, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased ftom other, jointly owned with others, or operated otherwise than by
reason of sole ownership by the rcspondent. For any substation or equipment opeEted under lease, give name of lessor, date and
period of lease, and annual ront. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or o[rer accounting between the parties, and state amounts and accounts
affected in respondenfs books of account. Specifi in each case whether lessor, co-owner, or other parg is an associated company.
Capacity of Substauon
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(q)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total CapaciV
(ln MVa)ft)
't1 1 1
1 2
180 6 1 3
44 1 4
168 6 5
212 2 6
28 1 7
28 1 I
60 2 o
67 2 10
45 1 11
30 1 't2
30 1 't3
45 I 14
20 ,|15
11 1 16
11 ,,17
28 1 18
25 1 19
20 1 20
45 1 21
47 1 22
28 2 23
14 1 24
17 2 25
20 2 26
14 1 1 27
28 1 28
67 3 1 29
37 1 30
28 1 31
I 1 32
14 ,|33
11 I 34
20 2 35
14 1 ,|36
908 4 37
45 1 3E
7 I 39
7 1 40
FERC FORfti r,ro. 1 (EO, 12-96)Page 127.2
ldaho Power Company (1)
(2)
Original
Resrbmission
Dat6 of Roport(Mo. Da, Yr)
04118120'.t8
Year/Period of Report
End of 2O17lQ4
SUBSTATIONS
1. Report below the information called fior conceming suhtations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those seMng customers witfi energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate in column (b) the tunctional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (Q.
Line
No.Name and Location of Substation
(a)
Character of Subshtion
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Grove distribution 138.0C 13.0S
2 Grove distribution 138.00 13.00
3 Hagerman distribution 46.00 13.00
4 Hagerman distribution 69.00 13.00
5 Hailey distribution 138.00 13.00
o Happy Valley distribution 138.00 13.0S
7 Haven distribution 138.00 35.00
8 bansmission 138.00 46.00
I tlemlnguay fansrnission s00.00 230.00 34.50
10 Hewlett Pad<ard distribution 138.00 13.00
1'l Hidden Springs distribution 138.00 13.00
12 Highland distribution 138.00 13.00
13 Hiil distribution 't38.00 13.00
'14 Hillsdale distribution 138.00
'15 Homedale diskibution 69.00 13.00
'16 Horse Flat bansrnission 230.00 138.00 13.80
17 Horseshoe Bend distribution 35.00
18 Horseshoe Bend distribution 69.00 36.20
19 Horseshoe Bend distribuUon 69.00 25.00
20 Huston distribution 69.0C 13.00
21 Hulen distribution .t6.0C 13.00
22 Hunt transmission 230.0c 138.00 13.80
23 Hydra distribution 138.00 36.20
24 lsland distribution 69.00 13.00
25 Jeftrron bansmission 161.00
26 Jerome distribution 138.00 13.00
27 Jerome distribution 138.00 't3.09
28 Julion Clawson distribulion 138.00 35.00
29 Joplin distribution 138.00 13.00
30 Joplin distribuUon 138.00 35.00
31 Justice transmission 230.00 138.00 13.80
32 Karch€r distribution 138.00 13.00
33 Kenyon distribution 69.00 13.00
34 Ketchum distribution 138.00 13.00
35 Kimberly distribution 138.00 13.09
36 Kinport transmission 161.00 46.00 13.20
37 Kinport transmission 230.00 138.00 12.47
38 Kinport bansmission 230.00 138.00 13.80
39 KInpott tansmission 345.00 230.00 13.80
40 Kramer distribution 138.0C 35.00
FERC FORM NO.1 (ED.12-96)Page 426.3
Haven
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Roport(Mo. Da, Y0
04t1u2018
Year/Period o, Report
Endof 20171Q4.
SUBI
5. Show in columns (l), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate zubstations or major items of equipment leased from others, i:intly owned with others, or operated otherwise than by
reason of sole ownership by he respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other pa(y, explain basis of sharing expenses or other accounting between the parties, and Sate amounts and accounts
afiected in respondent's books of account Speciff in each case whether lessor, co-orner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS ANO SPECIAL EQUIPMENT Line
No,Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)ft)
90 2 1
45 1 2
14 1 3
6 1 4
37 1 5
30 1 6
20 1 7
47 1 I
1000 3 1 I
37 I 10
11 1 1',!
30 1 12
73 2 13
45 1 14
u 2 15
't00 1 t6
7 1 17
22 I 18
7 1 19
14 1 20
14 1 21
336 3 22
90 2 23
20 1 24
25
37 ,|26
37 1 27
56 2 2A
28 1 29
30 1 30
300 I 3'l
20 I 32
25 2 33
75 2 34
45 1 1 35
7 36
300 ,|37
300 1 3E
1000 3 1 39
20 1 40
FERC FORir NO. 1 (ED. 12-96)Page 427.1
Name of Respondent
ldaho Power Company (1)
(2)
Original
Resubmission
Date of Report(Mo. Da, Yr)
04t18t2018
Year/Period of Report
End of 20171Q4
SUBSTATIONS
1 . Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industraal or strcet railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving custorners with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate in column (b) the functlonal charac'ter of each substation, designating wh€thor transmission or distribution and whether
afiended or unattended. At the end of the page, summarize according to function the capacities report€d for the individual stations in
column (f).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Kramer distribution 138.00 36.20
2 Kuna distribution 138.0C 13.00
3 Lake distribution 69.0C 13.00
4 Lake Fork distribution 138.00 36.20
5 Lake Fork fansmis6ion 138.00 69.00 12.50
6 Lamb distribution 138.00 13.00
7 Langley Gulch- attended transmission 230.00 138.00 13.80
8 Langley Gulch- attended transmission 230.00
9 Langley Gulch- aftended hansmission 230.00 150.00
10 Lincoln distribution 138.00 13.09
11 Linden disFibution 138,00 13.00
12 Locust distibution 138.00 36.20
13 Locust fansmission 230.00 138.00 13.80
14 Lower Malad - attended bansmission 138.00 7.20
15 Lower Salmon - attended tansmission 138.00 13.80
16 Map Rock distribution 69.00 13.00
17 McCall distribution 138.00 13.09
18 McCall distribution 138.00 36.20
1S Melba distribution 69.00 13.00
20 Meridian distribution 138.00 't 3.00
21 Micron distribution 't38.00 13.09
22 Micron distribution 138.00 13.00
23 Midpoint tansmission 230.00 138.00 13.80
24 Midpoint fansmission 345.00 230.00 13.80
25 Mldpolnt transmission 500.00 345.00
26 Midros€disbibution 138.00 13.09
27 Milner transmission 138.00 69.00 12.47
28 Milner dishibution 69.00 46.00 6.90
29 Milner distribution 't 38.0c 35.00
30 Milner PP - attended bansmission 138.0C 't3.80
31 Moonstone distribution 138.0C 35.00
32 Mora disbibution 138.00 13.09
33 Mora distribution 138.00 36.20
34 Moreland distributlon 46.00 35.00 12.47
35 MounEin Home distribution 69.00 13.00
Jt,Mountain Home Air Force Base distribution 69.00 13.00
37 Mountiain Home Air Force Base distribution 138.00 13.00
38 Nampa transmission 230.00 '138.00 13.80
39 Nampa distribution 138.00 13.00
40 New Meadows distribution 138.00 36.20
FERC FORM ilO.1 (ED. 12-06)Page 426.4
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of R€port(Mo, Da, Yr)
04,|1812018
Year/Period of Report
End of 2417n4
5. Show ln columns (l), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or majqr items of equipment leased from others, jointy owned with others, or operated othendse than by
roason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rsnt. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing €xpenses or other accounting between the parties, and state arnounts and accounts
affected in respondent's books of account. Speciff in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substration
(ln Service) (ln MVa)
(0
Number of
Transficrmers
ln Service
(q)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
fi)
Number of Units
(i)
Total Capacity
(ln MVa)(k)
30 1 1
28 1 2
14 ,1 3
30 1 4
20 1 5
30 1 6
636 2 7
4'.t0 2 I
1 9
't4 1 't0
58 2 't1
134 3 12
600 2 13
16 1 14
70 4 15
13 1 16
22 1 17
30 1 18
11 1 19
60 2 20
40 2 21
40 2 22
204 1 23
't400 2 I 24
1500 3 ,|25
45 1 26
125 3 1 27
I 3 1 2E
50 2 29
60 ,|30
20 1 31
45 1 32
45 1 33
7 3 ,|34
28 1 35
1 36
u 1 37
300 1 36
87 3 39
22 1 40
FERC FORrrl NO.1 (Eo.12-96)Page 427.1
Name of Respondeat
ldaho Power Company )Original
(2)Resubmission
Date of Report(Mo. Da, Yr)
04118t2018
YearlPeriod of Report
End of 20171Q4
SUBSTATIONS
1 . Report below the information called for concerning substations of the respondont as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unaftended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (Q.
Line
No.Name and Location of Substation
(a)
Charader of SubsEtion
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 New Plymouth distribution 69.00 13.00
2 Northview distibution 138.00
3 Notch Butte distribution 138.00 13.09
4 Orchard distribution 69.00 36.20
5 Orchard distribution 69.00
6 Parma distribution 69.00 13.00
7 Parma distribution 69.00 35.00
I Paul distribution 138.00 35.00
I Paul distribution 138.00 36.20
10 Payette distribution 138.00 13.00
11 Pingree bansmission 138.00 46.00 12.50
12 Pingree distribution 138.00 35.00
13 Pleasant Valley distribution 138.00 35.00
14 Pleasant Valley distribution 138.00 36.20
15 Pocatello distribution 46.00 13.00
16 Pocket distribution 138.00 36.20
17 Poleline distribution 138.00 13.0S
18 Poput$transmission 345.00
19 Portneuf distribution 138.00 35.00
20 Portneuf distribution 46.00 35.00
21 Rockficrd distribution 46.00 13.00
22 Russett distribution 138.00 13.00
23 Sailor Creek diskibulion 138.00 2.40
24 Sailor Cre€k <listribution 138.00 35.00
25 Salmon dishibution 69.00 13.00
26 Salmon distribution 6S.00 34.50 12.47
27 Salmon distribution 69.00 7.20
28 Shoshone diskibution 46.00 13.00
29 Shoshone distribution 46.00 7.20
30 Shoshone Falls - attended tsansmission 46.00 2.30
31 Shoshone Falls - attended transmission 46.00 6.60
32 Silver distribution 138.00 35.00
33 Simplot distribution 138.00 13.00
u Sinker Creek distribution 138.00 35.00
35 Siphon distribution 138.00 35,00
36 South Park distribution 46.00 13.00
37 Spring Valley distribution 138.00 2.44
38 Star distribution 138.00 13.09
39 Starkey transmission 138.00 6S.00 12.47
40 State distribution 69.00 13.00
FERC FORM NO. r (ED.,t2-96)Page 426.5
Name o, Respondont
ldaho Power Company (1)
(2)
An Original
Resubmission
Date of Report(Mo, Da, Yr)
04t1u2018
Year/Period of Report
End of 20171Q4
5. Show in columns (l), fi), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipm€nt for
increasing capacity.
6. Designate substations or maior items of equipment leased ffom others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substiation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any subsitation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other pafi, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Speciff in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(q)
Numb€r of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capaclty
(ln MVa)
(k)
13 1 1
45 1 2
14 I 3
8 1 4
33 1 5
'14 1 6
20 1 7
30 1 1 E
45 1 I
32 3 't0
67 3 11
34 2 1Z
30 1 13
45 1 14
60 2 15
45 ,|16
30 1 17
18
30 1 19
1 20
25 2 21
30 1 22
21 2 23
28 1 24
14 1 4 25
10 3 1 26
1 27
13 1 2E
2 3 29
4 1 30
14 1 31
20 1 32
53 2 33
20 1 34
55 2 35
14 1 36
11 1 37
30 1 38
30 1 39
58 2 40
FERC FORlrl NO. 1 (EO. 12-96)Page 127.5
Name of Respondent
ldaho Power Company (1)
(21
Original
Resubmission
OatE of Report(Mo, Da, Yr)
04118t2018
Year/Period of Reporl
End of 2O17lQ4
1. Report below the information called for conceming substations of the rospondent as of the end of the year.
2. Substations which serve only one industdal or street railway customer should not be lisled below.
3. Substations with capacities of Less than 10 MVa except those s€rving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.4. lndicate in column (b) the functional character of each substation, designating whether transmission or distributlon and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (Q.
Line
No.Name and Location of Substation
(a)
Charac-ter of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Seoondary
(d)
Teilary
(e)
1 Sterling distribution 46.00 13.00
2 Stoddard dlstribution 138,00 13.00
3 Strike Power Plant - attended transmission 138.00 13.80
4 Sugar distribution 138.00 35.00
5 Swan Falls - attended transmission 't38.00 6.90
6 Taber distribution 46.00 13.00
7 Tamarack distribution 138.00 2.40
8 Ten Mile distribution 138.00 13.09
I Terry distribution 138.00 13.0S
10 Terry distribution 138.00 13.00
11 Thousand Springs - att€nded tlansmission 46.00 7.20
12 Thrce Mlle l0roll lransmission 345.00
13 Toponis distribution 138.00 33.00
14 Twin Falls distribution 138.00 13.0S
'15 Twin Falls transmission 138.00 46.00 12.98
16 Twin Falls PP - attonded transmission 138.00 7.20
17 Twin Falls PP - aftended transmission 138.0C 13.20
't8 Tyhee distribution 46.0C 13.00
19 Upper Malad - attended transmission 45.00 7.20
20 Upper Salmon- attended transmission 138.00 7.20
Ustick distributiofl 138.00 13.00
22 Valliwe distribution 138.00 13.09
23 Victory dislribution 138.00 13.00
24 Mctory dislribution 138.00 13.09
25 Ware distribution 69.00 13.00
26 Weiser distribution 69.00 13.00
27 Weiser fansmission 138.00 69.00 12.47
2a Wlder dislribution 69.00 13.00
29 Willis dislribution 138.00 13.09
30 Wllow Creek dislribution 't38.00 13.00
31 wye distribution 138.00 13.00
32 wye distribution 138.00 13.09
33 Zilog distribution 138.00 13.0S
34
35
36 The above are all Shte of ldaho
37
38 Montana:
39 Mlt C-rc€k lfansmission 230.00
40 Psterson transmission 230.00 69.00 13.20
FERC FORI' NO. I (ED. 12-96)Page 426.6
21
Name of Respondent
ldaho Power Company (1)
(2')
An Original
A Resubmission
Date of Report(Mo. Da, Yr)
041'tu2018
Year/Period of Report
End of 20171Q4
5. Show in columns (l), fi), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased fom others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or tease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondenfs books of account. Speci$ in each case whether lessor, co-owner, or other parg is an associated company.
Capadty of SubstaUon
(ln Service) (ln MVa)
(f)
Number of
Transformers
ln Service
(q)
Number of
Spare
Transbrmers
(h)
CONVERSION APPARATUS ANO SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)(k)
11 2 1
28 1 2
104 3 3
28 2 4
34 1 5
6 1 6
11 1 7
90 2 8
20 1 I
50 2 10
I 1 11
12
30 1 13
82 ?14
50 2 15
13 I 16
72 1 17
14 1 18
8 1 19
42 4 20
77 2 21
30 1 22
45 1 23
30 1 24
20 1 1 25
27 2 26
42 1 27
14 1 28
30 1 29
11 1 30
60 2 31
37 1 32
45 1 33
34
35
36
37
3E
39
30 3 1 40
FERC FORM NO.1 (ED.12-96)Page 427.6
Name of Respondent
ldaho Power Company (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
0411812018
Year/Psriod of R€port
End of 2O17lQ4
SUBSTATONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving custorners with energy for resale, may be grouped according
to functional character, but the number of such zubstations must be shown.
4. lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Prlmary
(c)
Secondary
(d)
TerUary
(e)
1
2 Nevada:
3 \ldmy -atMcd hansmission 345.0C 18.00
4 Valmy-ettended bansmission 345.00 22.00
5 Wells fansmission 138.00 69.00 13.00
6
7 Oregon:
8 Adrian distribution 69.00 13.00
9 Boer0nan - attcndcd transmission 500.00 24.00
10 Eoqrdman - attcndod tansmission 230.00 7.20
11 Boardman - atbnded fansmission 24.00 7.20
12 &rmr tansmission 500.00
13 Cairo dislribution 69.00 13.00
14 Hells Canyon - aftended fansmission 230.00 13.80
15 Hells Canyon - attended dlstribution 69.00 0.50
16 Hines transmission 't 38.00 115.00 12.47
17 Hurlcanc 230.0c
18 Jacobson Gulch diskibution 69.00 2.40
19 Malheur Butte distribution 69.00 34.50
20 Nyssa distribution 69.00 13.00
21 Ontario distribution 138.00 13.00
22 Ontario transmission 138.00 69.00 't2.47
23 Ontario transmission 230.00 138.00 13.80
24 Ontario transmission 138.00 69.00 12.98
25 Ontario transmission 138.00 69.00 13.09
26 Ontario transmission 138.00 69.00 12.s0
27 Ore-lda distribution 69.00 13.00
28 Oxbow - attended transmission 138.00 69.00 13.00
29 Oxbow - attended transmission 230.00 13.80
30 Oxbow - attended transmission 230.00 138.00 13.80
31 Quartr transmission 't38.00 69.00 12.50
32 Quarz transmission 230.00 138.00 12.9A
33 QuarE transmission 138.0C 69.00 12.98
34 SummsLrke transmission 500.0c
35 Val€distribution 69.0C 13.00
36
37 Washington:
38 Wdh La/aila transmission 230.00
39
40 Wyoming:
FERC FORIil NO.1 (ED.12-90)?age 426.7
transmission
Name of Respondent
ldaho Powe Company (1)
(2)Resubmission
Date of Report(Mo, Da, Yr)
04/1A2018
Year/Period of Roport
End of 20171Q4
5. Show in columns (l), O, and (k) special equipment such as rotary converters, rectifiers, @ndensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased ftom others, jointly orrvned with others, or operated othenrise than by
reason of sole ownership by the respondent. For any substation or equipment operated und€r leass, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or leasa, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
afiected in respondent's books of account. Specifr in eact case whether lessor, co-owner, or other party is an associated @mpany.
Capacity of Substation
(ln Service) (ln MVa)
(f)
Number of
Transformers
ln Service
(s)
Number ol
Spare
Transfcrmers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of UniG
(i)
Total Capacity
(ln MVa)(k)
1
2
315 1 3
300 1 4
25 3 1 5
6
7
11 1 I
685 3 I
55 1 10
55 1 11
12
20 1 13
560 3 14
,|1 15
50 1 't6
17
11 1 1E
't1 3 1 19
28 2 20
67 2 21
47 1 22
400 2 23
93 2 24
1 25
1 26
28 1 27
13 3 ,|28
259 2 29
100 ,|30
25 1 31
167 3 1 32
20 1 33
34
14 ,|35
36
37
38
39
40
FERC FORir NO. 1 (ED. 12-96)Pagc 127.7
Namo of Respondent
ldaho Power Company (1)
(21
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
o411812018
Year/Period of Report
End of 20171Q4
SUBSTATIONS
'l . Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street rallway customer should not be listed below.
3. Substatlons with capacities of Less than '10 MVa except those serving customers with energy br resale, may be grouped according
to functional character, but the number of such substations mu* bs shown.
4. lndicate in column (b) the functional character of each substration, designating whether transmission or distribution and whether
aftended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
No.Name and Location of Substation
(a)
Charac'ter of Subsbtion
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Terliary
(e)
1 Jlm Brldgcr- liand.d 345.00 22.00 34.50
2
3
4
5
6
7 Transformersdistribution substations under'10,000
B KVA 65 unattended.
I
10
't1
12
13
14
15
16
17
't8
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED.12-96)Page tlll6.8
.transmission
Name of Respondent
ldaho Power Company (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0411812018
Year/Period of Report
End of 20171Q4
5. Show in columns (l), fi), and (k) special equipment such as rotary converters, rectifiers, condenseni, etc. and auxiliary equipment for
increasing capacity.
6, Designate substations or maior items of equlpment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownorship by the respondent. For any substation or equipment operated under lease, give name of l€ssor, date and
period of lease, and annual rent. For any substatlon or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and stat6 amounts and accounts
afiected in respondent's books of account. Specif, in each case whether lessor, co-owner, or other party is an associated oompany.
Capacity of Substation
(ln Service) (ln MVa)
(o
Number of
Transformers
ln Service
(q)
Number of
Spare
TransformerE
ft)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capaclty
(ln MVa)
(k)
2244 4 1
2
3
4
5
6
7
228 I
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 FORITI ilo. 1 (ED. 12-06)Page 127.8
Name of Respondent
ldaho Power Company
This Report is:
(1)X An Original
(2)_A Resubmission
Date of Report
(Mo, Da, Yr)
o4l'1812018
Year/Period of Report
2017tQ4
FOOTNOTE OATA
Schedule Page: 126 Line No.: 7 Column: aPacifiCorp has an ownership interest in certain high-voltage transmission related andinterconnection equipment located at Idaho Power's Adelaide station. Ownership interestvaries by terminal. 100? of the capacity is reported.
Schedule Page:126 Line No.:1 Column: f
For all of column F:
Top rating capacity repol!_ed unless_ otherwise noted
Schedule Page:126 Une No.:7 Column: aIdaho Powei has an ownership interesc in cerLain high-vc-ILage tr:ansmission relaued andj-nterconnecti-on equipment focated at Pacificorprs Antelope stat-ion. Ownership interestvarles by termlnal. 100t of the capacity reported.
$c&edulePage;426""t'##XJi, ,??3*1'r'in certain hish-vorrase rransmission reratea ana
interconnection equj-pment located ac PacifiCorp's Big Grassy station. Ownership interest
varies by terminal.
Schedule Page:126 Llne No.: 26 Column: aPa:ifiCorp has an ownership interes: in certain high-voliJge cransnission related andinterconnectj-on equipment located ai ldaho Power's Borah station, Ownership interestvarles by terminal. 100? of the capacity is reported.
Schedsle Page: 126.2 Line No.: 37 Column: a
Idaeo Powei has an o*ne:ship interest ir. certain high-voltage transmission related andinterconnection equipment located a: PacifiCorp's Goshen station. Ownership interestvaries by terminal. 100? cf che capacity repor--ed.
Schgdule Page: 426.3 Line No.: 9 Column: a
eacifiCorp has an ownership interesr in certain high-volcage transmission refated and
interconnection equipment focated at Idaho Power's Hemingway statj-on. Ownership i-nterest
varies by terminal. 1008 of the capacity is reported.
Schedule Page: 126.3 Line No.: 25 Column: afdaho Power has an ownership i-nterest in certain high-voltage transmission related andinterconnection equipment located at PacifiCorp's .Jefferson stat-ion. Ownership interestv?ries by terminal.
Schedule Page:426.3 Line N_o.; 39 Co-!u1pg; a
Pacifj-Corp has an ownership interest in certain high-voltage transmission related andinterconnection equipment located at fdaho Power's Kinport statj-on. Ownership interest
varies by terminal. l00t of the capaclty is reported.
Schedule Page: 126.1 Line No.: 25 Column: aPacifiCorp has an ownership j-nterest i-n certain hj-gh*voltage transmission related andinterconnection equipment located at Idaho Power's Midpoint stati-on. Ownership interestvaries by terminal. 100E of the capacity is reported.
Schedule Page: 126.5 Line No.: 18 Column: a
ldaho Power has an ownership interest j.n certain high-voltage transmission related and
interconnection equipment l-ocated at PacifiCorp's Populus station. Ownership interest
varies by terminal.
Sctedule Page:126.6 LineNo.:12 Column: aIdaho Power has an ownership interest in certain high-voltage transmi.ssion related and
-interconnection equipment -l-ocated at' PacifiCorp's Three Mile KnolL station, Ownershipinterest varies by terminal.
tchedule Page:426.6 Line No.: 39 Column: aIdaho Power has 328 ownership interest in certain l-ransmission related equipment located
at Northwestern Energy's Mi11 Creek Statlon,
Schedule Page: 126.7 Llne No.: 3 Column: aJoi-ntly owned with Sierra Pacific Power Company, d/b/a NV Energy. fdaho Power has a 50%
share of ownership. f00t .of the capacity reported.
'schadute Page: 126.7 Line No.: I Column: aJointLy owned with Sierra Pacific Power Company, d/b/a NV Energy. Idaho Power has a 50%
share of ownership. 1008 of the capacity reported.
FERC FORM NO.1 450.1
Name of Respondent
ldaho Power Company
This Report is:
(1) X An Original
(2) -A Resubmission
Date of Report
(Mo, Da, Yr)
04t1u2018
Year/Period of Report
2017tQ4
FOOTNOTE DATA
Schedule Page: 126-7 Line No.: 9 Column: aJointly owned with PortLand Generar E1ectric, Power Resources Cooperative and BA Leasingof the jointl-y owned capacity. 100? of the capacity
a
BCS, LLC. ldaho P,is reported.
Schedule Page:126.7
Schedule Page: 126.7Jointly owned with
ower has a 103 share
Line No.: 1O Column:
Line No.: 11 Column: aPorcland General- Etectric,
7 Line No.: 12 Column: a
a 222 ownersh ip interest in certain
Llne No.: I Column: a
Jointly owned with Portland General Electric, Power Resources Cooperative and BA Leasing
BCS, LLC. Idaho Power has a 10* share of the jointly owned capacity. 100? of the capacity
l9 rted
BCS, LLC. Idaho Power has a 10E share of the jointly owned capacity. 1008 of the capacityis reported.
Schedule Page:426.Idaho Power has
interconnection equj-pment located at PacifiCorp's Burns statlon.
Schedute Page: 426.7 Line No.: 17 Column: a
Id.aho Powei has an owneisfrip interest in certain hj.qh-voltage transmission relateinterconnection equipment located at PacifiCorp's Hurricane station. Ownership interestvaries by terminal.
Scfiedule Page: 426.7 Line No.: 31 Column: a
Idaho Powei has an ownership interes'- in certain higl-.-voitage
interconnection equipment located at PacifiCorp's Summer Lakevaries by termlnal.
Schedule Page: 426.7 Line No.: 38 Column: aldaho Power has an ownership interest in certaininterconnectj-on equipment. Iocated at PacifiCorp's Walla Wal1a station. Ownership interestvaries by terminal
Schedule Page: 126.8Jointly owned with Pacifi-cCorp.
capacity is reported.
ldaho Power has a 33.3? share of ownershj-p. 100% of the
Powei ne.sor-rrces Cooperative and BA Leailn6'
high-voltage transmissj-on related and
d ind
transmission rel-ated and
station. Ownership interest
hiqh-i;;ltage transmission related and
450.2FERC FORM NO.1
Name of Respondent
ldaho Power Company (2)A Resubmission
Date ol Reoort(Mo. Da, Yi)
04t'1u20't8
Year/Period of Report
End of 20171Q4
1. Report below the information called for conceming all non-power goods or seMces received fom or provided b associated (afflllated) companies.
2. The reporting lhreshold for reporting purpos€s is $250,000. The threshoH applies b the annual amount billed to he respondont or billed b
an associated/affiliated company for nonAower goodE and services. The good or servi@ must be specific in natur6. Respondents should not
attempt to include or aggregate arnounts in a nonspecific category suctt as'general".
3. Where amounts billed to or received from $e associated (affiliated) company are based on an alloceton prcoess, explain in a footnote.
Line
No.Description of the Non-Power Good or S€rvice
(a)
Name of
AssociatedlAffliated
Company
(b)
Account
Charged or
Credited
(c)
Amount
Charged or
Crodited
(d)
1 l{on-power Goodr or Services Provlded by Afflllated
2
3
4
5
6
7
8
I
10
11
12
13
't4
15
16
17
18
19
20 Non-porver Goods or Servicer Provided for Affiliate
21 06 IDACORP, INC.417420 430,U7
22 922000 40,958
23
24
25
26
27
28
29
30
3'l
32
33
34
35
36
37
38
39
40
41
42
FERC FORI, NO. 1(New)
FERG FORII NO. l-F (New)
Page tl29
December 3'1, 2017
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM 1
MULTI€TATE ELECTRIC COMPANIES
INDEX
Page
Number Title
Statement of lncome for the Year
Taxes Allocated to ldaho
Notes and Accounts Receivable
Accumulated Provision for Uncollectible Accounts
Receivables from Associated Companies
Gain or Loss on Disposition of Property
Professional or Consultative Services
Electric Plant in Service
Electric Operating Revenues
Electric Operation and Maintenance Expenses
Number of Electric Department Employees
1
2
3
3
4
5
6
7-10
11
12-15
15
IDAHO SUPPLEMENT
ldaho Power Company
STATE OF IDAHO -ALLOCATED
An Original Ilecember 31, 2017
STATEMENT OF INCOME FOR THE YEAR
1 . Report amounts for accounts 412 and 4'13, Re\renue and E)eenses from Utility Plant Leased to Others, in another utility
cdumn (i,k,m,o) in a similar manner to a utility department. Spread the amount(s) over lines 01 thru 24 as appropriate.
lnclude these amounts in columns (c) and (d) totals.
2. Reportamountsinaccount414,OtherUtilityOperatinglncome,inthesarnemannerasac@unts412and413above.
3. ReportdataforlinesT,9,andl0forNatural Gascornpaniesusingaccounts404.1,404.2,404.3,407.'l',and407.2.
4. Use page I 22 for important notes regarding the state ment of income or any account thereof.
5. Give concise elplanations conceming unsettled rate proceedings where a contingency odsts such that refunds of a
material amount may need to be made to the utilitys customers or which may result in a material refund to the utilig
with respect to po^/er or gas purchases. State for each year affected the gross revenues or co6ts to which the contingency
relates and the tax effects together with an erelanation of retain such rarenues or recover amounts paid with respect
to porer and gas purchases.
6. Give concise oplanations conceming significant amounts of any refunds mde or received during the year.
Line
No.
Account
(a)
(Ref.)
Page
No.
(b)
TOTAL
Current Year
(c)
Previous Year
(d)
1
2
3
4
5
6
7
I
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
UTILITY OPERATING INCOME
Operating Revenues (400)
Operating Expenses
Operation Epenses (40'l )....
Maintenance Expenses (402).....
Depreciation Etpense (403)..
Amort. & Depl. of Utility Plant (4(X-405)......
Amort. of Utility Plant Acq. Adj. (406)..
Amort. of Property Losses, Unrecovered Plant and
Accretion Epense (41 1 ).....
Regulatory Study Costs (407)..
Amort. of Conversion Expenses (407).................
Regulatory Debits/Credits (407 .3 & 407.4).
Taxes Other Than lncome Taxes (408.1 )
lncome Ta(es - Federal (409.1)..
- Other (409.'l)....
Provision for Defened lncome Taxes (4 1 0. 1 & 41 1 . 1 ) Net... .....
lnrrestment Tax Credit Adj. - Net (41 1.4)..
(Less) Gains from Disp. of Utility Plant (411 .6).....
Losses from Disp. of Utility Plant (411.7).
(Less) Gains from Dispositim of Allo^,ances (41 1 .8)..............
Losses from Disposition of Alloivances (41 1.S)..
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 221...........
Net Utility Operating lncorne (Enter Total of line 2 less 24).....
1'l
15
15
2
2
2
2
2
$ 1,280,695,095 $ 1,196,237,660
734,257,170
57,900,000
147,829,833
5,882,4',11
212,100
1,075,354
31,671,383
43,471,706
10,223,599
(24,713,707)
7,'.105,141
1,014,9'14,989
695,609,784
63,704,243
129,831,533
6,315,212
221,856
1,075,354
30,506,918
893,579
3,660,26s
30,612,022
29',t,753
962,722,s15
$ 265,780,106 $ 233,515,145
IDAHO SUPPLEMENT Page 1
TAXES ALLOCATED TO IDAHO
Kind of Tax
Taxes Charged
Durino Year
Taxes Other Than lncome Taxes:
Labor Related:
Ftc4............
FUTA...........
State Unemployment.......
Payroll Deduction & Loading....
Total Labor Related........
Property Taxes..........
Kilowatt-hour Tax............
Licenses......
Regulatory Commission Fees.................
lrrigation P1C..............
Canada Sales Tax....
Total Taxes Other Than lncome Taxes.....
$ 14,851,066
87,001
344,575
(15,282,642)
0
27,129,696
1,629,706
4,384
2,665,964
241,632
0
31,671,383
Federal lncome Taxes..........
State lncome Taxes..........
Deferred lncome Taxes..........
lnvestment Tax Credit Adjustment - Net.
43,471,706
10,223,599
(24,713,707)
7,105,141
Total Taxes Allocated to ldaho.$ 67,758,120
ldaho Power Company
STATE OF IDAHO. ALLOCATED
An Original December 31, 2017
IDAHO SUPPLEiIIENT Page 2
STATE OF IDAHO
An Original December 31, 2017ldaho Power Company
NOTES AND ACCOUNTS RECEIVABLE
Summary for Balance Sheet
Sho^/ separately by footnote the total amount of notes and accounts receimble
from directors, officers, and employees included in Notes Recei\rable (Account
141) and OtherAccounts Recei\rable (Account 143)
Line
No.
Accounts
(a)
Balance
Beginning of
Year
(b)
Balance
End of
Year
(c)
1
2
3
4
5
6
7
I
I
't0
11
't2
13
't4
15
16
17
18
19
20
Notes Receivable (Account 14'l).
Customer Accounts Receivable (Account 142)..
Other Accounts Recei\rable (Account 143).
(Disclose any capital stock subscription received)
Total...
Less: Accumulded Provision for Uncollectible
Accounts-Cr. (Account 144)...........
Total, Less Accumulated Provision for
Uncollectible Accounts..
$(83,038)
73,276,818
2s,535,458
$ 98,729,238
1,131,759
$ 97,597,479
$(86,399)
77,764,379
28,1 69,330
$ 105,847,309
2,192,252
$ 103,655,057
ACCUMULATED PROVISION FOR UNCOLLECTIBLE ACCOUNTS - CR. (Account 144)
1. Report belolv the information called for concerning this accumulated prorision.
2. Eplain any important adjustments of subaccounts.
3. Entries with respect to officers and employees shall not include items for utility services.
Line
No.
Item
(a)
Utility
Customers
(b)
Mdse,
Jobbing &
Contract
Work
(c)
Officers
and
Employees
(d)
Other
(e)
Total
(0
21
22
23
24
25
26
27
28
29
30
31
32
33
Balance Beg of Year:
Uncollectible Retail Electric Sales
Uncollectible Damage Claims
Uncollectibe Other Revenues
Balance end of year.....
$ (1,131,759)
(1,024,042)
(15,562)
(20,889)
$$
$
$
$
$
$
(1,131,759)
('t,024,M2\
(1s,562)
(20,889)
$ (2,192,252)$$$$ (2,192,252)
IDAHO SUPPLEMENT Page 3
RECEIVABLES FROM ASSOCIATED COMPANIES (Accornts 145, 1.16)
1. Report particulars of notes and accounts recei\Eble frorn associated companies at end of year.
2. Provide separate headings and totals for acrounts 145, Notes Recei\rable from Associated Companies, and '146,
Accounts Receivable from Associated Cornpanies, in addition to a total for the combined accounts.
3. For notes recei\rable list each note separately and state purpooe for which received. Shor also in column
(a) date of note, date of maturity and interest rate.
4. lf any note was received in satisfaction of an open account, state the period co/eled by such open account.
5. lnclude in column (f) interest recorded as income during the year, including interest on accounts and notes
held at any time during the year.
6. Give particulars of any notes pledged or discounted, also of any collateral held as guarantee of payment
of any note or account.
Line
No.(a)
Balance
Beginning
of Year
(b)
Totals for Year Balance
End of Year
(e)
lnterest
For Year
(0
Debits
(c)
Credits
(d)
1
2
3
4
5
6
7
I
I
10
1'r
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
Account l4S:
tERCO........
Total Account 145...
Account'146:
IDACORP, lnc...
Total Account 146............... .....
$$$$
$6,635,901 $ 6,635,901 $0
$$ 6,635,901 $ 6,63s,901 $0
ldaho Power Gompany
STATE OF IDAHO
An Original D,ecember 3'1, 20'17
IDAHO SUPPLEMET{T Page 4
Particulars
STATE OF IDAHO -TOTAL SYSTEM DATA
GAIN OR LOSS ON DISPOSITION OF PROPERTY (Account 421.1 and 421 .2)
1. Give a brief descriptior of property creating the gain or loss. lnclude name of party acquiring the property (whar
acquired by another utility or associated company) and the dde transaction was completed. ldentify property
by type; Leased, Held for Future Use, or Nonutili$.
2. lndiMdual gains or loGses relating to property with an original cost of less than $50,000 may be grouped, with the
number of such transrctions disclosed in column (a).
3. Gi\re the date of Commission approval of joumal entries in cdumn (b), when approval is required. Where approral
is required but has not been received, give explanation folloiling the item in column (a). (See account 102, Utility
Plant Purchased or Sold.)
Line
No.
Description of Property
(a)
Original Cost
of Relded
(b)
Date Journal
Entry Approved
(When Required)
(c)
Accl42'1.1
(d)
Accl421.2
(e)
,|
2
3
4
5
6
7II
10
11
't2
13
14
't5
16
't7
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Gain on dispcition of
property:
Hoku Substation Transformers
*Transaction completed 4 n 8nU7
Total gain...
Total 1o6s................
$$$
$0 5t30t2017-$ (450,000)
$0 $ (450,000)
0$$0
ldaho Power Company
STATE OF IDAHO
An Original Ilecember 31, 2017
IDAHO SUPPLEMENT Page 5
STATE OF IDAHO
An Original December 31, 2017ldaho Porcr Company
STATE OF IDAHO - TOTAL SYSTEM DATA
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $1O,OOO AND OVER
Line
No
PAYEE
(a)
SERVICE TYPE
(b)
Amount
(c)
Management Services
Customer Service
Legal Services
Legal Services
Management Services
Legal Services
Management Services
lT Services
Training Consultants
lT Services
Legal Services
Envimmental Services
Corporate Tax Services
Legal Services
Management Services
Management Services
lT Services
Legal Services
Legal Services
Legal Services
Legal Services
Management Services
lT Services
Legal Services
Management Services
Consulting Services
Engineering Services
Management Services
Legal Services
Engineering Services
Legal Services
lT Services
Legal Services
Legal Services
Staffing Services
Legal Services
lT Services
lT Services
Legal Services
Training Consultants
lT Services
lT Services
Legal Services
Envimmental Services
Customer Service
14,571
13,928
24,696
68,'198
210,255
519,841
11,000
526,770
75,000
28,157
1,008,539
26,426
15,000
43,219
404,049
10,600
41,379
13,927
51,989
12,290
22,834
111,396
11,050
1 3,1 33
149,887
20,535
19,412
79,413
16,162
56,999
14,630
17,000
562,262
24,448
19,700
10,317
't0,131
164,359
224,353
11,641
20,278
't4,500
20,771
42,504
90,000
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33u
35
36
37
38
39
40
41
42
434
45
ADECCO
ADM ENERGY
AKIN GUMP STRAUSS HAUER & FELD
ANDERSON SCHWARTZMAN WOODARD B
AVERTRA CORPORATION
BARKER, ROSHOLT & SIMPSON LLP
BIGGINS LACY SHAPIRO & CO., LL
CGI TECHNOLOGIES AND SOLUTIONS
CLEAREDGE PARTNERS
COMPUNET, INC
DAVIS WRIGHT TREMAINE LLP
DEERE AND AULT CONSULTANTS INC
DELOITTE TAX LLP
EVANS KEANE
EVERGREEN CONSULTING GROUP, LL
EXPRESS MANAGED SERVICES
EXTRAHOP SERVICES A
FIRE CAUSE ANALYSIS
GIVENS PURSLEY LLP
HAWLEY TROXELL ENNIS & HAWLEY
HOLLAND & HART LLP
HONEYWELL INTERNATIONAL INC
ICEBERG NETWORKS CORPORATION
INDUSTRIAL HYGIENE RESOURCES,
INTELLITECT
J M ROCHE AND ASSOCIATES
JLR ENGINEERING LLC
KEMA INC
KLAROUIST SPARKMAN LLP
LEIDOS ENGINEERING LLC
MACT ENERGY ASSURANCE SERVICES
MAINLINE INFORMATION SYSTEMS I
MCDOWELL RACKNER & GIBSON PC
MIRANDE, MICHAEL
MODISE&T,LLC
MORROW & FISCHER PLLC
NEXTAXIOM TECHNOLOGY INC
NIELSEN GROUP INC, THE
PERKINS COIE LLP
PROFESSIONAL TRAIN ING SYSTEMS
QUALIry COMMUNICATIONS INC
QUESTLINE INC
RAMLOW & RUDBACH PLLP
REED HARRIS ENVIRONMENTAL LTD
REGULUS INTEGRATED SOLUTIONS
IDAHO SUPPLEMENT
PROFESSIONAL OR CONSULTATIVE SERVICES - ITEMS $1O,OOO AND OVER
STATE OF IDAHO - TOTAL SYSTEM DATA
SERVICE TYPE
(b)
Amount
(c)
Line
No.
PAYEE
(a)
252,215
11,280
329,844
66,000
45,024
16,364
296,358
11,707
15,737
37,670
141,199
34,943
161,243
54,758
y4,687
95,859
14,598
188,422
46
47
48
49
50
51
52
53
il
55
56
57
58
59
60
61
62
63u
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83u
RESOURCE DATA, INC
RIGHT SYSTEMS, INC
RM ENERGY CONSULTING
SAP INDUSTRIES INC
SCHWABE WILLIAMSON & WYATT
STOEL RIVES LLP
TATA AMERICA INTERNATIONAL
TEKSYSTEMS
TERRAGRAPHICS ENVIRONMENTAL EN
THE REGENTS OF UNIVERSIry OF CA
TIBCO SOFTWARE INC
TRINITY CONSULTANTS INC
TRINOOR LLC
TUERI LLC
UNIVERSIry OF IDAHO
UT-BATTELLE LLC
UTILITIES AVIATION
VAN NESS FELDMAN
TOTAL
lT Services
lT Services
Management Services
lT Services
Legal Services
Legal Services
Management Services
HR Services
Environmental Services
Environmental Services
lT Services
Environmental Services
HR Consulting
Management Services
Management Services
Environmental Services
Training Services
Legal Services
$ 6,985,454
ldaho Porer Company
STATE OF IDAHO
An Original December 31, 2017
IDAHO SUPPLEMENT
6A
Line
No.
PROFESSIONAL OR CONSULTATIVE SERVICES
ITEMS $5.OOO OR MORE BUT LESS THAN $1O.OOO
PREDOMINANT
NATURE OF SERVICEPAYEE I nuouur
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
ABB ENTERPRISE SOFTWARE
AGREE TECHNOLOGIES AND SOLUTIO
ANDERSON PERRY & ASSOCIATES
ANDERSON SCHWARTZMAN WOOOARD
BETHKE LAW PLLC
CASE FORENSICS CORPORATION
CORPORATE OFFICE I NSTALLATIONS
D J RESEARCH
EDM INTERNATIONAL, INC
GJORDING & FOUSER, PLLC
HIRST APPLEGATE LLP
HOLTON ENTERPRISES INC
J M MULLIS INC
JACKSON LEWIS PC
JONES GLEDHILL FUHRMAN GOURLEY
PATRIOT ELECTRIC INC
PHONEPRO
POWERPLAN CONSULTANTS INC
STRUCTURED COMMUNICATION SYS.
TERRI HUGHES, LLC
TOWERS WATSON DELAWARE INC
WINNER MANAGEMENT INC
TOTAL
lT Services
lT Services
LegalServices
LegalServices
LegalServices
Engineering Consulting
Management Services
Management Services
Engineering Consulting
LegalServices
LegalServices
Management Services
Electrical Contracting Services
LegalServices
Legal Services
Electrical Contracting Services
Customer Service
Management Services
lT Services
Management Services
HR Consulting
Management Services
$155,380
ldaho Pou,er Company
STATE OF IDAHO
An Original Ilecember 31,2017
IDAHO SUPPLETUENT
Page 68
5,280.00
8,255.25
7,755.00
9,450.00
6,066.50
6,080.00
7,966.81
7,515.25
6,075.60
7,243.50
5,950.00
7,303.54
6,661.00
9,009.12
6,562.20
5,000.00
7,873.84
6,200.00
7,000.00
9,400.00
6,882.25
1 Report belor/ the original cost of electric plant in service according to the prescribed accounts.
2. lnadditiontoAccountl0l,ElectricPlantinService(Classified),thispageandthenertincludeAccountl02,ElectricPlant
Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Co.npleted Construction
Not Classified - Electric.
3. lnclude in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. Enclose in parentheses credit adjustments of plant accounts to indicate the negative efiect of such acrounts.
5. Classiry Account 1 06 according to prescrib€d accounts, on an estimated basis if necessary, and include the entries in
column (c) . Also to be included in column (c) are entries for ra/ersals of tentative distributions of prior year reported in
column (b). Likeu/ise, if the respondent has a significant amount of plant retirements the end of the year, include in
column (d) a tentdive distribution of such retirements, on an estimated basis, with appropriate contra entry to the account
ficr accumulated depreciation provision. lnclude also in column (d) reversals of tentative distributions of prior year of un-
classified retirements. Attach supplemental statement shor/ing the account distributions of these tentative classifications in
columns (c) and (d), including the reversals of the prior years tentative account distributions of these amounts. Careful ob-
servance of the above instructions and the texts of Accounts 1 01 and 1 06 will avoid serious omissions of the reported amount
of respondent's plant etually in service at end of year.
ELECTRIC PLANT lN SERVICE (Accounts 101, 102,'103 and 106)
Line
No,
Account
(a)
Beginning of year
(b)
Additions
(c)
$5,457
28,735,693
21,722,267
50,463,418
14,807,729
1 ,13'1,205,806
784,225,548
,l
2
3
4
5
6
7
8
I
10
11
12
13
14
15
16
17
18
19
20
2'l
22
23
24
25
26
27
28
29
30
31
32
33u
35
36
37
38
39
40
4'l
42
43
1. INTANGIBLE PTANT
(301) Organization................ .....
(302) Franchises and Consents.....
(303) Miscellaneous I ntangible P|ant..................
TOTAL lntangible Plant (Enter Total of lines 2, 3, and 4).............
2. PRODUCTION PLANT
A. Steam Production Plant
(310) Land and Land Rights................
(31'l ) Structures and 1mprovements.......................
(312) Boiler Plant Equipment
(313) Engines and Engine Driven Generators
(31 4) Turbogenerator Units..........
(31 5) Accessory Electric Equipment.........................
(316) Misc. Po/ver Plant Equipment.........
(317) Asset Retirement Co6ts br Steam Prcduction.........
TOTAL Steam Production Plant (EnterTotal of lines I thru 15)........................
B. Nuclear Production Plant
(320) Land and Land Rights................
(321 ) Structures and 1mprovements.......................
(322) Reactor Plant Equipment.
(323) Turbogenerator Units..........
(324) Accessory Electric Equipment.......................
(325) Misc. Po,ver Plant Equipment-..-......
(326) Asset Retirement CGts br Nuclear Production................
TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 24).................
C. Hydraulic Prcduction Plant
(330) Land and Land Rights................
(332) Reservoirs, Dams, and Waterways.........
(333) Water Wheels, Turbines, and Generdors..............
(334) Accessory Electric Equipment.................................
(335) Misc. Pover Plant Equipment..........
(337) Asset Retirement Costs for Hydraulic Production.........
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)......
D. Other Production Plant
(341) Structures and 1mprorements..................................
(342) Fuel Hdders, Products and Accessories.....,....,
(345) Accessory Electric Equipment.................,..............
(346) Misc Pover Plant Equipment..........
(336) Roads, Railloads, and Bridges.
(344) Generators
(340) Land and Land Rights.............
STATE OF IDAHO
An Original December 31, 2017ldaho Power Company
7
IDAHO SUPPLEMENT
ELECTRIC PI-ANT lN SERVICE (Accounts 101,102,103 and 106) (Continued)
Sho/lr in column (0 reclassifications or transfers within utility plant accounts. lnclude also in column
(0 the additions or reductions of primary account classifications arising from distribution of amounts
initially recorded in Account 1 02. ln shoving the clearance of Account 1 02, include in column (e) the
amounts with respect to accumulated provision icr depreciation, acquisition adjustments, etc., and shor/
in column (0 only the otrset to the debits or credits distributed in column (0 to primary account classifications.
For Account 399, state the nature and use of plant included in this account and if substantial in amount
submit a supplementary statement shoi/ing subaccount classification of such plant conforming to the
requirements of these pages.
For each amount comprising the reported balance and changes in Account 1 02, state the property purchased
or sold, name of vendor or purchaser, and date of transaction. lf proposed joumal entries have been filed
with the Commission as requircd by the Uniform System of Accounts, give also date of such filing.
Retirements
(d)
Adjustments
(e)
Transfers
0
End of Year
(s)
Line
No,
b 5,457
29,363,51 4
25,470,704
(301)
(302)
(303)
1
2
3
4
5
6
7
8
I
10
'l'l
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
54,839,676
14,392,313
(31 0)
(31 1)
(312)
(313)
(314)
(315)
(316)
(317)
1,141,859,307
(320)
(321)
(322)
(32s)
(324)
(32s)
(326)
(330)
(331)
(332)
(333)
(334)
(33s)
(336)
(337)
824,267,595
(s40)
(341)
(342)
(343)
(344)
(345)
(345)
ldaho Power Company
STATE OF IDA}IO
An Original December 31, 2017
IDAHO SUPPLEMENT
Page I
ELECTRIC PLANT lN SERVICE (Accounts 101,102,103 and 106) (Continued)
No.
Line
Account
(a)
Balance at
Beginning ofyear
(b)
Additions
(c)
$ 526,346,795
2,441,778,149
35,587,007
76,1 04,269
393,495,642
189,547,402
1 67,575,31 1
209,723,704
373,412
1,072,406,748
5,814,678
35,010,074
214,473,222
236,613,191
122,399,952
49,1't't,697
240,258,034
514,889,065
56,597,01 7
u,220,958
2,788,954
4,291,616
1,566,468,460
16,434,544
1 1 3,336,404
46,953,216
77,914,731
2,506,903
8,292,085
12,460,246
14,433,881
54,1 50,326
6,287,681
352,780,01 6
352,780,0'16
5,483,896,790
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
6'l
62
63
64
65
66
67
68
69
70
71
72
73
74
75
/b
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
(346) Misc. Povver Plant Equipment.........
TOTAL Other Production Plant (Enter Total of lines 37 thru 44)......................
TOTAL Production Plant (Enter Total of lines 16, 25, 35, and 45)...................
3. TRANSMISSION PLANT
(350) Land and Land Rights................
(352) Structures and 1mprovements.......................
(353) Station Equipment..........
(354) To\rers and Fixtures.......
(355) Poles and Fixtures.......
(356) Overhead Conductors and Devices.......
(357) Underground Conduit...........
(358) Underground Conductors and Devices..............
(359) Roads and Trai|s..................
(359.1) Asset Retirement Costs for Transmission P|ant........
TOTAL Transmission Plant (Enter Total of lines 48 thru 57) . . .
4. DISTRIBUTION PLANT
(360) Land and Land Rights...... .........
(361) Structures and lmprovements
(362) Station Equipment..........
(363) Storage Battery Equipment.........................
(364) Poles, To rers, and Fixtures..............
(365) Overhead Conductors and Devices....
Underg round Cmductors and Da/ices..............
Line Transbrmers
Services.............
Meters...............
lnstalldions on Custorner Premises............
Leased Property on Customer Prem ises....................
(373) Street Lighting and Signal Systems..
(374) Asset Retirement Costs for Distribution Plant... .. . ... ... . . .
TOTAL Distribution Plant (Enter Total of lines 60 thru 74)...
5. GENERAL PLANT
(389) Land and Land Rights................
(390) Structures and I mprovements.......................
(391) Otrce Fumiture and Equipment..........
(392) Transportation Equipment....
(393) Stores Equipment..........
(394) Tools, Shop, and Garage Equipment......................
(395) Laboratory Equipment..........
(396) Pover Operated Equipment.....
(397) Communication Equipment....
(398) Miscellaneous Equipment.....
SUBTOTAL (Enter Total of lines 77 thru 86)... . . .......
(399) Other Tangible Property.......
(399.1) Asset Retirement Costs for General P|ant......... ... ...............
TOTAL Gefleral Plant (Enter Total of lines 87, 88 and 89)..............
TOTAL (Accannts 1 01 and 1 06)...................
(102) Electric Plant Purchased
(Less) (1 02) Electric Plant So|d......................
(1 03) Epefi mental Plant Unc|assified......................
TOTAL Electric Plant in Service.....
(366) Underground Conduit...............
(367)
(368)
(36e)
(s70)
(371)
(372)
$ 5,483,896,790
STATE OF IDAHO
ldaho Power Company An Original December 31, 2017
IOAHO SUPPLEMENT
ldaho Power Company
STATE OF IDATIO
An Orlglnal December 31, 2017
ELECTRIC PI-ANT lN SERVICE (Accounts 1o1,102,103 and 106) (Continued)
Retirements
(d)
Adjustments
(e)
Transfers
(D
Balance at
End of Year
(s)
Line
No.
(346)44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
$ 522,265,343
2,488,392,245
35,546,253
76,844,700
410,649,711
1 97,756,009
175,495,31 1
216,945,532
373,645
(3s0)
(352)
(353)
(354)
(3s5)
(356)
(3s7)
(3s8)
(3se)
(3s9 1)
1 ,1 13,61 1 ,163
5,881 ,1 80
35,655,472
227,302,609
244,612,888
1 26,868,663
50,053,945
254,802,559
537,475,593
57,896,482
86,953,1 32
2,827,642
4,31 5,930
(360)
(361 )
(362)
(363)
(364)
(36s)
(366)
(367)
(368)
(36e)
(370)
(371)
(372)
(373)
(374)
1,634,646,096
16,709,488
1 1 5,458,1 61
42,978,376
84,352,770
2,820,707
9,988,646
13,271,792
15,564,817
51,804,398
6,678,546
(38e)
(3e0)
(3e1)
(3s2)
(3s3)
(3s4)
(3s5)
(3e6)
(3s7)
(3e8)
359,627,703
(3ee)
(3es.1 )
359,627,703
5,651 ,1 1 6,882
(102)
(102)
(371)
$ s,651,116,882
IDAHO SUPPLEMENT
Page l0
STATE OF IDAHO
An Original December 31, 2017ldaho Pou,Er Gompany
ELECTRIC OPERATING REVENUES (Account 400)
1. Report belof operating revenues for each prescribed account, and manufactured gas ranenues in total.
2. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate
accounts; except that where separate meter readings are added for billing purpoGes, one customer should be counted
for each group of meters added. The average number of custorners means the average of twelve figures at the close
ofeach month.
3. lf prwious year (columns (c), (e) and (g), are not derived from prwior.rsly reported figures, oelain any
inconsistencies in a footnote.
No.
(a)
OPERATING REVENUES
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
1
2
3
4
5
b
7
I
I
10
't1
12
13
14
15
't6
17
18
't9
20
21
22
23
24
25
26
Sales of Electricity
(440) Residential Sales.
(/142) Commercial and lndustrial Sales
Small (or Commercial)(See lnstr. 4) (1 )........
Large (or lndustrial)(See lnstr. 4) (2)........
(444) Public Street and Highway lighting.............
(445) Other Sales to Public Authorities...................
(446) Sales to Railroads and Railways.....
(448) lnterdepartmental Sales.....
TOTAL Sales to Ultimate Consumers................
(447) Sales for Resale - Opportunity....Non-Firm On|y............
TOTAL Sales of Electricity.
(449) Prot/ision for Rate Refunds....
TOTAL Revenue Net of Prodsion for Refunds...................
Other Operating Revenues
(450) Forfeited Discounts....
(45 1 ) Miscellaneous SeMce Revenues..........
(453) Sales of Water and Water
(454) Rent from Electric Property.
(455) lnterdepartrnental Rents......
(456) Other Electric Revenues
TOTAL Other Operating Revenues.
TOTAL Electric Operating Re\renues..........
$533,040,709
446,560,444
179,311,752
3,935,296
$496,885,590
43s,838,063
166,852,687
3,851,019
1,162,848,202 -
31,832,409
1,103,427,358
24,028,928
1,194,680,611
(10,706,040)
1,'t83,974,571 1,116,750,246
4,1 90,975
14,488,022
78,041,526
4,006,859
13,550,308
61,930,248
96,720,524 79,487,414
$1,280,695,095 $1,196,237,660
(1) Commercial and lndustrial sales - Small - under'1,000 KW and includes all irrigation customers.
(2) Commercial and lndustrial sales - Large - 1,000 KW and over.
1,127 ,456,286
(10,706,040)
IDAHO SUPPLEMENT
Page'11
ELECTRIC OPERATING REVENUES (Account 400) (Continued)
4. Commercial and lndushial Sales, Account 442, may be classified according to the basis of classification
(Small or Commercial, and Large or lndustrial) regularly used by the respondent if such basis of classification
is not generally greater than 1000 Kw of demand. (See Acrount 442 of the Uniform System of Accounts. Explain
5. See page 108, lmpodant Changes During Year, for important ne$, tenitory added and important rate increases or
decreases.
6. For lines 2,4,5, and 6, see page 304 for amounts relating to unbilled revenue by accounts.
7. lnclude unmetered sales. Provide details of such sales in a fmtnote.
KILOWATT HOURS SOLD AVERAGE NUMBER OF CUSTOMERS PER MONTH
Line
No.
Amount for
Cunent Year
(d)
Amount for
PreviqJs Year
(e)
Amount for
Cunent Year
(f)
Number for
Previous Year
(s)
5,',t61,441,049
5,619,619,5'l 1
3,076,839,087
30,888,003
4,825,036,794
5,691,721 ,809
2,98',t,154,794
30,473,840
435,376
82,202
'113
2,961
426,966
81,209
114
2,764
1
2
3
4
5
6
7
8
I
10
1',|
12
13
13,888,787,650 *
2,036,s15,949
't3,528,387,237
1,130,546,242
520,652
N/A
51 't,053
N/A
't 5,925,303,599 't4,658,933,479 520,652 511,053
" lncludes <$3,592,199> in unbilled revenues
** lncludes <57,1 10,659> KWH relating to unbilled revenues.
Lines 1 l through 21 are on an "allocated" basis
ldaho Power Company
STATE OF IDAHO
An Original December 31, 2017
IOAHO SUPPLEMENT
Page lla
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for pre\rious year is not derived from previously reported figures, eplain in footnotes.
Ltne
No.Account
(a)
Amount for
Current Year
(b)
AMOUNI rcT
Previous Year
(c)
1 1. POWER PRODUCTION EXPENSES
2
3
4
5
6
7
8
9
10
11
't2
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
A. Steam Pon er Generatton
Operation
(500) Operation SupeNision and Engineering....
(502) Steam Expenses.....,..
(503) Steam frorn Other Sources.............
(Less) (504) Steam Transfened-Cr..........
(505) Electric Expens€s...........
(506) Miscellaneous Steam Po,ver Expens€s...........
(507) Rents........
(509) Allo,Yances
TOTAL Operation (Enter Total of lines 4 thru 12).............
Maintenance
(510) Maintenance Supervision and Engineering.
(51 1) Maintenance of Structures....
(51 2) Maintenance of Boiler P|ant..................
(51 3) Maintenance of Electric P|ant..................
(514) Miscellaneous Steam Plant....
TOTAL Maintenance (Enter Total of Lines 15 thru 19)..............
TOTAL Po,ver Prcduction Expenses-Steam Po ,er (Enter Total d lines 13 and 2
B. Nuclear Po\rer Generation
Operation
(517) Operation Supervision and Engineering.
(518) Fue|.............
(519) Coolants and Wder..........
(520) Steam Epenses...........
(521 ) Steam from Other Sources..........................
(Less) (522) Steam Transferrcd-Cr.......................
(523) Electric Expenses....
(524) Miscellaneo{.rs Nuclear Por/er Expenses........
TOTAL Operation (Enter Total of lines 24 thru 32).....
Maintenance
(528) Malntenance Supervision and Engineering.......
(529) Maintenance of Structures....
(530) Maintenance of Reactor Plant Equipment.........
(531) Maintenance of Electric P|ant...........................
(532) Maintenance of Miscellaneous Nuclear P|ant............
TOTAL Po,\,er Production Expenses.Nuclear Poiver (Enter Total of lines 33 and
C. Hydraulic Poiler Generation
Operation
(535) Operation Supervision and Engineering.
(536) Water ficr Por/er...............
(537) Hydraulic Epenses..........
(538) Electric Expenses......
(539) Miscellaneous Hydraulic Pover Generation Expeflses..........
(540) Rents.......
TOTAL Operation (Enter Total of lines 44 thru 49).................
$937,038
1 02,885,430
8,1 06,81 2
1,331,231
11,196,839
314,936
$1,1 08,81 5
't31,264,237
8,552,599
1,397,666
8,704,375
197,814
124,772,286 1 51,225,505
52,876
421,677
10,519,310
4,1 30,31 I
5,682,502
95,779
505,3 t4
1 3,597,821
4,910,251
6,157,433
20,806,683 25,266,597
145,578,969 't76,492,102
5,455,1 02
5,607,626
14,369,221
1,829,572
7,91 8,583
231,490
5,429,890
5,765,563
14,033,868
1,622,635
5,453,486
225,201
35,411,594 32,530,642
ldaho Poxer Company
STATE OF IDAHO
An Original December 31, 2017
IDAHO SUPPLEMENT
Page 12
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount firr previous year is not derived frorn previously reported figures, e)elain in footnotes.
Line
No.Account
(a)
Amount for
Current Year
(b)
Amount tor
Previous Year
(c)
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83u
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
00
01
02
1
,|
1
103
C. Hydraulic Power Generation (Continued)
Maintenance
(541) Maintenance Supervision and Engineering.
(542) Maintenance of Structures....
(543) Maintenance of Reservoirs, Dams, and Waterways.........
(544) Maintenance of Electric P|ant..................
(545) Maintenance of Miscellaneous Hydraulic Plant..................
TOTAL Maintenance (Enter Total of lines 53 thru 57)..............
TOTAL Poffer Production Expenses-Hydraulic Po,ver (Enter Total of lines 50 and
D. Other Po,ver Generation
Operation
(546) Operation Supervision and Engineering.
(547) Fue|..........
(548) Generation Expenses......................
(549) Miscellaneous Other Poiver Generation Expenses...........
(550) Rents........
TOTAL Operation (Enter Total of lines 62 thru 66)..............
Maintenance
(551) Maintenance Supervision and Engineering.
(552) Maintenance c,f Structures....
(553) Maintefl ance of Generating and Electric P|ant..................
(554) Maintenance of Miscellaneous Other Po,ver Generation Plant...........................
TOTAL Maintenance (Enter Total of lines 69 thru 72)..............
TOTAL Pover Production Expens€s-Other Porer (Enter Total of lines 67 and 73)
E. Other Porer Supply Expens€s
(555) Purchased Pofler................
(556) System Control and Load Dispatching
(557) Other Expenses.....
TOTAL Other Pova Supply E&enses (Enter Total of lines 76 thru 78).. . . . . . .
TOTAL Pover Prcduction Expens€s (Enter Total of lines 21, 41, 59,74, and 79)..
2. TRANSMISSION EXPENSES
Operation
(560) Operation Supervision and Engineering.
(561 ) Load Dispatching........
(562) Station Expenses...........
(563) Overhead Line Expenses....
(564) Underground Line beenses.
(565) Transmission of Electricity by Others...........
(566) Miscellaneous Transmission Erpenses...........
(567) Rents........
TOTAL Operation (Enter Total of lines 83 thru 90)..............
Maintenance
(568) Maintenance Supervision and Engineering......
(569) Maintenance of Structures....
(570) Maintenance of Station Equipment..........
(57'l) Maintenance of Overhead Lines..............................
(572) Mainteflance d Underground lines.........................
(573) Maintenance of Miscellaneous Transmission Plant..
TOTAL Maintenance (Enter Total of lines 93 thru 98)..............
TOTAL Transmission Expenses (Enter Total of lines 91 and 99)...........................
3. DISTRIBUTION EXPENSES
Operation
(580) Operation Supervision and Engineering.
$90,009
1,090,583
786,880
1 ,795,1 1 8
2,699,480
111,688
1 ,1 65,830
629,906
2,100,451
2,244,052
$
6,462,071 6,251,928
41,873,665 38,782,570
658,619
36,174,281
3,987,044
944,800
0
706,592
39,851,771
3,969,924
772,208
0
41,764,744 45,300,494
217
320,820
567,680
2,'t31 ,303
0
383,507
121,306
2,645,297
3,020,021 3,1 50,1 1 0
44,784,765 48,450,604
233,048,178
2,762
55,329,959
229,010,441
2,562
(3,886,233)
288,380,900 225j26,770
520,61 8,298 488,852,047
3,0'16,021
4,680,012
2,764,669
1,024,360
4,356,342
24
4,577,995
2,825,373
4,493,749
2,523,821
912,113
5,295,921
7,148
3,960,6s1
20,419,423 20,018,776
1 48,1 35
924,202
1,843,040
845,567
3,214
162,4U
901,331
2,124,188
1,083,753
0
3,764,157 4,271,756
24,1 83,580 24,290,532
4,023,195 4,044,090
STATE OF IDA}IO
An Original December 3{, 2017ldaho Power Company
IDAHO SUPPLEMENT
Page 13
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount br previous year is not derived from previously reported figures, erplain in footnotes.
Lrne
No.Account
(a)
Amount for
Cunent Year
(b)
Amount br
Previous Year
(c)
104
105
106
107
108
109
110
1'.t1
112
113
114
115
116
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
1U
135
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
152
153
3. DISTRIBUTION ExPENSES (Continued)
(581) Load Dispatching........
(582) Station Expenses...........
(583) Overhead Line Expenses....
(584) Underground Line Expenses.
(585) Street Lighting and Signal System Epenses...........
(586) Meter Expenses...........
(587) Customer lnstallations E&enses...........
(588) Miscellaneous Distribution Expenses...........
TOTAL Operation (Enter Total of lines 103 thru 113)............
Maintenance
(590) Maintenance Supervision and Engineering.
(591 ) Maintenance of Structures....
(592) Maintenance of Station Equipment..........
(593) Maintenance of Overhead 1ines..................
(594) Maintenance of Underground Lanes..................
(595) Maintenance of Line Transficrmers.................
(596) Maintenance of Street Lighting and Signal Systems..
(597) Maintenance of Me{ers.........
(598) Maintenance of Miscellaneous Distribution P|ant..................
TOTAL Maintenance (Enter Total of lines 1'16 thru 124).............
TOTAL Distribution E&enses (Enter Total of lines 114 and 125)............
4. CUSTOMER ACCOUNTS EXPENSES
Operation
(901) Supervision
(902) Meter Reading Expenses
(903) Customer Records and Collection Expenses...........
(904) Uncollectible Accounts........
(905) Miscellaneous Customer Accounts Expenses....
TOTAL Customer Accounts Expenses (Enter Total of lines 129 thru 133).............
5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
Operation
(907) Supervision
(908) Custorner Assistance Epenses...........
(909) lnformational and lnstructional Expenses........
(91 0) Miscellaneous Customer Service and lnformational Expenses......
TOTAL Cust. Service and lnformational Epenses (Enter Total of lines 137 thru 14
6. SALES EXPENSES
Operation
(911) Supervision
(91 2) Dernonstrating and Selling Expenses...........
(91 3) Advertising Epenses.......................
(916) Miscellaneous Sales Expenses...........
TOTAL Sales Epenses (Enter Total of lines 144 thru '147).........
7, ADMINISTRATIVE AND GENERAL EXPENSES
Operation
(920) Administrative and General Sa|aries..............
(921) Otrce Supplies and Expenses...........
(Less) (922) Administrative Expenses Transferred-Credit...........
$3,999,053
1,489,990
4,549,577
3,563,678
113,144
4,737,753
1 , 180,48'l
6,583,446
364,520
3,863,491
1 ,489,97 1
3,341,544
3,034,028
78,799
4,553,1 70
829,907
7,194,670
291,921
$
30,604,836 28,721,590
(1,s71,512)
3,722,890
12,787,293
737,531
22,883
528,581
949,377
222,377
(1 ,487,577)
0
3,733,657
13,877,337
856,648
27,427
561,312
843,267
351,377
17,399,4 t 9 18,763,447
48,004,255 47,485,037
896,826
1,212,550
1 3,709, 1 89
5,331,296
(8e0)
584,522
1,291,407
'14,113,296
3,718,544
(521)
21,148,971 19,707,249
778.082
41,859,835
429,007
608,294
744,559
38,536,31 5
392,796
419,876
43,675,2',t8 40,093,546
23
23
75,372,652
13,472,038
(26,461,608)
77,526,927
14,066,090
(32,175,51 1)
STATE OF IDAHO
An Original December 31, 2017ldaho Power Company
IDAHO SUPPLEMENT
Page 14
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported figures, explain in fuotnotes.
Ltne
No.Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
154
't 55
156
157
158
159
160
161
162
163
164
165
166
167
168
169
7. ADMINISTRATIVE ANO GENERAL EXPENSES (Continued)
(923) Outside Services Employed....
(924) Property lnsurance...........
(925) lnjuries and Damages.....................
(926) Employee Pensions and Benefi ts..............
(927) Franchise Requirements.....
(928) Reg ulatory Com m ission Expenses...........
(929) Duplicate Charges-Cr....................
(930. 1 ) General Advertising Epenses....
(930. 2) Miscellaneous General Expenses.........
(931 ) Rents..................
TOTAL Operation (Enter Total of lines 151 thru 164)............
Maintenance
(935) Maintenance of General P|ant.........
TOTAL Admin and General Epenses (Enter Total of lines 165-167)
TOTALElecOpandMaintEpOotal of 80, 100, 126,'tU, 141,148, 168).....
$6,452,407
2,984,435
5,382,410
43,41 5,053
0
3,725,080
347,329
3,389,737
(335)
$7,833,'149
3,218,491
5,705,266
49,259,561
0
3,514,748
554,212
3,382,255
0
128,079,197 1 32,885,1 88
6,447,650 6,000,405
'134,526,848 1 38,885,592
$792,157,170 $759,314,027
ldaho Power Company
STATE OF IDAHO
An Original December 31, 2017
IDAHO ONLY
NUMBER OF ELECTRIC DEPARTMENT EMPLOYEES
1 . The data on number of employees should be reported for the payroll period ending nearest to October 31,
or any payroll period ending 60 days before or after October 31.
2. lfthe respondent's payroll for the reporting period includes any special construction personnel, include
such employees on line 3, and shoil the number of such special construction employees in a footnote.
3. The number of employees arisignable to the electric department frorn joint functions of combination utilities
may be determined by estimate, on the basis of employee equivalents. Shofl the estimated number of equiv-
alent employees attributed to the electric department from jcint functaons.
1 Payroll Period Ended (Date).December 31 , 201 6 December 31, 2017
'1,964
9
1,973
2 Total Regular Full-Time Employees....1,999
3 Total Part-Time and Temporary Employees.............10
4 Total Employees 2,009
IDAHO SUPPLEMENT
Page 15