2018Annual Report FERC Form.pdf

Pnc- E
Y ROCKY MOUNTAIN
FOWER
A OTVTSTON OF PACTFTCORP
May29,2019
VA OWRNIGHT DELIVERY
RECEIVED
l0lgttAY 29 Pll la 00
, r,,j?m:Jc!,?*h18 u' o *
1407 West North Temple, Suite 310
Salt Lake City, Utah 84116
Idaho Public Utilities Commission
472West Washington
Boise,ID 83702-5983
Attention:Diane Hanian
Commission Secretary
RE: FERC Form I
PacifiCorp (d.b.a. Rocky Mountain Power) submits for filing one copy of PacifiCorp's annual
FERC Form I report for the year ended December 31, 2018. An electonic copy of the report is
provided on the enclosed CD for your convenience.
PacifiCorp respectfully requests that all data requests regarding this matter be addressed to:
By email (preferred): [e-mail]
By regular mail Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR97232
Please direct any informal questions to Ted Weston, Regulatory Manager, at [phone].
Sincerely,
President,
G^"^-D
FJtu,ion
Enclosure
THIS FILING IS
Item 1: E] An lnitial(Original)
Submission
OR E Resubmission No. _
Form 1 Approved
OMB No.1902-0021
(Expires 1213112019)
Form 1-F Approved
OMB No.1902-0029
(Expires 1213112019)
Form 3-Q Approved
OMB No.1902-0205
(Expires 1213112019)
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory underthe Federal PowerAct, Sections 3,4(a), 304 and 309, and
18CFR141 .1 and14'1.400. Failuretoreportmayresultincriminal fines,civil penaltiesand
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Exact Legal Name of Respondent (Company)
PacifiCorp
Year/Period of Report
End of 20181Q4
FERG FORM No.1/3-Q (REV.02-04)
INSTRUCTIONS FOR FILING FERC FORM NOS.l and 3-Q
GENERAL INFORMATION
Purpose
FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others
(18 C.F.R. S 141.1). FERC Form No. 3-Q ( FERC Form 3-Q)is a quarterly regulatory requirement which supplements the
annualfinancial reporting requirement (18 C.F.R. S 141.400). These reports are designed to collect financial and
operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy
Regulatory Commission. These reports are also considered to be non-confidential public use forms.
ll. Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission's Uniform System of Accounts
Prescribed for Public Utilities and Licensees Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101),
must submit FERC Form 1 (18 C.F.R. S 141.1), and FERC Form 3-Q (18 C.F.R. S 141.400).
Note: Major means having, in each of the three previous calendar years, sales or transmission service that
exceeds one of the following:
(1) one million megawatt hours of totalannualsales,
(2) 100 megawatt hours of annual sales for resale,
(3) 500 megawatt hours of annual power exchanges delivered, or
(4) 500 megawatt hours of annualwheeling for others (deliveries plus losses)
ll!. What and Where to Submit
(a) Submit FERC Forms 1 and 3-Q electronically through the forms submission software. Retain one copy of each report
for your files. Any electronic submission must be created by using the forms submission software provided free by the
Commission at its web site: http://www.ferc.gov/docs-filinq/forms/form-1/elec-subm-soft.asp. The software is
used to submit the electronic filing to the Commission via the lnternet.
(b) The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
(c) Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the
latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to
the Secretary of the Commission at:
Secretary
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
(d) For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report
(not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can
be either eFiled or mailed to the Secretary of the Commission at the address above.
FERC FORM 1 & 3-Q (ED.0347)
t.
The CPA Certification Statement should
a) Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the
Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the
Chief Accountant's published accounting releases), and
b)Be signed by independent certified public accountants or an independent licensed public accountant
certified or licensed by a regulatory authority of a State or other political subdivision of the U. S. (See 18
C.F.R. SS 41.1041 .12for specific qualifications.)
Reference Schedules Paqes
Comparative Balance Sheet
Statement of lncome
Statement of Retained Earnings
Statement of Cash Flows
Notes to Financial Statements
110-113
114-117
118-119
120-121
122-123
e) The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions,
explained in the letter or report, demand that it be varied. lnsert parenthetical phrases only when exceptions are
reported.
"ln connection with our regular examination of the financial statements of _ for the year ended on which we have
reportedseparatelyunderdateof-,wehavealsoreviewedschedules
of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for
conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its
applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such
tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph
(except as noted below) conform in all material respects with the accounting requirements of the Federal Energy
Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases."
The letter or report must state which, if any, of the pages above do not conform to the Commission's requirements.
Describe the discrepancies that exist.
(f) Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling.
To further that effort, new selections, "Annual Report to Stockholders," and "CPA Certification Statement" have been
added to the dropdown "pick list" from which companies must choose when eFiling. Further instructions are found on the
Commission's website at http://urww.ferc.qov/help/how{o.asp.
(g) Federal, State and Local Governments and other authorized users may obtain additional blank copies of
FERC Form 1 and 3-Q free of charge from http://www.ferc.qov/docs-filinq/forms/form-1/form-1 .pdf and
http ://www. fe rc. q ovid o cs-fi I i n q/fo rms. as p#3 Q-q as .
lV. When to Submit:
FERC Forms 1 and 3-Q must be filed by the following schedule
FERC FORM 1 & 3-Q (ED.03-07)
a) FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR S 141.1),
and
b) FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. S
141.400).
V. Where to Send Comments on Public Reporting Burden.
The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,168
hours per response, including the time for reviewing instructions, searching existing data sources, gathering and
maintaining the data-needed, and completing and reviewing the collection of information. The public reporting burden for
the FERC Form 3-Q collection of information is estimated to average 168 hours per response.
Send comments regarding these burden estimates or any aspect of these collections of information,
including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426 (Attention: lnformation Clearance Officer); and to the Office of lnformation and Regulatory Affairs,
Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory
Commission). No person shall be subject to any penalty if any collection of information does not display a valid control
number (44 U.S.C. $ 3512 (a)).
IllFERC FORM 1 & 3-Q (ED.03-07)
GENERAL INSTRUCTIONS
l. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). lnterpret
all accounting words and phrases in accordance with the USofA.
ll. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and
figures per unit where cents are important. The truncating of cents is allowed except on the four basic financial statements
where rounding is required.) The amounts shown on all supporting pages must agree with the amounts entered on the
statements that they support. When applying thresholds to determine significance for reporting purposes, use for balance
sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the
current year's year to date amounts.
lll Complete each question fully and accurately, even if it has been answered in a previous report. Enter the
word "None" where it truly and completely states the fact.
lV. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not
Applicable" in column (d) on the List of Schedules, pages 2 and 3.
V. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the
header of each page is to be completed only for resubmissions (see Vll. below).
Vl. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must
be reported as positive. Numbers having a sign that is different from the expected sign must be reported by enclosing the
numbers in parentheses.
Vll For any resubmissions, submit the electronic filing using the form submission software only. Please explain
the reason for the resubmission in a footnote to the data field.
Vlll. Do not make references to reports of previous periods/years or to other reports in lieu of required entries,
except as specifically authorized.
lX. Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based
upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different
figures were used.
Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows
FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission
Service as described in Order No. 888 and the Open Access Transmission Tariff. "Self'means the respondent.
FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as
described in Order No. 888 and the Open Access Transmission Tariff.
LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and" firm"
means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse
conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access
Transmission Tariff. For all transactions identified as LFP, provide in a footnote the
FERC FORM { & 3-Q (ED.0347)lv
termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.
OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the
terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and "firm" means that service
cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all
transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either
buyer or seller can unilaterally get out of the contract.
SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point
transmission reservations, where the duration of each period of reservation is less than one-year.
NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is
intended to remain reliable even under adverse conditions.
OS - Other Transmission Service. Use this classification only for those services which can not be placed in the
above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC
Form. Describe the type of service in a footnote for each entry.
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.
FINITIONS
Commission Authorization (Comm. Auth.) - The authorization of the Federal Energy Regulatory Commission, or
other Commission. Name the commission whose authorization was obtained and give date of the authorization.
ll. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose
the report is made.
FERC FORM 1 & 3-Q (ED.03-07)v
EXCERPTS FROM THE LAW
Federal Power Act, 16 U.S.C. $ 791a{25r
Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:
(3)'Corporation'means any corporation, joint-stock company, partnership, association, business trust,
organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the
foregoing. lt shall not include 'municipalities, as hereinafter defined;
(4) 'Person' means an individual or a corporation;
(5) 'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act,
and any assignee or successor in interest thereof;
(7) 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or
agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or
distributing power; ......
(11) "project' means. a complete unit of improvement or development, consisting of a power house, allwater
conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit,
and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power
there from to the point of junction with the distribution system or with the interconnected primary transmission system, all
miscellaneous structures used and useful in connection with said unit or any part thereof, and allwater rights,
rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or
appropriate in the maintenance and operation of such unit;
"Sec. 4. The Commission is hereby authorized and empowered
(a) To make investigations and to collect and record data concerning the utilization of the water 'resources of any region
to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and
concerning the location, capacity, development -costs, and relation to markets of power sites; ... to the extent the
Commission may deem necessary or useful for the purposes of this Act."
"Sec. 304. (a) Every Licensee and every public utility shallfile with the Commission such annual and other periodic or
special* reports as the Commission may be rules and regulations or other prescribe as necessary or appropriate to assist
the Commission in the -proper administration of this Act. The Commission may prescribe the manner and FERC Form in
which such reports salt be made, and require from such persons specific answers to all questions upon which the
Commission may need information. The Commission may require that such reports shall include, among other things, full
information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due
and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the
project and other facilities, cost of renewals and replacement of the project works and other facilities, depreciation,
generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such
person to make adequate provision for currently determining such costs and other facts. Such reports shall be made
under oath unless the Commission otherwise specifies*.10
FERC FORM 1 & 3-Q (ED.0347)vt
"Sec. 309. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind
such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this Act. Among
other things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may
prescribe the FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the
Commission, the information which they shall contain, and the time within which they shall be field..."
General Penalties
The Commission may assess up to $1 million per day per violation of its rules and regulations. See
FPA $ 316(a) (200s), 16 U.S.C. $ 825o(a).
FERC FORM I & 3-Q (ED.0347)vil
FERC FORM NO. 1/3.Q:
IDENTIFICATION
01 Exact Legal Name of Respondent
PacifiCorp
02 Year/Period of Report
End of 20181Q4
03 Previous Name and Date of Change (if name changed during yeaf
tt
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
825 N.E. Multnomah Street, Suite 1900, Portland, OR97232
05 Name of Contact Person
Mark Reis
06 Title of Contact Person
Corporate Accounting Director
07 Address of Contact Person (Street, City, State, Zp Code)
825 N.E. Multnomah Street, Suite 1900, Portland, OR97232
08 Telephone of Contact Persontncluding
Area Code
(503) 813-685e
09 This Report ls
(1)[ An Original
10 Date of Report
(Mo, Da, Yr)
tt
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accounts.
01 Name
Nikki L. Kobliha
02 Title
Vice President, CFO and Treasurer
03 Signature
Nikki L. Kobliha (Signature on file)
04 Date Signed
(Mo, Da, Yr)
04112t2019
Title '18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as lo any matter within its jurisdiction.
FERC FORM No.1/3-Q (REV. 02-041 Page 1
(2) n A Resubmission
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]en originat(2\ TIA Resubmissiontt
Date of Reoort(Mo, Da, Yi)Year/Period of Report
End of 2018tQ4
LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
1 General lnformation 101
2 Control Over Respondent 102
2 Corporations Controlled by Respondent 103
4 Ofiicers 't04
5 Directors 105
6 lnformation on Formula Rates 1 06(axb)
7 lmportant Changes During the Year 1 08-1 09
8 Comparative Balance Sheet 110-113
I Statement of lncome for the Year 114-117
10 Statement of Retained Earnings for the Year 118-119
11 Statement of Cash Flows 120-121
12 Notes to Financial Statements 122-123
13 Statement of Accum Comp lncome, Comp lncome, and Hedging Activities 122(a)(b)
14 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
15 Nuclear Fuel Materials 202-203 NA
16 Electric Plant in Service 204-207
17 Electric Plant Leased to Others 213 NA
'18 Electric Plant Held for Future Use 214
19 Construction Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Electric Utility Plant 2'.t9
21 lnvestment of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowances 228(ab)-229lab)
24 Extraordinary Property Losses 230 NA
25 Unrecovered Plant and Regulatory Study Costs 230 NA
26 Transmission Service and Generation lnterconnection Study Costs 231
27 Other Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accumulated Deferred lncome Taxes 234
30 Capital Stock 250-251
3'r Other Paid-in Capital 253
32 Capital Stock Expense 254
33 Long-Term Debt 256-257
u Reconciliation of Reported Net lncome wilh Taxable lnc for Fed lnc Tax 261
35 Taxes Accrued, Prepaid and Charged During the Year 262-263
36 Accumulated Deferred lnvestment Tax Credits 266-267
FERC FORM NO.1 (ED.12-96)Page 2
Name Respondent
PacifiCorp (1)
(2)Resubmission
Date of Report(Mo, Da, Yr)
tl
Year/Period of Report
End of 2018tQ4
continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
37 Other Deferred Credits 269
38 Accumulated Deferred lncome Taxes-Accelerated Amortization Property
39 Accumulated Deferred lncome Taxes-Other Property 274-275
40 Accumulated Deferred lncome Taxes-Other 276-277
41 Other Regulatory Liabilities 278
42 Electric Operating Revenues 300-301
43 Regional Transmission Service Revenues (Account 457.1)302 NA
44 Sales of Electricity by Rate Schedules 304
45 Sales for Resale 310-3'1 '1
46 Electric Operation and Maintenance Expenses 320-323
47 Purchased Power 326-327
48 Transmission of Electricity for Others 328-330
49 Transmission of Electricity by ISO/RTOs 331 NA
50 Transmission of Electricity by Others 332
51 Miscellaneous General Expenses-Electric
52 Depreciation and Amortization of Electric Plant 336-337
53 Regulatory Commission Expenses 350-351
54 Research, Development and Demonstration Activities 352-353
55 Distribution of Salaries and Wages 354-355
56 Common Utility Plant and Expenses 356 NA
57 Amounts included in ISO/RTO Settlement Statements 397
58 Purchase and Sale of Ancillary Services 398
59 Monthly Transmission System Peak Load 400
60 Monthly ISO/RTO Transmission System Peak Load 400a NA
6'l Electric Energy Account 401
62 Monthly Peaks and Output
63 Steam Electric Generating Plant Statistics 402403
64 Hydroelectric Generating Plant Statistics 406407
65 Pumped Storage Generating Plant Statistics 408-409 NA
66 Generating Plant Statistics Pages 410411
FERC FORM NO.I (ED.,t2-96)Page 3
272-273
335
401
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn original(2\ r-'rA Resubmissiontt
Date of Reoort(Mo, Da, Yi)
tt
Year/Period of Report
End of 20181Q4
continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
67 Transmission Line Statistics Pages 422423
68 Transmission Lines Added During the Year 424-425
69 Substations 426427
70 Transactions with Associated (Affi liated) Companies 429
71 Footnote Data 450
Stockholders' Reports Check appropriate box:
I Two copies will be submitted
I No annual report to stockholders is prepared
FERC FORM NO.1 (EO.12-96)Page 4
Name of Respondent
PacifiCorp
This Report ls:
(1) tr An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
ll
Year/Period of Report
End of 2018tQ4
GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
Nikki L. xobliha, Vice Preeident, chief Financial officer and Treaaurer
825 N.E. Multnomah St.reet, Suite 1900
Portland, OR 97232
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, give reference to such law. lf not incorporated, state that fact and give the type
of organization and the date organized.
3. lf at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not applicable.
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
Pacificorp ie a United SlateB regulatsed electsric utility company headquartered in Oregon that Bervea 1.9
million retail electric cuatomerB, including resident,ial, conunercial, indugtrial, irrigation and other
cuatomerB in portione of utsah, oregon, gfyoming, waahingt.on, rdaho and CalifornLa. Pacificorp is
principally engaged in the bueiness of generating, transmit,ting, distsributing and selling electricitsy. In
addit,ion Eo retail aalea, PacifiCorp buys and se116 electricity on the vrholesale marke! with other
utilitieB, energy marketing compaaiee, fi.nancial instiEutions and other market part,icipante. Pacificorp
detivere electricity to cuBtomers in Ut,ah, Wlroming and Idaho under tshe trade name Rocky Mountain Power
and tso cuatomers in Oregon, washington and California under the lrade name Pacific Power.
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?
...Enter the date when such independent accountant was initially engaged:(1) tr Yes
(2) E No
FERC FORM No.l (ED. 12-87)PAGE 101
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
Q\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
20't8tQ4
FOOTNOTE DATA
101 Line No.:1 Column: ltem 2
Pac Corp was t v ncorporate 1910 r aws t state o Mathe name Pacific Power & Light Company. In 1984, Pacific Power & Light Company changed its
name to PacifiCorp. In 1989, iE merged wit.h Utah Power and Light Company, a Utahcorporation, in a transaction wherein boEh corporaEions merged int.o a newly formed Oregoncorporat.ion. The resulting Oregon corporation was re-named PacifiCorp, which is theoperating entity today.
FERC FORM NO.I (ED. 12-871 Paqe 450.1
Name of Respondent
PacifiCorp
This Report ls:
(1) tr An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 2018tQ4
CONTROL OVER RESPONDENT
1. lI any corporation, business trust, 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
which control was held, and e)dent 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 trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
Berkshire Hathaway lnc.(a)
Berkshire Hathaway Energy Company ('BHE") (100%)
PPW Holdings LLC (100% controlled by BHE)
Pacificorp (100% of common stock held by PPW Holdings LLC)
(a) Berkshire Hathaway lnc., Mr. Walter Scott, Jr., a member of BHE's Board of Directors (along with his family members and
related or affiliated entities) and Mr. Gregory E. Abel, BHE's Executive Chairman, beneflcially own 90.9%, 8.1% and 1.0%,
respectively, of BHE's voting common stock.
FERC FORM NO.1 (ED. 12-96)Page 102
PacifiCorp (1)
(2)
An Original
A Resubmission
(Mo, Da,lt
Year/Period of
End of
Report
2018/Q4
CORPORATIONS CONTROLLED BY RESPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. 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 jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. lndirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual
agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the
Uniform System of Accounts, regardless of the relative voting rights of each party.
Line
No.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent Voting
Stock Owned
(c)
Footnote
Ref.
(d)
1 Mining 100.00
2 Fossil Rock Fuels, LLC Mining 100.00
3 Mining 100.00
4 lnteMest Mining Company Management services 100.00
5 Management services 100.00
6 Mining 66.67
7 Mining 21.40
I PacifiCorp Foundation Non-profit foundation
I
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO. r (ED. r2.96)Page 103
Energy West Mining Company
Glenrock Coal Company
Pacific Minerals, lnc.
Bridger Coal Company
Trapper Mining Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Pase: 103 Line No.: 1 Column: a
Schedule Page: 103 Line No.:3 Column: a
103 Line No.: 5 Column: a
WeSI ceas ons 20L5
Glenrock Coal ceased ons in 1999
Pac i f i-c
ownershi
s, Inc. is a who11y owned subsidiary o Pac t a 66.672interest in Bri Coal
Brj-dger Coa Company s a coal mining joint venture Energy Resources Company, asubsidiary of Idaho Power Company, and is jointly controfled by Pacific Minerals, Inc. and
fdaho Resources
PacifiCorp SA nor ty owner in Trapper ng Inc., a coopera ve members are SaltRiver Project Agricultural Improvement and Power District (32.10?), Tri-State Generationand Transmission Association, Inc. (26.57v.), PacifiCorp (21,.40%) and Platte River PowerAuthori(r_9.93?)
The Pac fiCorp Founda on san t non-profit foundation created by PacifiCorpl-988. The PacifiCorp Foundation operates as the Rocky Mountain Power Foundation and thePacific Power Foundation. As of December 3L,20l-8, the Foundationrs two di-rectors, arealso directors of PacifiCorp.
FERC FORM NO. I (ED. 12-871 Page 450.1
103 Line No.: 6 Column: a
103 Line No.:7 Column: a
103 Line No.:8 Column: c
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5l1Rn originat(2) [A Resubmission
Date of ReDort(Mo, Da, Yi)
tt
Year/Period of Report
2018tQ4End of
OFFICERS
1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officef' 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 remuneration of the previous
incumbent, and the date the change in incumbency was made.
Line
No.
Trtle
(a)
Name ot otficer
(b)
salarvfor Yedr(c)
1
2 Chairman of the Board of Directors
3 and Chief Executive Officer, PacifiCorp
4
5 President and Chief Executive Officer,
6 Pacific Power Stefan A. Bird 355,000
7
I President and Chief Executive Ofiicer,
9 Rocky Mountain Power 315,570
10
11 Vice President, Chief Financial Officer and Treasurer,
12 PacifiCorp Nikki L. Kobliha 224,510
13
14 Former Chairman of the Board of Directors
15 and Chief Execulive Officer, PacifiCorp
'16
17 Former President and Chief Executive Officer,
18 Rocky Mountain Power 355,000
19
20
2',!
22
z5
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (ED. 12-96)Page 104
\Mlliam J. Fehrman
Gary W. Hoogeveen
Gregory E. Abel
Cindy A. Crane
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
20't8tQ4
FOOTNOTE DATA
104 Line c
104 Line No.:3 Column: b
Pac f Corp sets forth compensat n ormat or ts rl execut veo cers" for theyear ended December 31, 201,8, consistent with ltem 402 of Regulation S-K promulgated by
the Securities and Exchange Commission, in its Annual Report on Form 10-K. Salaryinformation of other officers will be provided to the Federal Energy Regulatory Commission
upon request, but the company considers such information personal and confidential to such
officers . See 18 C. F. R. S388 . 107 (d) ( f ) .
On rTanuary 10, 2018, William rI . Fehrman was elected as Pacif Corp t sof Directors and Chief Executive Officer and Gregory E. Abef resigned as
Chairman of the Board of Directors and Chief Executive officer.
Wiltiam .f. Fehrman received no direct compensation from Pacificorp. PacifiCorp reimbursedits indirect parent company, Berkshire Hathaway Energy Company (trBHEn), for the cost of
Mr. Fehrman's time spent on maLLers supporting Pacificorp, including compensation paid to
him by BHE, pursuant to an intercompany administrative services agreement among BHE andits subsidiaries. For further information on executive compensation, refer to BHE's Annual
on Form 10-K, for the r ended December 31 20]-8.
Gary w. Hoogeveen succeeded C A. Crane as pres dent and ef execut ve cer
Rocky Mountain Power and was elected as a direcLor of PacifiCorp during 20l-8. For further
information, refer to Item l-3 in rtant the Year in this Form No. 1
Gregory E. Abel rece no rect compensat rom Pac Corp.2018, Pac Corp
did not incur reimbursements to BHE, for the cost of Mr. Abel's time spent on matters
supporting PacifiCorp, including compensation paid to him by BHE, pursuant to an
intercompany administrative services agreement. For further information on executive
compensation, refer to BHE's Annual Report on Form 10-K, for the year ended December 31,
201,8 .
Cindy A. Crane,ormer pres and ef execut ve off cer of Rocky Mount n Power,
resigned as director and employee of Pacificorp on February 4, 2019. For further
i-nformation, refer to Item 13 in Important Changes During the Year in this Form No. 1
FERC FORM NO. 1 1 450.'1
rman of the Board
PacifiCorp's
104 Line No.:9 Column: b
104 Line No.: 15 Column: b
104 Line No.: 18 Column: b
Name of Respondent
PacifiCorp (2)Resubmission
Date of Report(Mo, Da, Yr)
tl
Year/Period of Report
End of 2018tQ4
DIRECTORS
1 . Report below the information called for concerning each director of the respondent who held oflice at any time during the year. lnclude in column (a), abbreviated
titles of the directors who are officers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
LIIIENo.ness Address
)
1 PacifiCorp Board of Directors as of December 31, 2018:
2
J
4 (Chairman of the Board of Directors and CEO, PacifiCorp)666 Grand Avenue, 27th Floor, Des Moines, lA 50309
5
6 Stefan A. Bird
7 (President and CEO, Pacific Power)825 N.E. Multnomah Street, Suite 2000, Portland, OR 97232
I
I
10 (President and CEO, Rocky Mountain Power)1407 West North Temple, Suite 310, Salt Lake City, UT 84116
1',!
12 Nikki L. Kobliha
13 (VP, CFO and Treasurer, PacifiCorp)825 N.E. Multnomah Street, Suite 1900, Portland, OR97232
14
15 Patrick J. Goodman 666 Grand Avenue, 27th Floor, Des Moines, lA 50309
16
17 Natalie L. Hocken 825 N.E. Multnomah Street, Suite 2000, Portland, OR 97232
18
19 '1407 West North Temple, Suite 310, Salt Lake City, UT 84116
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
FERC FORM NO. r (ED. 12-95)Page '105
rnnctpat E t
\Mlliam J. Fehrman
Gary W. Hoogeveen
Cindy A. Crane
Name of Respondent
PacifiCorp
This Report is:
(1) XAn OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
20't8tQ4
FOOTNOTE DATA
105 Line No.: 3
On .January 10, 201-8, Gregory E res as Pac f Corp's Cha of the Board ofDirectors and Chief Executive Officer and Wi11iam,J. Fehrman was elected as Pacificorp's
Chairman of the Board of Directors and Chief Executive officer.
Schedule Page: 105 Line No;9 Column: a
Gary W. Hoogeveen s c A. Crane as pres t execut ve cer
Rocky Mountain Power and was elected as a director of PacifiCorp during 201-8. For furtherinformationrefer to Item 13 in Dur the Year in this Form No. 1.
C A. Crane, former pres execut veo f cer of Power,resigned as director and employee of Pacificorp on February 4, 201,9. For furtherinformation, refer to Item l-3 in Tmportant Changes During the Year in this Form No. 1
FERC FORM NO. r (ED. 12-871 Page 450.1
105 Line No.: 19 Column: a
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of ReDort
(Mo, Da, Yi)tt
Year/Period of Report
966 61 2018/Q4
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent have formula rates?I ves
ENo
1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No)
accepting the rate(s) or changes in the accepted rate.
Line
No.FERC Rate Schedule or Tariff Number FERC Proceeding
I FERC Electric Tariff Volume No. 1 1 , Attachment H-l ER1 1-3643
2
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
3'1
32
33
34
35
36
37
38
39
40
41
FERC FORm NO. I (NEW. 12-08)Page 106
Name of Respondent
PacifiCorp
This ReDort ls:
(1) E] An original
(2) l-l A Resubmission
Date of ReDort(Mo, Da, Yi)
tt
Year/Period of Report
En6 e1 2018/Q4
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent)
filings containing the inputs to the formula rate(s)?I Yes
ENo
2. lf yes, provide a listing of such filings as contained on the Commission's eLibrary website
Line
No.Accession No.
Document
Date
\ Filed Date Docket No.Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
1 20180323-5024 03t23t2018 ER11-3&43
2 201 80330-51 1 8 03/30/201 8 ER1 8-1 243
3 201 8051 5-5352 05t15t2018 ER11-3643
4
5
6
7
8
o
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO.1 (NEW 12-08)Page 106a
Name of Respondent
PacifiCorp
This Report is:
(1) X An Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
2018/Q4
FOOTNOTE DATA
1061 Line No.:1 Column: d
1061 Line No.: 1 Column: e
1061 Line No.: 2 Column: d
Pac f Corp ts tar ff f 1 per 35 . 19a (b FERC t Refund Report to be effect ve
N A under FERC Docket No. ER11-3643
Pac f 's Volume No. 1l-en Access Tr SS on ff
Pac f Corp submits t ff fi1 per 35.13(a) (2) (iii): OATT Revised Attachment H-1
Revised ciation Rates 2018) to be effective 6/1/2018 under FERC Docket No. ER18-1243
Pac f 's Volume No. 11 Access Transmission Tariff
Transmission Formula Rate Annual Update lnformational Filing of PacifiCorp under FERC
Docket No. ER11-3643
PacifiCorp's Volume No. l-1 Open Access Transmiss on Tar
FERC FORM NO.1 1 4s0.1
1061 Line No.:2 Column: e
1061 Line No.:3 Column: d
1061 Line No.: 3 Column: e
Name of Respondent
PacifiCorp
This Reoort ls:
(1) E An Original(2)n A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
gn6 61 2018/Q4
INFORMATION ON FORMULA RATES
Formula Rate Variances
1. lf a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from
amounts reported in the Form 1.
2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the
Form'1.
3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items
impacting formula rate inputs differ from amounts reporled in Form 1 schedule amounts.
4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line
No.Page No(s).Schedule Column Line No
1 204-207 Electric Plant in Service (b)5
2 204-207 Electric Plant in Service (b)46
3 204-207 Electric Plant in Service (s)46
4 204-207 Electric Plant in Service (b)75
q 204-207 Electric Plant in Service (s)75
6 204-207 Electric Plant in Service (b)99
7 204-207 Electric Plant in Service (s)99
8 204-207 Electric Plant in Service (b)104
I 204-207 Electric Plant in Service (s)104
10 219 Accum. Prov. for Depr. of Electric Utility Plant (c)20
11 219 Accum. Prov. for Depr. of Electric Utility Plant (c)22
12 219 Accum. Prov. for Depr. of Electric Utility Plant (c)24
13 219 Accum. Prov. for Depr. of Electric Utility Plant (c)25
14 219 Accum. Prov. for Depr. of Electric Utility Plant (c)26
15 219 Accum. Prov. for Depr. of Electric Utility Plant (c)28
'16 219 Accum. Prov. for Depr. of Electric Utility Plant (c)29
17 320-323 Electric Operation and Maintenance Expenses (b)'185
18 320-323 Electric Operation and Mainlenance Expenses (b)197
19 336-337 Depreciation and Amortization of Electric Plant (d)1
20
21
22
23
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30
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32
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36
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40
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42
43
44
FERC FORM NO. I (NEW. 12-08)Page 106b
Name of Respondent
PacifiCorp
This Report ls:(1) E An Original(2) [ A Resubmission
Date of Report
tt
Year/Period of Report
End of 20181Q4
I M PORTANT C HAN GES DU RI N G THENARTEFWBR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. lf
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. lf acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactlons, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and
reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were
submitted to the Commission.
4. lmportant leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. lmportant extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers
added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new
continuing sources of gas made available to it from purchases, development, purchase contract or otheruise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments,
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Page 104 or 105 of the Annual Report Form No. 'l , voting trustee, associated company or known
associate of any of these persons was a party or in which any such person had a material interest.
1 1. (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 furnish 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 the respondent that may have occurred
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
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash
management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE lOS INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO. I (ED.12-96)Page 108
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
IMPORTANT CHANGES DURING THE QUARTERTYEAR (Continued)
ITEM 1.
The following table includes new or modified franchise agreements. The fee represents the fee attached to the franchise agreement.
State Effective Date Expiration Date Fee
California(l)
None
Idahq(2)
Ririe 0711212018 07112/2028
Oreeon(3)
Arlington
Bend
Chiloquin
Eagle Point
Lyons
Merrill
Monroe
Stanfield
Talent
utah(a)
Bluff
Brigham City
Cedar Highlands
Clinton
Deweyville
Farr West
Fruit Heights
Herriman
Iron County
Lehi
Minersville
Naples
Roy
Sunset
Taylorsville
Washington Terrace
12120t2018
05/0 l/201 8
06t0u2018
0510U2018
12t01/20t8
09t0112018
0711912018
0810y2018
tlt0u20t8
06/1y2018
04/1612018
0s/01/2018
04/0u2018
04115t2018
08/18/2018
tzt2U20t8
0y0y2018
02t27t2018
04n7t2023
06t30t2019
05109t2028
07123t2023
1012412038
03n6t2028
09t12t2038
03t26t2032
04/20t2028
1212012038
0510U2028
0610U2028
0s10U2028
12t0U2028
0910U2028
0711912038
0810U2038
11t0y2033
06111t2023
04t16t2028
05t01t2028
0410112028
0411512028
0811812028
12t2y2028
3.5Yo
5.0yo
3.5%
7.0Yo
3.5Yo
5.0%
5.0Yo
7.0%
7.0%
7.0Yo
l.0Yo
Washington(4)
None
Wvomins(S)
Casper
Evanston
0y0y2038
02127/2043
(l)
(2\
(3)
(4)
(s)
In Califomia, franchise agreenrent fees are an expense to PacifiCorp and are enrbedded in rates.
In Idaho, PacifiCorp collects franchise agreement fees from customers and remits them directly to the applicable municipalities.
In Oregon, the first 3.5% ofthe franchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 3.5%o is collected fronr
customers and remitted directly to the applicable municipalities. The franchise agreement for Bend, Oregon is an extension ofthe agreement effective August
31,2007, for which the agreement is expected to be modified by the expiration date.
In Utah and Washington, PacifiCorp collects associated taxes fiom customers and remits then directly to the applicable municipalities.
In Wyoming, the first 1.0% of the franchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 1.0Yo is collected
from customers and remitted directly to the applicable municipalities. The franchise agreement fee for Casper, Wyoming is expected to be reduced to 5.0o/o,
after four years.
FERC FORM NO. I (ED.12-96)Page 109.1
0411712018
1212112018
05t09t2018
07/23/2018
1012412018
03t16t2018
0911212018
11t17 t2018
04t20t2018
Name of Respondent
PacifiCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
IMPORTANT CHANGES DURING THE QUARTERTYEAR (Continued)
ITEM 2.
None.
ITEM 3.
None.
ITEM 4.
None.
ITEM 5.
In May 201 8, PacifiCorp filed an update to its 2017 Integrated Resource Plan ("IRP") with state commissions, originally filed in April
2017. The updated IRP which discusses the Energy Vision 2020 project ("Energy Vision 2020"), includes investments in renewable
energy resources, upgrades to PacifiCorp's existing wind fleet, energy efficiency measures to meet future customer needs and
incorporates building an additional transmission line segment to facilitate the expansion of wind generation. Collectively, these
resources contribute to meeting the capacity need identified in PacifiCorp's updated load-and-balance and are on track to be in service
by the end of 2020 . The transmission segment included in Energy Vision 2020 is part of the Energy Gateway Transmission expansion
program and PacifiCorp plans to construct 140 miles of 500kV transmission line between Aeolus and BridgeriAnticline, to be placed
in-service in2020.
Refer to pages 424-425, Transmission lines added or altered during the year, in this Form No. I for additional information regarding
transmission lines added or removed during the year ended December 3 I , 2018.
ITEM 6.
Short-term Debt
Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of December 31,2018, PacifiCorp had $30 million of
short-term debt outstanding at a weighted average interest rate of2.85%o.
Commission authorizations currently for up to $1.5 billion outstanding at any one time in commercial paper and other unsecured
short-term debt are as follows:
Federal Energy Regulatory Commission - Docket No. ES l8-3-000, dated December 20,2017,letter order effective January
1 , 201 8 through December 31,2019.
Idaho Public Utilities Commission ("IPUC") - Case No. PAC-E-16-03, Order No. 33476, dated March 4, 2016, effective
through April30,202l.
o Oregon Public Utility Commission ("OPUC") - Docket No. UF-4120, Order No. 98-158, dated April 16, 1998.
o Washington Utilities and Transportation Commission ("WUTC") - Docket No. UE-980404, dated April 8, 1998.
For further discussion, refer to Note 6 of Notes to Financial Statements, in this Form No. l.
a
EEECjORM NO. I (ED. 12-e6)Page 109.2
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
lYear/Period of Report
II 2uata4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
Longlerm Debt
In March 2019, PacifiCorp issued $400 million of its 3.500% First Mortgage Bonds due June 2029 and $600 million of its 4.150%
First Mortgage Bonds due February 2050. PacifiCorp used a portion of the net proceeds to repay short-term debt that was partially
incurred to repay all of PacifiCorp's $350 million 5.50% First Mortgage Bonds due January 2019. PacifiCorp intends to use the
remaining net proceeds to fund capital expenditures and for general corporate purposes.
PacifiCorp had regulatory authority from the OPUC and the IPUC to issue $2.0 billion of long-term debt, as of December 31, 2018.
PacifiCorp must make a notice filing with the WUTC prior to any future issuance. As of December 3 I , 201 8, PacifiCorp cunently had
an effective shelf registration statement with the United States Securities Exchange Commission to issue up to $2.0 billion additional
first mortgage bonds through October 2021.
State commission authorizations for the above issuance and future issuances are as follows:
IPUC - Case No. PAC-E-18-10, OrderNo. 34205, dated December7,2018, effective through September 30,2023
OPUC - Docket No. UF-4304, Order No. l8-452, dated December 4,2018
InJuly2018,PacifiCorpissued$600millionofits4.1250 FirstMortgageBondsdueJanuary2049.PacifiCorpusedaportionofthe
net proceeds to repay all of PacifiCorp's $500 million 5.65% First Mortgage Bonds due July 2018 and used the remaining net
proceeds to fund capital expenditures and for general corporate purposes. State commission authorizations for this issuance are as
follows:
a
a
IPUC - Case No. PAC-E-14-05, Order No. 33083, dated July 29,2014.
OPUC - Docket No. UF-4288, Order No. 14-268, dated July 22,2014.
PacifiCorp made repayments on long-term debt, excluding repayments for lease obligations, totaling $586 million during the year
ended December 3 l, 201 8.
PacifiCorp's Mortgage and Deed of Trust creates a lien on most of PacifiCorp's electric utility property, allowing the issuance of
bonds based on a percentage of utility property additions, bond credits arising from retirement of previously outstanding bonds or
deposits of cash. The amount of bonds that PacifiCorp may issue generally is also subject to a net earnings test. As of December 31,
2018, PacifiCorp estimated it would be able to issue up to $10.3 billion of new first mortgage bonds under the most restrictive
issuance test in the mortgage. Any issuances are subject to market conditions and amounts may be furlher limited by regulatory
authorizations or commitments or by covenants and tests contained in other financing agreements. PacifiCorp also has the ability to
release property from the lien ofthe mortgage on the basis ofproperty additions, bond credits or deposits ofcash.
For further discussion, refer to Note 7 of Notes to Financial Statements, in this Form No. I
ITEM 7.
None.
a
FERC FORM NO.1 (ED.12-96)Page 109.3
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
IMPORTANT CHANGES DURING THE QUARTERTYEAR (Continued)
ITEM 8.
For the year ended December 3l, 2018, PacifiCorp's bargaining unit wage scale changes were as follows:
Unions Represented 7o Increase(l) Effective Date(s)
Estimated Annual
Financial Impact(2)
IBEW 57 Combustion Turbine (UT)
IBEW 57 Laramie (WY)
IBEW 57 Power Delivery (UT, ID & WY)
IBEW 57 Power Supply (UT,ID & WY)
rBEW 77 (WA)
IBEW 125 (OR, WA)
IBEW 125 (OR, WA)
rBEW 6s9 (OR, CA)
uwuA 127 (WY)
uwuA 197 (oR)
Total
1.86%
1.04o/o
7.83o/o
1.86%
2.10%
2.33%
0.20%
1.37o/o
0.71%
r.20%
01126120r8
0612612018
0U2612018
0U2612018
0t/2612018
0y2612018
t2lty2018
0412612018
0912612018
05t2612018
$59,125
5,854
1,497,243
694,2t1
24,084
621,398
5 1,038
435,317
324,013
18,358
$3,724,641
(l)This percentage increase represents the increase in wages from the effective date ofthe increase to the end ofthe calendar year as compared to the wage scale
ofthe prior calendar year.
(2)The estimated annual impact is based on the time period from the effective date of the increase to the end of the calendar year. Some amounts may be
reimbursed by joint owners.
ITEM 9.
Refer to Note l3 of Notes to Financial Statements, in this Form No. I for information regarding certain legal proceedings affecting
PacifiCorp.
ITEM IO.
For the year ended December 31, 2018, Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp, declared and paid a dividend
of $18.0 million to PacifiCorp. In addition, Fossil Rock Fuels, LLC, a wholly owned subsidiary of PacifiCorp, distributed $5.4 million
of dividends, consisting of $2.7 million unappropriated retained eamings distribution and $2.7 million return of capital to PacifiCorp.
Refer to page 429, Transactions with associated (affiliated) companies, in this Form No. I for information regarding related-party
transactions.
There have been no officer, director or security holder transactions during the year ended December 31, 2018, other than preferred
and common stock dividends declared and paid.
ITEM 11.
(Reserved.)
ITEM 12.
None.
FERC FORM NO.1 (ED.12-96)Page 109.4
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
ITEM 13.
On February 4, 2019, Cindy A. Crane, former president and chief executive officer of Rocky Mountain Power, a division of
PacifiCorp, resigned as director and employee of PacifiCorp.
During 2018, Gary W. Hoogeveen succeeded Cindy A. Crane as president and chief executive offrcer of Rocky Mountain Power. Mr,
Hoogeveen was elected as a director of PacifiCorp on November 19,2018.
On January 10,2018, Gregory E. Abel resigned as PacifiCorp's Chairman of the Board of Directors and Chief Executive Officer and
William J. Fehrman was elected as PacifiCorp's Chairman of the Board of Directors and Chief Executive Officer.
ITEM 14.
Not applicable.
FERC FORM NO.1 (ED.12.96)Page 109.5
Deloitte.Dcloittc I Touche LLP
U.S, Brncorp Towrr
111 Soulhh,est Fifth Avenue
Suite 3900
Portl.nd, OR 97204-3642
USA
T;l:[phone]:,
Fax:+l 5O3 224 2172
www.dclolttc.com
INDEPENDENT AUDITORS' REPORT
PacifiCorp
Portland, Oregon
We have audited the accompanying financial statements of PacifiCorp (the'Company"),
which comprise the balance sheet-regulatory basis as of Decernber 31, 2018, and the
related statements of income-regulatory basis, retained earnings-regulatory basis, and
cash flows-regulatory basis for the year then ended, included on pages 110 through 123 of
the accompanying Federal -nergy R.egulatory Commission Form 1, and the related notes to
the financial statements.
Managenrent's Responsihility for tlre Financial Statements
Management is responsible for the preparation and fair presentation of these financial
statements in accordance arith 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 maantenance
of internal control relevant to the preparation and fair presentation of financial statements
that are free from materia! 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 audlt 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 tlre
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
Companyk intemal 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.
0piniorr
In our opinion, the regulatory-basis financial statements referred to above present fairly, in
all material respects, the assets, liabilities, and proprietary capital of PacifiCorp as of
December 31, 2018, 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 2 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
rnanagement 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.
iorTi( +ffit uu?
April 12, 2019
Name of Respondent
PacifiCorp
This Report ls:
(1) tr An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
End of 2018tQ4
COMPARATIVE BAIANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Cunent Year
End of QuarterfYear
Balance
(c)
Prior Year
End Balance
12t31
(d)
1 UTILITY PLANT
2 Utility Plant (101-106, 114)200-201 28,425,063,446 27,861,824,875
3 Construction Work in Progress (107)200-201 1,194,168,876 676,995,960
4 TOTAL Utility Plant (Enter Total of lines 2 and 3)29,619,232,322 28,538,820,835
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 1 1 0, 1 I 1, 1 15)200-201 11,032,877,405 10,301,826,872
6 Net Utility Plant (Enter Total of line 4 less 5)18,586,354,917 18,236,993,963
7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)202-203 0 0
I Nuclear Fuel Materials and Assemblies-Stock Account (120.2)0 0
Nuclear Fuel Assemblies in Reactor (120.3)0 0
10 Spent Nuclear Fuel (120.4)0 0
11 Nuclear Fuel Under Capital Leases (120.6)0 0
12 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)202-203 0 0
13 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)18,586,354,917 18,236,993,963
15 Utility Plant Adjustments (1 16)0 0
16 Gas Stored Underground - Noncurrent (1 '17)0 0
17 OTHER PROPERTY AND INVESTMENTS
'18 Nonutility Property (121)13,578,986 13,710,649
19 (Less) Accum. Prov. for Depr. and Amort. (122)3,149,894 3,045, I 38
20 lnvestments in Associated Companies (123)69,928 69,928
21 lnvestment in Subsidiary Companies (123.1)224-225 '183,401,017 186,007,067
22 (For Cost of Account 1 23. 1, See Footnote P age 224, line 42)
23 Noncunent Portion of Allowances 228-229 0 0
24 Other lnvestments (1 24)95,479,061 97,005,097
25 Sinking Funds (125)0 0
26 Depreciation Fund (126)0 0
27 Amortization Fund - Federal (127)0 0
28 Other Special Funds (128)14,919,564 5,835,163
29 Special Funds (Non Major Only) (129)0 0
30 Long-Term Portion of Derivative Assets ('175)2,565,604 766,962
31 Long-Term Portion of Derivative Assets - Hedges ('176)0 0
32 TOTAL Other Property and lnvestments (Lines 18-21 and 23-31)306,864,266 300,349,728
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds (Non-major Only) (130)0 0
35 Cash (131)20,006,166 4,805,006
36 Special Deposits (1 32-134)0 9,003,656
37 Working Fund (135)0 0
38 Temporary Cash lnvestments (136)49,330,12',1 8,735,365
39 Notes Receivable (141)5,068,150 2,730,593
40 Customer Accounts Receivable (142)426,619,902 419,318,429
41 Other Accounts Receivable (143)48,930,705 46,887,023
42 (Less) Accum. Prov. for Uncollectible Acct.-Credit (1,t4)7 ,691,154 9,773,266
43 Notes Receivable from Associated Companies (145)0 0
44 Accounls Receivable from Assoc. Companies (146)628,714
45 Fuel Stock (151)227 '179,588,705 197,499,39'1
46 Fuel Stock Expenses Undistributed (152)227 0 0
47 Residuals (Elec) and Extracted Products (153)227 c 0
48 Plant Materials and Operating Supplies (154)227 237,694,431 235,276,870
49 Merchandise (155)227 0 0
50 Olher Materials and Supplies (156)227 0 0
51 Nuclear Materials Held for Sale (157)202-203t227 0 0
52 Allowances (158.1 and 158.2)228-229 0 0
FERC FORM NO.1 (REV.12-03)Page 110
I
73,462,590
Name of Respondent
PacifiCorp
This Report ls:
(1) X An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 2018tQ4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBlTSpontinueal
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarlerl/ear
Balance
(c)
Prior Year
End Balance
12t31
(d)
53 (Less) Noncurrenl Portion of Allowances 0 0
54 Stores Expense Undistributed (163)227 0 0
55 Gas Slored Underground - Current (164.1)0 0
56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)0 0
57 Prepayments (165)48,020,660 75,998,324
58 Advances for Gas (166-167)0 0
59 lnterest and Dividends Receivable (171)0 0
60 Rents Receivable (172)1,128,478 1,343,210
61 Accrued Utility Revenues (173)229,061,000 255,1 54,000
62 Miscellaneous Current and Accrued Assets (174)0 0
63 Derivative lnstrument Assets (1 75)27,458,631 8,996,262
64 (Less) Long-Term Portion of Derivative lnstrument Assets (175)2,565,604 766,962
65 Derivative lnstrument Assets - Hedges ( 1 76)0 0
66 (Less) Long-Term Portion of Derivative lnstrument Assets - Hedges (176 0 0
67 Total Current and Accrued Assets (Lines 34 through 66)1,263,278,901 1,328,670,491
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (181)29,412,802 26,785,398
70 Extraordinary Property Losses (182.1)230a 0 0
71 Unrecovered Plant and Regulatory Study Costs (1 82.2)230b 0 0
72 Other Regulatory Assets (182.3)232 1,107,326,144 1,055,465,461
73 Prelim. Survey and lnvestigation Charges (Electric) (183)477,354 510,567
74 Preliminary Natural Gas Survey and lnvestigation Charges 183.1)0 0
75 Olher Preliminary Survey and lnvestigation Charges (183.2)0 0
76 Clearing Accounts (184)0 0
77 Temporary Facilities (1 85)26,1 88
78 Miscellaneous Deferred Debits (1 86)233 83,1 76,009 76,159,711
79 Def. Losses from Disposition of Utility Plt. (187)0 0
80 Research, Devel. and Demonstration Expend. (188)352-353 0 0
81 Unamortized Loss on Reaquired Debt (189)4,554,871 5,139,793
82 Accumulated Deferred lncome Taxes ('190)234 824,459,6',t2 836,588,163
83 Unrecovered Purchased Gas Costs (191)0 0
84 Total Deferred Debits (lines 69 through 83)2,049,432,S80 2,000,625,766
85 TOTALASSETS (lines 14-16,32,67, and 84)22,205,931,064 21 ,866,639,948
FERC FORM NO.1 (REV.1243)Page 111
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) - A Resubmission
Date of Report
(Mo, Da, Yr)u
Year/Period of Report
2018tQ4
FOOTNOTE DATA
110 Line No;77 Column: d
110 Line No.:44 Column: dAs of December 31, 201-7, Account 145, Accounts receivable from associated companies,included $71-,800,895 of income taxes receivable from Berkshire Hathaway Energy Company,Pacif 's indirect
The c t balance represents a t difference between work incurred and advancesreceived from customers.
FERC FORM NO.1 (ED. 12-871 Page 450.1
Name of Respondent
PacifiCorp
This Report is:
(1) tr An Original
(2) tr A Resubmission
Date of Report
(mo, da, yr)
tt
Year/Period of Report
end of 2018tQ4
CoMPARATTVE BALANCE SHEET (LrABtLtTtES AND OTHER CREDTTS)
Line
No.Title of Account
(a)
Ref.
Page No
(b)
Current Year
End of QuarterA/ear
Balance
(c)
Prior Year
End Balance
12t31
(d)
1 PROPRIETARY CAPITAL
2 Common Stock lssued (201)250-251 3,417,945,896 3,417,945,896
3 Preferred Stock lssued (204)250-251 2,397,600 2,397,600
4 Capital Stock Subscribed (202, 205)0 0
5 Stock Liability for Conversion (203, 206)0 0
6 Premium on Capital Stock (207)0 0
7 Other Paid-ln Capital (208-211)253 1,102,063,956 1,102,063,956
8 lnstallments Received on Capital Stock (212)252 0 0
I (Less) Discount on Capital Stock (213)254 0 0
10 (Less) Capital Stock Expense (214)254b 41 ,101 ,061 41 ,1 01 ,061
11 Retained Earnings (21 5, 21 5.1, 216)118-119 3,271,969,500 2,984,484,352
12 Unappropriated Undistributed Subsidiary Earnings (21 6.1 )1 18-'t't 9 104,399,245 '104,337,295
't3 (Less) Reaquired Capital Stock (2'17)250-251 0 0
14 Noncorporate Proprietorship (Non-major only) (218)0 0
15 Accumulated Other Comprehensive lncome (219)122(a)(b)-12,635,042 -15,266,178
't6 Total Proprietary Capital (lines 2 through 15)7,845,040,094 7,554,861,860
17 LONG-TERM DEBT
18 Bonds (221)256-257 7,055,275,000 7,041,475,000
'19 (Less) Reaquired Bonds (222)256-257 0 0
20 Advances from Associated Companies (223)256-257 0 0
21 Other Long-Term Debt (224)256-257 0 0
22 Unamortized Premium on Long-Term Debt (225)36,022 47,048
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)10,793,807 10,464,531
24 Total Long-Term Debt (lines 18 through 23)7,044,517,215 7 ,031,057 ,517
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent (227)18,996,630 18,233,170
27 Accumulaled Provision for Property lnsurance (228.1)8,591,841 6,095,041
28 Accumulated Provision for lnjuries and Damages (228.2)23,79',t,641 13,502,436
29 Accumulaled Provision for Pensions and Benefits (228.3)190,648,668 167 ,737,085
30 Accumulated Miscellaneous Operating Provisions (228.4)34,600,459 34,624,22',1
31 Accumulated Provision for Rate Refunds (229)2,551,062 5,099,189
32 Long-Term Portion of Derivative lnstrument Liabilities 24,683,756 24,8U,055
33 Long-Term Portion of Derivative lnstrument Liabilities - Hedges 0 0
34 Asset Retirement Obligations (230)227,371,811 214,900,520
35 Total Other Noncurrent Liabilities (lines 26 through 34)531,235,868 484,995,717
CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)30,000,000 80,000,000
38 Accounts Payable (232)523,289,313 436,508,588
39 Notes Payable to Associated Companies (233)
40 Accounts Payable to Associated Companies (234)136,903,471 146,997,905
41 Customer Deposits (235)49,781,902 47,576,366
42 Taxes Accrued (236)262-263 I 46,331 ,988
43 lnteresl Accrued (237)114,623,',t1',!1 19,870,086
44 Dividends Declared (238)40,475 40,475
45 Matured Long-Term Debt (239)0 0
FERC FORM NO.1 (rev.1243)Page 112
36
31,009,817 9,005,123
Name of Respondent
PacifiCorp
This Report is:
(1) tr An Original
(2) tr A Resubmission
Date of Report
(mo, da, yr)
tl
Year/Period of Report
end of Lrya4
COMPARATIVE BALANCE SHEET (LlABlLlTlES AND OTHER CREDlTSntinued)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Ouarterl/ear
Balance
(c)
Prior Year
End Balance
12t31
(d)
46 Matured lnterest (240)0 0
47 Tax Collections Payable (241)20,623,597 19,610,180
48 Miscellaneous Current and Accrued Liabilities (242)74,069,122 83,984,662
49 Obligations Under Capital Leases-Current (243)1,788,634 2,004,747
50 Derivative lnstrument Liabilities (244)65,799,907 38,902,575
51 (Less) Long-Term Portion of Derivative lnstrument Liabilities 24,683,756 24,804,055
52 Derivative lnstrumenl Liabilities - Hedges (245)0 0
53 (Less) Long-Term Portion of Derivative lnstrument Liabilities-Hedges 0 0
54 Total Cunent and Accrued Liabilities (lines 37 through 53)1,071 ,827 ,44C 1,006,028,640
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)76,528,076 36,720,467
57 Accumulated Deferred lnvestment Tax Credits (255)266-267 13,313,777 15,670,323
58 Deferred Gains from Disposition of Utility Plant (256)c 0
59 Other Deferred Credits (253)269 202,519,682 204,360,620
60 Other Regulatory Liabilities (254)278 2,044,239,90e 2,101,876,268
61 Unamortized Gain on Reaquired Debt (257)c 0
62 Accum. Deferred lncome Taxes-Accel. Amort.(28 1 )272-277 180,339,43C 185,416,334
63 Accum. Deferred lncome Taxes-Other Properg (282)2,910,580,06€2.972,737,275
Accum. Deferred lncome Taxes-Other (283)285,789,51C 272,914,927
65 Total Deferred Credits (lines 56 through 64)5,713,310,447 5,789,696,214
66 TOTAL LIABILITIES AND STOCKHOLDER EQUIry (lines 16, 24,35,54 and 65)22,205,93',t,064 21,866,639,948
FERC FORM NO.1 (rev.12-03)Page 113
64
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2UAA4
FOOTNOTE DATA
112 Line No.: 39 Column: c
112 Line No.:39 Column: d
Represents amounts due to Pac c Minerals, Inc., a who1ly ryo Corp,pursuant to an umbrella loan agreement for which the interest rate is determined daily andis equal to the fowest cost of short-term borrowings Pacificorp could otherwise incurexternally. At December 3l-, 201,8, the interest rate on the outstanding loan balance was
2 .8596 .
Represents amounts due to nerals, Inc., a who11y owned subsidiary of PacifiCorp,pursuant to an umbrella loan agreement for which the interest rate is determined daily andis egual to the lowest cost of short-term borrowings PacifiCorp could otherwise incurexternally. At December 31, 20L7, the interest. rate on the out.standing loan balance was
1 .83t.
As of Deceniber 31, 20L8, Account 235, Taxes acc nc 4,894,455 of taxespayable to Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company
FERC FORM NO.I (ED. 12.871 Page 450.'l
f
112 Line No.:42 Column: c
(1)
(2)
AnPacifiCorpA Resubmission
Date of Report(Mo, Da, Yr)
tl
Year/Period of Report
End of 20181Q4
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 column (g) plus the data in column (i) plus the
data in column (k), Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
2. Enter in column (e) the balance for the reporting quarter and in column (f; the balance for the same three month period for the prior year.
3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k)
the quarter to date amounts for other utility function for the current year quarter.
4. Report in column (h) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounls for gas utility, and in column (l) the
quarter to date amounts for other utility function for the prior year quarter.
5. lf additional columns are needed, place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (0
6. Report amounts for accounts 412 and 41 3, Revenues and Expenses from Utility Plant Leased to Olhers, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. lnclude these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utility Operating lncome, in the same manner as accounts 412 and 413 above.
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Total
Cunent Year to
Date Balance for
Ouarterffear
(c)
Total
Prior Year to
Date Balance for
Quarter/Year
(d)
Cunent 3 Monhs
Ended
Quarterly 0nly
No 4h Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4h Quarter
(0
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301 5,090,358,956 s,242,965,626
3 Operating Expenses
4 Operation Expenses (401)320-323 2,470,313,861 2,425,109,768
5 Maintenance Expenses (402)320-323 413,932,883 400,069,497
6 Depreciation Expense (403)336-337 727,650,690
7 Depreciation Expense for Asset Retirement Costs (403.1)336-337
I Amort. & Depl. of Utility Plant (404405)336-337 46,883,718 41,396,782
I Amort. of Utility PlantAq. Adj. (406)336-337 5,083,195 5,083,195
10 Amort. Property Losses, Unrecov Plant and Regulatory Study Cosb (407)
11 Amort. of Conversion Expenses (407)
12 Regulatory Debib (407,3)150,275 150,507
13 (Less) Regulatory Credits (407.4)
14 Taxes Other Than lncome Taxes (408.1)262-263 196,653,710
15 lncome Taxes - Federal (409.1)262-263 162,384,813 237,993,786
16 - Other (409.1)262-263 41,626,061 40,955,946
17 Provision for Deferred lnmme Taxes (410.1)234,272-277 450,529,508 '1,065,406,630
18 (Less) Provision for Deferred lncome Taxes-Cr. (41 1.1)234,272-277 648,977,032 987,845,373
19 lnvestment Tax Credit Adj. - Net (41 1.4)266 -3,1 52,01 5 -3,698,228
20 (Less) Gains from Disp. of Utility Plant (411.6)
21 Losses from Disp. of Utility Plant (411.7)
22 (Less) Gains fom Disposition of Allowances (41 1.8)181 178
23 Losses from Disposition of Allowances (41 1.9)
24 Accretion Expense (41 1 .1 0)
25 TOTAL Utility Operating Expenses (Enter Total of lines 4 hru 24)4,048,492,341 4,148,926,732
26 Net Util Oper lnc (Enter Tot line 2 less 25) Carry to P9117 ,line27 1,041,866,615 1,094,038,894
FERC FORM NO. r/3-Q (REV.02-04)Page 114
908,461,901
201,255,354
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
9. Use page 122 for important notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the
gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the
utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary ofthe adjustments made to balance sheet, income,
and expense accounts.
12. 11 any notes appearing in the report to stokholders are applicable to the Statement of lncome, such notes may be included al page 122.
1 3. Enter on page 1 22 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous yeafs/quarter's figures are differenl from that reported in prior reports.
15. lf the columns are insufiicient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY
Line
No.
Current Year to Date
(in dollars)
(s)
Previous Year to Date
(in dollars)
(h)
Current Year to Date
(in dollars)
(D
Previous Year to Date
(in dollars)
0)
Cunent Year to Date
(in dollars)
(k)
Preuous Year t0 lJate
(in dollars)
(D
1
5,090,358,956 5,242,965,626 2
3
2,470,313,861 2,425,',109,768 4
413,932,883 400,069,497 5
908,461,901 727,650,690 6
7
46,883,718 4',t,396,782 8
5,083,195 5,083,195 I
10
11
150,275 150,507 12
13
201,255,354 196,653,710 14
162,384,813 237,993,786 '15
41,626,061 40,955,946 16
450,529,508 1,065,406,630 17
648,977,032 987,845,373 18
-3,152,015 -3,698,228 19
20
21
181 178 22
23
24
4,0/,8,492,341 4,',t48,926,732 25
1 ,041 ,866,615 1,094,038,894 26
FERC FORM NO. 1 (ED. t2-96)Page t1S
STATEMENT OF INCOME FOR THE YEAR
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn original(2) ;lA Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
TOTAL Cunent 3 Monms
Ended
Quarterly Only
No 4h Quarter
(e)
Pnor 3 Monhs
Ended
Quarterly 0nly
No 4th Quarter
(0
Current Year
(c)
Previous Year
(d)
27 Net Utility Operating lncome (Carried foruard from page 114)1,041,866,615 1,094,038,894
28 Other lncome and Deductions
29 Oher lncome
30 Nonutilty Operating lncome
31 Revenues From Merchandising, Jobbing and Contract Work (415)'1,500,7 1 1 3,280,869
32 (Less) Costs and Exp. of Merchandisinq, Job. & Contract Work (416)1,372,254 3,080,394
33 Revenues From Nonutility Operations (417)
34 (Less) Expenses of Nonutilig Operations (41 7.1)79,216 1 10,838
35 Nonoperating Rental lncome (418)275,014 263,039
36 Equity in Earnings of Subsidiary Companies (418.1)1'19 20,869,978 17,814,281
37 lnterest and Dividend lncome (419)14,250,874 7,989,04s
38 Allowance for Oher Funds Used During Constuction (4'19.1)34,835,895 1 9,939,361
39 Miscellaneous Nonoperating lnmme (421)-728,378 2,280,438
40 Gain on Disposition of Property (42 1.1)939,906 299,714
41 TOTAL Other lnome (Enter Total of lines 31 thru 40)70,492,530 48,675,51 5
42 Other lncome Deductions
43 Loss on Disposition of Property (421.2)88,035 53,895
44 Miscellaneous Amortization (425)1,329,336 1,328,501
45 Donations (426.1)2,387,899 3,297,350
46 Life lnsurance (426.2)-3,252,632 -8,228,460
47 Penalties (426.3)1,1 12,093 -22,896
48 Exp. for Certain Civic, Political & Related Activities (426.4)1,239,589 1,427,597
49 Oher Deductions (426.5)7,940,472 6,007,522
s0 TOTAL Other lnome Deductions (Total of lines 43 thru 49)10,844,792 3,863,509
51 Taxes Applic. to Other lncome and Deductions
52 Taxes Other Than lncome Taxes (408.2)262-263 340,043 314,1 04
53 lncome Taxes-Federal (409.2)262-263 1,079,374 997,900
54 lncome Taxes-Other (409.2)262-263 243,788 1 35,598
55 Provision for Deferred lnc. Taxes (410.2)234,272-277 109,004,879 90,136,224
56 (Less) Provision for Defened lncome Taxes-Cr. (41 1.2)234,272-277 1 09,467,521 88,460,786
57 lnvestment Tax Credit Adj.-Net (41 1.5)
58 (Less) lnvestment Tax Credits (420)236,733 373,166
59 TOTAL Taxes on Other lncome and Deductions (Total of lines 52-58)963,830 2,749,874
60 Net Other lncome and Deductions (Total of lines 4'1, 50, 59)58,683,908 42,062,132
61 lnterest Charges
62 lnterest on Long-Term Debt (427)358,695,455 360,014,410
63 Amort. of Debt Disc. and Expense (428)4,027,405 4,121,973uAmortization of Loss on Reaquired Debt (428.1 )584,922 639,595
65 (Less) Amort. of Premium on DebtCredit (429)1 1,026 1 1,026
66 (Less) Amortization of Gain on Reaquired DebtCredit (429.1)
bl lnterest on Debt to Assoc. Companies (430)69,069 24,990
68 Other lnterest Expense (431)17,922,378 14,124,383
69 (Less) Allowance fo Borrowed Funds Used During Construc{ion-Cr. (432)18,446,680 1 1,250,383
70 Net lnterest Charges (Total of lines 62 thru 69)362,84 1,523 367,663,942
71 lncome Before Extraordinary ltems (Total of lines 27, 60 and 70)737,709,000 768,437,084
72 Exkaordinary ltems
73 Extraordinary lncome (434)
74 (Less) Extraordinary Deductions (435)
75 Net Extraordinary ltems (Total of line 73 less line 74)
76 lncome Taxes-Federal and Other (409.3)262-263
77 Exkaordinary ltems After Taxes (line 75 less line 76)
78 Net lnmme (Total of line 71 and 77)737,709,000 768,437,084
FERC FORM NO. 1/3-Q (REV. 02-04)Page {17
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
20181Q4
FOOTNOTE DATA
114 Line No.:6 Column: c
Deprec t expense assoc ated th transportat on equipment is generally charged tooperations and maintenance expense and construction work in progress. During the years
ended Decernlcer 31, 2018 and 2017, depreciation expense associated with transportation
was t_5 829 895 and 15 045 329 ivel
Genera y, Pac Corp rec the dL on expense o asset rement ob1 ASeither a 1at asset or liabilit
Payro taxes are v to opera ons and ma tenance expense and construct onwork in progress. During the years ended Deceriber 31, 2018 and 2017, payroll taxes were
39 770 569 and 39 077 979 tivel
Genera Pac f Corp rec ac on expense of asset rement ob1 at saseither a regulatory asset or liability.
t114 Line No.:7 Column: c
114 Line No.: 14 Column: c
114 Line No.:24 Column: c
FERC FORM NO.1 (ED. 12-871 Page 450.1
Name of Respondent
PacifiCorp
ls:
Original
(2)Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436 -
439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. lf such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. lf any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
Contra Primary
Account Affected
(b)
Current
QuarterfYear
Year to Date
Balance
(c)
Previous
OuarterfYear
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARN INGS (Account 2 1 6)
1 Balance-Beginning of Period 2,948,638,352 2,778,346,006
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acct. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct. 439)
'16 Balance Transferred from lncome (Account 433 less Account 4'18.1)716,839,022 750,622,803
17 Appropriations of Retained Earnings (Acct. 436)
18 Appropriation of excess earnings at certain hydroelectric generating facilities 215.',|-8,732,124 ( 10,591,983)
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acct. 436)-8,732,124 ( 10,591,983)
23 Dividends Declared-Preferred Stock (Account 437)
24 Preferred Stock, various series and rates 238
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)-16'r,902 ( 161,902)
30 Dividends Declared-Common Stock (Account 438)
3'1 Common Stock 238 -450,000,000 ( 600,000,000)
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acct. 438)-450,000,000 ( 600,000,000)
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings 216.1
38 Balance - End of Period (Total 1,9,t5,16,22,29,36,37)3,227,391,376 2,948,638,352
APPROPRIATED RETAINED EARNINGS (Account 215)
39
40
FERC FORM NO. 1r3-Q (REV. 02-04)Page 118
30,423,42820,808,028
-'r 61,902
Name of
PacifiCorp (1)
(2)Resubmission
Date of Report
(Mo, Da, Yr)tl
Year/Period of Report
2018tA4End of
STATEMENT OF RETAINED EARNINGS
'l . Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436 -
439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. lf such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. lf any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
Contra Primary
Account Affected
(b)
Current
QuarterfYear
Year to Dale
Balance
(c)
Previous
QuarterfYear
Year to Date
Balance
(d)
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Eamings-Amorl. Reserve, Federal (Acct. 215.1)
47 TOTAL Approp. Retained Earnings (Acct. 2'15, 215.1) (Total 45,46)44,578,124 35,846,000
48 TOTAL Retained Earnings (Acct. 215, 215.1 , 216) (Total 38, 47) (216.1)3,271,969,500 2,984,484,352
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)104,337,295 116,946,442
50 Equity in Earnings for Year (Credit) (Account 418.1)20,869,978 17,814,281
51 (Less) Dividends Received (Debit)
52 Transfers to/from Unappropriated Retained Earnings (Account 216)-20,808,028 ( 30,423,428)
53 Balance-End ofYear (Total lines 49 thru 52)104,399,245 104,337,295
FERC FORM r{O. 1/3-Q (REV.02-04)Page 119
44,578,'.t24 35,846,000
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Outst pre sto aso r 31, 2018 onpreferred stock during the year ended December 31, 2018 were as follows:
Shares Dividend
5.0
7.0
0% Serial Preferred
0? Serial Preferred 5, 930
18,046 $ 35,580
]-26 322
976 161 902
Outs ngs aso December 31, 20L7 onpreferred stock during the year ended December 31, 2017 were as follows:
Shares Dividend
$ 35,5805.0
7.0
0? Serial Preferred
0? Serial Preferred
5,930
18, 045 1,26 322
23 976 151 902
Dur ng the year ended December 31, 20L8,d str ons from subs eso
PacifiCorp were as foffows
Pacific Minerals, Inc.
Fossil Rock Fuels, LLCTrapper Mining Inc.
$18, ooo
2 ,663
145
000
000
028
20 80 o 0 28
Dur year December 31, 2017,d str bu ons eso
PacifiCorp were as follows:
Pacific Minerals, Inc.
Fossil Rock Fue1s, LLCTrapper Mining Inc.
$27 ,000 ,000
000
428
3 3 94
9
3 0 3 28
The balance in Account 215.1, Appropriated retained earnings - Amortization reserve,Federal, is due to rements of certain h lectric relicens ects
The balance in Account 2!5.1, Appropriated retained earnings - Amortizatj-on reserve,Federal, is due to requirements of certai-n hydroelectric relicensing projects.
FERC FORM NO.1 (ED. 12471 Paqe 450.1
Schedule Page:118 Line No.:24 Column: d
118 Line No.: 37 Column: c
118 Line No.: 37 Column: d
118 Line No.:46 Column: c
118 Line No.:46 Column: d
Schedule Paoe: 718 Line No.: 24 Column: c
PacifiCorp (1)
(2)
Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
STATEMENT OF CASH FLOWS
('l ) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) lnclude commercial paper; and (d) ldentify separately such items as
investments, fixed assets, intangibles, etc.
(2) lnformation about noncash investing and financing activilies must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and
Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
reported in those activities. Show in the Notes lo the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General lnstruction 20; instead provide a reconciliation of
the dollar amount of leases capitalized with the plant cost.
Line
No.
Description (See lnstruction No. 1 for Explanation of Codes)
(a)
Current Year to Date
Quarter^fear
(b)
Previous Year to Date
QuarterA/ear
(c)
I Net Cash Flow from Operating Activities:
2 Net lncome (Line 78(c) on page 1 17)737,709,000 768,437,084
3 Noncash Charges (Credits) to lncome:
4 Depreciation and Depletion 748,385,225
5 53,322,235 47,8U,694
b
7
I Deferred lncome Taxes (Net)-1 98,91 0,1 66 79,236,695
I lnvestment Tax Credit Adjustment (Net)-3,388,748 4,071,394
10 Net (lncrease) Decrease in Receivables 22,276,393 15,260,809
11 Net (lncrease) Decrease in lnventory 15,493,125 10,178,857
12 Net (lncrease) Decrease in Allowances lnventory
13 Net lncrease (Decrease) in Payables and Accrued Expenses 88,063,038 -34,768,339
14 Net (lncrease) Decrease in Other Regulalory Assets -19,930,044 -8,349,1 I 8
15 Net lncrease (Decrease) in Other Regulatory Liabilities 107,413,446 26,841,U3
16 (Less) Allowance for Other Funds Used During Construction 34,835,895
17 (Less) Undistributed Earnings from Subsidiary Companies 61,950 -12,609,147
18 Amounts Due To/From Affiliates (Net)69,557,216 -51 ,495,765
'19 Derivative Collateral (Net)14,900,000 -5,600,000
20 4,701,78',1 7,874,142
21
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)1,782,337,532 1,592,4U,0',t9
23
24 Cash Flows from lnvestment Activities:
25 Construction and Acquisition of Plant (including land)
26 Gross Additions to Utility Plant (less nuclear fuel)-1,291,567,102 -797,523,778
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construction -34,835,895 -28,783,864
31 Other (provide details in footnote):
32
33
34 Cash Outflows for Plant (Total of lines 26 thru 33)-1,256,73',t,207 -768,739,914
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
38
39 lnvestments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc. and Subsidiary Companies 2,668,000 3,507,000
41 Disposition of lnvestments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of lnvestment Securities (a)
45 Proceeds from Sales of lnvestment Securities (a)
FERC FORM NO. I (ED. 12-96)Page ,120
926,028,121
\mortization:I
4,229,118 1,680,014
19,939,361
Name of Respondent
PacifiCorp
This
(1)
(2)
Reoort ls:
5]an Original
EA Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 2018/Q4
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt: (c) lnclude commercial paper; and (d) ldentify separately such items as
investments, fixed assets, intangibles, etc.
(2) lnformation about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and
Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General lnstruction 20; instead provide a reconciliation of
the dollar amount of leases capitalized with the plant cost.
Line
No.
Description (See lnstruction No. 1 for Explanation of Codes)
(a)
Cunent Year to Date
QuarterfYear
(b)
Previous Year to Date
Ouarterlfear
(c)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (lncrease) Decrease in Receivables
50 Net (lncrease ) Decrease in lnventory
51 Net (lncrease) Decrease in Allowances Held for Speculation
52 Net lncrease (Decrease) in Payables and Accrued Expenses
53 Other lnvesting Activities:-2,495,368 9,546,359
54
55
56 Net Cash Provided by (Used in) lnvesting Activities
57 Total of lines 34 thru 55)-1,252,329,457 -754,006,541
58
59 Cash Flows from Financing Activities:
60 Proceeds from lssuance of:
61 Long-Term Debt (b)593,102,815
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
66 Net lncrease in Short-Term Debt (c)
67 I 22,000,000 9,000,000
68
69
70 Cash Provided by Outside Sources (Total 61 thru 69)615,102,815 9,000,000
71
72 Payments for Retirement of:
73 Long-term Debt (b)-586,200,000 -51,722,000
74 Preferred Stock
75 Common Stock
76 Other (provide tn I -1 ,1 1 8,205 -1,299,802
77 Repayment of Capital Lease Obligations -1,736,324 -5,689,206
78 Net Decrease in Short-Term Debt (c)-50,000,347 -189,924,944
79
80 Dividends on Preferred Stock -161,902 -161 ,902
81 Dividends on Common Stock -450,000,000 -600,000,000
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)-474,1 1 3,963 -839,797,854
u
85 Net lncrease (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83)55,894,1 12 -1 ,370,376
87
88 Cash and Cash Equivalents at Beginning of Period 28,361,7 14,910,747
89
90 Cash and Cash Equivalents at End of period 84,255,851 13,540,371
FERC FORM NO. I (ED. 12-96)Page 121
Cther (provide details in footnote):
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
20't8tQ4
FOOTNOTE DATA
120 :4 Column: b
yearsLransportation equipment and capitalrespectively.
31, 2018 20!7 ,rec expense assoc te
l-ease assets were $17,566,220 and $20,734,535,
t t
120 Line No.:5 Column: a
Years Ended December 31
2 018 201_7Amortization of software development & other intangibles
Amortization of efectric plant acquisition adjustmentsAmortization of a regulatory asset
i 42,725,283
5, 083, 195
26 246$ ss,322,235 47 ,834,694
$ 48,21-3,054
5, og3 , 195
25 ,986
120 Line No.: 16 Column: cIncfsanustment o $8,844,503 to Account 4l.9.1, Allowance roduring construction, per FERC Docket No. FA16-4-000.
r used
120 Line No.:20 Column: a
Years
201_8
Dec 31
201_7Depreciation and depletion included in cost of fuelNet gain on sale of propertyWrite-off of assets under construction
Change in corporate owned life insurance cash surrender
value
Amortization of debt issuance expenses and bond
discount/premium
Changes in derivative contract assets/Iiabilities, net
Noncash adjustment to allowance for borrowed funds usedduring construction, per FERC Docket No. FA15-4-000
Other
4 ,429 ,935
B43 587 (1 3s3 63r-)
$ 4,70L,78L $ 7,874,!42
t 2,076,1-62 $(955,310)
1, 903, 891
4 , ol5 ,3'79(94]- ,21-3)
2 ,039 ,1_89
(282 ,093)
8, 005, 1l-7
4 , l!0 ,947(881,283)
(3 ,24t ,7t5)(8,195,039)
1
120 Line No.:37 Column: b
Represents proceeds from the d sposal of f assets.
120 Line No.:37 Column: c
Represents proceeds from the d loff assets .
Schedule Page: 120 Line No.: 53 Column: a
Years fnded December 31
2078 20t7Other investments/special fundsRestricted cashInvestment in long-term incentive plan securitiesInvestment in supplemental executive retirement plan
$ 1 ,986,a33
(4,481,501)
-
$ (2 ,495,368)
$ 714,850
1,138,31_0
(2 ,17 4 ,547 )
9,867 ,746
$ 9 ,546,359
120 Line No.:67 Column: a
Net proceeds of aff 1 te
deferred f costs
ry company, Pac s, Inc
120 Line No.:76 Column: a
FERC FORM NO.1 (ED. 12471 Page 450.1
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
20't8tQ4
FOOTNOTE DATA
120 Line No.:88 Column: b
Cash and cash equ valents and restricted cash and cash equivalent.s consist of thefollowing amounts as of December 31, 20L7:
Cash (131)
Temporary cash investments (136)
Total cash and cash eguivalents
$ 4, 805, 006
I 735 355
a3 ,540 ,371,
Other special funds (L28)
Other special deposits (l-34)
Total restrj-cted cash and cash equivalents
Total cash and cash equivalents and restricted cash
and cash eguivalent.s
5 ,930 ,367
891 001
1_4 ,821_ ,368
$ 28,36]-,739
FERC FORM NO.1 (ED. 12-871 Page 450.2
Name of Respondent
PacifiCorp
This Report ls:
(1)
(2)
An Original
A Resubmission
Date of Report
tl
Year/Period of Report
End of 20181Q4
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of lncome for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the lnternal Revenue Service involving possible assessment of additional income taxes of material amount, or of a
claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on
cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. \Mere Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an
explanation, providing the rate treatment given these items. See General lnstruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. lf the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements, and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters
shall be provided even though a significant change since year end may not have occurred.L Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
PAGE l22INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO. I (ED. 12-96)Page 122
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
PACIF'ICORP
NOTES TO F'INANCIAL STATEMENTS
(l) Organization and Operations
PacifiCorp is a United States regulated electric utility company serving retail customers, including residential, commercial, industrial,
irrigation and other customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and Califomia. PacifiCorp
owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric
transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy
marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal
regulation. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des
Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire
Hathaway Inc. ("Berkshire Hathaway").
(2) Summary of Significant Accounting Policies
Basis of Presentation
These financial statements are prepared in accordance with the requirements of the Federal Energy Regulatory Commission ("FERC")
as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of
accounting other than accounting principles generally accepted in the United States of America ("GAAP"). These notes include
certain applicable disclosures required by GAAP adjusted to the FERC basis of presentation and include specific information
requested by the FERC.
The following are the significant differences between the FERC accounting and reporting standards and GAAP
Inves tments in Subs idiaries
In accordance with FERC Order No. ACI l-132-000, PacifiCorp accounts for its investment in subsidiaries using the equity
method for FERC reporting purposes rather than consolidating the assets, liabilities, revenues and expenses ofsubsidiaries as
required by GAAP. GAAP requires that entities in which a company holds a controlling financial interest be consolidated.
Also in accordance with FERC Order No. ACl l-132-000, PacifiCorp does not eliminate intercompany profit on transactions
with equity investees as would be required under GAAP. The accounting treatment described above has no effect on net
income or the combined retained earnings of PacifiCorp and undistributed earnings of subsidiaries.
Costs of Removal
Estimated removal costs that are recovered through approved depreciation rates, but that do not meet the requirements of a
legal asset retirement obligation ('ARO') are reflected in the cost of removal regulatory liability under GAAP and as
accumulated depreciation under the FERC accounting and reporting standards.
Income Taxes
Accumulated defened income taxes are classified as net non-current assets or liabilities on the balance sheet for GAAP.
Under the FERC accounting and reporting standards, accumulated deferred income taxes are classified as gross non-current
assets and gross non-current liabilities. Additionally, there are certain presentational differences befween FERC and GAAP
for amounts related to unrecognized tax benefits associated with temporary differences in accordance with FERC Docket
No. A107-2-000, "Accounting and Financial Reporting for Uncertainty in Income Taxes." For GAAP, unrecognized tax
benefits associated with temporary differences are reflected as other liabilities while for FERC the income tax impact of
uncertain tax positions associated with temporary differences are reflected in accumulated deferred income taxes.
Interest and penalties on income taxes for GAAP are classified as income tax expense. All such amounts are classified as
interest income, interest expense and penalties underthe FERC accounting and reporting standards.
FERC FORM NO,1 ED.1 't23.1
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Pensions and Postretirement Benefits Other Than Pensions
Pension and postretirement benefits other than pensions ("PBOP') are comprised of several different components of net
periodic benefit costs. As required by GAAP, the service cost component is reported with other compensation costs arising
from services rendered by employees, while the other components of net periodic benefit costs are presented outside of
operating income. Additionally, only the service cost component of net periodic benefit costs is eligible for capitalization
under GAAP. In accordance with FERC Order No. AIl8-l-000, PacifiCorp continues to report the components of net
periodic benefit costs for pension and PBOP on the statement of income and follows GAAP guidance to capitalize only the
service cost component ofnet periodic benefit costs.
Reclassifications
Certain other reclassifications of balance sheet, income statement and cash flow amounts have been made in order to
conform to the FERC basis of presentation. These reclassifications had no effect on net income.
Use of Estimates in Preparation of Financial Statements
The preparation of the financial statements in conformity with FERC and GAAP requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of
revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; certain assumptions
made in accounting for pension and other postretirement benefits; AROs; income taxes; unbilled revenue; valuation of certain
financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the
estimates used in preparing the financial statements.
Accountingfor the Effects of Certain Types of Regulation
PacifiCorp prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the
economic effects of regulation. Accordingly, PacifiCorp defers the recognition of certain costs or income if it is probable that, through
the ratemaking process, there will be a corresponding increase or decrease in future rates. Regulatory assets and liabilities are
established to reflect the impacts of these deferals, which will be recognized in eamings in the periods the coresponding changes in
rates occur.
PacifiCorp continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and
liabilities are probable of inclusion in future rates by considering factors such as a change in the regulator's approach to setting rates
from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit
PacifiCorp's abilif to recover its costs. PacifiCorp believes the application of the guidance for regulated operations is appropriate and
its existing regulatory assets and liabilities are probable of inclusion in future rates. The evaluation reflects the current political and
regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be
included in future rates, the related regulatory assets and liabilities will be written offto net income or re-established as accumulated
other comprehensive income (loss) ('AOCI").
Fair Yalue Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal
market or in the most advantageous market when no principal market exists. Adjustrnents to transaction prices or quoted market
prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be
appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an
orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and
not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in
interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not
necessarily indicative of the amounts that could be realized in a current or future market exchange.
FERC FORM NO.1 (ED.12-88)Page 123.2
Name of Respondent
PacifiCorp
This Report is:
(1)XAn Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
ll
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Cash Equivalents and Restricted Cash and Cash Equivalents and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a
maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal
requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents are included in other special
funds and other special deposits primarily consist of escrow accounts for disputed funds, vendor retention, custodial and nuclear
decommissioning funds.
Cash and cash equivalents and restricted cash and cash equivalents consist of the following amounts as of December 31 (in millions):
2018 2017
Cash (131)
Temporary cash investments (136)
Total cash and cash equivalents
Beginning balance
Charged to operating costs and expens€s, net
Write-offs, net
Ending balance
$$520
49 9
14
Other special funds (128)
Other special deposits (134)
Total restricted cash and cash equivalents
t5
15 t4
Total cash and cash equivalents and restricted cash and cash equivalents 84$28
Investments
Available-for-sale securities are carried at fair value with realized gains and losses, as determined on a specific identification basis,
recognized in earnings and unrealized gains and losses recognized in AOCI, net of tax. As of December3l, 2018 and 2017,
PacifiCorp had no unrealized gains and losses on available-for-sale securities. Trading securities are carried at fair value with realized
and unrealized gains and losses recognized in eamings.
Allowance for Doubtful Accounts
Accounts receivable are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts. The
allowance for doubtful accounts is based on PacifiCorp's assessment of the collectability of amounts owed to PacifiCorp by its
customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. The
change in the balance of the allowance for doubtful accounts, which is included in accumulated provision for uncollectible accounts
on the Comparative Balance Sheet, is summarized as follows for the years ended December 31 (in millions):
69
5
9
$
2018
$10
t2
(14)
2017
$7
15
04
$8 $10
Derivatives
PacifiCorp employs a number of different derivative contracts, which may include forwards, options, swaps and other agreements, to
manage price risk for electricity, natural gas and other commodities and interest rate risk. Derivative contracts are recorded on the
Comparative Balance Sheet as either assets or liabilities and are stated at estimated fair value unless they are designated as normal
purchases or normal sales and qualiS for the exception afforded by GAAP. Derivative balances reflect offsetting permitted under
master netting agreements with counterparties and cash collateral paid or received under such agreements.
FERC FORM NO.1 (ED.12-88)Page 123.3
Name of Respondent
PacifiCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
20't8tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for
and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market
and settled amounts are recognized as operating revenues or operating expenses on the Statement oflncome.
For PacifiCorp's derivative contracts, the settled amount is generally included in rates. Accordingly, the net unrealized gains and
losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in rates
are recorded as regulatory assets. For a derivative contract not probable ofinclusion in rates, changes in the fair value are recognized
in earnings.
Inventories
Inventories consist mainly of materials and supplies and fuel stocks (coal, natural gas and fuel oil), which are stated at the lower of
average cost or net realizable value.
Net Uility Plant
General
Additions to utility plant are recorded at cost. PacifiCorp capitalizes all construction-related material, direct labor and contract
services, as well as indirect construction costs, which include debt and equity allowance for funds used during construction
("AFUDC"). The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives
ofthe related assets are generally expensed.
Depreciation and amortization are generally computed on the straight-line method based on composite asset class lives prescribed by
PacifiCorp's various regulatory authorities or over the assets' estimated useful lives. Depreciation studies are completed periodically to
determine the appropriate composite asset class lives, net salvage and depreciation rates. These studies are reviewed and rates are
ultirnately approved by the various regulatory authorities. Net salvage includes the estimated future residual values of the assets and
any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either
accumulated provision for depreciation or an ARO liability on the Comparative Balance Sheet, depending on whether the obligation
meets the requirements of an ARO. As actual removal costs are incurred, the accumulated provision for depreciation or ARO liability
is reduced.
Generally when PacifiCorp retires or sells a component of utility plant, it charges the original cost, net of any proceeds from the
disposition, to accumulated provision for depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the consffuction of utility
plant, is capitalized as a component of utility plant, with offsetting credits to the Statement of Income. AFUDC is computed based on
guidelines set forth by the FERC. After construction is completed, PacifiCorp is permifted to earn a return on these costs as a
component ofthe related assets, as well as recover these costs through depreciation expense over the useful lives ofthe related assets.
Ass et Retirement Obligations
PacifiCorp recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon
retirement of an asset. PacifiCorp's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is
recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying
amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial
recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding
adjustments to utility plant, net) and for accretion of the ARO liability due to the passage of time. The difference between the ARO
liability, the corresponding ARO asset included in utility plant and amounts recovered in rates to satisfo such liabilities is recorded as
a regulatory asset or liability.
FERC FORM NO.1 (ED.12.88)Page 123.4
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Impairment
PacifiCorp evaluates long-lived assets for impairment, including utility plant, when events or changes in circumstances indicate that
the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurence of a triggering
event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the
residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated
recoverable amounts, appropriate FERC accounts are adjusted to write down the asset to the estimated fair value and any resulting
impairment loss is reflected on the Statement of Income. The impacts of regulation are considered when evaluating the carrying value
ofregulated assets.
Revenue Recognition
PacifiCorp recognizes revenues from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or
services in an amount that reflects the consideration to which PacifiCorp expects to be entitled in exchange for those goods or
services. PacifiCorp records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing
authorities on a net basis on the Statement of Income.
Substantially all of PacifiCorp's Customer Revenue is derived from tariff-based sales arrangements approved by various regulatory
authorities. These tariff-based revenues are mainly comprised of energy, transmission and distribution and have performance
obligations to deliver energy products and services to customers which are satisfied over time as energy is delivered or services are
provided. Other revenue consists ofcontractual agreements, including derivative arrangements.
Revenue recognized is equal to what PacifiCorp has the right to invoice as it corresponds directly with the value to the customer of
PacifiCorp's performance to date and includes billed and unbilled amounts. Payments for amounts billed are generally due from the
customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual
arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations.
When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue
collected may be subject to refund and classified in accordance with FERC accounting standards.
Income Taxes
Berkshire Hathaway includes PacifiCorp in its United States federal income tax retum. Consistent with established regulatory
practice, PacifiCorp's provision for income taxes has been computed on a stand-alone basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and
liabilities using estimated income tax rates expected to be in effect for the year in which the differences are expected to reverse.
Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are
charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with certain
property-related basis differences and other various differences that PacifiCorp deems probable to be passed on to its customers in
most state jurisdictions are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when
the temporary differences reverse or as otherwise approved by PacifiCorp's various regulatory commissions. Other changes in
deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets
and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or
liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the
amount that is more-likely-than-not to be realized.
Investment tax credits are generally deferred and amortized over the estimated useful lives ofthe related properties or as prescribed by
various regulatory jurisdictions.
FERC FORM NO.1 (ED.12-88)Page 123.5
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
In determining PacifiCorp's income taxes, management is required to interpret complex income tax laws and regulations, which
includes consideration of regulatory implications imposed by PacifiCorp's various regulatory commissions. PacifiCorp's income tax
returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different
interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before
these examinations are completed and these matters are resolved. PacifiCorp recognizes the tax benefit from an uncertain tax position
only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical
merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest
benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of PacifiCorp's federal,
state and local income tax examinations is uncertain, PacifiCorp believes it has made adequate provisions for these income tax
positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not
expected to have a material impact on PacifiCorp's financial results.
Segment Information
PacifiCorp currently has one segment, which includes its regulated electric utility operations.
New Acc o unting Pro nounc ements
In August 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2018-14,
which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The
amendments in this guidance modifu the disclosure requirements for employers that sponsor defined beneht pension or other
postretirement plans. The amendments in this guidance remove disclosures that no longer are considered cost beneficial, clarifr the
specific requirements of disclosures and add disclosure requirements identified as relevant. The updated disclosure requirements make
a number of changes to improve the effectiveness of disclosures within the notes to financial statements. This guidance is effective for
annual reporting periods ending after December 15,2020, with early adoption permitted and is required to be adopted retrospectively.
PacifiCorp elected to early adopt ASU No. 2018-14 effective December 31, 2018. The adoption did not have a material impact on
PacifiCorp's financial statements and disclosures included within Notes to Financial Statements.
In March 2017,the FASB issued ASU No. 2017-07, which amends FASB ASC Topic 715, "Compensation - Retirement Benefits."
The amendments in this guidance require that an employer disaggregate the service cost component from the other components of net
benefit cost and report the service cost component in the same GAAP financial statement line item as other compensation costs arising
from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be
presented in the GAAP statement of operations separately from the service cost component and outside the subtotal of operating
income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable.
PacifiCorp adopted this guidance January l, 2018 prospectively for the capitalization of the service cost component and is in
accordance with requirements specified in FERC Order No. AI18-1-000, "Accounting and Financial Reporting for Pensions and
Post-retirement Benefi ts other than Pensions".
In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, "Statement of Cash Flows -
Overall." The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of
cash, cash equivalents, and amounts generally described as restricted cash and restricted cash equivalents. Amounts generally
described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the
beginning-of-period and end-of-period total amounts shown on the statement of cash flows. PacifiCorp adopted this guidance January
l, 2018 for FERC reporting, as presented in the Statement of Cash Flows.
In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The
amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the
objective of reducing the existing diversity in practice. PacifiCorp adopted this guidance January I , 201 8 for FERC reporting.
FERC FORM NO.I (ED.12€8)Page 123.6
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
In February 2016, the FASB issued ASU No. 2016-02, which creates FASB ASC Topic 842, "Leases" and supersedes Topic 840
"Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the
balance sheet and disclosing key information about leasing arrangements. A lessee should recognize on the balance sheet a liabiliff to
make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term.
The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly
changed from previous guidance. During 2018, the FASB issued several ASUs that clarified the implementation guidance and
provided optional transition practical expedients for ASU No. 2016-02 including ASU No. 2018-01 that allows companies to forgo
evaluating existing land easements if they were not previously accounted for under ASC Topic 840, "Leases" and ASU No. 201 8- l I
that allows companies to apply the new guidance at the adoption date with the cumulative-effect adjustment to the opening balance of
retained eamings recognized in the period of adoption. This guidance is effective for interim and annual reporting periods beginning
after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach.
PacifiCorp adopted this guidance, electing all practical expedients, effective January 1,2019, for all contracts currently in-effect.
PacifiCorp is finalizing its implementation efforts relative to the new guidance and currently expects to recognize operating lease right
of use assets and lease liabilities of approximately $15 million based on the contracts currently in-effect. PacifiCorp's implementation
of this guidance will be in accordance with FERC OrderNo. AIl9-l-000, "Accounting and Financial Reporting for Leases" issued
December 27 . 2018.
In May 2014,the FASB issued ASU No. 2014-09, which created FASB ASC Topic 606, "Revenue from Contracts with Customers"
("ASC 606") and superseded ASC Topic 605, "Revenue Recognition." The guidance replaced industry-specific guidance and
established a single five-step model to identi$ and recognize revenue Customer Revenue. The core principle of the GAAP guidance
is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that
reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Following the issuance of
ASU No. 2014-09, the FASB issued several ASUs that clarified the implementation guidance for ASU No.2014-09 but did not
change the core principle ofthe guidance. PacifiCorp adopted this guidance for all applicable contracts as ofJanuary l, 2018 under a
modified retrospective method. The adoption did not have a cumulative effect impact at the date of initial adoption.
Subsequent Events
PacifiCorp has evaluated the impact of events occurring after December 31,2018 up to February 22,2019, the date that PacifiCorp's
GAAP financial statements were filed with the United States Securities and Exchange Commission and has updated such evaluation
fordisclosurepurposesthrough April12,20l9.Thesefinancialstatementsincludeallnecessaryadjustmentsanddisclosuresresulting
from these evaluations.
(3) Net Utility Plant
The average depreciation and amortization rate applied to depreciable utility plant was 3.5%o for the year ended December 31, 2018,
including the impact of accelerated depreciation for Utah's share of certain thermal plant units, and 2.9%o for the year ended
December 31,2017 .
(4) Jointly Owned Utility Facilities
Under joint facility ownership agreements with other utilities, PacifiCorp, as a tenant in common, has undivided interests in jointly
owned generation, transmission and distribution facilities. PacifiCorp accounts for its proportionate share of each facility, and each
joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on
their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the
Statement of Income include PacifiCorp's share of the expenses of these facilities.
FERC FORM NO.1 (ED.12.88)Page 123.7
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility as of December3l, 2018
(dollars in millions):Facility Accumulated ConstructionPacifiCorp in Depreciation and Work-in-Share Service Amortization Progress
Jim Bridger Nos. 1 - 4( I )
Hunter No. I
Hunter No. 2
Wyodak
Colstrip Nos. 3 and 4
Hermiston
Craig Nos. I and 2
Hayden No. I
Hayden No. 2
Foote Creek
Transmission and distribution facilities
Total
2018:
Credit facilities
Less:
Short-term debt
Tax-exempt bond support
Net credit facilities
2017:
Credit facilities
Less:
Short-term debt
Tax-exempt bond support
Net credit facilities
67
94
60
80
l0
50
l9
25
l3
79
Various
o/o $1.458 $
484
298
471
248
180
367
74
43
40
808
$659
176
ll6
226
136
87
245
38
22
27
296
ll
-)
1j
I
76
$4,471 $2.028 $100
(1) Includes PacifiCorp's share of disallowances resulting from a rate settlement with the Washington Utilities and Transportation Commission ("WUTC").
(5) Regulatory Matters
Regulatory Assets
PacifiCorp had regulatory assets not earning a return on invesfinent of $63 I million and $5 84 million as of December 3 I , 20 I 8 and
2017, respectively.
(6) Short-term Debt and Credit Facilities
The following table summarizes PacifiCorp's availability under its credit facilities as of December 31 (in millions):
$ 1,200
(30)
(8e)
$ 1.081
$1,000
(80)
(130)
$790
PacifiCorp has a $600 million unsecured credit facility expiring in June 2021 with a one-year exension option subject to lender
consent and a $600 million unsecured credit facility expiring in June 2021 with two one-year extension options subject to lender
consent. These credit facilities, which support PacifiCorp's commercial paper program, certain series of its tax-exempt bond
obligations and provide for the issuance ofletters ofcredit, have variable interest rates based on the Eurodollar rate or a base rate, at
PacifiCorp's option, plus a spread that varies based on PacifiCorp's credit ratings for its senior unsecured long-term debt securities.
As of December 31, 2018 and 2017, the weighted average interest rate on commercial paper borrowings outstanding was 2.85%o and
1.83%, respectively. These credit facilities require that PacifiCorp's ratio of consolidated debt, including current maturities, to total
capitalization not exceed 0.65 to 1.0 as ofthe last day ofeach quarter.
FERC FORM NO.1 (ED.12.88}Page 123.8
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018/o.4
NOTES TO FINANCIAL STATEMENTS (Continued)
As of December3l,20l8 and 20lT,PacifrCorp had $184 million and $230 million, respectively, of fully available letters of credit
issued under committed arrangements. As of December3l,20l8 and2017, $170 million and $2l6million, respectively, of these
letters of uedit, support PacifiCorp's variable-rate tax-exempt bond obligations and expire in March2019 and $14 million support
certain transactions required by third parties and have provisions that automatically extend the annual expiration dates for an
additional year unless the issuing bank elects not to renew a letter of credit prior to the expiration date.
In March 2019, PacifiCorp completed a re-offering of variable rate tax-exempt bond obligations totaling $168 million, involving the
cancellation at PacifiCorp's request for $170 million of letters of credit support by the issuing banks. As a result, PacifiCorp's credit
facility support for outstanding variable rate tax-exempt bond obligations increased by $168 million.
(7) Long-term Debt and Capital Lease Obligations
As of April 2019, PacifiCorp currently has regulatory authority from the Oregon Public Utility Commission ('OPUC') and the Idaho Public
Utilities Commission ("IPUC") to issue an additional $1.0 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC
prior to any future issuance. As of April 2019, PacifiCorp currently has an effective shelf registration statement filed with the United States
Securities and Exchange Commission to issue up to $ I .0 billion additional first mortgage bonds through October 2021 .
In March 2019, PacifiCorp issued $400 million of its 3.500% First Mortgage Bonds due June 2029 and $600 million of its 4.150%
First Mortgage Bonds due February 2050. PacifiCorp used a portion of the net proceeds to repay short-term debt that was partially
incurred to repay all of PacifiCorp's $350 million of its 5.50% First Mortgage Bonds due January 2019. PacifiCorp intends to use the
remaining net proceeds to fund capital expenditures and for general corporate purposes.
In July 2018, PacifiCorp issued $600 million of its 4.l25oA First Mortgage Bonds due January 2049.PacifrCorp used a portion of the
net proceeds to repay all of PacifiCorp's $500 million 5.65% First Mortgage Bonds due July 2018 and used the remaining net
proceeds to fund capital expenditures and for general corporate purposes.
PacifiCorp's long-term debt generally includes provisions that allow PacifiCorp to redeem the first mortgage bonds in whole or in
part at any time through the payment of a make-whole premium. Variable-rate tax-exempt bond obligations are generally redeemable
at par value.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, eamings tests and other provisions of PacifiCorp's
mortgage. Approximately $28 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage
as of December 3 l, 20 I 8.
PacifiCorp has entered into long-term agreements that qualifo as capital leases and expire at various dates through March 2035 for
transportation services, a power purchase agreement and real estate. The transportation services agreements included as capital leases
are for the right to use pipeline facilities to provide natural gas to two of PacifiCorp's generating facilities. Net capital lease assets of
$21 million and $20 million as of December 31, 2018 and 2017, respectively, were included in net utility plant on the Comparative
Balance Sheet.
As of December 31, 2018, the annual principal maturities of long-term debt and total capital lease obligations excluding unamortized
discount for 2019 and thereafter are as follows (in millions):
Long-term Capital LeaseDebt Obligations Total
2019
2020
2021
2022
2023
Thereafter
Total
Unamortized discount
Amounts representing interest
Total
$3s0 $
38
420
605
449
5,1 93
354
4t
427
608
451
5,209
$4
3
7
3
2
l6
7,055
(10)
35
(14)
7,090
(10)
(14)
$7,045 $2t$7,066
FERC FORM NO.1 (ED. {2-88)Page 123.9
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
(8) Income Taxes
Tax Cuts and Jobs Act
The Tax Cuts and Jobs Act enacted on December 22,2017 ("2017 Tax Reform") impacted many areas of income tax law. The most
material items included the reduction of the federal corporate tax rate from 35oh to 2loh effective January l, 201 8 and limitations on
bonus depreciation for utility property.
In December 2017 , the SEC issued Staff Accounting Bulletin I l8 to assist in the implementation process of the 201 7 Tax Reform by
allowing for calculations to be classified as provisional and subject to remeasurement. There are three different classifications for the
accounting: (1) completed, (2) not complete but reasonably estimable or (3) not complete and amounts are not reasonably estimable.
On December 31,2017, PacifiCorp recorded the impacts of the2017 Tax Reform and believed all the impacts to be complete with the
exception of interpretations of the bonus depreciation rules. PacifiCorp determined the amounts recorded and the interpretations
relating to this item to be provisional and subject to remeasurement during the measurement period upon obtaining the necessary
additional information to complete the accounting. PacifiCorp believed its interpretations for bonus depreciation to be reasonable,
however, clarifuing guidance was needed. During 2018, PacifiCorp finalized its provisional amounts recording a current tax benefit
and deferred tax expense of $21 million following clarifuing bonus depreciation guidance. As a result of 2017 Tal< Reform and
PacifiCorp's regulatory nature, PacifiCorp reduced the associated defened income tax liabilities $8 million and increased regulatory
liabilities by the same amount.
Income tax expense (benefit) consists of the following for the years ended December 3l (in millions):
2018 2017
Current:
Federal
State
Total
Deferred:
Federal
State
Total
Investment tax credits
Total income tax expense
Federal statutory income tax rate
State income taxes, net of federal income tax benefit
Amortization of excess deferred income taxes
Federal income tax credits
Other
Effective income tax rate
$163 $
42
239
4t
205 280
(r e0)
(e)
63
t6
(lee)79
(3)(4)
$3$355
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax
expense is as follows for the years ended December 3l:
2018 2017
2t%
4
(17)
(7)
(l)
35%
J
(s)
(l)
-o/o 32%
FERC FORM NO.1 (ED. 12.88)Page'123.10
Name of Respondent
PacifiCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
2018/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Income tax credits relate primarily to production tax credits eamed by PacifiCorp's wind-powered generating facilities. Federal
renewable electricity production tax credits are eamed as energy from qualifuing wind-powered generating facilities is produced and
sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities
are eligible forthe credits for l0 years from the date the quali$ing generating facilities are placed in-service. Amortization of excess
deferred income taxes is primarily attributable to the amortization of $127 million of Utah allocated excess deferred income taxes
pursuant to a2017 Tax Reform settlement approved by the Utah Public Service Commission ('UPSC"), whereby a portion of Utah
allocated excess deferred income taxes was used to accelerate depreciation on Utah's share of certain thermal plant units.
The net deferred income tax liability consists of the following as of December 3l (in millions):
2018 2017
Deferred income tax assets:
Regulatory liabilities
Employee benefits
Derivative contracts and unamortized contract values
State carryforwards
Asset retirement obligations
Other
$
824 836
503
9l
45
77
53
55
$5 t7
84
48
83
50
54
Deferred income tax liabilities:
Property, plant and equipment
Regulatory assets
Other
Net operating loss carryforwards
Deferred income taxes on net operating loss carryforwards
Expiration dates
Tax credit carryforwards
Expiration dates
(3,0e 1)
(273)
(12)
(3,1s7)
(261)
(12)
(3,376)(3,430)
Net deferred income tax liabilitv $(2,552) $(2,594)
The following table provides PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December3l,
2018 (in millions):
State
$
$
1,230
58
2019 - 2032
$19
2019 - indefinite
The United States Internal Revenue Service has closed its examination of PacifiCorp's income tax returns through December3l,
20 I 1 . The statute of limitations for PacifiCorp's state income tax returns have expired through December 3l , 2009, with the exception
of ldaho, for which the statute of limitations has expired through December 31,2014, except for the impact of any federal audit
adjustments. The statute of limitations expiring for state filings may not preclude the state from adjusting the state net operating loss
carryforward utilized in a year for which the statute of limitations is not closed.
FERC FORM NO.1 ED. 12-88 123.11
Name of Respondent
PacifiCorp
This Report is:
(1) XAn OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
In general, PacifiCorp's excess deferred income tax was calculated by measuring the difference between the gross temporary
differences as of December 31,2017 at PacifiCorp's post-tax reform combined federal and state statutory income tax rate, as
compared to the same gross temporary differences at PacifiCorp's pre-tax reform combined federal and state statutory income tax
rate. As of December 31,2017, an estimate of excess deferred income tax was recorded in Account 254, Regulatory liabilities. The
excess deferred income tax balances presented in the table below represents the final excess defened income tax balances after the
completion of PacifiCorp's December 31,2017 federal income tax return and does not reflect any amortizations recorded during the
year ended December 3 l, 20 I 8 (in millions):
Protected(l) l\6n-Pystsslsfl(2)Total
Deferred income tax asset (190)$$63$63
Deferred income tax liability
Accelerated amortization property (28 1 )
Other property (282)
Other (283)
Other regulatory assets (182.3)
Total excess deferred income taxes
Gross-up
Regulatory Liabilities (254)
(5)
(372)
(200)
(ee)
(1,590)
(200)
(e4)
(1,218)
12)(s77)( 1,889)
190 190
(s33)
$(2,169 )
(l)Protected excess deferred tax balances will be amortized using the Average Rate Assumption Method over the remaining book life ofthe related assets to
Account 4 I L l. Provision for defened income taxes-credit.
Non-protected excess deferred income tax balances will amortize over the period authorized by each ofPacifiCorp's regulatory commissions and amortized
to Account 4l l.l, Provision for deferred income taxes-credit. The UPSC authorized the full amortization ofnon-protected balances in 2018 and in Idaho, a
stipulation was filed and expected to be amortized over seven-years. For all other jurisdictions, the amortization period has not yet been determined.
The company is working to include a mechanism for excess deferred income tax in its FERC formula rate. The status of tax reform is
further discussed below by state jurisdiction.
Utah
In April 201 8, the UPSC ordered a rate reduction of $61 million , or 4.7oh, effective May l, 201 8 through December 3 I , 2018, based
on a preliminary estimate of the revenue requirement impact of 2017 Tax Reform. In November 2018, the UPSC approved an
all-party settlement that continues the current rate reduction of $61 million, with other benefits provided to customers through a
combination of $174 million of accelerated depreciation of certain thermal steam plant units and deferral of other benefits to offset
costs in the next general rate case.
Oregon
In December 2018, PacifiCorp proposed to reduce customer rates to reflect the lower annual current income tax expense in Oregon
resulting from 2017 Tax Reform. PacifiCorp reached an all-party settlement on the amortization of the current income tax expense
benefits and the deferral of the decision regarding the ratemaking treatment of excess deferred income tax balances until PacifiCorp's
next rate case. The settlement, which results in a rate reduction of $48 million, or 3.7yo, effective February 1,2079, was approved by
the OPUC in January 2019.
FERC FORM NO.1 (ED.12-88)Page 123.12
(21
$ (tJp) $ (3r4) $ (r^636)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
20't8tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Wyoming
In April 2018, PacifiCorp filed a partial settlement related to the impact of 2017 Tax Reform with the Wyoming Public Service
Commission ("WPSC') that provides a rate reduction of $23 million, or 3 .3Yo, effective July I , 201 8 through June 30, 20 19, with the
remaining tax savings to be deferred with offsets to other costs. In June 2018, the WPSC approved the rate reduction on an interim
basis. In June 2018, PacifiCorp filed reports with the WPSC with the calculation of the full impact of the tax law change on revenue
requirement of $28 million annually, comprised of $20 million in current tax savings and $8 million for the amortization of excess
deferred income tax. These reports initiated the next phase ofthe proceedings including a hearing held in January 2019 and public
deliberations in February 2019. During public deliberations the WPSC approved the continuation of the rate reduction until the next
general rate case with other savings to be deferred to offset other costs. In March 2019,the WPSC issued a written order approving
the continued annual rate reduction of $23 million until base rates are reset in the next general rate proceeding with an additional $4
million to be offset against PacifiCorp's 2018 energy cost adjustment mechanism. The order reflected the $20 million of current tax
savings and was updated to reflect a projection of $7 million for amortization of excess deferred income tax.
Washington
In November 201 8, PacifiCorp proposed to reduce customer rates by $8 million, or 2.3o/o, effective January l, 2019, to reflect the
lower annual current income tax expense in Washington resulting from 2017 Tax Reform and to defer all other tax savings to offset
costs in the next general rate case. PacifiCorp's proposal was approved by the WUTC in December 2018.
Idaho
In May 2018, the IPUC approved an all-party settlement to implement a rate reduction of $6 million, or 2.2o/o, effective June l, 2018
through May 31, 2019,to pass back a portion of the benefits associated with 2017 Tax Reform. The credit may be adjusted following
the next phase of the proceeding. In June 2018, PacifiCorp filed a report with the IPUC with the calculation of the full impact of the
tax law change on revenue requirement of $ I 1 million annually, comprised of $8 million in current tax savings and $3 million of the
amortization of excess defered income tax. In March 2019, a stipulation was filed to resolve the treatment of the remaining tax
savings, including an additional $7 million to be returned to customers or used to offset customer costs effective June I , 2019.
Calfornia
The decision on how to return the benefits associated with 20 I 7 Tax Reform to Califomia customers has not been finalized.
(9) Employee Benefit Plans
PacifiCorp sponsors defined benefit pension and other postretirement benefit plans that cover the majority of its employees, as well as
a defined contribution 401(k) employee savings plan ("401(k)Plan"). In addition, PacifiCorp contributes to a joint trustee pension
plan and a subsidiary previously contributed to a multiemployer pension plan for benefits offered to certain bargaining units.
Defined Benefit Plans
PacifiCorp's pension plans include non-contributory defined benefit pension plans, collectively the PacifiCorp Retirement Plan
("Retirement Plan")n and the Supplemental Executive Retirement Plan ("SERP"). The Retirement Plan is closed to all non-union
employees hired after January l, 2008. All non-union Retirement Plan participants hired prior to January l, 2008 that did not elect to
receive equivalent fixed contributions to the 401(k) Plan effective January 1,2009 earned benefits based on a cash balance formula
through December 31,2016. Effective January 1,2017, non-union employee participants with a cash balance benefit in the
Retirement Plan are no longer eligible to receive pay credits in their cash balance formula. In general for union employees, benefits
under the Retirement Plan were frozen at various dates from December 31,2007 through December 3l,20ll as they are now being
provided with enhanced 401(k) Plan benefits. However, certain limited union Retirement Plan participants continue to eam benefits
under the Retirement Plan based on the employee's years of service and a final average pay formula. The SERP was closed to new
participants as of March 21,2006 and froze future accruals for active participants as of December 31,2014.
During 2018, the Retirement Plan incurred a settlement charge of $22 million as a result of excess lump sum distributions over the
defined threshold for the year ended December 3 l, 201 8.
other healthcare and life insurance benefits to
FERC FORM NO.1 ED.1 123.13
benefit retirees.
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Net Periodic Benefit Cost
For purposes ofcalculating the expected return on plan assets, a market-related value is used. The market-related value ofplan assets
is calculated by spreading the difference between expected and actual investment returns over a five-year period beginning after the
first year in which they occur.
Net periodic benefit cost or benefit for the plans included the following components for the years ended December 3l (in millions):
Pension Other Postretirement
2018 2017 2018 2017
Service cost
Interest cost
Expected retum on plan assets
Settlement
Net amortization
Net period benefit cost (credit)
$$$2$
l1
(21)
2
t4
(21)
43
(72)
22
l3
49
(72)
t4 (6)(6)
$6$(e) $(14) $(11)
Funded Status
The following table is a reconciliation of the fair value of plan assets for the years ended December 3l (in millions):
Pension Other Postretirement
2018 2017 2018 2017
Plan assets at fair value, beginning ofyear
Employer contributions
Participant contributions
Actual return on plan assets
Seftlement
Benefits paid
PIan assets at fair value, end ofyear
$1,111 $
4
999
54
166
$332 $
1
5
(16)
302
I
7
49
(27)
(s2)
(s2)
G9 (108)(2s)
$942 $ 1,lll $297 $332
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions)
Pension Other Postretirement
2018 2017 2018 2017
Benefit obligation, beginning of year
Service cost
Interest cost
Paticipant contributions
Actuarial (gain) loss
Settlement
Benefits paid
Benefit obligation, end of year
$)\I $,276
49
34
(r08)
$331 $
2
ll
5
(26)
358
2
14
7
(23)
43
(68)
(s2)
(6e)(2s)
los $1,251 $
Accumulated benefit 105 1
FERC FORM NO.1 ED.1 123.14
end of
298 $331
(27\
$
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The funded status of the plans and the amounts recognized on the Comparative Balance Sheet as of December 3l are as follows
(in millions):
Pension Other Postretirement
2018 2017 2018 2017
Plan assets at fair value, end ofyear
Less - Benefit obligation, end ofyear
Funded status
$942 $ l,lil $297 $552
1,105 1,251 298 331
$ (163) $ (l4o) $ (l)$I
Amounts recognized on the Comparative Balance Sheet:
Other special funds (128)
Miscellaneous current and accrued liabilities (242)
Accumulated provision for pension and benefits (228.3)
Amounts recognized
$$$$
(4)
(lse)
(4)
(136)(l)
$ (163) $ (l4o)s
The SERP has no plan assets; however, PacifiCorp has a Rabbi trust that holds corporate-owned life insurance and other investments
to provide funding for the future cash requirements of the SERP. The cash surrender value of all of the policies included in the Rabbi
trust, net of amounts borrowed against the cash surrender value, plus the fair market value of other Rabbi trust investments, was
$52 million and $60 million as of December 31, 2018 and2017, respectively. These assets are not included in the plan assets in the
above table, but are reflected in temporary cash investments, totaling $l million and $9 million as of December3l, 2018 and2077,
respectively, and other investments, totaling $51 million as of December 31, 2018 and2017 on the Comparative Balance Sheet.
The projected benefit obligation for the pension and other postretirement plans were in excess of the fair value of their respective
plans assets as of December 31, 2018. The accumulated benefit obligation for the pension plans was in excess of the fair value of plan
assets as of December 31,2018.
Unrecognized Amounts
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 3l is as follows (in
millions):
Pension Other Postretirement
20lE 2017 20r8 2017
Net loss (gain)
Prior service credit
Regulatory deferrals
Total
$461 $442 $(2) $(12)
(6)
7(l)(4)7
$460 s 438 $5 $ (ll)
FERC FORM NO 1 I 123.15
I
I
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
20181Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 3 I , 20 1 8
and2017 is as follows (in millions):
Accumulated
OtherRegulatory Comprehensive
Asset Loss Total
Pension
Balance, December 31, 2016
Net (gain) loss arising during the year
Net amortization
Total
Balance, December 31, 2017
Net loss (gain) arising during the year
Net amortization
Settlement
Total
Balince, December 31, 2018
491 $20$
(u
(73)(73)
418 20
25 (3)22
443 $17$460
Other Postretirement
Balance, December 31, 2016
Net gain arising during the year
Net amortization
Total
Balance, December 31, 2017
Net loss arising during the year
Net amortization
Total
Balance, December 31, 2018
$
(5 1)
(l l)
l0
$
Plan Assumptions
Pension Other Postretirement
2018 2017 2018 2017
$5l I
(60)
(13)
(se)
(14)
438
59
(t2)
(:22)
(2)
(l)
57
( l3)
(22)
$
34
6
(45)
6
l6
5
Benefit obligations as of December 3 I :
Discount rate
Rate of compensation increase
Interest crediting rates for cash balance plan(lX2)
Net periodic benefit cost for the years ended December 3 I
Discount rate
Expected retum on plan assets
Rate of compensation increase
4.25%
N/A
3.40%
3.60%
7.00
N/A
3.60%
N/A
l.610
4.05%
7.25
N/A
4.25%
N/A
N/A
3.60%
6.86
N/A
3.60%
N/A
N/A
4.05%
7.25
N/A
(l)
(2)
201 8 Cash Balance Interest Crediting Rate assumption is 3A0% for 20 I 9 and all future years for nonunion participants and 3.15% for 2019-2020 and 3.25Yo
for 2021+ for union participants.
2017 Cash Balance Interest Crediting Rate assumption was 2 .26% for 2018-2019 and 1.60% for 2020+ for nonunion participants and 2.78% for 2018-2019
and2.60%o for 2020+ for union participants.
FERC FORM NO.1 (ED.12.88)Page 123.16
Regulatory
Asset (Liability)
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
In establishing its assumption as to the expected return on plan assets, PacifiCorp utilizes the asset allocation and return assumptions
for each asset class based on historical performance and forward-looking views of the financial markets.
As a result of a plan amendment effective on January 1,2017, the benefit obligation for the Retirement Plan is no longer affected by
future increases in compensation. As a result of a labor settlement reached with United Mine Workers of America ("UMWA") in
December 2014,the benefit obligation for the other postretirement plan is no longer affected by healthcare cost trends.
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $- million,
respectively, during 2019. Funding to PacifiCorp's Retirement Plan trust is based upon the actuarially determined costs of the plan and
the requirements of the Internal Revenue Code, the Employee Retirement Income Security Act of 1974 ('ERISA") and the Pension
Protection Act of 2006, as amended ("PPA"). PacifiCorp considers contributing additional amounts from time to time in order to
achieve certain funding levels specified under the PPA. PacifiCorp's funding of its other postretirement benefit plan is subject to tax
deductibility and subordination limits and other considerations.
The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2019 through 2023
and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Pension Other Postretirement
$2019
2020
2021
2022
2023
2024-2028
Debt securities(2)
Equity securities(2)
Limited partnership interests
r0s $
102
98
92
88
369
24
26
zt
22
2l
95
Plan Assets
Investment Policy and Asset Allocations
PacifiCorp's investment policy for its pension and other postretirement benefit plans is to balance risk and return through a diversified
portfolio of debt securities, equity securities and other altemative investrnents. Maturities for debt securities are managed to targets
consistent with prudent risk tolerances. The plans retain outside investment advisors to manage plan investments within the
parameters outlined by the PacifiCorp Pension Committee. The investment portfolio is managed in line with the investment policy
with sufficient liquidity to meet near-term benefit payments.
The target allocations (percentage of plan assets) for PacifiCorp's pension and other postretirement benefit plan assets are as follows
as of December31,20l8:
Other
Pension(l) Postretirement(l)
%
30-43
48-65
6-12
%
-37
66
J
JJ
62
I
(l) PacifiCorp's Retirement Plan trust includes a separate account that is used to fund benefits for the other postretirement benefit plan. In addition to this
separate account, the assets for the other postretirement benefit plan are held in Voluntary Employees' Beneficiary Association ('VEBA-) trusts, each of
which has its own investment allocation strategies. Target allocations for the other postretirenent benefit plan include the separate account ofthe Retirement
Plan trust and the VEBA trusts.
(2)For purposes of target allocation percentages and consistent with the plans' investment policy, investment funds are allocated based on the underlying
investments in debt and equity securities.
FERC FORM NO.1 (ED.12.88)Page 123.17
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Fair Value Measurements
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit pension plan (in
millions):
Input Levels for Fair Value Measurements
Level 1(1) Level2(1) Level3(l)Total
As of December 31. 2018:
Cash and cash equivalents
Debt securities:
United States government obligations
International govemment obligations
Corporate obligations
Municipal obligations
Agency, asset and mortgage-backed obligations
Equity securities:
United States companies
International companies
Investment funds(2)
Total assets in the fair value hierarchy
Investment funds(2) measured at net asset value
Limited partnership interests(3) measured at net asset value
Investments at fair value
$lr $$1l
$400 $153 $
$
4 4
I
88
10
43
327
l5
54
327
l5
54
$$
553
285
104
$942
$
As of December 31.2017:
Cash and cash equivalents
Debt securities:
United States govemment obligations
Corporate obligations
Municipal obligations
Agency, asset and mortgage-backed obligations
Equity securities:
United States companies
International companies
Total assets in the fair value hierarchy
Investment funds(2) measured at net asset value
Limited partnership interests(3) measured at net asset value
Investments at fair value
43$
60
9
37
45
43
45
60
9
37
416
22
416
22
$483 $149 $632
416
63
$ l,llr
(l) Refer to Note l2 for additional discussion regarding the three levels ofthe fair value hierarchy
(2) Investment funds are substantially comprised ofmutual funds and collective trust funds. These funds consist ofequity and debt securities ofapproximately
55o/o and 45% respectively, for 2018 and 60%o and 40%, respectively. for 2017, and are invested in United States and intemational securities of
approximately 68Yo utd 32%, respectively, for 201 8 and 57Yo and 43Y0, respectively, for 2017 .
(3) Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
FERC FORM NO.1 (ED. 12481 Page 123.18
I
88
l0
43
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table presents the fair value of plan assets, by major category, for PacifiCorp's defined benefit other postretirement plan
(in millions):
Input Levels for tr'air Value Measurements
Level 1(1) Level 2(l) Level3(l) Total
As of December 31.2018:
Cash and cash equivalents
Debt securities:
United States govemment obligations
Corporate obligations
Municipal obligations
Agency, asset and mortgage-backed obligations
Equity securities:
United States companies
International companies
Investment funds(2)
Total assets in the fair value hierarchy
Investment funds(2) measured at net asset value
Limited partnership interests(3) measured at net asset value
Investments at fair value
$4$l$$5
J
;
2
17
J
23
2
t7
83 83
4
38
4
38
$132 $43$175
116
6
$297
As of December 31.2017:
Cash and cash equivalents
Debt securities:
United States government obligations
Corporate obligations
Municipal obligations
Agency, asset and mortgage-backed obligations
Equity securities:
United States companies
International companies
Investment funds(2)
Total assets in the fair value hierarchy
Investment funds(2) measured at net asset value
Limited partnership interests(3) measured at net asset value
Investments at fair value
$4$3$$7
11 ll
t6
2
l6
98
6
32
98
6
32
$lsl $37$188
140
4
$332
(l ) Refer to Note 12 for additional discussion regarding the tkee levels ofthe fair value hierarchy.
(2) Investment funds are substantially comprised ofmutual funds and collective trust funds. These funds consist ofequity and debt securities ofapproximately
59% and 4lolo, respectively, for 2018 and 63% and 37%, respectively, for 2017, and are invested in United States and intemational securities of
approximately 90% and l0%, respectively, for 2018 and11%o and23%o, respectively, for 2017.
(3) Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
FERC FORM NO.1 (ED.12.88)Paqe 123.19
t6
2
t6
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
For level I investments, a readily observable quoted market price or net asset value of an identical security in an active market is used
to record the fair value. For level 2 investments, the fair value is determined using pricing models based on observable market inputs.
Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and
commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for
expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.
Multiemplover and Joint Trustee Pension Plans
PacifiCorp contributes to the PacifiCorp/IBEW Local 57 Retirement Trust Fund ("Local 57 Trust Fund") (plan number00l) and its
wholly owned subsidiary, Energy West Mining Company, previously contributed to the UMWA 1974 Pension Plan (plan
number 002). Contributions to these pension plans are based on the terms of collective bargaining agreements.
As a result of the Utah Mine Disposition and UMWA labor settlement, PacifiCorp's wholly owned subsidiary, Energy West Mining
Company, triggered involuntary withdrawal from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased
performing work for the subsidiary. PacifiCorp recorded its estimate of the withdrawal obligation in December 2014 when withdrawal
was considered probable and deferred the portion ofthe obligation considered probable ofrecovery to a regulatory asset. PacifiCorp
has subsequently revised its estimate due to changes in facts and circumstances for a withdrawal occurring by July 2015. As
communicated in a letter received in August 2016,the plan trustees have determined a withdrawal liability of $ll5 million. Energy
West Mining Company began making installment payments in November 2016 and has the option to elect a lump sum payment to
settle the withdrawal obligation. The ultimate amount paid by Energy West Mining Company to settle the obligation is dependent on a
variety of factors, including the results of ongoing negotiations with the plan trustees.
The Local 57 Trust Fund is a joint trustee plan such that the board of trustees is represented by an equal number of trustees from
PacifiCorp and the union. The Local 57 Trust Fund was established pursuant to the provisions of the Taft-Hartley Act and although
formed with the ability for other employers to participate in the plan, there are no other employers that participate in this plan.
The risk of participating in multiemployer pension plans generally differs from single-employer plans in that assets are pooled such
that contributions by one employer may be used to provide benefits to employees of other participating employers and plan assets
cannot revert back to employers. If an employer ceases participation in the plan, the employer may be obligated to pay a withdrawal
liability based on the participants' unfunded, vested benefits in the plan. This occurred as a result of Energy West Mining Company's
withdrawal from the UMWA 1974 Pension Plan. If participating employers withdraw from a multiemployer plan, the unfunded
obligations of the plan may be borne by the remaining participating employers, including any employers that withdrew during the
three years prior to a mass withdrawal.
The following table presents PacifiCorp's participation in individually significant joint trustee and multiemployer pension plans for
the years ended December 3l (dollars in millions):
PPA zone status or plan
funded strtus percentage for
plan years beginning July I,Contributions(1 )
2017
Funding
improvemcnt
plan 2018 2017 total contributions(2)
Employcr
ldentilication
Number
Surchargc
imposed under
PPA(I)
Year contributions to plan
exceeded more than 57o of
Plan namc 201E
Local 57
Trust Fund
(l)
87-0640888 At least 80% At least 80% None None $ 7 $ 7 2016,2015
PacifiCorp's minimum contributions to the plan are based on the amount of wages paid to employees covered by the Local 57 Trust Fund collective
bargaining agreements, subject to ERISA minimum funding requirements.
For the Local 57 Trust Fund, information is for plan years beginning July l, 2016 and 2015. Information for the plan year beginning July 1, 2017 is not yet
available.
(2)
The current collective bargaining agreements goveming the Local 57 Trust Fund expires in 2023
FERC FORM NO.1 (ED.12-88)Page 123.20
Name of Respondent
PaciliCorp
This Report is:
(1) X An Original
(2) - A Resubmission
Date of Report
(Mo, Da, Yr)
ll
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Defined Contribution Plan
PacifiCorp's 401(k) Plan covers substantially all employees. PacifiCorp's matching contributions are based on each participant's level
of contribution and, as of January 1,2018, all panicipants receive contributions based on eligible pre-tax annual compensation.
Contributions cannot exceed the maximum allowable for tax purposes. PacifiCorp's contributions to the 401(k) Plan were $39 million
for the years ended December 3 l, 2018 and 2017 .
(10) Asset Retirement Obligations
PacifiCorp estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash
spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a
credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations,
plan revisions, inflation and changes in the amount and timing of the expected work.
PacifiCorp does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate
removal date, the fair value of the associated liabilities on certain transmission, distribution and other assets cannot currently be
estimated, and no amounts are recognized on the financial statements other than those included in the accumulated provision for
depreciation established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled
$994 million and $955 million as of December 31, 2018 and 2017 , respectively.
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 3l
(in millions):
2018 2017
Beginning balance
Change in estimated costs
Additions
Retirements
Accretion
Ending balance
$zts $
9
2t5
(8)
6
(6)
8
o,
8
227 S 215
Certain of PacifiCorp's decommissioning and reclamation obligations relate to jointly owned facilities and mine sites. PacifiCorp is
committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other
joint participants, PacifiCorp may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of
the defaulting party's liability. PacifiCorp's estimated share of the decommissioning and reclamation obligations are primarily
recorded as ARO liabilities.
(11) Risk Management and Hedging Activities
PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to
electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its service
territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity
prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and
sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable
items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation
constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of
proprietary trading activities.
FERC FORM NO.1 (ED.12.88)Page'123.21
$
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
PacifiCorp has established a risk management process that is designed to identify, assess, manage, mitigate, monitor and report, each
of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity
derivative contracts, which may include forwards, options, swaps and other agreements, to effectively secure future supply or sell
future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates
primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally,
PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate
PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not
hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Notes 2 and 12 for
additional information on derivative contracts.
The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the
normal purchases or normal sales exception, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and
reconciles those amounts to the amounts presented on a net basis on the Comparative Balance Sheet (in millions):
Current Long-term Current Long-term
Assets Assets Liabilities Liabilities Total
As of December 31. 2018:
Not designated as hedging contracts(1):
Commodity assets
Commodity liabilities
Total
4$l$
(l)(7t)
$36$
(e)
l0$
(67)
5l
( 148)
27 (s7)(70)(e7)
Total derivatives
Cash collateral receivable
Total derivatives - net basis
As of December 31. 2017:
Not designated as hedging contracts(l):
Commodity assets
Commodity liabilities
Total
Total derivatives
Cash collateral receivable
Total derivatives - net basis
Beginning balance
Changes in fair value recognized in regulatory assets
Net (losses) gains reclassified to operating revenue
Net gains (losses) reclassified to energy costs
Ending balance
27
(2)
$2s$
3 (57)
l6
(70)(e7)
5945
3 $ (41)$ (2s)$ (38)
$11 $
(3)
l3
(ll7)
l$l$$
(32)(82)
8 (31)(82)(r04)
8 (3 1)
t7
(r04)
74
(82)
57
$8$l $ (r4)$ (25)$ (30)
(l) PacifiCorp's commodity derivatives are generally included in rates and as of December3l, 2018 afi 2017, a regulatory asset of
$96million and $l0l million, respectively, was recorded related to the net derivative liability of $9Tmillion and $l04million,
respectively.
The following table reconciles the beginning and ending balances of PacifiCorp's regulatory assets and summarizes the pre-tax gains
and losses on commodity derivative contracts recognized in regulatory assets, as well as amounts reclassified to eamings for the years
ended December 3l (in millions):
2018 2017
$l0l s
l2
(68)
5l
73
47
9
(28)
$e6$l0l
FERC FORM NO.1 (ED.I2.88)Pase 123.22
3
I
I
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Derivative Contract Yolumes
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that
comprise the mark-to-market values as of December 3l (in millions):
Unit of
Measure 2018 2017
Electricity sales
Natural gas purchases
Fuel oil purchases
Megawatt hours
Decatherms
Gallons
(6)
tt7
(e)
lt3
Credit Risk
PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities,
energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent
PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among
the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale
counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the
appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparfy credit risk, PacifiCorp
enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains
third-party guarantees, letters ofcredit and cash deposits. Ifrequired, PacifiCorp exercises rights under these arrangements, including
calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale derivative contracts contain credit support provisions that in part base certain
collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating
agencies. These derivative contracts may either specifically provide bilateral rights to demand cash or other security if credit
exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the
right for counterparties to demand "adequate assurance" in the event of a material adverse change in PacifiCorp's creditworthiness.
These rights can vary by contract and by counterparfy. As of December3l,2018, PacifiCorp's credit ratings for its senior secured
debt and its issuer credit ratings for senior unsecured debt by Moody's Investor Service and Standard & Poor's Rating Services were
investment grade.
The aggregate fairvalue of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features
totaled $ I l3 million and $ I l0 million as of December 31, 2018 md 2017, respectively, for which PacifiCorp had posted collateral of
$61 million and $74 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative
contracts in liability positions had been triggered as of December3l,20l8 and2017, PacifiCorp would have been required to post
$35 million and $34 million, respectively, of additional collateral.
In addition to derivative contracts in liability positions, PacifiCorp has non-derivative wholesale agreements with specified
credit-risk-related contingent features that base certain collateral requirements on credit ratings. If all credit-risk-related contingent
features or adequate assurance provisions for wholesale agreements, including non-derivative agreements and derivative contracts in
liabilify positions, had been triggered as of December 31, 2018 and December 31,2017, PacifiCorp would have been required to post
$289 million and $233 million, respectively, of additional collateral.
PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in
legislation or regulation or other factors.
FERC FORM NO.1 (ED.12-88)Page 123.23
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
20't8tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
(12) Fair Value Measurements
The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, other special funds, other investments, payables,
accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments.
PacifiCorp has various financial assets and liabilities that are measured at fair value on the financial statements using inputs from the
three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the
lowest level input that is significant to the fair value measurement. The three levels are as follows:
Level I - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the
ability to access at the measurement date.
Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or
similar assets or liabilities in markets thal are not active, inputs other than quoted prices that are observable for the asset
or liability and inputs that are derived principally from or conoborated by observable market data by correlation or other
means (market corroborated inputs).
Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in
pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best
information available, including its own data.
a
a
a
The following table presents PacifiCorp's assets and liabilities recognized on the Comparative Balance Sheet and measured at fair
value on a recurring basis (in millions):
Input Levels for Fair Value
Measurements
Level I Level 2 Level 3 Other(1)Total
As of December 31. 2018:
Assets:
Commodity derivatives
Money market mutual funde(2)
Investment funds
$$st $
$87$sl $
Liabilities - Commodity derivatives $- $ (148) $
$ (23) $28
63
24
63
24
$(23) $115
-$82$(66)
As of December 31.2017:
Assets:
Commodity derivatives
Money market mutual funds(2)
Investment funds
$$13$$(4) $9
2t
2t
2l
2t
$42$13$-$(4) $51
Liabilities - Commodity derivatives $$ (117) $$78$(3e)
( I ) Represents netting under master netting arrangements and a net cash collateral receivable of$59 million and $74 million as ofDecember 3 l, 201 8 and 201 7,
respectively.
Amounts are included in other special funds and deposits and temporary cash investments on the Comparative Balance Sheet. The fair value ofthese money
market mutual funds approximates cost.
FERC FORM NO.1 (ED.12-88)Page 123.24
(2)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
20181Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Derivative contracts are recorded on the Comparative Balance Sheet as either assets or liabilities and are stated at estimated fair value
unless they are designated as normal purchases or normal sales and qualifu for the exception afforded by GAAP. When available, the
fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp
transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves
represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates.
PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial
models, with intemal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers,
exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for
certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's
forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and
natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts,
as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on
perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these
derivative contracts is a function of underlying forward commodify prices, interest rates, currency rates, related volatility,
counterparty creditworthiness and duration of contracts. Refer to Note I I for further discussion regarding PacifiCorp's risk
management and hedging activities.
PacifiCorp's investments in money market mutual funds and investment funds are stated at fair value and are primarily accounted for
as available-for-sale securities. When available, PacifiCorp uses a readily observable quoted market price or net asset value of an
identical security in an active market to record the fair value. In the absence ofa quoted market price or net asset value ofan identical
security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market
prices of securities with similar characteristics.
PacifiCorp's long-term debt is carried at cost on the financial statements. The fair value of PacifiCorp's long-term debt is a Level 2 fair
value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash
flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's
variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The
following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt as of December 3l (in millions):
2018 2017
Fair
Value
Long-term debt
(13) CommitmentsandContingencies
Legal Matters
$7,045 $7,833 $7,03r $8,370
PacifiCorp is parfy to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or
exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its financial
results.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards,
emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected
species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp
believes it is in material compliance with all applicable laws and regulations.
FERC FORM NO.1 (ED.12.88)Pase 123.25
Carrying
Value
Fair
Value
Carrying
Value
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Hydroelectric Relicens ing
PacifiCorp's Klamath hydroelectric system is currently operating under annual licenses with the FERC. In February 2010, PacifiCorp,
the United States Department of the Interior, the United States Department of Commerce, the state of California, the state of Oregon
and various other governmental and non-governmental settlement parties signed the Klamath Hydroelectric Settlement Agreement
("KHSA"). Among other things, the KHSA provided that the United States Department of the Interior would conduct scientific and
engineering studies to assess whether removal of the Klamath hydroelectric system's mainstem dams was in the public interest and
would advance restoration of the Klamath Basin's salmonid fisheries. If it is determined dam removal should proceed, dam removal
would begin no earlier than2020.
Congress failed to pass legislation needed to implement the original KHSA. In April 2016, the principal parties to the KHSA
(PacifiCorp, the states of Califomia and Oregon and the United States Departments of the Interior and Commerce) executed an
amendment to the KHSA. Consistent with the terms of the amended KHSA, in September 2016, PacifiCorp and the Klamath River
Renewal Corporation ("KRRC"), a private, independent nonprofit 501(cX3) organization formed by certain signatories of the
amended KSHA, jointly filed an application with the FERC to transfer the license for the four mainstem Klamath River hydroelectric
generating facilities from PacifiCorp to the KRRC. Also in September 2016, the KRRC filed an application with the FERC to
surrender the license and decommission the same four facilities. The KRRC's license surrender application included a request for the
FERC to refrain from acting on the surrender application until after the transfer of the license to the KRRC is effective. In March
2018, the FERC issued an order splitting the existing license for the Klamath Project into two licenses: the Klamath Project (P-2082)
contains East Side, West Side, Keno and Fall Creek developments; the new Lower Klamath Project (P-14803) contains J.C. Boyle,
Copco No. l, Copco No. 2 and Iron Gate developments. In the same order, the FERC deferred consideration of the transfer of the
license for the Lower Klamath facilities from PacifiCorp to the KRRC until some point in the future. PacifiCorp is currently the
licensee for both the Klamath Project and Lower Klamath Project facilities and will retain ownership of the Klamath Project facilities
after the approval and transfer of the Lower Klamath Project facilities. In April 2018, PacifiCorp filed a motion to stay the effective
date of the license amendment until transfer is approved. In June 2018, the FERC granted PacifiCorp's motion to stay the effective
date of the Lower Klamath Project license and all related compliance obligations, pending a FERC order on the license transfer.
Meanwhile, the FERC continues to assess the KRRC's capacity to become a project licensee for purposes of dam removal. The United
States Court of Appeals for the District of Columbia Circuit issued a decision in the Hoopa Valley Tribe v. FERC litigation, on
January 25,2019, finding that the states of Califomia and Oregon have waived their Clean Water Act, Section 401, water quality
certification authority over the Klanath hydroelectric project relicensing. PacifiCorp is evaluating the impact of this decision.
Under the amended KHSA, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilities. The KRRC
must indemnifu PacifiCorp from liabilities associated with dam removal. The amended KHSA also limits PacifiCorp's contribution to
facilities removal costs to no more than $200million, of which up to $l84million would be collected from PacifiCorp's Oregon
customers with the remainder to be collected from PacifiCorp's California customers. California voters approved a water bond
measure in November 2014 from which the state of California's contribution toward facilities removal costs are being drawn. In
accordance with this bond measure, additional funding of up to $250 million for facilities removal costs was included in the
California state budget in 2016, with the funding effective for at least five years. If facilities removal costs exceed the combined
funding that will be available from PacifiCorp's Oregon and California customers and the state of California, sufficient funds would
need to be provided by the KRRC or an entity other than PacifiCorp for removal to proceed.
If certain conditions in the amended KHSA are not satisfied and the license does not transfer to the KRRC, PacifiCorp will resume
relicensing with the FERC.
As of December31,2018, PacifiCorp's assets included $44 million of costs associated with the Klamath hydroelectric system's
mainstem dams and the associated relicensing and settlement costs, which are being depreciated and amortized in accordance with
state regulatory approvals through either December 3 1 , 2019, or December 3l , 2022, depending upon the state jurisdiction.
Hydro electic C ommitments
Certain of PacifiCorp's hydroelectric licenses contain requirements forPacifiCorp to make certain capital and operating expenditures
related to its hydroelectric facilities. PacifiCorp estimates it is obligated to make capital expenditures of approximately $155 million
over the next l0 years related to these licenses.
FERC FORM NO.1 (ED.12-88)Page 123.26
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Commitments
PacifiCorp has the following firm commitments that are not reflected on the Comparative Balance Sheet. Minimum payments as of
December 3 I , 201 8 are as follows (in millions):
Contract tvpe:
Purchased electricity contracts -
commercially operable
Purchased electricity contracts -
non-commercially operable
Fuel contracts
Construction commitments
Transmission
Operating leases and easements
Maintenance, service and
other contracts
Total commitments
$ 317 $ 194 $ 155 $ 152 $ 145 $ 1,522 $ 2,485
52 25 26
s 2,217 $ 1,548 $ 839 $ 618 $ 538 $ 3,893 s 9,ss3
Purchased Electricity Contracts - Commercially Operable
As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-term purchases and exchange
agreements. PacifiCorp has several power purchase agreements with wind-powered generating facilities that are not included in the
table above as the payments are based on the amount of energy generated and there are no minimum payments. Included in the
purchased electricity payments are any power purchase agreements that meet the definition of a lease. Rent expense related to those
power purchase agreements that meet the definition of a lease totaled $26 million for 2018 and $14 million for 2017.
Included in the minimum fixed annual payments for purchased electricity above are commitments to purchase electricity from several
hydroelectric systems under long-tern arrangements with public utility districts. These purchases are made on a "cost-of-service"
basis for a stated percentage ofsystem output and for a like percentage ofsystem operating expenses and debt service. These costs are
included in operation expenses on the Statement of Income. PacifiCorp is required to pay its portion of operating costs and its portion
of the debt service, whether or not any electriciry is produced. These arrangements accounted for less than 5% of PacifiCorp's 2018
and 2017 energy sources.
Purchased Electricity Contracts - Non-commercially Operable
PacifiCorp has several contracts for purchases of electricity from facilities that have not yet achieved commercial operation. To the
extent any of these facilities do not achieve commercial operation, PacifiCorp has no obligation to the counterparty.
Fuel Contracts
PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments.
Cons truction Commitments
PacifiCorp's construction commitments included in the table above relate to firm commitments and include costs associated with
certain generating plant, transmission, and distribution projects.
FERC FORM NO.1 (ED.12.88)Pase 123.27
2t
648
559
95
6
48
521
2
80
7
977
3,471
1,449
842
121
l3
732
888
108
7
797
976
8l
49
268
63
5
8
49
326
69
6
l6
427
90
2024 and
2019 2020 2021 2022 2023 Thereafter Total
208
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Transmission
PacifiCorp has contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to PacifiCorp's
customers.
Operating Leases and Easements
PacifiCorp has non-cancelable operating leases primarily for certain operating facilities, office space, land and equipment that expire
at various dates through the year ending December 31, 2096. These leases generally require PacifiCorp to pay for insurance, taxes and
maintenance applicable to the leased properfy. Certain leases contain renewal options for varying periods and escalation clauses for
adjusting rent to reflect changes in price indices. PacifiCorp also has non-cancelable easements for land on which its wind-powered
generating facilities are located. Rent expense totaled $ 15 million for the years ended December 3 I , 2018 afi 2017 .
Guarantees
PacifiCorp has entered into guarantees as part ofthe normal course ofbusiness and the sale ofcertain assets. These guarantees are not
expected to have a material impact on PacifiCorp's financial results.
(14) Preferred Stock
In the event of voluntary liquidation, all preferred stock is entitled to stated value or a specified preference amount per share plus
accrued dividends. Upon involuntary liquidation, all preferred stock is entitled to stated value plus accrued dividends. Dividends on
all preferred stock are cumulative. Holders also have the right to elect members to the PacifiCorp Board of Directors in the event
dividends payable are in default in an amount equal to four full quarterly payments.
(15) Common Shareholder's Equity
In February 2019, PacifiCorp declared a dividend of $175 million to PPW Holdings LLC, a wholly owned subsidiary of BHE and
PacifiCorp's direct parent company ("PPW Holdings"), which was paid in March 2019.
Through PPW Holdings, BFIE is the sole shareholder of PacifiCorp's common stock. The state regulatory orders that authorized
BIIE's acquisition of PacifiCorp contain restrictions on PacifiCorp's ability to pay dividends to the extent that they would reduce
PacifiCorp's common equity below specified percentages of defined capitalization. As of December3l, 2018, the most restrictive of
these commitments prohibits PacifiCorp from making any distribution to PPW Holdings or BHE without prior state regulatory
approval to the extent that it would reduce PacifiCorp's common equity below 44o/o of its total capitalization. excluding short-term
debt and current maturities of long-term debt. As of December 3 I , 201 8, PacifiCorp's actual common equity percentage, as calculated
under this measure, was 54o/o, and PacifiCorp would have been permitted to dividend $2.6 billion under this commitment.
These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings or BFIE if PacifiCorp's senior
unsecured debt rating is BBB- or lower by Standard & Poor's Rating Services or Fitch Ratings, or Baa3 or lower by
Moody's Investor Service, as indicated by two of the three rating services. As of December3l, 2018, PacifiCorp met the minimum
required senior unsecured debt ratings for making distributions.
PacifiCorp is also subject to a maximum debt-to-total capitalization percentage under various financing agreements as further
discussed in Note 6.
FERC FORM NO.1 (ED.12-88)Page 123.28
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
(16) Supplemental Cash Flow Disclosures
The summary of supplemental cash flow disclosures as of and for the years ended December 3 I is as follows (in millions):
2018 2017
$349 $350Interest paid, net of amounts capitalized
Income taxes paid, ne(l)$l3l $331
Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to utility plant additions $184 $147
(l) PacifiCorp is party to a tax-sharing agreement and is part of the Berkshire Hathaway United States federal income tax retum. Amounts
substantially represent income taxes paid to BHE.
FERC FORM NO.1 (ED. r2-88)Page 123.29
PacifiCorp (1)
(2)
An Original
A Resubmission
Date(Mo,Year/Period of Report
End of 20181Q4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
'1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, wlrere appropriate.
2. Report in columns (0 and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Line
No
Item
(a)
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Minimum Pension
Liability adjustment
(net amount)
(c)
Foreign Currency
Hedges
(d)
Other
Adjustments
(e)
1 Balance ofAccount 219 at Beginning of
Preceding Year ( 12,594,198)
2 Preceding QtrfYr to Date Reclassifications
from Acct 219 to Nel lncome 548,090
3 Preceding Quarter^/ear to Date Changes in
Fair Value ( 3,220,070)
4 Total (lines 2 and 3)( 2,671,980)
5 Balance of Account 21 I at End of Preceding
Quarter^fear ( 15,266,178)
6 Balance ofAccount 219 at Beginning of
Current Year ( 15,266,178)
7 Current QtrfYr to Date Reclassifications
from Acct 2191o Net lncome 696,1 96
I Current Quarter^/ear to Date Changes in
Fair Value 1,934,940
o Total (lines 7 and 8)2,631 ,136
10 Balance of Account 21 I at End of Cunent
QuarterfYear ( 12,635,042\
FERC FORrr NO. 1 (NEW 06-02)Page1.22a
Name of Respondent
PacifiCorp
This ReDort ls:(1) 5]Rn originat(2) fiA Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20'l8lQ4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Line
No.
Other Cash Flow
Hedges
lnterest Rate Swaps
(0
Other Cash Flow
Hedges
ilnsert Footnote at Line 1
to specifyl
(s)
Totals for each
category of items
recorded in
Account 21 I
(h)
Net lncome (Carried
Forward from
Page 117 , Line 78)
0
Total
Comprehensive
lncome
0)
1 ( 12,594,198)
2 548,090
3 ( 3,220,070)
4 ( 2,671,980)768,437,084 765,765,104
A ( 15,266,178)
6 ( 1s,266,178)
7 696,196
8 1,934,940
I 2,631,136 737,709,000 740,340,1 36
10 ( 12,63s,042)
FERC FORi.lr NO. r (NEW 06-02)Page 122b
PacifiCorp (1)
(2)
An Original
A Resubmission
UAIE OT KEDON(Mo, Da, Yi)tt
YeaflHefloq or Kepon
End of 2018/Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (0, and (g) report other (speciry) and in
column (h) common function.
Line
No.
Classification
(a)
Total Company for the
Current Year/Quarter Ended
(b)
Electric
(c)
1 Utility Plant
2 ln Service
3 Plant in Service (Classified)27,934,965,226 27,934,965,226
4 Property Under Capital Leases 20,785,264 20,785,264
5 Plant Purchased or Sold
6 Completed Construction not Classified 286,429,253 286,429,253
7 Experimental Plant Unclassified
8 Total (3 thru 7)28,242,179,743 28,242,179,743
I Leased to Others
10 Held for Future Use 26,415,220 26,415,220
11 Construction Work in Progress 1 ,1 94,168,876 1,194,168,876
12 Acquisition Adjustments 156,468,483 '156,468,483
13 Total Utility Plant (8 thru 12)29,6',t9,232,322 29.6'.t9,232,322
14 Accum Prov for Depr, Amort, & Depl 11,032,877,405 11,032,877,405
15 Net Utility Plant (13 less 14)18,586,354,917 18,586,354,9't 7
16 Detail of Accum Prov for Depr, Amort & Depl
17 ln Service:
18 Depreciation 10,291,136,026 10,291 ,136,026
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort ofUnderground Storage Land/Land Rights
21 Amort of Other Utility Plant 614,571,348 614,571,348
22 Total ln Service (18 thru 21)'t0,905,707,374 10,905,707,374
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others (24 & 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj 127,170,031 127,170,031
33 Total Accum Prov (equals 14) (22,26,30,31,32)11,032,877,405 11,032,877 ,405
FERC FORM NO. 1 (ED. 12-89)Page 200
Name of Respondent
PacifiCorp
This ReDort ls:(1) 5l1Rn orisinat(2) J--lA Resubmission
Date of Reoort(Mo, Da, Yi)ll
Year/Period of Report
End of 20'l8lQ4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Gas
(d)
Other (Specify)
(e)
Other (Specify)
(f)
Other (Speciff)
G)
Common
(h)
Line
No.
1
2
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
FERC FORM NO. r (ED.12-89)Page 201
PacifiCorp (1)
(2)
An Original (Mo, Da,
Resubmission
Year/Period of Report
End of 20181Q4
1. Report belowthe original cost ofelectric plant in service according to the prescribed accounts.
2. ln addition to Account 101 , Electric Plant in Service (Classified), this page and lhe next include Account 102, Electric Plant Purchased or Sold; Account
103, Experimental Electric Plant Unclassified; and Account 106, Completed 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. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect ofsuch accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reporled in column (b). Likewise, if the respondent has a significant amount of
plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. lnclude also in column (d)
Line
No.
Account
(a)
Eatance
Beginning of Year
(b)
Adotltons
(c)
1 1. INTANGIBLE PLANT
2 (30'l) Organization
3 (302) Franchises and Consents 209,50S,1 18 769,444
4 (303) Miscellaneous lntanqible Plant 39,438,153
5 TOTAL lntanqible Plant (Enter Total of lines 2, 3, and 4)40,207,597
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Riqhts 92,989,902
I (311) Structures and lmprovements 1,029.940.705 13,320,303
10 (312) Boiler Plant Equipment 4.615,243.468 88,931,004
11 (313) Engines and Enqine-Driven Generators
12 (314) Turbogenerator Units 983,650,601 25,638,629
13 (315) Accessory Electric Equipment 488,876,291 2,521,295
14 (316) Misc. Power Plant Equipment 32,004,449 3,039,000
15 (317) Asset Retirement Costs for Steam Production 129,737,318 6,182,871
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)7.372.442.734 1 39,633,1 02
17 B. Nuclear Production Plant
18 (320) Land and Land Riqhts
19 (321) Structures and lmprovements
20 (322) Reactor Plant Equipment
2',!(323) Turbogenerator Units
22 (324) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Produclion Plant (Enter Total of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (330) Land and Land Rishts 36,312,178 7,926
28 (331) Structures and lmprovements 276,902,816 3,847,134
29 (332) Reservoirs, Dams, and Watemays 504,570,856 8,710,528
30 (333) Water Wheels, Turbines, and Generators 132,392,618 6,976,091
31 (334) Accessory Electric Equipment 83,048,610 2,284,407
32 (335) Misc. Power PLant Equipment 2,381,811 881
33 (336) Roads, Railroads, and Bridges 23,901,498 1,267,332
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 lhru U)1 23,094,299
36 D. Other Production Plant
37 (340) Land and Land Rights 45.478.205
38 (34'l) Structures and lmprovements 228,119,279 1,184,759
39 (342) Fuel Holders, Products, and Accessories 16,187,932 269
40 (343) Prime Movers ,92',!29,254,945
41 (344) Generators 477,502,450 1,530,410
42 (345) Accessory Electric Equipment 327 ,901 1,551,096
43 (346) Misc. Power Plant Equipment 15,906,388 47,709
44 (347) Asset Retirement Costs for Other Production 13,031 ,355 4,288,740
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)4,055,048,362 37,857,928
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)200,585,329
FERC FORM NO. I (REV. 12-05)Page 204
727.413.664
936.922.782
12.487.001.48i
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn origlnat(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
ll
Year/Period of Report
End of 20181Q4
101 1 103 and 1
distributions ofthese tentalive classifications in columns (c) and (d), including the reversals ofthe prioryears tentative account distributions ofthese
amounts. Careful observance of the above instructions and the texts of Accounts 101 and '106 will avoid serious omissions of the reported amount of
respondent's plant actually in service at end ofyear.
7. Show in column (0 reclassificalions or transfers within utility plant accounts. lnclude also in column (f) the additions or reductions of primary account
classifications arising from dishibution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, elc., and show in column (0 only the offset to the debits or credits distributed in column (f) to primary
account classifi cations.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. ForeachamountcomprisingthereportedbalanceandchangesinAccountl02,statethepropertypurchasedorsold,nameofvendororpurchase,
and date of transaction. lf proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at
End of Year(q)
Line
No.
1
2
673,747 209,604,815 3
6,024,611 760,827,206 4
6,698,358 970,432,021 5
6
7
92,989,902 8
3,650,364 1 ,039,610,644 I
39,986,727 726,531 4.664,914,276 10
1'.!
8,143,810 1,001,145,420 12
588,541 -1,',t07J24 489.701.921 13
1,553,116 33,490,333 14
4,661,230 13'1,258,959 15
53,922,558 -4,661,230 -380,593 7,453,111,455 16
17
'18
19
20
2',!
22
23
24
25
26
36,320,104 27
2,256,915 -54.179 278,438,856 28
1,458,410 54,179 511,877,153 29
898,124 138,470,585 30
529,288 84,803,729 31
8,340 2,374,352 32
194,410 24,974,420 33
34
5,U5,487 1 ,077.259.199 35
36
45,316 45,432,889 37
272,645 -3't2 229,031,081 38
-26 16,'188,175 39
19,475,582 29,482 2,940,730,523 40
388,968 -28,736 478,615,156 41
307,434 -392 329,144,345 42
29,760 -16 15,924,321 43
464,880 16,855,2'15 44
20,519,70s -464,880 4,O71,921,705 45
79,787,750 -5,',t26,110 -380,593 46
FERC FORM NO.1 (REV. 12-05)Page 205
12.602.292.351
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn orisinat(2) ;-lA Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
ELECTRIC PLANT lN SERVICE (Account 1O1,102, 103 and 106) (Continued)
Line
No.
Account
(a)
Addtttons
(c)
47 3. TRANSMISSION PLANT
48 (350) Land and Land Riqhts 265,463,991 7,592,764
49 (352) Structures and lmprovements 257,688,990 18,300,457
50 (353) Station Equipment 2,',t95,395,245 81,136,003
51 (354) Towers and Fixtures 1,294,996,299 6,290,713
52 (355) Poles and Fixtures 948,225,375 14,415,829
53 (356) Overhead Conductors and Devices 1,237,023,809 19,4S2,593
54 (357) Underground Conduit 3,519,394 604
55 (358) Underground Conductors and Devices 8,035,354
56 (359) Roads and Trails 11,937,200
57 (359.1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)147,229,023
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Riqhts 63,696,481 920,970
61 (361) Structures and lmprovements 1 15,852,040 5,122,912
62 (362) Station Equipment 1 27,789,643
63 (363) Storage Battery Equipment
64 (364) Poles, Towers, and Fixtures 1,183,290,681 44,813,U5
65 (365) Overhead Conductors and Devices 754,957,486 22,936,227
66 (366) Underground Conduit 370,250,464 16,846,056
67 (367) Underground Conductors and Devices 864,063,506 37,506,169
68 (368) Line Transformers 1,349,720,845 50,604,1 04
69 (369) Services 778,05',t,452 41,492,046
70 (370) Meters 205,790,437 63,016,074
71 (371) lnstallations on Customer Premises 72,428
72 (372) Leased Property on Cuslomer Premises
73 (373) Street Lighting and Signal Systems 62,639,259 1,428,',t21
74 (374) Asset Retirement Costs for Distribution Plant 1,U4,766
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)3't2,548,595
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380) Land and Land Rishts
78 (381) Shuctures and lmprovements
79 (382) Computer Hardware
80 (383) Computer Software
81 (384) Communication Equipment
82 (385) Miscellaneous Reqional Transmission and Market Operation Planl
83 (386) Asset Retirement Costs for Regional Transmission and Market Oper
84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Rights 21,695,015 12
87 (390) Structures and lmprovements 245,730,525 9,323,286
88 (391) Ofiice Furniture and Equipment 82,426,126 20,843,309
89 (392) Transportation Equipment 1 18,365,919 5,246,656
90 (393) Stores Equipment 15,428.202 541,338
9'l (394) Tools, Shop and Garage Equipment 64,895,499 3,041,657
92 (395) Laboratory Equipment 33,392,275 2,089,576
93 (396) Power Operated Equipment ,|20,020,098
94 (397) Communication Equipment 459,236,333 25,473,312
95 (398) Miscellaneous Equipment 8,319,050 252,613
96 SUBTOTAL (Enter Total of lines 86 thru 95)1,228,976,231 86,831,857
97 (399) Other Tangible Property
98 (399.1) Asset Retirement Costs for General Plant 39,748
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98)86,831,857
100 TOTAL (Accounts 101 and 106)27,658,984,089 787,402,401
101 (102) Electric Plant Purchased (See lnstr. S)
102 (Less) (102) Electric Plant Sold (See lnstr. 8)
103 (103) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)787,402,40',1
FERC FORM NO. 1 (REV. 12-05)Page 206
6.222.285.65',
6.781.903.36(
1.230.870.80i
27.658.984.08(
PacifiCorp (1)
(2)Resubmission
Date of Report
(Mo, Da, Yr)
ll
Year/Period of Report
End of 20181Q4
ELECTRIC PLANT lN SERVICE (Account 101 , 102, 103 and 106) (Continued)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at
End of Year(s)
Line
No.
47
139,171 -17,094 272,900,490 48
'114,452 275,874,995 49
10,954,761 't24,921 2,265,701,408 50
169,950 38,856 1 ,301 ,1 55,91 I 51
2,208,214 -12,468 960,420,522 52
2.990.978 -26,389 1,253,499,035 53
3,520,058 54
8,035,354 55
11,937,200 56
57
16,577,526 107,826 6,353,044,980 58
EO
26,636 -35,61 1 64,555,204 60
212,427 120,762,525 61
7,616,703 -132,817 1,043,475,099 62
63
7,345,965 1,220,758,561 64
3,433,947 774,459,766 65
1,938,372 385,1 58,148 66
3,447,833 898,121,U2 67
9,487,157 1,390,837,792 68
1,099,971 818,443,527 69
39,130,829 229,675,682 70
76,913 8,806,482 71
72
1,179,192 62,888,1 88 73
1,344,766 74
74,995,945 -168,428 75
76
77
78
79
80
81
82
83
84
85
154,406 21,540,62',1 86
4,652,520 2s0,401,291 87
14,954.083 88,315,3s2 88
5,904,032 -31,654 1 17,676,889 89
1 ,095,1 37 45,356 14,919,759 90
2,902,044 -1 ,366,194 63,668,918 91
1,777 ,009 1,169,183 34,874,025 92
8,088,420 407,870 191,826,835 93
1,767,005 7,896 482,950,536 94
458,960 156,032 8,268,735 95
41,753,616 388,489 1,274,442,961 96
97
39,748 98
41,753,616 388,489 99
219,813,195 -5,126,110 -52,706 28,221,394,479 100
101
102
103
219,813,195 -5,1 26,1 1 0 -52,706 104
FERC FORM NO. r (REV.12-05)Page 207
7.019.287.581
1.854.82e
1.276.337.537
28.221.394.479
Name of Respondent
PacifiCorp
This Report is:
(1) XAn original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Page:204 Line No.:4 Column: b
Schedule Page:204 Line No.: 5 Column: b
fncl assets related to roduction ant 14 654.
r FERC Docket No. ER11-3643-000, Attachmentustment to Pac Corp's of rate
H-1, is as follows:
Account
(a)
Ref.
Irane No.
(Column)
Balance
Beg. of Year
(b)
Less: Intangible mining plant(1)
Revised TOTAI Intangible Plant.
TOTAL Intang eP 935,922,782
L4 654
$ 936 ,908,a28
(1) To adjust PacifiCorp's formula rate, p€r FERC Docket No. FA15-4-000 for mining assetsrelated to 10n lant
Adj ustmentsH-1, are as
to Pac Corp's ormu ratefollows:
Account
r FERC Do et No. ERI-1-3543-000, Attachment
Ref.Line No.
(Column)
BalanceBeg. of Year
(b)
204 Line No.:46 Column: b
TOTAI Production PlantLess: (317) Asset Retirement. CosLsLess: (326) Asset Retirement CostsLess: (337) Asset Retirement CostsLess: (347) Asset Retirement Costs
Revised TOTAI Production Pfant
Steam Production(1)Nuclear Production(1)Hydraulic Production ( 1 )Other Production(1)
46
1s (b)
24 (b)
34 (b)
44 (b)
$a2 ,487, 001, 483
]_29,737 ,378forforforfor13, 031, 355
$12 ,344 ,232 ,810
(1) fn accordance with 18 C.F.R. S35.18(a-c) a public utility that files a transmissionrate schedule, tariff or service agreement under S35.1-2 or S35.13 and has recorded anasset retirement obligation on its books, but is not seeking recovery of the assetretirement costs in rates, must remove all asset-retirement-obligations-related costts from the cost of service s its sed rates
ustments to PacifiCorp's formula rate under FERC Docket No. ER11-3543-000, Attachmentfollows:H-1, are as
Account
(a)
Ref.
.tr].ne No.
(Column)
Balance
End of Year
(g)
204 Line No.:46 Column:
TOTAL Production PlantLess: (317) Asset Retirement CostsLess: (325) Asset Retirement CostsLess: (337) Asset RetiremenL CostsLess: (347) Asset Retirement Costs
Revised TOTAL Production Pfant
Steam Production(1)Nuclear Productlon(1)
Hydraulic Production ( 1 )Other Production(1)
1s (g
zq (9
za (J
s1-2 , 602 ,292 ,359
1,31, ,2s8 ,9s9
16,855,215
i1-2,454, 178, 185
(1) In accordance with 18 C.F.R. S35.18(a-c) a public utility that files a transmj-ssionrate schedule, tariff or service agreement under S35.12 or S35.1-3 and has recorded anasset retirement obligation on its books, but is not seeking recovery of t.he assetretirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
FERC FORM NO. I (ED. 12.871 Page 450.1
45 (g)
forfor
for
for qa (J
s (b)
\ctl
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tl
Year/Period of Report
2UAA4
FOOTNOTE DATA
204 Line No.:75 Column: b
ustment to Pac CorprsH-1, is as follows:rate FERC No. ER11-3543-000, At
Ref.Line No.
(Column)
t
Balance atBeg. of Year
(b)
Account
(a)
TOTAL Distribution PlantLess: (374) Asset Retirement Costs for Distribut.ion Plant(l-)
Revised TOTAL oistribution Plant
sed rates.
t No. ER11-3543-000, At
Ref.Line No.
(Column)
i 5 ,78],, 903, 350
!,344,766
Balance at
End of Year
(g)
7s (b)
74 (b)
$ 6, 780, 558, s94
(1) rn accordance with 18 C.F.R. S35.18(a-c) a public utility that files a transmissionrate schedule, tariff or service agreement under S35.12 or S35.1-3 and has recorded anasset retirement obligation on its books, buL is not seeking recovery of the assetretirement costs in rates, musL remove all asset-retirement-obligat.ions-related costts from the cost of servicec
a rate
its
r FERCustment to Pac Corp'sH-1, is as follows:
Account
\d/
204 Line No.:75 Column
$ 7,019 ,287 ,582
7 ,344 ,7 55
$ 7,017,942,8!6
(1) In accordance with 18 C.F.R. S35.18(a-c) a public utility that files a transmissionrate schedule, tariff or service agreement under S35.12 or S35.13 and has recorded anasset retirement obligation on its books, but is not seeking recovery of the assetretirement costs in rates, must remove all asset-retiremenE-obligations-related costts from the cost of service s its ed rates
Account 3992]-, Land owned in fee
Refer to footnote on 204 line no. 97 column (
204 Line No;99 Column: b
Adjustments to Pac ormu rate FERC No. ERll--3543-000, AtH-l-, are as follows:
TOTAL Distribution PlantLess: (374) Asset Retirement Costs for Distribution plant(1)
Revised TOTAL Oistribution Plant
Account
(a)
7s (g)
74 (g)
Ref .
Lane No.
(Column)
Balance at
Beg. of Year
(b)
204 Line No.:97 Column: b
TOTAL General PlantLess: (399) Other Tangible eroperty(1)Less: (399.1) Asset Retj-rement Costs for General Plant(2)
Revised TOTAL General Plant
ee (b)
e7 (b)
e8 (b)
$ 1,230 ,870,807
1,854 ,828
39 748
$ 1-,228,975,23a
(1) To adjust PacifiCorp's formula rate,related to production pIant.per FERC Docket No. FAI-6-4-000 for mining assets
(2) In accordance with 18 C.F.R. S35.18(a-c) a public utility that files a transmissionrate schedule, tariff or service aglreement under S35.12 or S35.13 and has recorded anasset retirement obligatj-on on its books, but is not seeking recovery of the assetretirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
FERC FORM NO.1 (ED. 12.871 Paqe 450.2
S
Schedule Pase:204 Line No.: 97 Column: s
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
204 Line No.:99 Column:ustments to Pacificorp's formula rate under FERC Docket No. ERll--3543-000, Attachment
H- 1, are as f ol-lows :
Account
(a)
Ref.
.tr1ne No.
(Column)
Balance at
End of Year
(s)
TOTAI General PlantLess: (399) other Tangible Property(1)Less: (399.L) Asset Retirement Costs for General Plant(2)
Revised TOTAI General Plant
ee (s)
e7 (g)
e8 (g)
i L,276,337,s37
7 ,854 ,828
39 748
$ L,274,442,95]-
(1) To adjust PacifiCorp's formula rate,related to production p1ant.
per FERC Docket No. FA15-4-000 for mining assets
(2) In accordance with l-8 C.F.R. S35.18(a-c) a public utility that files a transmissionrate schedule, tariff or service agreement under S35.12 or S35.13 and has recorded anasset retirement obligation on its books, but is not seeking recovery of the assetretirement costs in rates, must remove all asset-retirement-obligati-ons-related costts from the cost of service s its ed rates
ustments to Pac Corp'sf a rate FERC Docket No. ERI-1-3543-000, Attachment
H-1, are as follows
Account
(a)
Ref.Line No.
(Column)
Balance at
Beg. of Year
(b)
204 Line No.: 104 Column: b
Revised TOTAI Intangible Plant(1)
Revised TOTAL Production Plant (2)
TOTAL Transmission Plant
Revised TOTAL Distribution Plant (3)
Revised TOTAL General Plant(4)(l-02) Electric Plant Purchased(r,ess) (102 ) Electric Plant Sold(103) Experj-mental Plant Unclassified
Revised TOTAL Electric Plant in Service
s8 (b)
101(b)
102 (b)
103 (b)
<q
1,2 ,3
6,2
6,7
ar2
35 ,908 ,]-28
44 ,232 ,81,0
22 ,285 , 657
80,558,594
28,976,231
$27 ,51-2 ,96]- ,420
(1)
(2)
(3)
(4)
Refer
Refer
Refer
Refer
footnotefootnotefootnote
footnote
page
page
page
page
line noline noline noline no
column
column
column
column
tototo
to
on
on
on
on
)oa
204,
204,
204,
5,
46,
75,
99,
(b)
(b)
(b)
(b)
FERC FORM NO.1 (ED. 12ATI Page 450.3
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
20181Q4
FOOTNOTE DATA
204 Line No; 104 Column:ustments to Pac f Corp's formula rate under FERC Docket No. ER11-3543-000, Atta
H-1, are as follows
Account
Ref.
Line No.
(Column)
Balance at
End of Year
(g)(a)
TOTAL Intangible Plant
Revised TOTAL Production Plant (l-)
TOTAL Transmission Plant
Revised TOTAL Oistribution Plant (2)
Revised TOTAL General Plant(3)(102) Electric Plant Purchased(Less) (102) Electric Plant Sold(103) Experimental Plant Unclassified
Revised TOTAL Electric Plant in Service
s (s)
s8 (g)
$ 970 ,432,021-
12 ,454, 178, 185
6, 353 ,044,980
7 ,0L7 ,942,8]-5
1_,274,442,961,
101(g)
102 (g)
103 (g)
$28 , 070 ,040 ,963
1
3
Re
Re
Re
ferferfer
to footnote on page 204to footnote on page 204to footnote on page 204
line no.line no.line no.
46,
75,
99,
column
column
column
(s)
(s)
(s)
FERC FORM NO.1 (ED. 12-871 Page 450.4
Name of Respondent
PaciliCorp
This
(1)
(2)
Reoort ls:
5]Rn orisinal
[lA Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
1 . Report separately each property held for future use al end of the year having an original cost of $250,000 or more. Group other items of property held
for fulure use.
2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other required information, the date that utility use of such property was discontinued, and the date the original cost was hansferred to Account 105.
LineNo.
Date Onoinallv lncluded
in This A6count(b)tn Service
tsalance at
End ofYear(d)
1 Land and Rights:
2 Barnes Butte Substation 2007 2027 746,268
3 \Mld Horse \Mnd Plant 2007 6,763,094
4 Twelve Mile Wnd Plant 2007 2,160,207
5 Jumbers Point Substation 2008 2024 1,173,276
6 Mountain Green Substation 2009 2025 284,996
7 Hoggard Substation 2009 2025 254,397
I Oquirrh-Terminal 345kV Transmission Line 2009 2022 396,020
I Bend Service Center 2010 2020 3,507,838
10 Legacy Substation 2010 2021 562,276
11 Aeolus Substation 2011 1,013,577
12 Anticline Substation 201',!964,043
13 Populus Substation 2011 2024 254,753
14 Lassen Substation 2012 20't9 683,318
15 Old Mill Substation 20't2 2026 1,838,281
16 Chimney Butte-Paradise 230kV Transmission Line 2013 2025 598,457
17 Fiddlers Canyon Substation 2016 2028 1 ,1 36,587
18 Gateway Area Subslation 2017 2023 3,165,831
19 Miscellaneous, each under $250,000:912,001
20
21 Other Property:
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Total 26,415,220
FERC FORM NO.1 (ED. 12-96)Page 214
2039
2039
2020
2020
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
lYear/Period of Report
II 2o18tQ4
FOOTNOTE DATA
214 Line No.:3 Column: c
214 Line No.:4 Column: c
Land for ture opment an es u ty ce te 2039,
s ect to business stra and devel t ans.
Land or ture opment an es ut ty te 2039,
S ect to business stra and devel t ans
Property to n-serv ce n 2020, as part of the Energy on 2020
ect ect to environmental and economic reviews
Property to n-serv ce n 2020, as part of the Energy on 2020
ect ect to envi-ronmentaf and economic reviews
Var tes p
FERC FORM NO. r (ED. 12-871 Page 450.1
214 Line No.:11 Column: c
214 Line No.:12 Column: c
214 Line No.: 19 Column: c
Name of Respondent
PacifiCorp
This ReDort ls:(1) 5]Rn orislnat(2) IllA Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
CONSTRUCTION WORK lN PROGRESS - - ELECTRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating lo "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 ofthe Uniform System ofAccounts)
3. Minor projects (50/o of the Balance End of the Year for Account 107 or $1 ,000,000, wtrichever is less) may be grouped.
Line
No
Description of Project
(a)
Construction work in progress
Electric (Account 107)
(b)
1 lntangible:
2 Energizing Customer Tools Software 5,007,074
3 Mapping System Consolidation Software 1,974,501
4 Prospect No. 3 Hydro Relicensing 1,783,503
5 Ul Planner Revenue Model Sofiware 1 ,677,915
6 Weber Hydro Relicensing 1,205,066
7 Generation Optimization Software: Power Cosls, lnc.1,027,882
8 Production:
o Wind Repowering/Safe Harbor Equipmenl Purchases**1 29,565,1 85
10 Seven Mile Hill Wind Repowering""87,606,141
11 Glenrock \Mnd Repowering.*82,301,645
12 Leaning Juniper 1 Wind Repowering*.28,849,1 99
'13 Marengo Wind Repowering**24,302,848
14 Dunlap Ranch 1 Wind Repowering*.23,506,482
15 High Plains \A/ind Repowering.*20,958,237
16 Seven Mile Hill ll Wind Repowering**16,814,076
17 Goodnoe Hills Wnd Repowering**15,446,544
18 Rolling Hills Wind Repowering.*1 5,359,1 95
19 Marengo ll Wnd Repowering.*11,955,064
20 Lewis River System Relicensing lmplementation 9,297,610
21 Glenrock lll Wind Repowering*-6,317,931
22 TB Flats \Mnd Project 500 M\ f-5,368,537
23 Colstrip U3 and U4: Water Management System 3,713,077
24 Ekola Flats Wnd Project 250 MV1f-3,140,377
25 Toketee Dam Rehabilitation Evaluation 3,004,236
26 Merwin Spillway Gate Wood Extension Replacement 2,533,200
27 Lewis River System Maximum Flood lmprovement Study 2,171,070
28 Dave Johnston Ash Disposal System, Coal Combustion Residual 1,716,383
29 Cedar Springs Wind Project 200 M!^r.1,296,173
30 Dave Johnston Waste Ash Silo Modifications 1,243,913
31 Huntington U2 Boiler Economizer and lnlet Heater Replacement 1,228,789
32 Soda Hydro Spinning Reserve 1,208,124
33 Foote Creek VMnd Repowering**1,214,648
34 Jim Bridger U3 Catalyst Replacemenl, Selective Catalytic Reduction System 1,138,712
35 Dave Johnston Coal Yard Control System Update 1 ,1 08,001
36 Huntington Electric Lake Dam Outlet Upgrade 1 ,041,275
37 Bear River Hydro Flood and Structural Assessment Project 1 ,016,209
38 Transmission:
39 Aeolus - Bridger/Anticline 500kV Line."98,792,466
40 Aeolus - Mona 500kV Line 95,739,929
41 Boardman - Hemingway 500kV Line 70,587,478
42 Populus - Hemingway 500kV Line 60,425,148
43 TOTAL 1,194,168,876
FERC FORM NO. I (ED. r2-87)Page 216
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
1 . Report below descriptions and balances at end of year of projects in process of construction (1 07)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 1 07 of the Uniform System of Accounts)
3. Minor projects (5o/o of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line
No.
Description of Project
(a)
Construction work in progress -
Electric (Account 107)
(b)
1 VMndstar - Populus 230 - 500kV Line 54,680,076
2 Wallula - McNary 230kV Line 31 ,395,882
3 Vantage - Pomona Heights 230kV Line 27,727,351
4 Delta Fire Damaged Facilities 15,361,335
q Oquirrh - Terminal 345kV Line 14,070,180
6 Rexburg Substation - lnstall 161kV Source from Rigby 11,705,848
7 Sams Valley New 500 - 230kV Substation 6,916,269
8 Generation lnterconnection (Cedar Springs 1, TB Flats and Ekola Flats)"-6,461,838
I Jordanelle - Midway 138kV Line 4.251.594
10 Goshen - Sugarmill - Rigby 161 kV Line 3,766,609
11 Goshen Substation lnstall 3rd 345 - 161kV 700 MVA Transformer TPL 3,373,606
12 Rigby & Sugarmill 161kV Substation Shunt Capacitors 2,220,201
't3 Grace Substation: Relocate 46kV Line 't,745,520
14 Huntington U2 Generator Step-Up Transformer Replacement 1,563,088
15 NE Portland Voltage Conversion Project - Transmission Lines and Substations 1,089,689
16 Yreka Substation 1 15 - 69kV Transformer Addition 1,069,262
17 Dave Johnston - Thunder Creek 57 - 69kV System Conversion 1,041,394
18 Distribution:
19 Utah Advanced Metering lnfrastructure 9,750,807
20 Jackalope Substation lnstall 2nd Transformer, Remove Douglas Town Sub 4,860,287
21 Naples New 138 - 12.5kV Substation TPL 4,190,668
22 Lassen Substation - New Substation 3,838,714
23 Herriman Substation lnstall 2nd 138 - 12.5kV Transformer 3,795,355
24 Jordan Valley Underground Cable Testing and Replacement Project 3,597,434
25 Boise White Paper, LLC lnterconnect Load Addition 2,868,862
26 lvins Substation Replace Transformer 2,195,822
27 ldaho Advanced Metering lnfrastructure 1,755,852
28 Stadion, LLC New Load Addition 1,705,431
29 Oregon - Mandated Neutral Extensions - Roseburg 1,287,0U
30 General:
31 North Temple Office Parking Lot Upgrade 1,278,821
32 Replacement of DMX Fiber Optic Communications lnfrastructure/Equip - Jordan Valley Area 1,167,563
33
34 Miscellaneous Projects each under $1,000,000 120,792,641
35
36 .. Energy Vision 2020 projects
37
38
39
40
41
42
43 TOTAL 1 ,1 94,1 68,876
FERC FORM NO. r (ED.12-87)Page 2{6.'l
Name of Respondent
PacifiCorp
This(1)
(2)
Reoort
Enn
ls:Original
rrA Resubmissiontt
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 1 1, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. lf the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. ln addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Section A. Balances and During Year
No (a)(e)
1 Balance Beginning of Year 9,599,722,773 9,599,722,773
2 Depreciation Provisions for Year, Charged to
e (403) Depreciation Expense 908,461,901 908,461,901
4 (403. 1 ) Depreciation Expense for Asset
Retiremenl Costs I
E (413) Exp. of Elec. Plt. Leas. to Others
6 Transportation Expenses-Clearing
7 Other Clearing Accounts
8 Other Accounts (Specifo, details in footnote):22,089,061
I
10 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
930,550,962 930,550,962
't1 Net Charges for Plant Retired:
12 Book Cost of Plant Retired 210,218,153 210,218,153
13 Cost of Removal 40,800,230 40,800,230
14 Salvage (Credit)6,272,294 6,272,294
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
244,746,089 244,746,089
16 Other Debit or Cr. ltems (Describe, details in
foolnote):
5,608,380 5,608,380
17
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
10,291,136,026 10,291 ,1 36,026
Section B, Balances at End of Year According to Functlonal Classlflcation
2C Steam Production 3,633,335,055 3,
21 Nuclear Production
zl Hydraulic Production-Conventional 421,162,472 I
23 Hydraulic Production-Pumped Storage
24 Other Production 1 ,1 38,023,509
25 Transmission 1,768,071,124
26 Distribution 2,848,002,466
27 Regional Transmission and Market Operation
28 General 482,54',1,400 I
29 TOTAL (Enter Total of lines 20 thru 28)10,291 ,1 36,026 10,
FERC FORM NO. r (REv. 12-0s)Page 219
22,089,061
421,162,47i
1 ,138,023,50(
1,768,071,12t
2,848,002,46(
Gene Y, Pac Corp records the rec expense o asset rett t as
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
FOOTNOTE DATA
219 Line No.:8 Column: b
either a asset or liabili
Account 143, Other accounts rece vable: deprec L expensebil1ed to joint owners
Account L82.3, Other regulatory assets or Account 254, Other regulatoryliabilities: asset retirement obligations asset depreciation
Account L82.3, Other regulatory assets: deferral of Carbon depreciationAccount 1,82.3, Other regulatory assets: deferral of increased depreciation,
due to depreciation study rates, net of amortizationTransportation depreciation charged to operations and maintenance
expense and construction work in progress based on usage activity
Account 503, Steam from other sources: B1unde1l depreciationTotal Other Accounts
$ l-98,484
7_0 ,484 ,921_(5,081,468)
(1,355,393)
1,5 ,829 ,896
022 627
$ 22,089, 061
Schedule Page:219 Line No.: 16 Column: bRecl-assification of accrued removaf and spend on asset retirementobligations that were included in lines 3 and 13other items include:- Recovery from third parties for asset relocations and damagedproperties- fnsurance recoveries- Adjustments of reserve rel-ated to electric plant sold and/or
purchased- Reclassifications from electric plant
Totsal Other Debit or Cr. Items $ 5, 508, 380
$ 1, s33 , 843
4,074,537
Schedule Page:219 Line No; 20 Column: c
Adjustment to PacifiCorp's formula rat.e under FERC Docket No.H-1, is as follows:ER11-3543-000, Attachment
Item
(a)
Ref .
Line No.
(Column)
Electric Plant
in Service
(c)
Steam ProductionLess: Asset retirement obligations related cost components(l-)
Revised Steam Production
20 (c) $ 3, 633, 33s, 0s5
50 651 697
$ 3, 582, 583, 358
(1) In accordance with 18 C.F.R. S35.18(a-c) a public utility that files a transmissionrate schedule, tariff or service agreement under S35.1-2 or S35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the assetretirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed raEes.
FERC FORM NO.1 (ED. 12-871 Page 450.1
Line No.:4 Column: b
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
219 Line No.: 22 Column: cAdjustment to PacifiCorp's formufa rate under FERC Docket No. ER11-3643-000, AttachmentH-1, is as follows:
ftem
Ref.
.trane No.
(Column)
Electric Plantin Service
(c)(a)
22 (c) S 421- ,1-62 ,472
65s 237
$ 418,497,235
(1) In accordance with 18 C.F.R. S35.18(a-c) a public utility that files a transmissionrate schedule, tariff or service agreement under S35.12 or S35.L3 and has recorded anasset retirement obligation on its books, but is not seeking recovery of the assetretirement costs in rates, must remove all asset-retirement-obligations-related cost
ts from the cost of service its ed rates
ustment to Pac Corp's formula rate under FERC Docket No. ER11-3543-000, Attachment
H-1, is as follows:
Hydraulic Production - Conventional
Less: Asset retirement obligations related cost components(1)
Revised Hydraulic Production - Conventional
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service(c)
219 Line No.:24 Column: c
Other Production
Less: Asset retirement obligations related cost components(1)
Revised Other Production
Item
24(c) $ 1,138,023,509(2,422,695)
$ 1,140,446,1-94
(1) In accordance with 18 C.F.R. S35.18(a-c) a public utility that files a transmissionrate schedule, tariff or service agreement under S35.12 or S35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asseL
retirement costs in rates, must remove all asset-retirement-obligations-related costts from the cost of service s its ed rates
ustment to Pac f Corp's a rate FERC Doc t No. ERll--3543-000, At
H-1, is as follows
Ref.
Line No
Electric Plantin Service
219 Line No.: 25 Column: c
a Column
Transm on z5(c) $ t,768,071,1-24
(450, 501)Less: Asset retirement obligations related cost components(1)
Revised Transmission $ l_,768,53a,625
(1) In accordance with 18 C.F.R. S35.18(a-c) a public utility that files a transmissi-onrate schedule, tariff or service agreement under S35.12 or S35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the assetretirement costs in rates, must remove all asset-retirement-obligations-related cost
components from Ehe cost of service supporting its proposed rates.
FERC FORM NO.1 (ED. 12.871 Page 450.2
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
FOOTNOTE DATA
219 Line No.: 26 Column: custment to Pac fH-1, is as follows 's formula rate under FERC Docket No. ER11-3543-000, Attachment
Item
(a)
Ref.
Line No.
(Column)
Electric Plantin Service
(c)
DistrLess: Asset retirement obligations related cost components(1)
Revised Distribution
Item
(a)
26 2 ,848 , 002 ,455
8 51_802
$ 2,847 ,L50,554
(1) In accordance with 18 C.F.R. S35.18(a-c) a public utility that files a transmissionrate schedule, tariff or servj-ce agreement under S35.12 or S35.1-3 and has recorded anasset retirement obligation on its books, but is not seeking recovery of the assetretirement costs in rates, must remove a1f asset-retirement-obligations-related costts from the cost of service s its sed rates
ustment to Pac f Corp's formul-a rate under FERC Docket No. ERI-]--3543-000, AttachmentH-1, is as follows:
Ref.
Line No.
(Column)
Electric Plantin Service
(c)
219 Line No.:28 Column: c
$ 482,727,327
(1) fn accordance with 18 C.F.R. S35.1-8(a-c) a public utility that files a transmissionrate schedule, tariff or service agreement under S35.12 or S35.13 and has recorded anasset retirement obligation on its books, but is not seeking recovery of the assetretirement costs in rates, must remove all asset-retirement-obligations-related costs from the cost of service s its sed rates
GeneralLess: Asset retirement obligations related cost components(1)
Revised General
28 (c # 482 ,541- ,400
(aes ,927 )
FERC Docket No. ERll--3543-000, Attachment
Efectric Plantin Service
(c)
Adj ustmentsH-1, are as
to Pacfollows:Corprs rmu rate
Ref.Item Line No.(a) (column)
219 Line No.: 29 Column: c
Revised Steam Production (1)
Nuclear Product.ion
Revised Hydraulic Production - ConventionaL (2)
Hydraulic Production - Pumped Storage
Revised Other Production(3)
Revised Transmission (a )Revised Distribution ( 5 )Regional Transmission and Market Operation
Revised General (5)
Revised TOTAI
21 (c)
23 (c)
27 (c)
$ 3,582, 583, 358
41,8 ,497 ,235
L ,1_40 ,446 ,1,94
1, ,7 68 , 531 , 625
2 ,847 , a50 , 554
482,727,327
$10,240,035,403
1) Refer2) Refer3) Refer4) Refer5) Refer5) Refer
footnoEefootnote
footnote
footnotefootnote
footnote
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toto
to
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on
on
on
on
on
pa9e
pa9e
pa9e
page
page
page
linelineline
1 ine
1 ine
1 ine
21,9,
2]-9,
2]-9,
21,9 ,
2L9,
2L9,
no.
no.
no.
no.
no.
no.
20,))
24,
atr
25,
28,
column (c
column (c
column (c
column (c
column (c
column (c
FERC FORM NO.1 (ED. 12-871 Page 450.3
Name of Respondent
PacifiCorp
This Reoort ls:(1) 6]Rn originat(2) 1A Resubmission
Date of Reoort(Mo, Da, Yi)tt
Year/Period of Report
End of 20181Q4
INVESTMENTS lN SUBSIDIARY COMPANIES (Account 123.1)
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(0,(g) and (h)
(a) lnvestment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) lnvestment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specirying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 41 8.1 .
Line
No.
Description of lnvestment
(a)
Date Acquired
(b)
Amount of lnvestment al
Beoinnino of Year- (d)-
1 1 973
2 Common Stock 1
3 Paid-in Capital 47,960,000
4 Undistributed Subsidiary Earnings 96,606,077
5 SUBTOTAL 144,566,078
6
7 Energy West Mining Company 1990
8 Common Stock 1,000
9 SUBTOTAL 1,000
10
11 Glenrock Coal Company 1 991
12 Common Stock 1
13 SUBTOTAL 1
14
15 lnterwest Mining Company 1992
't6 Common Stock 1,000
17 SUBTOTAL 1,000
18
19 Trapper Mining lnc.1992
20 Members'Equity 6,038,000
21 Undistributed Subsidiary Earnings 7,730,250
22 SUBTOTAL 13,768,250
23
24 Fossil Rock Fuels, LLC 2011
25 Paid-in Capital 27,669,770
26 Undistributed Subsidiary Earnings 968
27 SUBTOTAL 27,670,738
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42 TOTAL 186,007,067
FERC FORM NO.1 (ED. 12-89)Page 224
Pacific Minerals, lnc.
l-otal Cost ofAccount 123.1 $79,001,7721
PacifiCorp (1)
(2)A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose ofthe pledge.
5. lf Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (Q interest and dividend revenues form investments, including such revenues form securities disposed ofduring the year.
7. ln column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.1
Equity in subsidiary
Earninqs ff Year
Revenues for Year
(D
Amounl oI lnvestmenl at
End ofYear(s)
Gain or Loss from lnvestment
Disoosed of' (h)
Line
No.
1
1 2
47,960,000 3
17,774,578 4
17,774,578 144,340,656 5
6
7
1,000 8
1,000 I
10
11
1 12
,|13
14
15
1,000 16
1,000 17
18
19
6,038,000 20
432,521 21
432.521 14,055,743 22
23
24
25
2,662,879 zo
2,662,879 25,002,617 27
28
29
30
31
32
33
34
35
36
37
38
39
40
4',!
20,869,978 183,401 ,017 42
FERC FORM NO. I (ED. 12.89)Page 225
96,380,655
8,017,743
25,001,770
847
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
224 Line No.:1 Column: a
Pac CM raIs, fnc s a who11y owned subs ary of Pac f Corp that holds a 66.672
ownership interest in Bridger Coal Company. Bridger Coal Company is a coal mining joint
venture with Idaho Resources a subsid of Idaho Power
Schedule Page: 224 Line No;4 Column: g
Dur the year ended Dec 31, 2018, Pac f cM a1s, fnc., a who11y owned subs ty
f
of Pacif
Dur
d a dividend of 18 000 000 to Pacif
the year ended December 31, 201-8, Trapper M Inc. , a subs ry of Pac f Corp,
224 Line No.:21 Column:
id a dividend of $145 028 to Pacifi
Dur the year ended December 31, 201-8, Foss 1 Rock Fuel-s, LLC, a who11y owned subs ry224 Line No; 25 Column:
of Pacif returned a 658 000 of tal to Pacifi
Dur the year ended December 31, 201-8, Foss 1 Rock Fuels, LLC, a who11y owned subsof PacifiCorp, paid distributions of $2,553,000 to PacifiCorp
224 Line No.:26 Column:
FERC FORM NO.1 (ED. 12.871 Page 450.1
Name of Respondent
PacifiCorp
This ReDort ls:(1) 5l1Rn originat(2\ r-rA ResubmissionLI
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
MATERIALS AND SUPPLIES
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. ln column (d), designate the department or departments which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
Line
No.
Account
(a)
Balance
Beginning of Year
(b)
Balance
End of Year
(c)
Department or
Departments which
Use Material(d)
1 Fuel Stock (Account 151)197,499,391 179,588,705 Electric
2 Fuel Stock Expenses Undistributed (Accounl 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)150,015,776 161,139,297 Electric
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated)73,975,748 63,541,336 Electric
I Transmission Plant (Estimated)381 ,386 786,256 Electric
I Distribution Plant (Estimated)10,875,356 12,201J22 Electric
'10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote)Electric
't2 TOTAL Account 1 54 (Enter Total of lines 5 thru 1 1)235,276,870 237,694,431
13 Merchandise (Account 1 55)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163)
17
18
'19
20 TOTAL Materials and Supplies (Per Balance Sheet)432,776,261 417,283,136
FERC FORM NO. 1 (REV. 12-0s)Page 227
28,604 26,420
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018/o.4
FOOTNOTE DATA
227 Line No.: 11 Column: b
227 Line No.: 11 Column: c
General ant materials and I ies
ant mate supp ES
FERC FORM NO.1 (ED. 12.871 Page 450.1
Name of Respondent
PacifiCorp
This ReDort ls:(1) 5]Rn originat(2) f]A Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
Allowances (Accounts 158.1 and 158.2)
1. Report below the particulars (details) called for concerning allowances.
2. Report all acquisitions of allowances at cost.
3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General
lnstruction No. 21 in the Uniform System of Accounts.
4. Report the allowances transactions by the period they are first eligible for use: the current year's allowances in columns (b)-(c),
allowances for the three succeeding years in columns (d)-(i), staffng with the following year, and allowances for the remaining
succeeding years in columns O-(k).
5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 3640.
Line
No.
SO2 Allowances lnventory
(Account 158.1)
(a)
Current Year 2019
No.
(b)
Amt.
(c)
No.
(d)
Amt.
(e)
1 Balance-Beginning of Year 81 1,485.00 151,417.00
2
3 Acquired During Year:
4 lssued (Less Withheld Allow)
5 Returned by EPA
6
7
8 Purchasesffransfers:
I
10
11
't2
13
14
15 Total
16
't7 Relinquished During Year:
't8 Charges to Account 509 25,925.00
19 Other:
20
21 Cost of Sales/Transfers
22
23
24
25
26
27
28 Total
29 Balance-End of Year 785,560.00 151,417.00
30
31 Sales:
32 Net Sales Proceeds(Assoc. Co.)
33 Net Sales Proceeds (Other)
34 Gains
35 Losses
Allowances \{ithheld (Acct 158.2)
36 Balance-Beginning of Year 2,259.00 2,259.00
37 Add: \Mthheld by EPA
38 Deduct: Returned by EPA
39 Cost of Sales 2,259.00
40 Balance-End ofYear 2,259.00
41
42 Sales:
43 Net Sales Proceeds (Assoc. Co.)
44 Net Sales Proceeds (Other)
45 Gains
46 Losses
FERC FORM NO. 1 (ED. 12-95)Page 228a
Name of Respondent
PacifiCorp
This Reoort ls:(1) E]An Original(2) [A Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
Allowances (Accounts 158.1 and 158.2) (Continued)
6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA's sales of the withheld allowances. Report on Lines
43-46 the net sales proceeds and gains/losses resulting from the EPA's sale or auction of the withheld allowances.
7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated
company" under "Definitions" in the Uniform System of Accounts).
8. Repo( on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies.
9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.
10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
2020 202'l Future Years Totals Line
No.No.
(f)
Amt.
(s)
No.
(h)
Amt.
(i)
No.
(i)
Amt.
(k)
No
o
Amt.
(m)
1 56,646.00 156,646.00 4,072,758.00 5,348,952.00 ,|
2
3
156,644.00 156,644.00 4
5
6
7
8
I
10
11
12
13
14
15
16
17
25,925.00 18
19
20
21
22
23
24
25
26
27
28
1 56,646.00 1 56,646.00 4,229,402.00 5,479,671.00 29
30
31
32
33
34
35
2,259.00 2,259.00 1 10,921.00 1 19,957.00 36
4,528.00 4,528.00 37
38
2,269.00 4,528.00 39
2,259.00 2,259.00 1 13,180.00 1 19,957.00 40
41
42
43
44
45
46
FERC FORM NO. I (ED. 12-95)Page 229a
Name of Respondent
PacifiCorp
This Reoort ls:
(1) E:] An original
(2) - A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
gn6 61 2018/Q4
fransmission Service and Generation lnterconnection Study Costs
1. Report the particulars (details) called for conceming the costs incuned and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separalely.
3. ln column (a) provide the name of the study.
4. ln column (b) report the cost incurred 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 with the reimbursement received for performing the study.
Line
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received Durino
the Period -
(d)
Account Credited
Wth Reimbursement
(e)
1 Transmission Studies
2 01977 3,343 561.6 3,343 456
3 Q2144 149 561.6
4 Q2292 149 561.6 149 456
5 Q2370 116 561.6 't 16 456
6 Q2409 'l,455 561.6 1,455 456
7 Q2422 612 561.6
8 Q2424 1,191 561.6
I 42427 3,985 561.6 3,985 456
10 Q2435 't2,495 561.6 4,185 456
1'l Q2455 3,107 561.6 2,146 456
12 Q2467 3,067 561.6
13 Q2469 7.145 561.6
14 Q2471 5,635 561.6
15 Q2472 4,326 561.6
16 Q2486 149 561.6
17 Q2487 1,057 561.6 1,057 456
18 Q2488 594 561.6 594 456
19 Q2497 149 561.6
20 Q2498 2,927 561.6
21 Generation Studies
22 GtQ0409 11,560 561.7 11,560 456
23 GtQ0650 4,052 561.7 4,052 456
24 GtQ0687 77,415 561.7 77,415 456
25 Gl00707 11,520 561.7 11,520 456
26 GtQ0708 9,248 561.7 12,002 456
27 GtQ0712 17,743 561.7 17,743 456
28 GtQ0713 4,625 56't.7 4,625 456
29 GlQ0715 13,010 561.7 't 3,010 456
30 GlQ0718 25,028 561.7 25,028 456
3'1 GtQ0719 10,894 561.7 10,894 456
32 GtQ0731 4,988 561.7 4,988 456
33 Gt00734 5,527 561.7 5,527 456
34 Gt00737 8,292 561.7 8,292 456
35 GtQ0738 12,326 561.7 't2,326 456
36 GtQ0739 6,1 94 561.7 6,1 94 456
37 GtQ0745 9,985 561.7 9,985 456
38 GtQ0752 79 561.7 79 456
39 Gl00753 454 561.7 454 456
40 GlQ0754 2,055 561.7 2,055 456
FERC FORM NO.1/1-Fl3-Q (NEW.03{7)Page 231
Name of Respondent
PacifiCorp
This Reoort ls:
(1) E] An Original
(2) E A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
En6 61 2018/Q4
Transmission Service and Generation lnterconnection Stud
Line
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
Wth Reimbursement
(e)
1 Transmission Studies
2 Q2499 5,242 561.6
3 Q2500 2,155 561.6
4 Q2504 3,706 561.6 3,706 456
5 Q2505 4,237 561.6 4,237 456
6 Q2517 149 561.6
7 Q251 8 7,558 561.6
8 Q2527 1,075 561.6
I Q2528 3,853 561.6
10 Order 45045642 10,559 561.6 10,559 456
11 AREF 84879085 926 561.6
12 AREF 848791 1 1 926 561.6
13 Customer Studies Accruals 10,91 1 561.6
14
15
16
17
18
'19
20
21 Generation Studies
22 Gt00763 11,554 561.7 11,554 456
23 GtQ0764 3,374 561.7 3,374 456
24 Gt00766 't9,251 561.7 19,25't 456
25 GlQ0777 6,393 561.7 6,393 456
26 GtQ0778 7,422 561.7 7,422 456
27 Glo078'1 3,762 56't.7 3,762 456
28 GlQ0783 8,423 561.7 8,423 456
29 Gto0784 5,940 561.7 5,940 456
30 GlQ0785 5,614 561.7 5,519 456
31 GtQ0786 16,550 561.7 16,559 456
32 GtQ0787 18,575 561.7 18,575 456
33 Gt00788 24,300 561.7 24,300 456
u Glo0789 7,823 56',t.7 7,823 456
35 Gl00792 '16,256 561.7 16,345 456
36 GlQ0799 25,498 561.7 25,498 456
37 GtQ0801 2,953 561.7 2,953 456
38 GtQ0802 13,646 561.7 13,646 456
39 GtQ0803 16,534 56'1.7 16,534 456
40 GlQ0804 16,422 561.7 16,422 456
FERC FORM NO. ,t/1-F/3-Q (NEW. 03-07)Page 231.1
Name
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
gn6 61 2018/Q4
Transmission Service and Generation lnterconnection Stud
Line
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
Rermbursemenls
Received During
the Period
(d)
Account Credited
Wth Reimbursement
(e)
1 Transmission Studies
2
3
4
5
6
7
8
I
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 GtQ080s 23,038 561.7 23,038 456
23 GlQ0806 79 561.7 79
24 Gt00807 12,848 561.7 12,848 456
25 Gro0810 19,929 561.7 19,929 456
26 Gto081 1 25,033 561.7 25,122 456
27 GlQ0815 12,660 561.7 12,749 456
28 GtQ0819 10,699 561.7 10,699 456
29 GtQ0820 7,274 561.7
30 GtQ0821 13,191 561 .7
31 GlQ0822 9,336 561.7
32 GlQ0823 7,978 561.7
33 GtQ0824 13,854 56'r.7 13,854 456
u GtQ0825 13,212 561.7 13,212 456
35 GrQ083s 22,120 561.7 22,120 456
36 GlQ0836 7,441 561.7 7,441 456
37 Gl00838 11jU 561.7 11,154 456
38 GtQ0839 545 561.7 545 456
39 GtQ0840 6,031 56'1.7 6,031 456
40 GtQ0846 5,403 561.7 5,403 456
FERC FORM NO. 1/1.F/3-Q (NEW. 03-07)Page 231.2
456
PacifiCorp )An Original
A Resubmission(2)
Date of Report
(Mo, Da, Yr)
Year/Period of Report
En6 s1 20'18/Q4
Transmission Service and Generation lnterconnection Stud
Ltne
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
1 Transmission Studies
2
3
4
5
6
7
8
o
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 Gto0849 12,415 561 .7 12,415 456
23 GtQ0850 't2,535 561.7 12,535 456
24 GtQ0852 675 561.7 675 456
25 Glo0853 19,692 561.7 19,692 456
26 GlQ0855 19,648 561.7 19,648 456
27 Glo0856 ( 1 1 ,801)561.7 ( 11,801)456
28 Gto08s6 12,820 561.7
29 GlQ0858 ( 5,570)561.7 ( 5,570)456
30 GtQ0858 8,645 561.7
31 Gto0859 ( 3,874)561.7 ( 3,874)456
32 Gto0859 9,877 561.7
33 GrQ0860 ( 1,733)561.7 ( 1,733)456
34 GrQ0860 6,831 561.7
35 GtQ0861 ( 1,293)561.7 ( 1,2e3)456
36 GtQ0861 5,562 561.7
37 Glo0862 13,690 561.7 13,690 456
38 Glo0863 ( 2,200)561.7 ( 2,200)456
39 Glo0863 19,030 561.7
40 Gt00864 72 561.7 72 456
FERC FORM NO. 1r1-Fl3-Q (NEW. 03-07)Page 23,l.3
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
pn6 61 2018/Q4
Transmission Service and Generation lnterconnection Stud
Ltne
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
f(ermDursements
Received During
the Period
(d)
Account Credited
\Mth Reimbursement
(e)
1 Transmission Studies
2
3
4
5
6
7
8
I
10
11
12
13
14
15
16
't7
18
19
20
21 Generation Studies
22 GtQ0865 72 561.7 72 456
23 Gto0866 161 561.7 '161 456
24 Gto0867 79 56'1.7 79 456
25 Gl00868 25,004 561.7 25,004 456
26 Gl00871 196 561.7 196 456
27 GlQ0872 562 561.7 562 456
28 GrQ0875 20 561.7 20 456
29 GlQ0876 ( 716)561.7 ( 716)456
30 GlQ0876 836 561.7
31 GtQ0877 58,861 561.7 58,861 456
32 GtQ0880 182 561.7 182 456
33 GtQ0882 100 561.7 100 456
34 Gro0883 20 561.7 20 456
35 GtQ0888 6,124 561.7 6,124 456
36 Gl00893 7,091 561.7 7,091 456
37 Glo0894 111 s6't.7 't11 456
38 GtQ0895 3,033 561.7 3,033 456
39 GrQ0897 '145 561.7 145 456
40 GrQ0898 238 561.7 238 456
FERC FORM NO. tr1-Fl3-Q (NEW 03-07)Page 231.4
Name of Respondent
PacifiCorp
This Reoort ls:
(1) E An original(2)E A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
gn6 e1 2018/Q4
Iransmission Service and Generation lnterconnection Stud
Lrne
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received Durinothe Period -
(d)
Account Credited
\Mth Reimbursement
(e)
,|Transmisslon Studies
2
3
4
5
6
7
I
I
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 GtQ0904 13,226 561.7 13,226 456
23 GtQ0905 '13,06s 561.7 13,065 456
24 GtQ0906 25,735 561.7 25,735 456
25 GlQ0907 21,709 561.7 21,709 456
26 Gl00909 19,556 561.7 19,556 456
27 GlQ0911 5,621 561.7 5,852 456
28 GtQ0914 ( 6,232')561.7 ( 6,232)456
29 GlQos14 7,704 56'1.7
30 GtQ0915 't7,631 561.7 17,631 456
31 GtQ0916 14,157 561.7 14,157 456
32 GlQ0917 11,268 56'l .7 11.268 456
33 GtQ0918 ( 4,470)561.7 ( 4,470\456
u GtQ0918 14,356 561.7
35 GtQ0919 ( 2,e81)561.7 ( 2,981)456
36 GlQ0919 12,028 561.7
37 Gl00923 948 561.7 948
38 Gl00937 40 561.7 40 456
39 GlQ0941 16,707 561.7 16,707 456
40 GlQ0946 10,413 561.7 10,413 456
FERC FORM NO. 1r1-Fl3-Q (NEW. 03-07)Page 231.5
456
PacifiCorp (1)
(2)
An Original
A Resubmission
(Mo, Da,
Year/Period of Report
gn6 61 2018/Q4
Transmission Service and Generation lnterconnection Stud
une
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
KermDursements
Received Durino
the Period '
(d)
Account Credited
With Reimbursement
(e)
1 Transmlssion Studies
2
3
4
5
6
7
8
o
10
11
12
13
14
15
16
17
18
'19
20
21 Generation Studies
22 GtQ0950 20 561.7 20 456
23 GtQ0951 20 561.7 20 456
24 GtQ0953 19,283 561.7 19,283 4s6
25 GlQ0954 286 561.7 286 456
26 Gl00955 12,007 561.7 12,007 456
27 Gl00956 27,911 561.7 27,911 456
28 GlQ0957 13,776 56'1.7 18,722 456
29 Gl00958 17,687 561.7 17,687 456
30 Gto0959 131 561.7 131 456
3'l GtQ0960 4,777 561.7 4,777 456
32 GtQ0961 237 561.7 237 456
33 GtQ0962 13,524 561.7 13,524 456
34 GlQ0963 3,265 561.7 3,265 456
35 GtQ0964 3,063 561.7 3,063 456
36 GtQ0965 315 561.7 315 456
37 Gl00967 15,031 561.7 15,031 456
38 GlQ0968 9,506 561.7 9,506 456
39 GtQ0969 6,411 561.7 6,411 456
40 GlQ0970 5,112 561.7 5,112 456
FERC FORM NO. t/1-Fl3-Q (NEW.03.07)Page 231.6
PacifiCorp (1)
(2)
An Original
A Resubmission
Year/Period of Report
6n6 61 2018/Q4
Transmission Service and Generation lnterconnection Study Costs (continued)
Line
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
\Mth Reimbursement
(e)
1 Transmission Studies
2
3
4
5
6
7
8
I
'10
1',!
12
't3
14
15
16
17
18
19
20
21 Generation Studies
22 GlQ0971 14,751 561.7 14.75',1 456
23 GrQ0973 2,499 561.7 2,499 456
24 GtQ0974 20,136 561.7 20,1 36 456
25 GlQ0976 512 56',t.7 512 456
26 GlQ0977 293 561.7 293 456
27 GtQ0978 609 561.7 609 456
28 GlQ0979 317 561.7 317 456
29 GlQ0980 949 561.7 949 456
30 Gt00981 7il 561.7 754 456
31 GtQ0982 566 561.7 622 456
32 GtQ0983 682 561.7 893 456
33 GtQ0984 683 561.7 683 456
34 GtQ0985 132 561.7 132 456
35 Gr00986 1,228 561.7 1,228 456
36 GlQ0987 56,475 561.7 56,475 456
37 Gl00988 459 561.7 459 456
38 GlQ0989 17,777 561.7 17,777 456
39 GtQ0990 8,533 561.7 8,533 456
40 Gt00991 222 561.7 222 456
FERC FORM NO. 1/1-Fl3-Q (NEW.03-07)Page 231.7
Date of Report(Mo, Da, Yr)tl
Name of Respondent
PacifiCorp
This ReDort ls:
(1) E:] An Original
(2) f] A Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
En6 61 2018/Q4
Transmission Service and Generation lnterconnection Study Costs (continued)
Lrne
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
Wth Reimbursement
(e)
1 Transmission Studies
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
40
20
21 Generation Studies
22 GtQ0992 13.479 561.7 13,479 456
23 GtQ0993 2,072 561.7 2,072 456
24 GtQ0994 1,107 561.7 1.107 456
25 GtQ0995 994 561.7 994 456
26 Gro0996 2,185 561.7 2,185 456
27 Glo0997 1,729 561.7 1,729 456
28 GlQ0998 '1,439 561.7 1,439 456
29 GtQ0999 18,077 561.7 18,077 456
30 Gto1000 1,287 561.7 1,287 456
31 GtQ1001 12,840 561.7 12,840 456
32 Gto'1002 10,764 561.7 10,764 456
33 Gto'1003 11,493 561.7 11,589
34 GtQ1004 1,446 561.7 1,542 456
35 GtQ1005 1,476 561 .7 1,476 456
36 GtQ1006 1,156 561.7 1,156 456
37 GlQ1007 7,427 561.7 7,427 456
38 GlQ1008 14,753 561.7 't4,753 456
39 GlQ1009 5,606 561.7 5,694 456
40 GtQ1010 1,803 561.7 1,803 456
FERC FORM NO. 1/1-FIS-Q (NEW. 03-07)Page 231.8
456
PacifiCorp (1)
(2)
Original
A Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
gn6 61 2018/Q4
Transmission Service and Generation lnterconnection Stud
Lrne
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
HetmDursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
I Transmission Studies
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 GlQ101 1 855 561.7 855 456
23 GtQ1012 8,317 561.7 8,317 456
24 GtQ1013 981 561.7 981 456
25 GlQ1014 756 561.7 756 456
26 GlQ1015 670 561.7 670 456
27 GtQ1016 620 561.7 620 456
28 GlQ1017 937 561.7 937 456
29 GrQ1018 't,023 561.7 1,023 456
30 GlQ1019 15,281 561.7 15,281 456
3'1 GtQ1020 8,992 561.7 8,992 456
32 GtQ1021 1,000 561.7 1,000 456
33 GtQ1022 9,861 561.7 9,861 456
34 GtQ1023 13,568 561 .7 13,568 456
35 GtQ1024 846 561.7 846 456
36 GlQ1025 1,299 561.7 1,299 456
37 Glo1026 3,328 561.7
38 GlQ1027 971 561.7 971 456
39 GtQ1028 859 561.7 859 456
40 GlQ1029 26,688 561.7 26,688 456
FERC FORM NO. 1r1-Fl3-Q (NEW. 03-07)Page 231.9
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
ll
Year/Period of Report
gn6 q1 2018/Q4
Lrne
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
1 Transmission Studles
2
3
4
E
6
7
8
I
10
11
12
13
14
'15
16
17
18
19
20
2'l Generation Studies
22 GtQ1030 4,778 561.7 4,778 456
23 GtQ1031 17,422 561.7 17,422 456
24 GtQ1032 8,858 561.7 8,858 456
25 Gto1033 7,038 561.7 7,038 456
26 GtQ1034 17,438 561.7 17,438 456
27 GtQ1035 995 561.7 995 456
28 GtQ1036 653 561.7 653 456
29 GlQ1037 968 561.7
30 Gto1038 1,174 561.7 1,174 456
31 GtQ1039 1,497 561.7 1,497 456
32 GtQ1040 1,093 561.7 1,093 456
33 GtQ1041 761 561.7 761 456
34 GtQ1042 416 561.7 416 456
35 Gto1043 12,122 561.7 12,122 456
36 Glo1044 1,150 561.7 1 ,'t 50 456
37 Glo1045 9,012 561.7 9,012 456
38 GlQ1046 930 561.7 930 456
39 GtQ1047 1,100 561.7 1,100 456
40 GtQ1048 876 561.7 966 456
FERC FORi'l NO. 1r1-Fl3-Q (NEW.03-07)Page 231.10
Transmission service and Generation lnterconnection stu(
Name of Respondent
PacifiCorp
This ReDort ls:
(1) E:] An Original(2)n A Resubmission
Date of Repo((Mo, Da, Yr)
Year/Period of Report
gn6 q1 2018/Q4
Transmassion Service and Generation lnterconnection Stud
Line
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
1 Transmission Studies
2
3
4
5
6
7
8
9
10
't1
't2
13
't4
15
16
17
18
19
20
21 Generation Studies
22 Gto1049 1.172 561.7 1,',t72 456
23 GlQ1050 85s 561.7 855 456
24 GtQ1051 802 561.7 802 456
25 GlQ1052 741 561.7 741 456
26 Glo1053 1,414 561.7 1,414 456
27 Glo1054 1,172 561.7 1.172 456
28 GlQ1055 7,476 561.7 7,476 456
29 GtQ1056 1,527 561.7 1,527 456
30 Glo1057 1,007 561.7 1,007 456
3'r GtQ1058 830 561.7 830 456
32 Glo1059 926 561.7 926 456
33 GtQ1060 815 561.7 815 456
34 GtQ1061 628 561.7 628 456
35 GtQ1062 1,082 561.7 't,082 456
36 Glo1063 8,713 561.7 8,713 456
37 GlQ1064 1,224 561 .7 1,224 456
38 GtQ1065 1,558 561.7 1,558 456
39 GlQ1066 120 561.7 120 456
40 GtQ1067 240 561.7 240 456
FERC FORM NO. rr1-Fl3-Q (NEW. 03-07)Page 231.11
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of ReDort
(Mo, Da, Yi)
tt
Year/Period of Report
En6 61 2018/Q4
Transmission Service and Generation lnterconnection Stud y Costs (continued)
Ltne
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
Wth Reimbursement
(e)
1 Transmission Studies
2
3
4
5
6
7
8
I
10
1'.!
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 GtQ1068 1,083 561.7 1,083 456
23 Gto1069 690 561.7 690 456
24 Gto1070 1,128 561.7 1,128 456
25 GtQ1071 724 56'1.7 724 456
26 GlQ1072 423 561.7 423 456
27 GtQ1073 1,244 561.7 1,244 456
28 Glo1074 1,125 561.7 't,125 456
29 GlQ1075 566 561.7 566 456
30 GtQ1076 1,153 561.7 1,153
31 GlQ1077 712 561.7 712 456
32 GtQ1078 1,057 561.7 1,057 456
33 GlQ1079 549 561.7 549 456
34 GtQ1080 1,065 561.7 1,065 456
35 GtQ1081 830 561.7 830 456
36 GtQ1082 40 55't.7 40 456
37 GtQ1083 992 561.7 992 456
38 GlQ1084 1,057 561.7 1,057 456
20 GlQ1085 942 56'1.7 942 456
40 GlQ1086 1,408 561.7 1,408 456
FERC FORM NO. 1/1-Fl3-Q (NEW. 03-07)Page 231.12
456
Name of Respondent
PacifiCorp
This Reoort ls:
(1) E:] An Original
(2)11 A Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
gn6 61 2018/Q4
fransmission Service and Generalion lnterconnection Study Costs (continued)
Lrne
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During
the Period
(d)
Account Credited
With Reimbursement
(e)
1 Transmission Studies
2
3
4
5
6
7
8
I
'10
1'l
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 GtQ'1087 865 561.7 86s 456
23 Glo'1088 227 561.7 227 456
24 GtQ1089 689 561.7 689 456
25 GtQ1090 51 1 561.7 51',!456
26 Glo1091 471 561.7 471 456
27 GtQ1092 187 561.7 187 456
28 GlQ1093 67 561.7 67 456
29 GlQ1094 270 561.7 270 456
30 Glo1095 231 561.7 231 456
31 Pre-Application Studies - East 8,131 561.7 8,1 31 456
32 Pre-Application Studies - West 23,572 561.7 23,572 456
33 Customer Studies Accruals 137 561.7
34
35
36
37
38
39
40
FERC FORM NO. 1r1-Fl3-Q (NEW.03-07)Page 231.13
Name of Respondent
PacifiCorp
ThiS
(1)
(2)
ReDort
EInn
ls:
Original
nA Resubmission
Date of(Mo, Da
Report
r, Yr)
Year/Period of Report
End of 2018tQ4
OTHER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for concerning other regulatory 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 Regulatory Assets
(a)
Balance at Beginning
of Current
Quarterffear
(b)
Debits
(c)
CREDITS Balance at end of
Cunent Quarterffear
(0
Written off During the
Ouarter /Year Account
cnarued 16y
Written ofi During
the Period Amount
(e)
1 DSM Balancing Account - UT 4,369,0'16 7,686,878 908 1 2,055,894
2 DSM Balancing Account - WA '143,58s 1 1,1 17,888 908 11,261 ,473
3 DSM Balancing Account - WY 5,509,914 7,666,122 908 4,588,755 8,587,281
4 lnigation Load Control - OR 57,874 171,8'16 908 132,857 96,833
5 Defened Excess Net Power Costs - CA 3,503,556 4,504,759 555 1,998,703 6,00s,612
6 Deferred Excess Net Power Costs - lD 9,484,694 16,550,448 555 7,858,1 59 18,176,983
7 Deferred Excess Net Porver Cosb - UT 7,559,200 24,647,749 182.3,555 1,835,1 85 30,37 1,764
I Deferred Excess Net Power Cosh - WY 5,512,772 5,512,772
I Deferred Excess RECs in Rates - UT 83,476 1,30 1,344 456 346,278 '1,038,542
'10 Deferred Excess RECs in Rates - WY 447,138 453,300 456 136,214 764,224
11 Solar ITC Basis Adjustment Regulatory Asset I 38,1 57 JJb 282,283 2,243 36,250
12 Pension 41 7,595,1 60 40,330,898 15,454,832 442,471,226
13 Other Postretirement I 5,713,302 |5,713,302
14 Postemployment Costs 1,338,783 476,51 0 862,273
15 Powerdale Decommissioning - lD (10)I 77 ,714 | +oz.s 25,986 51,728
16 Carbon Plant Regulatory Asset - lD (6)1,435,915 403 478,639 957,276
17 Carbon Plant Regulatory Asset - UT (6)10,333,924 403 3,444,641 6,889,283
18 Cafion Plant Regulatory Asset - WY (6)3,474,563 403 1,1 58,1 88 2,316,375
19 Carbon Plant lnventory Regulatory Asset 3,1 18,823 3,1 18,823
20 Depreciation Study Defenal - lD (1)4,133,277 254,403 4j33,277
21 Depreciation Study Defenal - UT (17)1,728,583 403 '128,043 1,600,540
22 Depreciation Study Deferral - WY (17)5,969,577 403 442,191 5,527,386
23 Generating Plant Liquidated Damages - UT 560,000 557 35,000 525,000
24 Generating Plant Liquidated Damages - WY 1,244,416 557 54,288 1,190,128
25 Klamath Hydroelectric Relicensing Costs - UT (10)I rs,z+z,ooo 717,344 404 4,287,002 15,672,342
26 Washington Colstrip Unit No. 3 (22)1 60,943 456 52,188 1 08,755
27 Environmental Costs (10)78,782,525 8,763,098 4,989,809 82,555,814
28 Asset Retirement Obligations Regulatory Difference 99,883,91 1 18,769,21 I 1 18,653,129
29 Unamortized Contract Values 88,808,488 242 10,056,772 78,751,716
30 Unrealized Loss on Derivative Contracts 101,301,707 175,244 s,s23,824 95,777,883
31 Solar Feed-ln Tariff Defenal - OR (1)I s,ezs,taz 5,314,733 908 5,518,070 5,'125,795
32 Solar lncentive Subscriber Program - UT 1,550,999 237,007 908 1 24,683 1,663,323
33 Renarable Portfolio Standards Compliance - OR (1)301,244 465,382 555 651,527 1 15,099
34 Renewable Portfolio Standards Compliance - WA (1)32,986 167,371 555 152,528 47,829
35 Protocol - MSP Deferral - lD 1 50,000 150,000
36 Protocol - MSP Defenal - UT 4,400,000 4,400,000 8,800,000
37 Protocol - MSP Defenal - WY 799,998 1,600,000 2,399,998
38 Deferred lntervenor Funding Grants - CA 41,019 976 41,995
39 Deferred lntervenor Funding Grants - lD 26,865 40,000 66,865
40 Defened lntervenor Funding Grants - OR 535,508 391,443 926,95 1
41 Catastrophic Event Regulatory Asset - CA (2)3,196,502 924 1,017,091 2,179,411
42 Alternative Rate for Energy (CARE) - CA s24,500 93,657 336,534 281,623
43 Deferred Overburden Cost - lD 354,223 1,497 ,748 501 1,358,477 493,494
FERC FORM NO.1/3.Q (REV. 02-04)Page 232
142
Name of Respondent
PacifiCorp
This ReDort ls:(1) 5]Rn original(2) nA Resubmission
Date of(Mo, Da
tt
Report
r, Yr)
Year/Period of Report
End of 2018tQ4
OTHER REGULATORY ASSETS (Account 182.3)
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $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 Regulatory Assets
(a)
Balance at Beginning
of Current
Quarterffear
(b)
Debits
(c)
CREDITS Balance at end of
Cunent Quarterffear
(D
Written off During the
Quarter /Year Account
Charsed (d)
Wriften off During
the Period Amount
(e)
1 Deferred Overburden Cost - VVY 996,686 4,214,280 501 3,822,401 1,388,56s
2 BPA Balancing Account - OR 6,'146,695 982,639 7,129,334
3 Propefi Sales Balancing Ac,count - OR 322,970 1,244,036 482,540 1,084,466
4 Property lnsurance Reserve - OR 6,687,383 3,434,414 924 7,068,568 3,053,229
5 Misc. Regulatory Assets/Liabilities - OR 265,573 192 265,765
6 Depreciation Deferral - WA 6,648 6,648
7 155,91 1,213 1,511,235 19,548,225 137,874,223
8 Prefened Stock Redemption Loss - UT (10)512,377 407.3 82,s29 429,848
I Preferred Stock Redemption Loss - WA (10)82,126 407.3 13,318 68,808
'10 Preferred Stock Redemption Loss - WY (10)1 76,575 407.3 28,442 148,133
11 Mobile Home Park Conversion - CA 73,822 124,888 198,710
12 Transportation Electrification Program - OR 48,792 48,792
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 1,055,465,461 183,022,567 131,161,884 1,107,326,144
FERC FORM NO. 1/3-Q (REV.02,04)Page 232.1
Utah Mine Disposition
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
20181Q4
FOOTNOTE DATA
232 Line No; 5 Column: a
232 Line No.:6 Column: a
We hted average rema life S mately one year for deferred excess net power
cost mechanisms be amortized
wei.ghted average remaining life is approximately one year for deferred excess net powercost mechanisms be amortized
Weighted average remaining life is approximately one year for deferred excess neL power
cost mechanisms be amortized
Weighted average remaining life is approximately one year for deferred excess renewable
ene credits in rates be amortized
Weighted average remaining life is approximately one year for deferred excess renewable
ene credits in rates be amortized
Weighted average remaining life being amortized is 20 years. Substantially represents
amounts not yet recognized as a component of net periodic benefit cost that are expectedto be included in rates when re zed.
Pensions are associated with labor and generally charged to operations and maintenance
expense and construction work in progress. Pension settlements, curtailments and
remeasurement date c s are to AccounL 926,e ions and benefits
ted 1 fe sf ve
Other postemployment costs are assoc ted th labor and generally charged to operat S
and maintenance e and construction work in
ted aver 1 1 fe s15 ars
hted aver 1 fe s24 ars
Account 514,
Account 545,
Account 554,
Ma .tenance o f
f
ff
m1
mi
ml-
ml-
scellaneous sLeam plant
scellaneous hydraulic plant
scellaneous other power generation plant
Account 598
Maintenance oMaintenance o
Maintenance o scellaneous distribution ant
We average rema ng e ve years. Represents rozen ues contracts
s1 accounted for as derivatives and recorded at fair value
We e s two
Account 182.3, Other regulatory assets
Account 421-L, Gain on disposition of propert.y
Account 431 Other interest
We average rema e s approx te y one year or neE property,ant
egui-pment not considered probable of disallowance and for the portion of losses associatedwith the assets held for sa1e. Additionally, the weighted average remai-ning life is
approxj-mately four years for closure costs incurred to date considered probable of
recovery.
Schedule Page: 232.1 Line No.:7 Column: d
FERC FORM NO.1 (ED.',12-871 Page 450.1
232 Line No.:7 Column: a
232 Line No.:9 Column: a
232 Line No.: 10 Column: a
232 Line No.:12 Column: a
232 Line No.:12 Column: d
232 Line No.: 14 Column: a
232 Line No.: 14 Column: d
232 Line No.:23 Column: a
232 Line No.:24 Column: a
232 Line No.: 27 Column: d
232 Line No.:29 Column: a
Schedule Pase:232 Line No; 30 Column: a.qhted averaqe remaininc
Schedule Page:232.1 Line No.: 3 Column: d
232.1 Line No.:7 Column: a
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Account 440,
Account 442,
Account 501,Account 505,
Residential saLes
Commercial and industrial sales
t.'ue l-Misceflaneous steam power expenses
FERC FORM NO. r (ED. 12-871 Page 450.2
Name of Respondent
PacifiCorp (2)Resubmission
Date of Report(Mo, Da, Yr)
tl
Year/Period of Report
End of 2018/Q4
1. Report below the particulars (details) called for concerning miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3. Minoritem(1%oftheBalanceatEndofYearforAccountlS6oramountslessthan$100,000,whicheverisless)maybegroupedby
classes.
Line
No.
Description of Miscellaneous
Deferred Debits
(a)
Balance at
Beginning of Year
(b)
Debits
(c)
CREDITS Balance at
End ofYear
(f)
Amount
(e)
I Joseph Settlement (21)11,447 557 11,447
2 Lacomb lnioation (24)186,690 557 45,720 140,970
3 Bogus Creek (41)91 1,600 557 41,280 870,320
4 Mead Phoenix Availability and
5 Transmission Charqe (46)11,008,487 565 574,404 10,434,083
6 TGS Buvout (23)32,236 557 15,473 16,763
7 Point-to-Point Transmission 971,032 8,000 979,032
8 Hermiston Swap (40)3,190,630 557 171 ,693 3,018,937IDefened Coal Costs - \A&odak
10 Settlement (22)1,675,908 501 335,182 1,340,726
11 148,463 931 41,568 106,895
12 Lake Side Maintenance Prepaid 't6,223,296 5,458,631 21,681,927
13 Lake Side 2 Maintenance Prepaid 17.216.022 6,466,792 107 14,963,558 8,719,256
14 Chehalis Maintenance Prepaid 9,381,583 3,430,701 12,812,284
15 Cunant Creek Maint. Prepaid 6,151 ,363 4,951 ,840 1 1 ,103,203
16 7,995 454 7,995
17 1,732,495 841,045 427,431 724,166 1,849,374
18 PCRB LOC/SBBPA Costs (2)3,222 427 2,578 644
19 308,126 67,500 427 90,394 285,232
20 '94 Series Restrucl. Costs (16)401,590 427 58,769 342,821
21 Deferred S-3 Shelf Regis. Costs 191,902 208,4U 181 86,899 313,467
22 BPA LT Transmission Prepaid 2,211,329 126,309 565 966,444 1,371 ,194
23 Emission Reduction Credits 306,510 306,510
24 Unamortized Contract Values 3,643,532 3,646,848 7,290,380
25 Sales of Electric Utility
26 Facilities & Properties 147,933 539 86,693 61,240
27 lT Licenses and Maint. Prepaid 96,320 75,000 921,923 42,640 128,680
28 Other Deferred Charqes 2,071 2,071
29
30
31
32
33
34
35
36
37
38
39
40
4',!
42
43
44
45
46
47 Misc. Work in Progress
48 Defened Regulatory Comm.
Expenses (See paqes 350 - 351)
49 TOTAL 76,159,711 83,176,009
FERC FORM NO.,t (ED.12-94)Page 233
LT Lease Commissions Prepaid
Lease lncentives
Credit Aoreement Costs
PCRB Mode Conversion Costs
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
20181Q4
FOOTNOTE DATA
233 Line No.: 11 Column: a
The wei ave
hted ave
The ghted average
life is t.hree
e s one
1 fe s three
1 fe s four years
Schedule Page:233 Line No; 16 Column: ahted average remaininc
Schedule Page: 233 Line No.: 17 Column: a
nlY
Schedule Page:233 Line No.: 19 Column: a
n
FERC FORM NO.1 (ED. 12-871 Page 450.1
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
1. Report the information called for below concerning the respondent's accounting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
Line
No.
Description and Location
(a)
tsalance ot tseornrnool Year
(b)
tsalance at Enoof Year
(c)
1 Electric
2 Employee benefits u,332,',t07 91 ,494,740
e Derivative contracts and unamortized contract values 48,351,596 45,186,081
4 State carryforwards 82,972,793 76,749,053
E Asset retirement obligations 49,995,035 53,1 01 ,1 52
b Regulatory liabilities 517,326,439 503,204,846
7 Other 53,610,193 54,723,740
8 TOTAL Electric (Enter Total of lines 2 thru 7)836,588,163 824,459,612
o Gas
10
11
12
13
14
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15
17 Other (Speciff)
18 TOTAL (Acct 190) (Total oflines 8, 16 and 17)836,588,1 63 824,459,612
Notes
FERC FORM NO. 1 (EO. 12-88)Page 234
Name of Respondent
PacifiCorp (2)Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
'1 . Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series
of any general class. Show separate totals for common and preferred stock. lf information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line
No.
Class and Series of Stock and
Name of Stock Series
(a)
Number of shares
Authorized by Charter
(b)
Par or Stated
Value per share
(c)
Call Price at
End ofYear
(d)
1 750,000,000
2 TOTAL COMMON STOCK 750,000,000
3
4 Account 204, Preferred stock issued
5 5% Cumulative Preferred 126,533 100.00
6 Serial Preferred, Cumulative:3,500,000
7 6.00o/o Series 100.00
8 7.00% Series 100.00
I No Par Serial Preferred 16,000,000
't0 TOTAL PREFERRED STOCK 19,626,533
11
12
13
'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
40
41
42
FERC FORM NO.1 (ED. 12-91)Page 2S0
Account 201, Common stock issued
Authorized and Unissued Capital Slock
)nalPacifiCorp(2)A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET(Total amount outstanding without reduction
for amounts held by respondent)
HELD BY RESPONDENT Line
No.AS REACQUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS
Shares(e)
Amount
(D shares(g)uost(h)Snares
(D
Amounlo
357,060,915 3,417,945,896 1
357,060,915 3,417,945,896 2
3
4
5
6
5,930 593,000 7
18,046 1,804,600 8
I
23,976 2,397,600 10
11
12
13
14
15
16
17
18
19
20
2',!
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. r (ED. r2-88)Page 251
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
20181Q4
FOOTNOTE DATA
250 No.:1 Column: a
250 Line No.: 1 Column: d
re Hathaway Energy Company indirectly owns all of the shares of Pac f Corp' s
outstanding common stock. Therefore, there is no public market for Pacificorp's common
stock.
s ass o not redeemable
Th ser es of f stock is not redeemable.
Th series of referred stock not e
Authorizat or the issuance of common stock are as follows
Idaho Public Ut.ilities Commission - Case No. PAC-E-05-7, Order No. 30099, dated
.July 7 , 2006.
- Oregon Public Utility Commission - Docket No. tJF-4228, Order No. 06-41-7, dated
,fu1y l-7 , 2006.
- Washington Utiflties and Transportation Commission - Docket No. UE-050974,
Order No. L, dated ,June 28, 2006,
As of December 31, 201-7, PacifiCorp had regulatory approval from the aforemenEioned
commissions for t.he issuance of an additional 30,000,000 shares of common stock out of the
750, OOO, 000 authorized (357, 060, 915 outstanding) by Pacificorp's articles of
incorporation.
FERC FORM NO.1 (ED. 12-871 Page 450.1
250 Line No.:7 Column: d
250 Line No;8 Column: d
250 Line No.: 12 Column: a
Name of
PacifiCorp (1
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
OTHER PAID-IN CAPITAL (Accounts 208-21 1, inc.
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 1 1 2. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries efiecting such
change.
(a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to wtrich related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end of
year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Account 21 1)-Classify amounts included in this account according lo captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
LtneNo.Amounl(b)
I Account 211, Miscellaneous paid-in capital
2 Additional Paid-in Capital:
3 Share based payments
4 Tax benefit from stock oplion exercises
5 Benefit plan separation
6 Capital contributions
7 Gain on sale of ScottishPower plc stock
8 Qualified production activity tax deduction
I Contribution of lntermountain Geothermal
10
11
12
13
14
't5
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40 TOTAL 1 ,1 02,063,956
FERC FORM NO. I (ED. 12-87)Page 253
1,973,218
14,422,979
-3,575,760
1,089,950,000
136,208
-1,275,241
432,552
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, YD
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
253 Line No.:3 Column: b
253 Line No;4 Column: b
Represents the fair value of
performance measures were met
stock opt s granted by ScottishPower p1c for which certainin March 2005. These options became fu11y vested in
2005.
Represents the j-ncome tax deduct attr Ie to the exercise of stock options granted
ScottishPower 1c.
Represents the effecL of transferr certa benef t plan obligat.ions and assets to PPM
Ene , Inc. as a result of the sale of Pacifi ScottishPower 1c
Represents capital contribut s to Pac f Corp (with no shares of stock issued) from itsindirect parent Berkshire Hathaway Energy Company (rrBHE"). No capital contributions were
made BHE to PacifiCo the ended December 31, 2018.
Represents a realized gain on stock related to separation of PPM Energy, fnc. participants
ensation 1an, which invested in ScottishPower 1c stock.
Represents amounts associated with Internal Revenue Code Section 199 qualified production
activities .
Represents contr ion of Intermountain Geothermal Company to PacifiCorp rom BHE
March 2006, subsequent to the safe of PacifiCorp to BHE. Intermountain Geothermal Company
was merged with and into its direct parent, PacifiCorp, on August 31, 2007, withPacif iCorp survivj-ng.
FERC FORM NO.1 (ED. 12-871 Page 450.1
253 Line No.:5 Column: b
253 Line No.:6 Column: b
253 Line No.:7 Column: b
253 Line No.:8 Column: b
253 Line No.:9 Column: b
from the deferred
Name of Respondent
PacifiCorp
This Report ls:(1) [An Original(2) 1-1A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
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 occurred during the year in the balance in respecl to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
Lrne
No.
ulass and series ot stocl(
(a)
Balance at End of Year
(b)
1 Common Stock 41,101,061
2
3
4
5
6
7
8
I
10
11
12
13
14
15
't6
17
18
19
20
21
22 TOTAL 41,101,061
FERC FORM NO.1 (ED. 12-87)Page 2ilb
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)lt
Year/Period of Report
End of 20181Q4
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies , and 224, Other long-Term Debt.
2. 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. Designate
demand notes as such. lnclude in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. 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. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specifled by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 Accounl 221, Bonds
2 First Mortgage Bonds:
3 5.650/o Series due July 15,2018 500,000,000 3,067,221
4 905,000 D
E 5.50o/o Series due January 15,2019 350,000,000 2,5',t5,793
6 2,292,500 D
7 3.85o/o Series due June 15,2021 400,000,000 3,007,139
8 744,000 D
I 2.95o/o Series due February 1, 2022 350,000,000 2,424,350
10 308,000 D
11 2.95% Series dueFebruary 1,2022 100,000,000 254,',129
12 -81 ,000 P
13 2.95% Series due June 1,2023 300,000,000 1,859,352
't4 900,000 D
15 3.60% Series due April 1 ,2024 425,000,000 3,345,164
16 255,000 D
17 3.35% Series due July 1, 2025 250,000,000 2,121,421
18 320,000 D
19 7.707o Series due November '15,2031 300,000,000 2,874,150
20 864,000 D
2',!5.90% Series due August 15,2034 200,000,000 1,892,365
22 722,000 D
23 5.25% Series due June 15,2035 300,000,000 2,912,O21
24 1,080,000 D
25 6.10% Series due August 1, 2036 350,000,000 2,907,881
26 1,'141,000 D
27 5.75% Series due April '1 , 2037 600,000,000 589,216
28 24,000 D
29 6.25% Series due October 15,2037 600,000,000 5,127,281
30 750,000 D
31 6.35% Series due July 15, 2038 300,000,000 2,290,333
32 I ,671,000 D
33 TOTAL 7 ,641,475 82,1 1 7,663
FERC FORM NO. { (ED. 12-96)Page 256
Name of Respondent
PacifiCorp (1)
(2)
An
A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
LONG-TERM DEBT (Account 221,222,223 and 224) (Continued)
10. ldentify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. ln a footnote, give explanatory (details) for Accounts 223 and 224 ol 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 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 incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, lnterest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Nominal Date
of lssue
(d)
Date of
Maturity
(e)
AMORTIZATION PERIOD uulslanorno(Total amount outstanding wilhout
reduction for amounts held by
resDondent)'(h)
lnterest for Year
Amount
0
Line
No.Date From
(0
Date To
G)
1
2
07t17t2008 0711512018 07t1712008 07t15t2018 15,302,083 3
4
01/08/2009 01t1512019 01/08/2009 01t15t2019 350,000,000 19,250,000 5
6
0511212011 06t'1512021 05t',t2t20't1 06115t2021 400,000,000 15,400,000 7
8
0110612012 02t0112022 01t06t2012 02t01t2022 350,000,000 10,325,000 o
'10
03t06t2012 02t01t2022 03t06t2012 02t0112022 100,000,000 2,950,000 11
12
06/06/2013 06t01t2023 06/06/201 3 06t01t2023 300,000,000 8,850,000 13
14
0311312014 04t0112024 03t13t2014 04t01t2024 425,000,000 15,300,000 15
16
06t19t2015 07 t0112025 o6t19t2015 07t01t2025 250,000,000 8,375,000 17
18
't1t21t2001 11t',t5t2031 11t2112001 't1t15t2031 300,000,000 23,100,000 19
20
0812412004 08t15t2034 08t24t2004 08t15t2034 200,000,000 11,800,000 21
22
06/1 3/2005 06/1 5/2035 06/1 3/2005 06/1 5/2035 300,000,00c 15,750,000 23
24
08/10/2006 08/01/2036 08/'t 0/2006 08/01/2036 350,000,000 21,350,000 25
26
03t14t2007 04t0112037 03t1412007 04to'U2037 600,000,000 34,500,000 27
28
10t03t2007 10t15t2037 10t03t2007 10t15t2037 600,000,000 37,500,000 29
30
07t17t2008 07t15t2038 07t17t2008 07t15t2038 300,000,000 19,050,000 31
32
7,055,275,000 358,695,455 33
FERC FORM NO.1 (ED.12-96)Page 257
PacifiCorp (1)
(2)
An Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 2018/Q4
1. Repo( by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221 , Bonds,222,
Reacquired Bonds, 223, Advances from Associated Companies , and 224, Other long-Term Debt.
2. 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. Designate
demand notes as such. lnclude in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. 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. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 6.00% Series due January 1 5, 2039 650,000,000 6,134,687
2 6,175,000 D
3 4.10% Series due February 1, 2042 300,000,000 2,737,911
4 987,000 D(600,000,000 5,640,085
6 1,344,000 D
7 8.53% Series C Medium-Term Notes due December 16,2021 15,000,000 115,202
8 8.375% Series C Medium-Term Notes due December 31,2021 5,000,000 38,400
I 8.26% Series C Medium-Term Notes due January 7,2022 5,000,000 33,243
10 8.27% Series C Medium-Term Notes due January 10,2022 4,000,000 30,594
11 8.05% Series E Medium-Term Notes due September '1, 2022 15,000,000 131 ,471
12 8.07olo Series E Medium-Term Notes due September 9, 2022 8,000,000 70,118
13 8.12% Series E Medium-Term Notes due September 9, 2022 50,000,000 438,238
14 8.1 1olo Series E Medium-Term Notes due September 9, 2022 12,000,000 105,177
15 8.05o/o Series E Medium-Term Notes due September 14,2022 10,000,000 87,648
16 8.08% Series E Medium-Term Notes due October 14,2022 26,000,000 208,1 98
17 8.08o/o Series E Medium-Term Notes due October 14,2022 25,000,000 200,1 90
18 8.23olo Series E Medium-Term Notes due January 20,2023 5,000,000 37,9',t4
'19 8.23% Series E Medium-Term Notes due January 20,2023 4,000,000 30,331
20 -81 ,560 P
21 7.26% Series F Medium-Term Notes due July 21 ,2023 27,000,000 246,981
22 7.26% Series F Medium-Term Notes due July 21 ,2023 11,000,000 100,622
23 7.23% Series F Medium-Term Notes due August 16, 2023 15,000,000 137,211
24 7.24olo Series F Medium-Term Notes due August 16, 2023 30,000,000 274,423
25 6.750lo Series F Medium-Term Notes due September '14,2023 5,000,000 38,250
26 6.750lo Series F Medium-Term Notes due September 14,2023 2,000,000 15,300
27 6.720lo Series F Medium-Term Notes due September 14,2023 2,000,000 15,300
28 6.75% Series F Medium-Term Notes due October 26,2023 20,000,000 1s2,326
29 6.75% Series F Medium-Term Notes due October 26,2023 16,000,000 121,861
30 6.750lo Series F Medium-Term Notes due October 26,2023 12,000,000 91,396
31 6.71olo Series G Medium-Term Notes due January 15,2026 100,000,000 904,467
32 Subtotal - First Mortgage Bonds 7,299,000,000 7s,645,300
33 TOTAL 7,U1,475,000 82,117,663
FERG FORM NO. 1 (ED. 12-96)Page 256.1
Name of Respondent
PacifiCorp (1)
(2')
Original
Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
End of 20'l8lQ4
10. ldentify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amorlization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. ln a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. lf the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. 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 incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, lnterest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Nominal Date
of lssue
(d)
Date of
Maturity
(e)
AMORTIZATION PERIOD outstandrno(Total amount outstanding without
reduction for amounts held byresoondent)' (h)
lnterest for Year
Amount
(i)
Line
No.Date From
(0
Date To
(s)
01/08/2009 01t15t2039 01/08/2009 0111512039 650,000,000 39,000,000 1
2
01t0612012 02t01t2042 01t06t2012 02101t2042 300,000,000 12,300,000 3
4
07t't3t2018 01t15t2049 07t13t2018 01t15t2049 600,000,000 11,550,000 5
6
12116t199',!12t16t2021 12t16t',t991 't2t16t2021 15,000,000 1,279,500 7
1213',U199',!12t31t2021 12t31t1991 't2t31t2021 5,000,000 418,750 8
01t08t1992 01t07t2022 01t08t1992 01t07t2022 5,000,000 413,000 I
01/09/1992 01t10t2022 01t09t1992 01110t2022 4,000,000 330,800 10
09/1 8/ 1 9S2 09t01t2022 09/1 8/1 992 09t01t2022 15,000,000 1,207,500 11
09/09/1 992 09t09t2022 09/09/1 992 09t09t2022 8,000,000 645,600 12
09t't1t1992 09t09t2022 09t't1t1992 09t09t2022 50,000,000 4,060,000 13
09t11t1992 09t09t2022 0911'U1992 09t09t2022 12,000,000 973,200 14
o9114t1992 09t14t2022 09114t1992 09t't4t2022 10,000,000 805,000 15
10t15t1992 10t1412022 10t15t1992 10t14t2022 26,000,00c 2,100,800 16
10115t't992 10t14t2022 10t15t1992 10t1412022 25,000,00c 2,020,000 17
01/20/1993 01t20t2023 01 /20/1 993 01t20t2023 5,000,000 41 1,500 '18
01t29t1993 01t20t2023 01t2012023 4,000,000 329,200 19
20
07t22t1993 07t21t2023 07t22t1993 07t21t2023 27,000,000 1,960,200 21
07t22t1993 07t21t2023 07t22t1993 07t21t2023 11,000,000 798,600 22
08/1 6/1 993 08116t2023 08/16/1993 08t16t2023 15,000,000 1,084,500 23
08/16/1993 08116t2023 08/1 6/1 993 ogt't6t2023 30,000,000 2,172,000 24
09/1411993 09t14t2023 09/1 4/1 993 09114t2023 5,000,000 337,500 25
09/'14l1993 09t14t2023 09/14l1 993 09114t2023 2,000,000 135,000 26
09/1 4/1 993 09t14t2023 09/1411 993 09t14t2023 2,000,000 134,400 27
1 0/26/1 993 10t26t2023 1 0/26/1 993 10t2612023 20,000,000 1,350,000 28
10t26t1993 10t26t2023 10t26t1993 10t26t2023 16,000,000 1,080,000 29
1 0/26/1 993 10t26t2023 10t26t1993 10t26t2023 12,000,000 810,000 30
01/23l1996 01t15t2026 01/23l1996 01115t2026 100,000,000 6,710,000 31
6,799,000,000 353,219,133 32
7,055,275,000 358,695,455 33
FERC FORM NO. I (ED. 12-96)Page 257.1
01t29t1993
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]nn originat(2) I_lA Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221 , Bonds,222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Olher 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. Designate
demand notes as such. lnclude in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. 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. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
Class and Series of Obligation, Coupon Rale
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 Pollution Control Obligations - Secured by Pledged First Mortgage Bonds:
2 Poll Ctrl Rev Refunding Bonds, Sweetwater County, VW, Series 1994 21,260,000 510,479
3 Poll Ctrl Rev Refunding Bonds, Converse Counly, WY, Series 1994 8,190,000 209,777
4 Poll Ctrl Rev Refunding Bonds, Emery County, UT, Series 1994 121 ,940,000 3,274,246
5 Poll Ctd Rev Refunding Bonds, Lincoln County, !\l/, Series 1994 15,060,000 422,858
6 Environ. lmprvmnt Rev Bonds, Converse County, WY, Series 1995 5,300,000 132,043
7 Environ. lmprvmnt Rev Bonds, Lincoln County, WY, Series 1995 22,000,000 404,262
I Subtotal Pollution Control Obligations - Secured by Pledged First Mortgage Bonds 193,750,000 4,953,665
I
10 Pollution Control Obligations - Unsecured:
11 Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Series 1988 45,000,000 380,1 98
12 Poll Ctrl Rev Refndng Bonds, City of Gillette, WY, Series 1988 41,200,000 351,905
13 Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Series 1992A 9,335,000 167,524
14 Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 22,485,000 242,163
15 Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Series 19928 6,305,000 151 ,908
16 Environ. lmprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 24,400,000 225,000
17 Subtotal - Pollution Control Obligations - Unsecured 148,725,000 1 ,518,698
18
19 TOTAL ACCOUNT 221 7,641,475,000 82,117,663
20
21 Account 222, Reacquired bonds
22
23 Account 223, Advances from associated companies
24
25 Account 224, Olher long-term debt
26
27
28
29
30
31
32
33 TOTAL 7,641,475,000 82,117,663
FERC FORM NO. 1 (ED. 12-96)Page 256.2
Long-Term Debt Authorized but Unissued
Name of Respondent
PacifiCorp (2')Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20'l8lQ4
LONG-TERM DEBT (Account 221,222,223 and 224) (Continued)
10. ldentify 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, Amorlization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. ln a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. 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 incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, lnterest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Nominal Date
of lssue
(d)
Date of
Maturity
(e)
AMORTIZATION PERIOD uutstanotno(Total amount outstanding without
reduction for amounts held byrespqndent)(n)
lnterest for Year
Amount
(i)
Line
No.Date From
(0
Date To
(s)
,|
11117 11994 11t01t2024 11t1711994 11101t2024 21,260,000 496,056 2
11117 t1994 't'U0112024 11t17t',t994 11t01t2024 8,190,000 151,585 3
't'U17t'.t994 11t01t2024 11t17t1994 1',U01t2024 121 ,940,000 2,744,533 4
11t17t1994 11t01t2024 11t17t1994 11t0112024 15,060,000 294,273 5
11t17t1995 11t01t2025 11t17t1995 11t01t2025 5,300,000 95,772 6
11117t1995 11t01t2025 11t1711995 11t01t2025 22,000,000 426,10',1 7
193,750,000 4,208,320 8
o
10
01/01/1988 0'U01t2018 01 /01 /1 988 01t0112018 11
01/0'1/1988 01t0112018 01/01/'t 988 01t01t2018 12
09t29t1992 12t01t2020 09t291't992 't2t01t2020 9,335,000 174,425 13
09t29t1992 12t01t2020 09t29t1992 12t01t2020 22,485,00C 418,974 14
09t29t1992 12t01t2020 09129t1992 12t01t2020 6,305,00c 118,019 15
12t14t1995 11t01t2025 12114t199s 11t01t2025 24,400,00c 556,584 16
62,525,00C 1,268,002 17
18
19
20
21
22
23
24
25
26
27
28
29
30
3'1
32
7,055,275,000 358,695,455 33
FERC FORTU NO. 1 (ED. 12-96)Page 257.2
7,055,275,000 358,695,455
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2UAA4
FOOTNOTE DATA
1 Line No.: 5 Column: aIny 2018, Pac Corp ssued $600 mi ts 4. l25Z F rst Mortgage Bonds due
Idaho Public Utilities Commission ("IPUC") - Case No. PAC-E-14-05,dated July 29, 201,4, ef f ective through ,June 30 , 2079 .
Order No. 33083,a
Oregon Public Utility Commission (ilOPUCtr)
dated July 22, 20L4.
Docket No. UF-4288, Order No. 74-268,
256.2 Line No.: 19 Column: hRefer to It.em 6 n Important
Form No. 1
Year and Not.e 7 n Notes to FStatements, in this for a discussion of PacifiCorp's fong-term debt
Account represents resf expense to Account 427, Interest on long-term debt and
does not include any amount charged to Account 430, Interest on debt to associated
companies, as all such interest was accrued on amounts included in Account 233, Notespayable to associated companies during the year.
For autho zat on for the suance of long-term debt ($2.0 billion authori-zed; $2.02018), refer to Item 6 in Important Changes Duringbil-1ion available as of December 31,the Year, in this Form No. 1.
Authorization to borrow the proceeds of pollution control revenue refunding bonds issuedby the counties of Emery, Utah; Carbon, Utah; Converse, Wyoming; Lincoln, Wyoming;Sweetwater, Wyoming; and Moffat, Colorado (totaI of $300,345,000 authorized and
$156,450,000 available as of December 31, 2018) and authorization to borrow the proceedsof new pollution control- revenue bonds issued by one or more of the following counties ormunicipalities: Emery, Utah; Converse, Wyoming; Lj-nco1n, Wyoming; Sweetwater, Wyoming;City of Gill-ette, Wyoming; Navajo County, Arizona; and Routt County, Colorado (total of
$150,000,000 authorized and available as of December 31, 2018) is as follows:
IPUC - Case No. PAC-E-08-05, Order No. 30606, dated August 4, 2008.
OPUC - Docket No. UF-4250, Order No. 08-382, dated.fuly 29, 2008.
a
a
256.2 Line No.: 19 Column: i
256.2 Line No.: 27 Column: a
FERC FORM NO.1 1 450.1
.fanuary 2049. State commission authorizations for this issuance were as follows:
Name of Respondent
PacifiCorp
ReDort
Eonr-rA Resubmissiontt
This
(1)
(2')
ls:
Original
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
RECONCILIATION OF REPORTED NET INCOME WTH TAXABLE INCOME FOR FEDERAL INCOME TAXES
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. lnclude in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the lax return for
the year. Submit a reconciliation even though there is no taxable income for the year. lndicate clearly the nature of each reconciling amount.
2. lf the 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
return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated retum. State names of group member, tax
assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a parlicular need of a company, may be used as Long as lhe data is consistent and meets the requirements of the
above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context ofa footnote.
Amount
(b)
Line
No.
Particulars (Details)
(a)
737,709,0001Net lncome for the Year (Page 1 17)
2
3
4 Taxable lncome Not Reported on Books
5
6
7
207,262,370I
I Deductions Recorded on Books Not Deducted for Return
'10
11
12
1,161,583,33713I
14 lncome Recorded on Books Not lncluded in Return
15
'16
17
30,289,89818Other
19 Deductions on Return Not Charged Against Book lncome
20
21
22
23
24
25 973,987,622
-74,644,72226State Tax Deductions
27 1.027.632.465Federal Tax Net lncome
28 Show Computation of Tax
29
215,802,8',1830Federal lncome f ax al 21.00o/o
31 -7,135,278Provision to Return Adjustment
32 Tax Reserve Changes 3,653,988
33 Research and Experimentation Credits -32,500
48,824,84134Renewable Energy Production Tax Credits
2E
36 Federal lncome Tax Accrual
37
38
39
40
41
42
43
44
163,4il,
2-96)Page 261
Cther
Other
f,ther
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
20't8tQ4
FOOTNOTE DATA
261 Line No.:8
Amounts
contribution in Aid of constructionInvestment Gain/Loss - Book - Current
MCf F.O.G. Wire LeaseRegulat.ory Asset - A1! Ratse for Energy Program (CARE) -
Regulatory Asset - REC Sales Deferral - OR
ReguLaeory Asset - WA Colstrip #3
Regulatory Liability - Deferred Excess NPC - OR
Regulatory Liability - Deferred Excess NPC - wA
ReguLatory Liability - Depreciation Decrease - OR
Regulatory Liability - Excess Income Tax Deferral - ID
Regulatory Liability - Excess Income Tax Deferral - ORRegulatory Liability - Excess Income Tax Deferral - UT
Regulatory Liability - Excess fncome Tax Deferral - wA
Regulatory Liability - Excess Income Tax Deferral - wY
Regulatory Liabitity - Excess Income Tax Deferral - cARegulatory Liability - GHG Allordance Revenues - CA
Regulatory Liability - OR Direct Access 5 Year Opt OutRegulatory Liability - wA Accel Depreciation
Reimbursements
Transmission service Deposits
TotaI
CA
$ 107,5s7 ,673
L ,260
612
242,877
T86 , L44
52 , L88
s8,658
46 ,4L209, 098
5,6
4,6
L,2
555, 684
48, 555,250
527,997
8 , so2 ,72r
7 , 002 ,1873,199,939
r,036,410
1,690 ,477L2,6LL,58L
2 , 098 ,861
826 331
207 ,262 , 37 0
1
261 Line No.: 13 Column: a
culars (Details)Anounts@Fed/State Tax Expense - Interest
Meals and Ent.ertainmentAccrued Retention
Accrued Royalties
Accrued SeveranceAccrued Vacation
Avoided Costs
Bear River Settlement Agreement
Book Depreciation
Book Depreciation Allocated to Medicare and M&ECapitalized Labor and Benefit CostsCoal Pile Inventory Adjustmen!
Company Plane - Nonbusiness Use
CTIIP Reserve
Deferred Compensation Mark to Market Gain/Loss - Income StatementDeferred Revenue - CitibankDeferred Revenue - OtherEnvironmental Liability - RegulatedHermiston Swap
Hydro Relicensing ObligationInjuries and Damages Accrual - cash BasisInjuries & Damages Reserve - oRInsurance ReserveInventory Reserve,Joseph SettlementLewis River Sectlement Agreementtobbying Expenses
LT Incentive Plan
LT Incentive Plan Mark to Market Gain/Loss
Medicare SubsidyNon-deductible Fringe Benef itsNon-deductible Legal FeesNon-deductible Parking CostsPenaltiesPrepaid Aircraft Maintenance
Prepaid Membership FeesPrepaid Taxes - rPUcPrepaid Taxes - UPSCPrepaid Water RightsProperty Insurance Reserve - IDProperty Insurance Reserve - ORProperty Insurance Reserve - UT
$3,O35,L23
(2 ,3LO , 07'7 )1,056,315
343 ,4257,7L9,906
L8,322
236 ,928
29 ,86]-,966t,82s
967 ,774,68L
92 ,4364,907,Ls}
324 ,692
9,3s3
L ,280 , 8t2
t , 024 ,390
281, 105
992 , L69
3 ,202 ,927L71,693
L , 329 ,337
7 ,222,3s7
494 ,665
2 ,572 , r84
15 'lO11,447
21 ,845
L ,246 ,3324, 640,301
1, 156, 059
7 ,089 ,521
472 ,628
300, 000
1s0,834
1, 053 , 70r.
60,994
3,879,868
1,1, 555
s,122
3t ,2s0113,544
3 , 634 ,1542,033 ,447349,810Insurance Reserve - wY
FERC FORM NO.1 ED.1 450.1
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
20't8lQ4
FOOTNOTE DATA
Regulatory Asset - Carbon Unrecovered Plant - ID
Regulatory Asset - Carbon Unrecovered Plant - UT
Regulatory Asset - Carbon Unrecovered Plant - wY
Regulatory Asset - Demand side ManagementRegulalory Asset - Depreciation Increase - ID
Regulatory Asset - Deprecj-ation Increase - uT
Regulatory Asset - Depreciation Increase - wYRegulatory Asset - Environmental Costs - wA
Regulatory Asset - FAS 158 Pension Liability
Regulatory Asset - Klamath Hydroelectric Relicensing costs - Irr
Regufatory Asset - Liquidated Damages - uT
Regulatory Asset - Liquidated Damages - wY
Regulatory Asset - Pension MMT - UTRegulatory Asset - Postemployment. CostsRegulatory Asset - Post Merger Loss - Reacguired Debt
Regulatory Asset - Postretirement MMT - CA
Regulatory Asset - Postretirement MMT - OR
Regulatsory Asset - Post.retirement MMT - ur
Regulatory AsseE - Postretirement Settlement Loss
Regulatory Asset - Postretirement Settlement Loss cc - wYRegulatory Asset - Powerdale Decommissioning - ID
Regulatory Asset - Preferred Stock Redemption Loss - uT
Regulatory Asset - Preferred Stock Redemptsion Loss - wA
Regulatory Asset - Preferred Stock Redemption Loss - WY
Regulatory Asset - solar Feed-In Tariff Deferral - oR
Regulatory Asset - Transportation Electrification Program - CA
Regulatory Asset - STEP Pilot Program Balance Accoun! - llfRegulatory Assets - utah Mine Disposition
Regulatory Liability - 50& Bonus Tax Depreciation - wY
Regulatory Liability - ARo/Reg Diff - Trojan - wA PortsionRegulatory Liability - BIue Sky - OR
Regulatory Liability - Blue sky - ID
Regulatory Liability - BIue sky - UTRegulatory Liability - Blue Sky - WARegulatory Liability - Blue Sky - wYRegulatory Liability - clean Fuels Program - oR
Regulatory Liability - Contra-Carbon Decommissioning - wY
Regulatory Liability - OR Energy conservation ChargeRegulatory Liability - Solar Incentsive Program - UT
Regulatory Liability - wA Decoupling Mechanism
TGS BuyoutTrapper Mine Contracts Obligation
Intercompany Adjustment
Total
Part Is
4?8,639
3 ,444 ,64L
1, 158, 188
L9,966,390
4 ,22O , t82
L28 ,043
442 , L9]-
48,290
3 7, 508 , 593
3 ,569 , 6s8
35,000
54,288
1
476 ,5L0
584 ,922
L't ,48?193,034
1
353,07?
22 ,244
25
82
L3
28
03
5',?
46
,986
,529
, 318
4,2
442
337
600
567
990
331
936
292
2
4
18,035,
604,
a
425,
45,363
1,459 ,5481L4,994
34 ,23L
48?,500
335,226
603 ,2s5
4, L05,8842,067,L09
l5 ,473
258,3r-0
3,095,40r.
-@
261 Line No.: 18 Column: a
Book Fixed Asset Gain/Loss
Deferred Revenue - Lease Incentives
Dividend Received Deduclion - Deferred CompensationInvestment Gain/Loss - Taxofficer's Life Insurancenegulatory Asset - BPA Balancing Account - oRRegulatory Asset - REC Sales Deferral - (If
Regulatory Asset - REc sales Deferral - wA
Regulatory Asset - REC Sales Deferral - wYRegulatory Liability - BPA Balancing Account - ID
Regulatory Liability - BPA Balancing Account - wA
Regulatsory Liabilitsy - tI[ Home Energy Lifeline
Regulatory Liabitity - wA Low Income ProgramTrapper Mining stock Basis
Unearned ,]oint Use Pole Contract RevenueEquity Earnings in Subsidiaries
Total
$ (9ss,309)
(s38,993)
(194,310)
(2,313)(2,962,869)
(982,6391
(9ss,055)
( 14 ,843 )(317.085)
(220,266)-
(173,130)
(67,859)
(874 ,0s4\(1,113,723)
(47 ,460')(20 , 869 , 97 It
$ (30,289,898)
FERC FORM NO.1 (ED. 12.871 Page 450.2
Name of Respondent
PacifiCorp
This Report is:
(1) XAn OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
261 Line No.:25 Column: a
Part (Det.aiIs)Amounts
Accrued BonusAccrued Final ReclamationAmortization NOPAS 99-00 RARBasis htangible oifferenceCapitalized Depreciat ionCholla SHL NOPA (Lease Amortization)
Contra Receivable from .foint Owners
Cost of Removal
DEbt AEIJDCDeferred Compensation
Deseret Sett.lement ReceivableEnvironmental Liability - Non-regulatedEguity AFUDC - Temp
FAS 112 Book Reserve - Postemplo)rment Benefits
FAS 158 Pension Liability
FAS 158 Postretirement Liability
FAS 158 SERP LiabilityFederal Tax DepreciationFederal Tax Fixed Asset Gain/LossFuel Cost Adjustment
Income Tax InEerestMiscellaneous current and Accrued Liability
N Umpqua Settlement Agreement
Non-deductible Postretirement costs
oregon Regulatory Asset/Regulatory Liability consolidation
Pension/Retirement AccrualPre-1943 Preferred Stock Dividend - Deduction
Prepaid Taxes - OPUCPrepaid Taxes - Property Taxes
Regulatory Asset - Asset Sales Balancing Account - ORRegulatory Asset - CA Mobile Home Park ConversionRegulatory Asset - catastrophic Event Deferral - cARegulatory Asset - Contra Pension MMT & CTG - CA
Regulatory Asset - Contsra Pension MMT & CTG - ORRegulatory Asset - Contra Regulatory Asset - Pension Plan CTGRegulatory Asset - Deferred Excess NPc - cA
Regulatory Asset - Deferred Excess NPc - IDRegulatory Asset - Deferred Excess NPC - UT
Regulatory Asset - Deferred Excess NPC - wY '09 & After
Regulatory Asset - Deferred hdependent Evaluator Fee - tffRegulatory Asset - Deferred Intervenor Funding Grants - cARegulatory Asset - Deferred Interwenor Funding Grants - ID
Regulatory Asset - Deferred Intervenor Funding Grants - ORRegulatory Asset - Deferred overburden costs - IDRegulatory Asset - Deferred overburden costs - wY
Regulatory Asset - Environmental Costs
Regulatory Asset - FAS 158 Postretirement LiabilityRegulatory Asset - OR Transportatsion Electrification Program
Regulatory Asset - Protocol - MSP Deferral - ID
Regulatory Asset - Protocol - MSP Deferral - UTRegulalory Asset - Protocol - MSP Deferral - wY
Regulatsory Asset - Solar Incentive Program - UT
Regulatory Assets - (II Subscriber Solar ProgramRegulatory Asset - Postretirement Settlement Loss CC - U:IRegul,atory Liability - Blue sky - CA
Regulatsory Liability - Deferred Excess NPC - UT
Regulat.ory Liability - Deferred Excess NPC - wY
Regulatory Liability - Energy Savings Assistance - CARegulatory Liabitity - solar Feed-in Tariff Deferral - cA
Repairs Deduction
Reserve for Bad Debts
Rogue River - Habitat Enhancement Liability
Tax Depletion - SRC
Troj an Decommissioningwasatch workers Compensation Reserve
Western Coal Carrier Retiree Medical Accrual
TotaI
((80,070)
(24O,352)
(48,816)
(L94 ,94'7)(5,977,Ls7].
(318,53s)
(103,734)
(40,800,230)
(18,379,196)
(802,480)
(L25 ,298].(19,631)
(34 ,7 08 , 432].
(1 ,373 , 022].(3r,277,5L2)
,3s2 , Ol0')
,418 ,659)
, ss9 ,697)
,887 ,46L)
,845 ,93L)
,513,017)(959 ,49L)(584 ,97L)
,089 ,52L)(L921
(8
(1
(s62
(2
(1
(7
(155,077)
(r.07,935)
(4t,920)
(L97 ,415].(76L ,496)
( 124,888)(2,179,4LL)
( 90, 033 )(1,007,506)
(1,640,983)
(2, s06, 0s6)
(8 , 692 ,289)(22 ,812 ,564)(5,5L2,7721
(139,555)
(97 6l(40,000)
( 3 91,443 )(L39,27:-I
(391,879)
13 ,821-,579)(6,t4s,999\
(48,792],
(150,000)
(4,400,000)
(1,600,000)
(4,246,5671-
(LL2,324\
(291,300)
(6s, s38)
, 999,381)
, 899, 057)
( 111, s82 )(464,L95\
,]-79,370)
,LL1,994r,(73 ,640],
(32 ,4531(36,774t
(193,945)
(102,000)
(7
( 161
l)
$ ( 973, 98'7 ,6221
FERC FORM NO.I (ED. 12471 Page 450.3
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
261 Line No.: 36 Column: b
Inc udes f ts ted States Federal rncome Tax Returnprovision for income taxes has been computed on a stand-a1one basis.
Names of group members who will file a consolidated United states Federal Income Tax Return:
Under Berkshire Hathaway Energy Company (.BEE,) 3
PPW Holdings LLC Sub-Group:
Pacificorp
PPW Holdings LLC
Pacificorp Sub-Group:
Energy west Mining Companyclenrock CoaI CompanyInterwest Mining CompanyPacific Minerals, Inc.
ficorp' s
BEE Sub-Group3
ABA Ho1ding. LLc
ABA Management, L.L.C.
A1amo 5 Solar Holdings, LLC
Alamo 5, LLCAlaska cas Transmission Company, LLCAl1ie Beth Allman ReaI Estate, Ltd
Ambassador Real Estate CompanyAnbassador Real Estate-Linco1n, LLCApex Home Maint.enance, LLC
ARE Commercial Real Estate, LLC
ARE IOWA, LLCArizona Homeservices, LLCAttorneys Ti!1e Ho1dings, IncorporatedBerkshire Eathaway Energy Company
BG Energy Holding Company LLC
BH2H Holdings, LLC
BHE AC Holding, LLC
BHE America Transco, LLC
BHE Canada LLC
BHE Community Solar, LLC
BHE Gas, Inc,
BHE Geothermal, LLC
BHE Hydro, LLC
BHE Midcontinent Transmission Holdings LLC
BHE Pearl So1ar Holdings, LLC
BHE Pear1 Solar, LLC
BHE Renewables, LLC
BHE SOIAT, LLC
BHE Southvrest Transmission Holdings LLC
BHE Texas Transco, LLC
BHE U.K. ELect.ric, Inc.
BHE U.K. INC.
BHE U.K. Power, Inc.
BHE U.S. Transmission, LLC
BHE Wind, LLC
BHER Power Resources, Inc.
BHER Santa Rita Holdings, LLC
BHER Santa Rita Investment, LLC
BHER Santa Rita Tax, Inc.
BHES CSG Holdings, LLC
BHES Pearl Solar Ho1dings, LLC
BHH KC ReaI Estate, LLCBig Spring Pipeline Company
Bishop Hill Energy II, LLCBishop Hill II Holdings, LIJC
CalEnergy Company, Inc.
CalEnergy Generation Operating CompanyCalEnergy Inlernational Services, Inc.
CalEnergy !4inerals LLC
CalEnergy Operating CorporationCalEnergy Pacific Holdings CorpCalifornia Energy Development CorporationCalifornia Energy Management Company
Cal,ifornia Energy Yuma corporaEionCalifornia Utility Holdco, LLCCapitol Title company
CBSHome Real Estsate Company
CBSHome ReaI Estat.e of Iowa, Inc.
CE Black Rock Holdings LtC
CE Butte Energy Holdings LLc
CE Butte Energy LLC
CE Electric (NY), Inc.
CE Gen Oi1 Company
CE Gen Pipeline Corporation
CE Gen Pohrer Corporation
CE Generation LLC
CE Geothermal, Inc.
CE International Investments, Inc.
CE Leathers Company
cE obsidian Energy LLC
cE obsidian Holding LLc
CE Red Island Energy Holdings LLC
CE Red Island Energy LLC
CE Salton Sea Inc.
CE Texas Energy, LLC
CE Texas FueI LLC
CE Texas Pipeline LLC
CE Texas Power LLC
CE Texas Resources IJIJC
CE Turbo LLC
Champion Realty, Inc.
Chancellor Title Services, Inc.Columbia TitIe of Florida, Inc.
Commonsite, Inc.
Conejo Energy Companycordova Energy company, LLc
CTHM, L.L.C.
CTRE, L.L.C.
Dakota Dunes DeveLopment Company
DCCO, hc.Del Ranch company
Denver Rental, LLCDesert Valley Company
DG-SB Project Holdings, LLC
Ebby Alumni croup, Inc.
Ebby Halliday Properties, Inc.
Ebby Halliday ReaI Estate, rnc.Edina Financial Serwices, Inc.
Edina Realty Insurance, LLCEdina Realty Referral Network, IncEdina Realty Title, Inc.
Edina Rea1ty, Inc.
Elmore companyEsslinger-wooten-Maxwel1, Inc.
E-W-M Referral Services, Inc.
F&R/T LLc
FERC FORM NO.1 (ED. 12.871 Page 450.4
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
lYear/Period of Report
II 2018/Q4
FOOTNOTE DATA
Falcon Power Operating CompanyFFR, Inc.First Network Realty, Inc.First Realty Group, rnc.First Realty, LtdFirst Reserve Insurance, Inc.First weber Illinois, LLCFirst weber, Inc.Florida Netvrork LLCFlorida Network Property Management, LLc
For Rent, Inc.Fort Dearborn Land Title Company, LLC
FRTC, LLC
Geronimo Community Solar Gardens Holding Company, LLC
Geronimo Community Solar Gardens, LLCGibralt.ar TitIe Services, LLC
GPWH Holdings, LLC
Grande Prairie Land nolding, LLC
Grande Prairie wind Holdings, LLC
Grande Prairie wind II, LLC
Grande Prairie wind, LLc
Greystone Partners of virginia, LLC
Guarantee Appraisal CorporationGuarantee Real Estate
HMSV Financial Services, Inc.
HN Real Estate Group N.C., Inc.
HN Real Estate Group, LLC
HN Referral- Corporation
Home Service Connections, LLC
Homeservices Insurance Agency, LLC
Homeservices Insurance, Inc.
Homeservices Lending, LLC
Homeservices MidAtlantic, LLC
Homeservices Northeast, LLC
Homeservices of Alabama, Inc.
Homeservices of America, Inc.Homeservices of California, Inc.
Homeservices of Colorado, LLC
Homeservices of Connecticuts, LLCHomeservices of Florida, Inc.
Homeservices of ceorgia, LLC
Homeservices of IIlinois Holdings, LLC
Homeservices of Illinois, LLC
Homeservices of lorra, Inc.
Homeservices of Kentucky ReaI Estate Academy, LLC
Homeservices of Kentucky, hc.
Homeservices of Minnesotsa, LLC
Homeservices of MOKAN, LLC
Homeservices of Nebraska, Inc.Homeservices of New ,fersey, LLC
Homeservices of Ner^, York, LLC
Homeservices of Oregon, LLCHomeservices of Texas, LLC
Homeservices of the Carolinas, Inc.
Homeservices of washington, LLC
Homeservices of wisconsin, LLCHomeservices Referral Network, LLCHomeservices Relocation, LLC
Houlihan/Lawrence Inc.
HS Franchise Holding, LLC
HSF Affiliates LLC
HSGA ReaI Estate Group, L.L.C.
HSN Holding, LLC
HSTX TitlE, LLC
HSw Affiliates Holding, LLCHuff Commercial croup, LLC
Huff -Drees Realty, Inc.
IES Holding II LLC
IMO Company, Inc.Imperial Magma LLCIntero Franchise Services, Inc.Intero ReaI Estate Holdings, Inc.
Intero ReaI Estate Services, Inc.Intero Referral services, Inc.
Iowa Realty Company, Inc.
Iowa Realty fnsurance Agency, Inc.
Iowa Title Company
JBRC, InC.
.Iim Huff Realtsy, Inc.
,TRHBW Realty, Itrc. d/b/a Realtysouth
.fumbo Road Holdings, LLC
Kansas City Tit1e, Inc.
Kanstar Transmission, LLCKentucky ResidenEial Referral Service, LLC
Kentwood City Properties, LLC
Kentwood Commercial, LLC
Kentwood DTC, LLC
Kentwood ReaI Estate Services, LLC
Kentwood, tLCKern River Gas Transmission Company
Keystone Parlners, LLC
KR Hol,ding. LLCL&F/Fonvi1Ie Morisey Real Estate, LLCL&F/Fonvi1le Morisey TitIe, LLC
Lands of sierra, Inc.Larabee School of Real Estate, Inc.
LFFS, Inc.
Long & Foster Closing Services, LLC
Long & Foster Institutse of Real Estate, Inc.
Long & Foster Insurance Agency, Inc.
Long & Foster Licensing Company, Inc.tong & Foster Mortgage Ventures, Inc.Long & Foster ReaI EsEate Ventures, Inc.tong & Foster Real Estate, Inc.
Long & Foster Settlement services, LLctovejoy Realty Inc.tovejoy Referral Network, LLC
M & M Ranch acquisition Conpany LLC
M & M Ranch Holding Company LLC
Magma Land Company I
Magma Power CompanyMarshall wind Energy HoLdings, LLCMarshall wind Energy, LLc
MEc Construction Services Company
MEHC hvestment, Inc.
MEHC Merger Sub Inc.Mer1in Realty Technologies, LLC
MES Holding, LLCMetro Referral Associates, Inc.
MHC Investment Company
MHC, Inc.Mid-America Referral Network, Inc.
MidAmerican Central California Transco LLC
MidAmerican Energy CompanyMidAmerican Energy Machining Services LLC
MidAmerican Energy Services, LLC
MidAmerican Funding, LLC
MidAmerican Geothermal Development CorpMidAmerican wind Tax EquiEy tloldings, LLCMidland Escrow services, Inc.Mid-States Title hsurance Agency, Inc.
Midwest Capital Group, Inc.Midwest Power Midcontinent Transmission Development, LLCMidwest Power Transmission Arkansas LLC
Midwest Power Transmission Iowa LLC
Midwest Power Transmission Kansas, LLCMidwest Power Transmission Oklahoma, LLC
Midwest Power Transmission Texas, LLC
Midxrest Preferred Realty, Inc.Midwest Realty ventures, LLc
MPT Heartland Development, LLC
MTL Canyon Holdings LLC
Nebraska Land Title & rqbstract Company
Nebraska Referral, Inc.
FERC FORM NO.1 (ED. 12471 Page 450.5
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tO4
FOOTNOTE DATA
Nevada Power Company d/b/a NV Energy IncNiguel Energy Company
NNGC Acquisition LLC
Norcon Holdings, Inc.
Northeast Referral Group, LLCNorthern Consolidated Power, Inc.Northern NaturaL Gas Company
NRS Referral Services, LLc
NV Energ"y, Inc.
NVE Holdings, LLC
NVE Insurance Co, Inc.
NW Referral Services, LLCO.E. Merger Sub II, LLCo.E. Merger Sub III, LLC
O.E. Merger Sub Inc.
PCG Agencies, Inc.
PCRE, L.L.C.Pickford Escroh' Company, Inc.Pickford Holdings, LLcPickford ReaI Estate, Inc.Pickford Services Company, Inc.Pilot Butte, LLcPinyon Pines Funding, LLCPinyon Pines I Holding Company, LLC
Pinyon Pines II Holding Company, LLCPinyon Pines Projects Holding, LLCPinyon Pines wind I, LLC
Pinyon Pines wind II, LLC
PNW Referral, LLCPreferred Carolinas Realty, Inc.Preferred Carolinas Title Agency, LLCPremier Service Abstract., LLCPriority Title CorporationProfessional Referral Organization, Inc.Pru-One, Inc.
Quad Cities Energy CompanyReal Estate ,(nowledge Services, L.L.C.Real EsEate Links, LLC
Real Estate Referral Network, Inc.
Reece & Nichols Alliance, Inc.
Reece & Nichols Insurance, LLC
Reece & Nichols Realtors, Inc.Reece Commercial, Inc.Referral Associates of ceorgia, LLCReferral Network of cloria NiIson, LLCReferral Network of IL LLCReferral Network of NY/N,r, LLCRelocation Advantage Partners, LLC
RGS Settlements of Pemsylvania, LLC
RGS Title of Baltimore, LLC
RGS Titl,e, LLC
RHL Referral Company, LLC
121 Acquisition co., LLC
21 SPC, Inc.21st Communities, Inc.2Lst Mortgage Corporation
2K Poll.mer Systems, Inc.Jwlre GrOUp InC.A.E, Company, Inc.
AAA Aircraft Supply
Accra Manufacturing Inc.Accurate Installations, Inc.
Acme Brick Company
Acme Building Brands, hc.
Acme Management Company
Acme Ochs Brick and Stone, Inc
With respect to members of the BHE Sub-Group, BHE requires alI subsidiaries to pay or receive from BHE an amountof tax based primarily on the stand-aIone method of allocation. The computation includes aI1 tax benefits fromtax deductions from costs borne by utility customers.
Berkshire Hatshaway Inc. Srr.b-croup:
Roberts Brothers, Inc.
Roy H. Long Realty Company, Inc.
S.W. Hydro, hc.
Sage Title Group, LLcsalton sea Brine Processing company
saltson sea Funding corporationSalton Sea Minerals CorporationSalton Sea Power CompanySa1lon Sea Power Generation company
Sa1tson Sea Power LLC
Salton Sea Royalty Company
San Felipe Energy Companysanta Rita wind Energy LLc
Saranac Energy Company, Inc.
SCS Realt.y Investment Group, LLC
SECI Eoldings, Inc.Settlement Professionals, tLCsierra cas Holding companySierra Pacific Power Company d/b/a NV Energy IncSilvermine Ventures LLCsolar san Antonio LLcSolar Star 3, LLCSolar Star 4, LLCsolar Star California xlx, LLCsolar star california xx, LLcSolar St.ar Funding, LLCSolar Star Projects Holdings, LLC
Southrres! Relocation, LLC
SSC XIX, LLCssc xx, LLc
The Escrow Firm
The Kentwood Company at Cherry Creek, LLC
The Long & Fostser Companies, Inc.
The Referral CompanyThoroughbred Titl,e Services, LLC
TIAC LLCTitlesouth, LLC
TLTC LLC
Topaz Solar Farms, LLC
TPZ Holding, LLC
TRMC LLC
Two Rivers, Inc.Tx .rumbo Road wind, LLC
VPC Geothermal LLCvulcan Power Company
Vulcan/BN Geothermal Power CompanyWailuku Holding company LLcwailuku Investment LLC
Wailuku River Hydroelectric Power Co, Inc.walker,rackson Mortgage CorporationWalnut Ridge Wind, LLC
weathervane Referral Nelwork, Inc.
Acme Services Company, LLCAdalet/scott Fetzer company
AEG Processing Center No. 35, Inc.
AEG Processing Center No. 58, Inc.Aerocraft Heat Treating co., Inc.
Aerospace Dlmamics International IncAffiliated Agency Operations Co.Affordable Housing Partners, Inc.
AIPCF V CHI Blocker, Inc.
AJF warehouse Distributors, Inc.Al,bacor Shipping (USA) Inc.Albecca, Inc.Alexander Road Insurance Agency, Inc
Alpha Cargo Motor Express, Inc.
FERC FORM NO.1 (ED. 12-871 Page 450.6
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Alu-Forge, Inc.
Ambucor HealEh Solutions, hc.American All Risk Insurance services, Inc.
American Commercial Claims Administsrators Inc.
American Dairy Queen corporationAmerican Employers croup, Inc.
AmGUARD Insurance CompanyAndrews Laser works CorporationAngelo Po America, fnc.Applied croup rnsurance Holdings, Inc.Applied hvestigations Inc.Applied Logistics, Inc.Applied Premium Finance, Inc.Applied Processing Center No. 50, Inc.Applied Risk Services of New York. Inc.Applied Risk Services, Inc.Applied Underwriters Captive Risk Assurance Co., Inc.Applied Underwriters, fnc.Arcturus Manufacturing CorporationArtform InternationaL hc.
Atslanta International Insurance CompanyAtlantic Precision, Inc.
AU Captive Risk Assurance Co.
AU Holding Company, hc.Avibank Manufacturing Inc.
AZGUARD Insurance Company
Bayport Systems, Inc.
BDT I-A Plum Corp,
Ben Bridge ,feweler, Inc.
Benjamin Moore & Co.Benson Industries, Inc.Benson, Ltd.Berkshire Hatharray Assurance corporationBerkshire Halhaway Automotive Inc.Berkshire Hathaway credit CorporationBerkshire Hathaway Directs Insurance CompanyBerkshire Hathaway Finance CorporationBerkshire Hathaway clobal Insurance Services, LLCBerkshire Hathaway Homeslate Insurance CompanyBerkshire Hathaway Life hsurance Company of Nebraska
Berkshire Hathah,ay Specialty Concierge, LLCBerkshire Hathahray Specialty Insurance companyBerkshire Indemnity Group Inc,
BH Columbia Inc.
BH Credit LLC
lJH I, l,nance , J,nc .
BH Holding LLC
BH Media Group, Inc.
BH Shoe Holdings, Inc.
BHA Minority Interest Holdco, Inc,
BHG Life Insurance Company
BHG Structured Settlements, Inc.
BHSF, Inc.
biBERK fnsurance Services, Inc.BIue Chip Stamps, Inc.
Btt Leasing Corporation
BNSF Communications, Inc.
BNSF Logistics hternational, rnc.
BNSF Logistics Ocean IJine, Inc.
BNSF Logistics, LLC
BNSF Railway Company
BNSF Railway International Services, Inc.
BNSF Spectrum, Inc.
Boat America CorporationBoat Owners Association of the United StatesBoat/u.s, Inc.
Borsheim Jerrelry company, Inc.
BR Agency, Inc.Brainy Toys, Inc.Brilliant National Services, Inc.Brit.tain Machine Inc.Brooks Sports, hc.
Brookwood Insurance CompanyBuilderMT, hc.Burlington Northern Railroad Holdings, Inc.Burlington Northern Santa Fe, LLCBusiness Wire, Inc.C F1ow, Inc.
Caledonian Alloys Inc.California Insurance Conpany
Camp Manufacturing Company
Cannon Equipment LLC
Cannon -Muskegon Corporat ion
Carefree/Scotst Fetzer companyCarlton Forge worksCavalier Homes, Inc.ccc Lonestar LLcCencral States hdemnity Co. of OmahaCentral States of Omaha Companies, Inc.Charter Brokerage Holdings Corp,Chemtool Incorporated
C.]E II
Claims Services, Inc.
Clayton Commercial Buildings, Inc.Clayton Education Corp.
Clayton Homes, Inc.
Clayton Properties Group II, Inc.Clayton Properties Group, Inc.Clayton, Inc.
CMH Capital, rnc.
CMH Hodgenville, Inc.
CMH Homes, Inc.
cMH Manufacturing west, Inc.
cMH Manufacturing, Inc.
CMH of KY, Inc.
CMH Services, Inc.
CMH SeE. and Finish, Inc.
CMH Transport, Inc.Coil Master Corporation
columbia Insurance company
Combined Claims Services, Inc.
Commercial Casually Insurance CompanyCommercial General Indemnity, Inc.
Compass Aerospace Northwest Inc.
Complementary Coatings Corporation
Composites Horizons LLC
Consumer Value Products, Inc.Continental Divide Insurance Companycontinental Indemnity companyCornelius Inc.Cornelius Renew, Inc.Cort Business Services Corporation
Coverage Dynamics Group, Inc.Criterion Insurance Agency
Crovrd supply, Inc.
CSI Life Insurance Company
CTB Credit Corp
CTB Inc.
CTB Internat.ional Corp
CTB IW INC.
CTB Midwest Inc.
CTB MN Investments
cTB Technology Holding Inc.
CTMS North America, Inc.cubic Designs, Inc.
Cumberland Asset Management, Inc.
Cypress Insurance CompanyD.I. Properties Inc.Dairy Queen Corporate Stores, Inc.Davita, Inc.DcI Marketing Inc.Denver Brick Company
Designed Metal Connections, Inc.
Dickson Testing co., Inc.
FERC FORM NO.1 (ED. 12-871 Page 450.7
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Display Technologies LLC
DIY Technologies, hc.
DL Trading Holdings I. Inc.
D0 Funding Corporation
DQF, hc.
DQGC, Inc.
DragonF1y Aeronautics LLC
DTTF., Inc.DuraceLl Distributing Inc.Duracell Industrial Operations, Inc.Duracell Manufacturing Co.Duracell U.S. Operations Inc.
EaStGUARD Insurance CompanyEco Color Company
Ecodyne CorporationEllis & Watts G1oba1 Industries, Inc.
Elm Street CorporationEmpire Distributors of Colorado, rnc.
Empire Distributors of North Carolina, Inc.
Empire Distributors of Tennessee, Inc.
Empire Distributors, Inc.
Environment One Corporation
Exact.a Aerospace Inc,
Executive .fet Management, Inc.Exsif worldwide, hc.ExtruMed, Inc.Fatigue Technology Inc.Financial Services PIus, Inc.Finial Holdings, Inc.Finial Reinsurance CompanyFirst Berkshire HaEhaway Life hsurance CompanyFlightsafety Capital Corp.Flightsafety Development Corp.Flightsafety International Inc.FIightsafet.y International Middle Easts rnc.Flightsafety New York, Inc.Flightsafety Properties, Inc.Flightsafety Services CorporationFloors, Inc.
Focused Technology Solutions, Inc.Fontaine Commercial Trailer, Inc.
Fontaine Engineered Products, Inc.F'ontaine Fifth Wheel CompanyFontaine Modif ication CompanyFontaine Spray Suppression CompanyFontaine Trailer Company LLCForest River Holdings, Inc.Forest River Manufacturing LLCForest River, Inc.
Freedom warehouse Corp.Fruit of the Loom Direct, Inc.Fruit. of the Loom Trading CompanyFruit of the Loom, Inc.Fruit of the Loom, Inc. (sub)
FTI Manufaccuring Inc,
FTL Regional Sales Co., Inc.
Garan Cenlral America Corp.
Garan Incorporated
caran Manufacturing Corp.
Garan Services Corp
GaEeway Underhrriters Agency, Inc.
GE]CO Advantage Insurance Company
GEICO Casualty Co.
GEICO Choice Insurance Company
GEICO Corporation
GEICO General Insurance Co.
GEICO hdemnity Co.
GEICO hsurance Agency
GEICO Marine Insurance Company
GEICO Products, Inc.
GEICO Secure Insurance Company
Gen Re Intermediaries corporation
General Re corporationGeneral Re Financial Products CorporationGeneral Re Life corporation
General Reinsurance corporationGeneral star Indemnity company
General Star Management Company
General Star National Insurance Companycenesis Insurance company
Genesis ManagemenE and Insurance services corp
Government Employees Financial Corp.
Governmen! Employees Insurance Co.
cRD Holdings corporationGreenville Metals Inc.
GUARDCo, Inc.H.H. Brown Shoe Company, Inc.
H. J. ,Justin & Sons, Inc.
Hackney Ladish Inc.Halex/Scott, Fetzer CompanyHamilton Aviation Inc.
Hawthorn Life International, Ltd.HeatPipe Technology, Inc.
Helicomb International Inc.Helzberg's Diamond Shops, Inc.
Henley Holdings, LIJC
HG-Power Plant, Inc.
Hohmann & Barnard, Inc.
Home Trust CompanyHomefirst Agency, hc.
Homemakers Plaza, Inc.
Howell Penncraft, Inc.
HUM Marketing Group, Inc.Huntington Alloys corporationIdealife Insurance CompanyIllinois Insurance Companyhgersoll Cutting TooI CompanyInnovative Building Products, Inc.Innovative coatings Technology corporationInterco Tobacco Retailers, Inc.International Dairy Queen, Inc.rnternational Insurance Underwriters, rnc.Intrepid \TSB, Inc.
Ironwood Plastics Inc.fscar Metals Inc.ITTI Group USA Holdings, Inc.ITTI Investment Holdings, Inc.
.I&L Mining Company
,J. L. Fiber Services Inc.
.fohns Manville China, Ltd.
,Johns Manville Corporation
,Johns ManviLIe, Inc..fordan's Furniture, Inc.Justin Brands, Inc,
Kahn Ventures, Inc.Karmelkorn Shoppes, Inc.
Ken's Spray Equipment, Inc.Kinexo, Inc.
KITCO Fiber Optics, Inc.Klune Holdings rnc.
Klune Industries Inc,
Kova Solutions, Inc.L.A. Terminals, Inc.
Leachcarner, Inc.
Lipotsec uSA, Inc.LiquidPower Specialty Products, Inc.
L.f Aero Holdings Tnc.LJ Synch l{oldings Inc.
LMG Vent.ures, LLC
Lockwood St.reet Urban Renewal Corporation
Los Angeles ,Junction Railway company
LSP Holding, Inc.LSPI Holdings Inc.Lubricant Investments, Inc.
FERC FORM NO.1 (ED. 12.871 Page 450.8
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Lubrizol Advanced Materials China, Inc.Lubrizol Advanced Materials Holding CorporationLubrizol Advanced Materials, Inc.tubrizol G1oba1 Management, Inc.Lubrizol Int.er-Americas CorporationLubrizol International Management corporatsionLubrizol Oilfie1d Solutions, Inc.Lubrizol Overseas Trading Corporation
M&C Producls, Inc.
M&M Manufacturing, Inc.Mapletree Transportation, Inc.Marathon Suspension Systems, Inc.
Marmon Beverage Technologies, Inc.
Marmon Crane Services, Inc.
Marmon Distribution services, Inc.
Marmon Energy Services Company
Marmon Engineered Components Company
Marmon Foodservice Technologies LLC
Marmon Holdings, Inc.
Marmon Retail a uighway Technologies Co. LLC
Marmon Retail ProducEs, Inc.
Marmon Retail Store Equipment LLC
Marmon Retail Technologies Company
Marmon rubing, Fittings & wire Products, Inc.
Marmon Water, Inc.
Marmon Wire & Cable, Inc.Marmon-Herrington CompanyMarquis .Tet Holdings, Inc.Marquis \Tet Partners, Inc.
MaryIand Vent.ures, Inc.Mccarty-Hu11 Cigar Company, Inc.
McLane Beverage DisEribution, Inc.
McLane Beverage Holding, Inc.Mclane Company, hc.
McLane Eastern, Inc.
McIJane Express, Inc.Mclane Foods, Inc.
McLane Foodservice Distribution, Inc.
McIJane Foodservice, Inc.
McLane Mid-Atlantic, Inc.
McLane Midwest, Inc.
McLane Minnesota, Inc.
Mclane Netvrork Solutions, Inc.Mclane Ne!, \fersey, Inc.
McLane ohio, rnc.
Mclane Southern, Inc,Mclane Suneast, Inc.
McLane Tri-St.ates, Inc.
McLane Western, Inc.Mcwilliams Forge CompanyMedical Protective Finance Corporation
MedPro Group, Inc.MedPro Risk Retention Services, Inc.Merit. Distribution Services, Inc.Metalac Fasteners Inc.
Melm LLC
MFS Fleet, Inc.Midwest Northrdest Properties, Inc.Mi11er-Sage, Inc .Mindware CorporationMiTek Holdings, Inc.MiTek Industries, Inc.
MiTek USA, Inc.
MLMIC Insurance Company
MLMIC Services, Inc.
Montana Retail Properties, Inc.
Morgantown-Naliona1 Supply, Inc.Mount Vernon Fire Insurance Company
Mount Vernon Specialty Insurance Company
Mouser Electronics. InC.
Mouser JV 1, Inc.
MPP Co., Inc.
l.{PP PipeLine Corporation
MS Properly Company
l,lw WholesaIe, Inc .National Fire & Marine Insurance CompanyNational Indemnity CompanyNational hdemnity Company of Mid-AmericaNational Indemnity company of the southNaliona1 Liability & Fire Insurance CompanyNationwide Uniforms
Nebraska Furniture Marts, Inc.Net\Tets Aviation, Inc.
Net,Jets Europe Holdings, LLCNetJets Inc-
Net,Jets International, Inc.NetJets Sales, Inc.
NetlTets Services, Inc.
Net,Jets U,S., Inc.
New England Asset Management, Inc.
NFIrl of Kansas, Inc.
NFld Serwices, LLC
N.IE Holdings, LLCNJI Sa1es, Inc.
Noranco Manufacturins (USA) Ltd.
NoTGUARD Insurance CompanyNorth American Casualty Co.Northern States Agency. Inc.
Noveon Hilton Davis, Inc.
NSS Technologies Inc.
Oak River Insurance Company
O1d United Casualty Company
Orange .7u1ius Of AmericaOriental Trading Company, Inc,
OTC Brands, Inc.
OTC Direct, Inc.
OTC worldwide Holdings, Inc.Particle Sciences, Inc.
PCC Flow Technologies Holdings Inc.
PCC FIow Technologies Inc.
PCC RolLmet Inc.
PCC Structurals Inc.
Penn Coal Land, Inc.
Pennsylvania Insurance CompanyPerfection Hy-Test Company
Permaswage Holdings, Inc.Pine Canyon Land Company
Plasma Coating CorporationPlaza Financial Services Co,Plaza Resources Co.
PLICO
PLICO Financial, Inc.Polysols Holdings, Inc,Polysols Textile Solutions, Inc.Precision Brand Products, Inc.Precision Castparts CorpPrecision Founders Inc.Precision Steel warehouse - CharlottePrecision Steel Warehouse, Inc.Press Forge Company
Primus International Holding CompanyPrimus International Inc.Princeton Advertising & Marketing croup, IncPrinceton Insurance CompanyPrinceton Risk Prot.ection, Inc.Priority One Financial Services, Inc.
PRISM Holdings LLC
PRISM Plastics, Inc.Pro Inst.allations, Inc.
Procrane Holdings, Inc.Progressive Incorporated
Promesa Health, Inc.Protective Coating Inc.
QS Partners LLC
FERC FORM NO. r (ED. 12-871 Page 450.9
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
R.C. willey Home Furnishings
Radnor specialty Insurance companyRaiLserve, Inc.Railsplitter Holdings Corporation
Rathcibson Holding Co LLC
RCP Investment, Inc.
Redxrood Fire and Casualty Insurance Company
RENTCO Trailer CorporationResolute Management Inc.
RFMW, LTd.Richline Group, Inc.
Ringwalt & Liesche Co.Rio Grande, Inc.
Roxe11 UsA, Inc.
Rush Air Inc.sager Electrical supply co. rnc.
Sales Simplicity Software, Inc.
Sanla Fe Pacific Insurance Companysanta Fe Pacific Pipeline Holdings, Inc.
Santa Fe Pacific PipeJ.ines, Inc.santa Fe Pacific Railroad companyschi1l Loans, Inc.Schulz Investment Corporation
Schulz U,S.A. Inc.Scott Fetzer Financial Group, Inc.scottcare corporationsee's candies, Inc.
See,s Candy Shops, IncorporatedSerpentec, Inc.
seventeenth street Realty, Inc.
SFEG Corp.
Shaw Contrac! Flooring Services, Inc.
Shaw Diversified Services, Inc.
Shaw Floors, Inc.
Shaw Funding Company
Shav, Industries croup, Inc.
shaw Industries, rnc.
Shaw International Services, Inc.
Shae, Retail- Properties, Inc.
shah, Sports Turf California, rnc.
shaw Transport, Inc.Shultz Steel Company
SHx Flooring, Inc.
SidePlate systems, Inc.
Smilemakers Canada Inc.
smilemakers, Inc.
SN Management, Inc.
snappy ADP, Inc.
Soco west, Inc.
Sonnax Transmission Company
SOS Metals San Diego, LLCsos MeEal"s, Inc.
Southern Energy Homes, Inc.
Southvrest United Industries Inc,Special Metals CorporationSpecialized Pipe Services, Inc,spectra contract Flooring Puerto Rico, rnc.
SPS hternational Investmen! Company
SPS Technologies LLC
SPS Technologies Mexico LLC
ssP-si!.{atrix Inc.Stahl/Scott Fetzer CompanyStar Furniture companyStar Lake Railroad CompanyStrategic Staff Management, Inc.StratoFlight
Summit Distribut.ion Services, Inc.
SXP CRA-OCTG Inc.
TBS USA, Inc.
Texas Honing Inc.
Texas Insurance CompanyThe Ben Bridge Corporation
The Buffalo News, Inc.
The BvD Licensing Corporation
The Duracell Company Inc,
The Fechheimer Brothers co.
The Indecor Group, Inc.
The Lubrizol Corporation
The Medical Protective company
The Pampered chef, Ltd.The Scot.t Fetzer Company
The Wilkins Corporation
The zia company
THI Acquisition Inc.
TIMET Asia Inc.
TIMET Real Estate Corporation
Titanium Metals Corporation
TIVICA International Inc,
TMI Climate Solutions, hc.Tool-FIo Manufacturing, Inc.
Top Five CIub, Inc.Total Quality Apparel Resources
TPC European Holdings, Ltd.
TPC North America, Ltd.Transco, Inc.Transportation Technology Services, Inc.
TRH Holding Corp.Triangle Suspension Systems, Inc.Tricycle, Inc,
TSE Brakes, Inc.TTI, Inc.Tucker Safety ProducEs, Inc.
TXFM, INC.U.s. Investmen! Corporatsionu.S. underwriters Insurance Co.
UCFS Europe CompanyUnified Supply Chain, Inc.
Uni-Form Components Co.Union Sa1es, Inc.Union Tank Car Company
Union Underwear Co., Inc.
United Consumer Financial services companyUnited Direct Finance, Inc.United States Aviation underwriters, Inc.
United States Liability Insurance CompanyUniversity swaging corporation
UTLX Company
van Enterprises, Inc.vanderbilt ABS Corp.Vanderbilt Mortgage and Finance, Inc.vanity Fair, Inc.Velocit.y Freight Transport, Inc.Veritas Insurance Group, Inc,vesta Funding, Inc.vesta Intermediate Funding, Inc.
VFI-Mexico, Inc.Visilinx, Inc.Vision Retailing, Inc.
VT Insurance Acquisition Sub hc.Warwick Chemicals USA, Inc.wayne/scott Fetzer Company
weaver Manufacturing Inc.
Webb Wheel Products, Inc.western Builders Supply, hc,western Fruit Express Companywestern/Scott Fetzer Company
WeStGUARD Insurance Companywhitt.aker, Clark & Daniels, Inc.
WMC Corp.world Book Encyclopedia, Inc.world Book, Inc.world Book/Scott Fetzer Companyworld Investments, Inc.worldwide containers, Inc.
FERC FORM NO.1 (ED. 12-871 Page 450.10
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
WPLG, Inc.
Wrightsof t Corporation
wyman Gordan Investment Castings Inc
wyman Gordon company
wyman Gordon Forgings CleveLand Inc.
wyman Gordon Forgings Inc,
wyman Gordon Pennsylvania LLCX-L-Co., Inc.
XTRA Companies, Inc.
XTRA Corporation
XTRA Finance Corporation
XTRA Intermodal, Inc.
FERC FORM NO.1 (ED. 12-871 Page 450.'1 '1
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]en orisinal(2) nA Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
IAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1 . Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged lo operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which lhe taxed material was charged. lf the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. lnclude on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. lnclude in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total lax for each State and subdivision can readily be ascertained.
Lrne
No.
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR I axesPaid
%#s(e)
Adjust
ments
(0
Hreoato taxes(lnclude in Account 165)
(c)
1 Federal
2 lncome 2,086,346 163,464,187 92,864,797
3 FICA 540,378 6,511 36,918,373 36,908,951
4 Unemployment -34,160 233,225 192,630
E Foreign Withholding Taxes 1,522,888
6 Subtotal 4,115,452 6,511 200,615,785 129,966,378 68,665,825
7
8 State:
9
10 Arizona:
11 Property 1 ,830,515 2,872,740 3,266,885
't2 lncome 507,261 500,351
13 Subtotal 1,830,515 3,380,001 3,767,236 5,1 54
't4
't5 California:
't6 Property 2,25'1,937 2,251,937
17 Unemployment 132 23,753 22,353
18 Franchise-lncome 2,639,526 I ,918,210
19 Use 9,643 356,402 356,000
20 Local Franchise 1,311,455 1,353,368 1,2S0,959
21 Subtotal 1,321,230 6,624,986 5,839,459 99,612
22
23 Colorado:
24 Property 2,330,000 2,930,427 2,410,427
25 Subtotal 2,330,000 2,930,427 2,410,427
26
27 ldaho:
28 Property 3,651,782 6,415,434 6,369,005
29 lncome 2,447,140 2,188,279
30 KWh 18,336 77,507 78,673
31 Unemployment 2,447 63,998 64,888
32 Use 5,819 271,022 240,368
33 Subtotal 3,678,384 9,275,101 8,941,213 189,268
34
35
36
37
38
39
40
41 TOTAL 46,331,988 13,392,342 382,773,438 71,805,64'l
FERC FORM NO. r (ED. r2-96)Page 262
r axes Accrueo(Account 236)(b)
68,665,825
5,154
99,612
189,268
PacifiCorp (1)
(2)
Original
Date of Report(Mo, Da, Yr)
Resubmission
Year/Period of Report
End of 20181Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5. lf any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identirying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otheMise pending
lransmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. 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 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnole the basis (necessity) of apportioning such tax.
BALANCE AT :ND OF YEAR Line
No.(Taxes accrued
Account 236)(s)
Prepaid Taxes
(lncl. in Account 165)
Electric(Account 408.1, 409.1)Extraordinary ltems
(Account 409.3)
Adiustments to Ret-
Earnings (Account 439)
(k)
Other
o
1
4,019,91 1 162,384,813 2
543,289 3
6,435 4
1,522,888 5
6,092,523 162,384,813 38,230,972 6
7
8
I
10
1,436,370 2,872,740 11
1,756 504,449 12
1,438,126 3,377,1 89 2,812 13
14
15
2,',t15,104 16
1,532 17
621,704 2,626,470 18
10,045 19
1,373,864 1,353,368 20
2,007,145 6,094,942 530,044 21
22
23
2,850,000 2,928,875 24
2,850,000 2s28,875 1,552 25
26
27
3,698,211 6,414,355 28
69,593 2,431,047 29
17,170 77,507 30
1,557 3'l
36,473 32
3,823,004 8,922,909 352,192 33
34
35
36
37
38
39
40
48,581,847 13,873,220 405,266,228 51,081,832 4',!
FERC FORM NO. r (ED. 12-96)Page 263
1,079,374
36,9'18,373
233,221
2,812
136,833
23,753
't3,056
356,402
1,552
1,O79
16,093
63,998
271,022
PacifiCorp (1)
(2')
Original (Mo, Da,ltResubmission
Year/Period of Report
End of 20181Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. lf the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. lnclude on this page, taxes paid during the year and charged directto final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. lnclude in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited lo taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Ltne
No.
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR I axesCharoedq#]s
(d)
.F
a/
(
Adjush
ments
(0
Iaxes Accrued(Account 236)
(b)
Preoaid laxes
(lnclude in Account 165)
1 Montana:
2 Property 2,831,820 5,671,723 5,669,957
3 Corporate License-lncome 298,361 279,176
4 Unemployment 397 397
5 Energy License 60,000 194,594 194,594
6 Vvholesale Energy 42,000 138,648 138,648
7 Subtotal 2,933,820 6,303,723 6,282,772 9,731
8
I Nevada:
10 Commerce Tax 't3,821 40,369 36,190
11 Subtotal 't3,821 40,369 36,190
12
13 New Mexico:
14 Property 21,633 21,633
15 lncome 155,846 149,337
16 177,479 170,970 407
17
18 Oregon:
19 Property 12,518,813 25,777,048 26,041,557
20 Unemployment 63,630 1 ,319,015 1,324,222
21 Excise-lncome 21 ,069,576 19,573,491
22 City of Portland-lncome 71,402 56,912
23 Department of Energy 867,0'18 1,728,773 1,723,510
24 Tri-Met 383,739 1,0't0,292 1,001,912
25 Lane County 't,330 1,330
26 Franchise 4,759,730 30,081,587 30,288,639
27 Subtotal 5,207,099 13,385,831 81,059,023 80,01 1,573 1,979,908
28
29 Texas:
30 Unemployment 32 32
31 Subtotal 32 32
32
33 Utah:
34 Property 731,971 77,556,631 77,546,589
35 lncome 14,683,340 13,192,326
36 Unemployment 3,084 68,116 69,462
37 Navajo Nation
38 Use 324,524 3,714,304 3,720,05',1
39 Subtotal 1,059,579 96,022,391 94,528,428 856,s50
40
41 TOTAL 46,331,988 13,392,342 456,348,060 382,71,805,641
FERC FORM NO. 1 (ED. 12-96)Page 262.'l
9,731
407
Subtotal
1,978,163
1,745
856,55C
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]nn originat(2) alA Resubmission
Date of Report(Mo, Da, Yr)tl
Year/Period of Report
End of 20181Q4
5. lf any tax (exclude Federal and State income taxes)- covers more lhen one year, show lhe required information separately for each tax year, identirying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.L Report in columns (i) through (l) how the taxes were distributed. 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 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.L For any lax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT :ND OF YEAR DIS'Line
No.(Taxes accrued
Account 236)(s)
Prepaid Taxes
(lncl. in A.cncyunt 165)
Electric(Account 408.1, 409.1)
Exlraordinary ltems
(Account 409.3)
Adiustments to Ret.
Eamings (Account 439)
(k)
Other
o
1
2,833,586 5,671,723 2
9,454 296,890 3
4
60,000 194,594 5
42,000 138,648 6
2,945,040 6,301,855 1,868 7
I
I
18,000 40,369 10
18,000 40,369 11
12
13
21,633 14
6,916 155,383 15
6,916 177,0',t6 463 16
17
18
13,01 1 ,465 24,518,234 19
58,423 20
482,078 20,965,224 2',\
12,745 71,065 22
861 ,755 1,728,773 23
392,1 1 I 24
25
4,552,678 30,081,587 26
4,762,030 13,873,220 77,368,883 3,690,140 27
28
29
30
32 31
32
33
742,013 77,396,644 34
634,464 14,574,136 35
1,738 36
37
318,777 38
1,696,992 91,970,780 4,051 ,61 1 39
40
48,581,847 13,873,220 405,266,228 51 ,081,832 41
FERC FORM NO. 1 (ED. 12-96)Page 263.1
1,47'.\
39i
46:
228,143 1,258,814
1,319,01I
100,352
337
1,010,292
1,330
32
159,987
109,204
68,1 '1 6
3,714,304
Name of Respondent
PacifiGorp
This Reoort ls:(1) 5]nn orlsinat(2) 3A Resubmission
Date of Report(Mo, Da, Yr)tl
Year/Period of Report
End of 2018/Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1 . Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes lvhich have been charged to the accounts to which the taxed material was charged. lf the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. lnclude on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. lnclude in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited lo proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Lrne
No.
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR ,F
I'
(
Adjust-
ments
(0
Taxes Accrued(Account 236)(b)
PreDaid Taxes(lnclude in Account 165)
1 Washington:
2 Property 1 1,700,000 12,172,957 11,872,957
3 Unemployment 1,186 27,748 28,214
4 Business & Occupation 3,100 25,685 25,485
5 Public Utility 1,295,000 12,43'.t,865 14,210,492
6 Natural Gas Use Tax 226,034 1 ,619,654 1,706,532
7 Use 41,972 554,696 494,620
8 Forest Excise Tax 19,026 19,026
o Subtotal 13,267,292 26,851,631 28,357,326
10
11 VWoming:
12 Property 8,411,110 17,108,388 16,965,348
13 Wind Generation Tax 1,787,702 2,064,726 1,820,812
't4 Unemployment 2,490 104.290 104,115
15 Franchise 279,000 1,907,930 1,899,730
16 Use 84,728 't,296,407 1 ,'1 55,609
't7 Annual Report 70,783 70.783
'18 Subtotal 10,565,030 22,552,524 22,016,397
19
20 State Other:2,603 -2,603
21
22 Miscellaneous:
23 Goshule Possessory 25,900 25,900
24 Sho-Ban Possessory 292,630 292,630
25 Navajo Possessory 7,163 14,635 14,481
26 Ute Possessory 43,893 43,893
27 Crow Possessory 72,000
28 Umatilla Possessory 68,133 68,133
29 Subtotal 9,766 514,588 445,037
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 46,331,988 13,392,342 456,348,060 382,773,438 71,805,641
FERC FORM NO. I (ED. 12-96)Page 262.2
PacifiCorp (1)
(2')
Original
Resubmission
Date of Repo((Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
5. lf any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identirying
the year in column (a).
6. Enter all ad,ustments of the accrued and prepaid tax accounts in column (0 and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otheruise pending
transmittal of such taxes lo the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (l) only the amounts charged to Accounls 408.1 and 409.1
pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.
9. For any lax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT :ND OF YEAR Line
No.(Taxes accrued
Account 236)(s)
Prepaid Taxes
(lncl. in Account 165)
Electric(Account 408.1, 409.1)
Extraordinary ltems
(Account 409.3)
Adlustments to Ret.
Earnlngs (Account 439)
(k)
Other
o
1
12,000,000 11,892,268 2
720 3
3,300 25,685 4
12,431,865 5
1 39,1 56 6
102,048 7
8
11,761,597 24,349,818 2,501 ,813 I
10
't1
8,554,1 50 16,790,752 12
2,031,616 2,064,726 13
2,665 14
287,200 1,907,930 15
225,526 16
70,783 17
11,',t0't,157 20,834,191 1,718,333 18
19
-2,603 20
21
22
25,900 23
292,630 24
7,317 14,635 25
43,893 26
72,000 72,000 27
68,1 33 28
79,317 514,588 29
30
31
32
33
34
35
36
37
38
39
40
48,581,847 13,873,220 405,266,228 51 ,081,832 41
FERC FORM NO. I (ED. 12-96)Page 263.2
280,689
27,748
483,627
1 ,619,654
554,696
19,026
317,ffie
104,29C
1,296,40i
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
ll
Year/Period of Report
201AA4
FOOTNOTE DATA
262 Line No.:2 Column: f
262 Line No.:2 Column: I
Represents a reclass t U ance rom Account 145, Accounts receivable from
associated 1es
Account 409.2, Income taxes,other income and deductions.
ra represents ncome tax eto
Payro taxes are genera v to operat ma ntenance expense construc on
work in ss
Payro taxes are gene v to operat ma tenance expense cons on
work in SS.
resents a rec ASS cat ono CE rom Account 143 accounts rece e
Account 409.2, Income taxes, other and deduct S ch represents statetaxlicable to other income and deductions.
$13s
1
4
4
0
3
3 Account 408.2, Taxes other than0 Account 589, Rents
taxes, other and deduct
1 3 6 B 3 3
taxes are generally charged to operat s and ma e expense and constructwork in ss.
Represents a reclass ca on t ance rom Account L45, Accounts rece romassociated c
Account 409.2, Income taxes, ot ncome t represents state income
tax icable to other income and deductions.
to same account as related
Account 408.2 Taxes ncome taxes r ome t ons
Account 408.2 Taxes ncome taxes, other ome and duct ons
Represents a reclass f cat on of the balance from Account L45, Accounts rece vable fromassociated c ES
Account 409.2, Income taxes, other ncome and deduct ons,ch represents state ometaxicable to other income and deductions
Payro taxes are g'enera11y charged to opera ons and tenance expense and construct on
work in
to same account as related
Represents a reclass f t of the balance from Account 146, Accounts receivable from
associated r-es
Account 409.2, Income taxes, other and deductions, which represents statelicable to other income and deducti-ons
FERC FORM NO. I ED.1 450.1
262 Line No.:3 Column: I
262 Line No.:4 Column: I
262 Line No.: 12 Column: f
262 Line No.:12 Column: I
262 Line No.:16 Column: I
262 Line No.: 17 Column: I
262 Line No.: 18 Column: f
262 Line No.:18 Column: I
262 Line No.:19 Column: I
262 Line No.:24 Column: I
262 Line No.: 28 Column: I
262 Line No.: 29 Column: f
262 Line No.:29 Column: I
262 Line No.:31 Column: I
262 Line No.:32 Column: I
262.1 Line No.:3 Column: f
262.1 Line No.:3 Column: I
262.1 Line No.:4 Column: I
tax ncome
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Payroll taxes are generally charged to operations and maintenance expense and construction
work in ea
ts a recl f ca ono ance to Account 143, Other accounts rece vab1e.
Account 409.2, Income taxes, other ncome and ded ons,ch represents state income
tax icabl-e to other income and deductions
ts taxes e for feased
25,730 Account 408.2, Taxes other than income taxes,453,036 Account 589, Rents
t
780 048 Account 107, Construction work in progress
$1,258, 8l_4
Schedule Pase:262.1 Line No.: 20 Column: IPayroll taxes are generally charged to operations and maintenance expense and constructionwork in ss.
Represents a rec assification of the balance from Account 145, Accounts receivable from
associated ES
Account 409.2, Income taxes, other income and deductions, which represents state income
tax icable to other income and deductions
Represents a rec ass ca on of the balance rom Account 146, Accounts rece rom
ncome
262.1 Line No.: 15 Column: f
262.1 Line No.: 15 Column: I
262.1 Line No.: 19 Column:
262.1 Line No.: 19 Column: I
262.1 Line No.: 21 Column: f
262.1 Line No.:21 Column: I
262.1 Line No.: 22 Column: f
associated es
Account 409.2, fncome taxes,ncome ons,represents state262.1 Line No.: 22 Column: I
tax icable to other income and deductions
taxes are yc to operat ons ntenance expense construct262.1 Line No;24 Column: I
work in
taxes are yc to operat ons ntenance expense construct262.1 Line No.: 25 Column: I
work in SS.
Payroll taxes are yc to operat ons and ntenance expense and construct
262.1 Line No.:30 Column: I
262.1 Line No.: 34 Column: I
work in ss.
55,202 Account 408.2, Taxes ncome taxes, other ncome and deduct
94 785 Account 107, Construction work in progress
159 987
Represents a rec ass ca on the balance rom Account 146, Accounts rece rom
associated ES
Account 409.2, Income taxes, other income and deductions, which represents state incometaxicable to other income and deductions
Pa taxes are generally charged to operations and ntenance expense and construction
work in ss.
to same account as related
FERC FORM NO.1 (ED, 12.871 Page 450.2
262.1 Line No.: 35 Column: f
262.1 Line No.: 35 Column: I
262.1 Line No.: 36 Column: I
262.1 Line No;38 Column: I
262.2 Line No.: 2 Column: I
$ 51,177 Account 408.2, Taxes other than income taxes, other income and deductions
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Y0
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
229,51,2 Account 107, Construction work in progress
$ 2Bo, 6Be
262.2 Line No.:3 Column: IPayroll taxes are generally charged to operations and ntenance expense and construct
work in
Represents a prepayrnent of public utility tax result from customer payments for solar
262.2 Line No.: 5 Column:
262.2 Line No.:6 Column: I
activit in the state
Account l-51 Fuel stock
to same account as re
Account 408.2 Taxes other than
$
taxes r
B
o
9
6
3
6
24 Account 408.2, Taxes other than
70 Account 589, Rents
taxes, other ons
1
29 42 Account 107, Construction work in progress
262.2 Line No.:7 Column: I
262.2 Line No.: 8 Column: I
262.2 Line No.: 12 Column: I
31 3667
taxes are T to operat enance expense and construction
262.2 Line No.: 14 Column: I
work i-n
to same account as re ate
262.2 Line No.:16 Column: I
FERC FORM NO.1 (ED. 12.871 Page 450.3
Name of Respondent
PacifiCorp
(1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility
operations. Explain by footnote any correction adjustments to the account balance shown in column (g).lnclude in column (i) the average
period over which the tax credits are amortized.
Lrne
No.
ACCOUnt
Subdivisions(a)
tsalance.ailJegrnnrng
(b)
Deferred for Year AICurren Adjustments
(s)ACCOUNI NO.(c)AMOUNI(d)ACCOUnI NO.(e)Am((frunl
1 Electric Utility
2 3o/o
'1 4o/o
4 7o/o
6 1OYo 411.4,420 3,188,457
6 30%234,071 11,695
7 ldaho 411.4,420 13,689
8 TOTAL 12,399,369 3,213,841
I Other (List separately
and show 3o/o, 4o/o,7o/o
10o/o and TOTAL)
10
11 ldaho 3,270,954 '190 986,865 420 174.907
12 Total Nonutility 3,270,954 986,865 174,907 45,337
13
14
15
16
17
18
19
2A
21
22
23
24
,E
26
27
28
30
31
32
33
34
35
36
37
38
?o
4A
41
42
43
44
45
46
47
48,
FERC FORrrr NO. I (ED. 12-89)Page 266
12,068,837
420
96,461
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]en orisinat(2) [-lA Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
Balance at Endof Year
ft)
Averaoe Peflod
of Allocation
to lncome
fi)
ADJUSTMENT EXPLANATION Line
No.
1
2
3
4
8,880,380 38.82 and 30 5
222,376 24 6
82,772 38.82 and 30 7
9,185,528 8
9
10
4,128,249 30 11
4J28,249 12
13
14
15
't6
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
Name of Respondent
PacifiCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
266 Line No.: 5 Column: bThe elect.ric utfollows:ity subdi sion of l-0? accumulated deferred investment tax c ts are as
Acct
Sub
(a)
Beginning
Balance
Deferred for Yr. A11ocat. to CY Adj
(g)
Ending
Balance
(h)(b
Acct.
(c)
Amount
(d)
Acct.
(e)
Amount(f)
10%
10?
$L1-,957,631 $4r_r_.4 (1)
420 (2)
$3 , L44 ,173
44,284
$3, 188,4s7
$ 8,823,458 38 82
3010120655oa,
$1-2 ,058 ,837
-
e g,ggo,3go
L) Internal Revenue Code 46(f)22) Internal Revenue Code 45 (f) 1
In Revenue 46 1
ect cut I ty o ac dL nvestmenL tax ts are
as follows
Acct.
Sub.
(a)
Beginning
Balance
(b)
Deferred for Yr. Allocat. to CY Adj
(g)
Ending
Balance
(h)
Avg.
Per.(i)Acct. Amount(c) (d)
Acct.
(e)
Amount(f)
Idaho $fdaho
49 ,502 4t]-.4 (t)
420 (2)i 7,842 $$ 41- ,560 38.82
3046959584741,1_1,2
$ 96,46L $$ 13, 589 $$ 82,772
(1)Internal Revenue Code a5(f)2
(2) fnternal Revenue Code a5 (f) 1
Represents an ustment to the balance at beginning of year debited to Account 190,
Accumulated deferred income taxes.
FERC FORM NO. 1 (ED. 12.871 Page 450.1
266 Line No.:6 Column: e
266 Line No.:7 Column: b
266 Line No.: 11 Column:
Avg.
Per.(i)
Name of Respondent
PacifiCorp
This Report ls:(1) [An Original(2\ lllA Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
OTHER DEFFERED CREDITS (Account 253)
1. Report below the particulars (details) called for conceming other deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minoritems(5%oftheBalanceEndofYearforAccounl 253oramountslessthan$100,000,whicheverisgreater)maybegroupedbyclasses.
Line
No.
Description and Other
Deferred Credits
(a)
Balance at
Beginning of Year
(b)
DEBITS
Credits
(e)
Balance at
End ofYear
(0
Contra
Account
(c)
Amount
(d)
1 Working Capital Deposits 5,726,612 131 156,000 3,750 5,574,362
2 Reclamation Costs - Trapper Mine 6,252,483 245,698 6,498,181
3 Western Coal Carriers Benefits
4 Obligation 10,581,000 131 686,081 5M,081 10,479,000
5 Deferred Compensation Plans 9,41 1,956 131 9'14,766 112,287 8,609,477
6 Long-Term lncentive Plan 16,1'1 1,099 '131 '103,937 4,744,238 20,751,400
7 Regulated Environmental
8 Liabilities 52,303,713 131,182.3 8,171,087 11,374,014 55,506,640
I Non-Regulated Environmental
10 Liabilities 1,966,644 131 242,494 222,863 1,947,013
11 Uneamed Joint Use
12 2,924J63 454 6,156,452 6,1 08,992 2,876,703
13 Misc. Security Deposits 75,675 4',t5 52,',t77 95,809 119,307
14 694,303 101,931 538,993 15s,310
15 Covvlitz/Lewis River O&M (1)124,388 539 301 ,705 303,973 126,656
16 Employee Housing Security Deposits 19,900 131 2,800 1,800 18,900
17 Cogeneration Bonds-Sunnyside 413,417 413,417
18 Transmission Security Deposits 4,913,000 131 3,891,000 6,713,000 7,735,000
19 Transmission Service Deposits 509,217 131 ,235,456 859,931 2,686,262 2,335,il8
20 MCI F.O.G. \Mre Lease (1)557,390 454 3,347,401 3,348,013 558,002
21 Unamortized Contract Values 82,395,248 242 14,940,726 67,4t4,522
22 Accrued Right-of-Way Obligations 3,443,821 131 1,626,707 603,'t 78 2,420,292
23 93,995 456 102,714 894,883 886,164
24 Energy Supply Management
25 Deferral (1)379,167 456 3s0,000 550,000 579,167
26 Deer Creek Accrued Royalties 5,463,429 1,719,528 7,182,957
27 Deferred Revenue - Other 291,664 291,664
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL 204,360,620 42,444,971 40,604,033 202,519,682
FERC FORM NO.1 (ED.12.94)Page 269
Pole Contact Revenue
Lease lncentives
Facility Use Fee
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Pase: 269 Line No; 12 Column: a
Schedule Pase:269 Line No.: 14 Column: a
269 Line No;23 Column: a
The hted aver
The wei aver
average
fe s one ar
fe is five ars
life is 14 years
1
1
FERC FORM NO.1 (ED. 12.871 Page 450.1
PacifiCorp (1)
(2)Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20'l8lQ4
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to amortizable
property.
2. For other (Specify),include deferrals relating to other income and deductions.
Line
No.
Account
(a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Account 41 1.1
(d)
1 Accelerated Amortization (Account 281 )
2 Electric
3 Defense Facilities
4 Pollution Control Facilities 185,416,334 2,26s,332 7,342,236
5 Other (provide details in footnote):
6
7
8 TOTAL Electric (Enter Total of lines 3 thru 7)185,416,334 2,265,332 7,342,236
I Gas
10 Defense Facilities
11 Pollution Control Facilities
12 Other (provide details in footnote):
'13
14
15 TOTAL Gas (Enter Total of lines 1 0 thru 14)
16
17 TOTAL (Acct 281) (Total of 8, 15 and 16)185,416,334 2,265,332 7,342,236
18 Classification of TOTAL
19 Federal lncome Tax 151,178,573 885,628 5,025,064
20 State lncome Tax 34,237,761 1,379,704 2,317,172
21 Local lncome Tax
NOTES
FERC FORM NO.1 (ED.12.96)Page 272
qccounl 261)
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn originat(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 2018/Q4
3. Use footnotes as required
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End ofYear
(k)
Line
No.
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 411.2
(f)
Debits Credits
Account
Credited(s)
Amount
(h)
Account
Debited
(i)
Amount
o
1
2
3
180,339,430 4
5
6
7
180,339,430 8
I
10
11
12
13
14
'15
'16
180,339,430 17
18
147,039,137 19
33,300,293 20
21
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 273
Name of Respondent
PacifiCorp (2)Resubmission
Date
(Mo,
tt
Year/Period of Report
End of 20181Q4
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to property not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
Line
No.
Account
(a)
Balance at
Beginning ofYear
(b)
CHANGES DURING YEAR
Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Account 41 1.1
(d)
1 Account 282
2 Electric 2,972,737,275 279,489,640 467,380,758
3 Gas
4
5 TOTAL (Enter Total of lines 2 thru 4)2,972,737,275 279,489,640 467,380,758
6 Nonutility
7
8
I TOTAL Account 282 (Enter Total of lines 5 thru 8)2,972,737,275 279,489,640 467,380,758
't0 Classification of TOTAL
11 Federal lncome Tax 2,447,858,515 176,934,385 353,439,354
12 State lncome Tax 524,878,760 102,555,255 113,941,404
13 Local lncome Tax
NOTES
FERC FORi,t NO. 1 (ED. 12-96)Page 274
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]An original(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End ofYear
(k)
Line
No.
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 411.2
(0
Debits Credits
Account
Credited(s)
Amount
(h)
Account
Debited
(i)
Amount
(i)
1
182.3,254 31 1 ,913,302 't82.3,254 437,647,211 2,910,580,06€2
3
4
31 1 ,913,302 437,647,211 2,910,580,06(5
6
7
8
31 1 ,913,30i 437,647,211 2,910,580,06€I
10
308,787,481 434,881,63t 2,397,447,70i 11
3,12s,821 2,765,57i 513,132,36t 12
13
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 275
Name of
PacifiCorp (2)Resubmission
Date of Report(Mo, Da, Yr)
lt
Year/Period of Report
End of 20181Q4
1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
Line
No.
Account
(a)
Balance at
Beginning ofYear
(b)
CHANGES DURING YEAR
to AccolJJt 41 1.1
,|Account 283
2 Electric
3 Regulatory Assets 260,766,772 28,826,479 28,997,472
4 Other 12,148,155 15,594,037 16,528,823
5
6
7
8
I TOTAL Eleckic (Total of lines 3 thru 8)272,914,927 44,420,516 45,s26,295
10 Gas
11
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)272,914,927 44,420,516 45,526,295
20 Classification of TOTAL
21 Federal lncome Tax 222,771,074 36,830,033 37,744500
22 State lncome Tax 50,143,853 7,590,483 7,781,795
23 Local lncome Tax
NOTES
FERC FORM NO. { (ED. 12-96)Page 276
ort ls:
An Original
PacifiCorp )(Mo, Da,
(2)Resubmission
Year/Period of Report
End of 20181Q4
3. Provide in the space below explanations for Page 276 and 277 . lnclude amounts relating to insigniflcant items listed under Other
4. Use footnotes as required.
Balance at
End of Year
ft)
Line
No.
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 411.2
(D
Debits Credits
Account
cr1$ted
Amount
(h)
ACCOUnIDebitedo
AmounI
(i)
1
2
51,384,019 55,214,757 3,236,752 19,845,448 273,373,737 3
7,430,630 6,907,637 190,283 31,428 190,283 710,839 12,415,773 4
5
6
7
8
58,814,649 62,122,394 3,268,180 20,556,287 285,789,510 I
10
11
12
13
14
15
16
17
't8
58,814,649 62,',t22,394 3,268,180 20,556,287 285,789,510 19
20
47,919,414 50,632,882 2,698,707 16,807,379 233,25',t,8',t1 21
10,895,235 11,489,512 569,473 3,748,908 52,537,699 22
23
NOTES (Continued)
FERC FORi' NO. I (ED. 12-96)Page 277
(1I.]AN/:trq VtrAP
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
20't8tQ4
FOOTNOTE DATA
276 Line No.:3 Column: i
Account 1,82.3 ,regu tory assets
Account 190, Accumulated deferred j-ncome taxes
Account 283 Accumulated deferred income taxes-other
Account 482.3,regu .tory assets
Account 190, Accumulated deferred income taxes
Account 283, Accumulated deferred income taxes-other
FERC FORM NO. r (ED. 12471 Page 450.1
Name of Respondent
PacifiCorp
This ReDort ls:(1) fian Original(2) nA Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
OTHER REGULATORY LIABILITIES (Account 254)
'l . Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Line
No.
Description and Purpose of
Other Regulatory Liabilities
(a)
Balance at Begining
of Current
QuarterA/ear
(b)
DEBITS
Credits
(e)
Balance at End
of Current
Quarterl/ear
(D
ACCOUnI
Credited
(c)
Amount
(d)
1 DSM Balancing Account - CA 1,1 75,496 440,442,444 2,257,015 4,004,33€2p22,817
2 DSM Balancing Account - lD 1127,251 440,442,444 4,747,062 5,1 60,875 '1,541,064
3 DSM Balancing Account - UT 13,057,31C 13,057,310
4 DSM Balancing Account - WA 1,757,0X 1,757,029
5 DSM Balancing Account - WY 1,594,411 1,594,641
6 Oregon Energy Conservation Charge 3,n2,072 440,442,444 33,629,829 34,233,084 4,375,327
7 Defened Excess Net Power Costs - UT 3,999,381 182.3 3,999,381
I 18,419,803 555 2,257,755 6,904,1 67 23,066,215
I 7,899,057 555,182.3 7,959,227 60,17C
10 Decoupling Mechanism - WA 1,254,W2 440,442 8U,229 2,951,338 3,322,101
11 lncome Tax Reg. Liability - Flow Through - WA 193,304 545,628 738,932
12 3,1 94,547 190 838,704 3,21a 2,359,0s8
13 1,956,616,227 lW,n2 617,985,956 461,420,339 1,800,050,61 0
14 Excess lncome Tax Deferral 182.3 3,425,023 71,768,801 68,343,778
15 Tax on Bonus Depreciation - WY 1,462,493 928 28,300 632,631 2,066,824
16 10,385,290 10,97'1,133 585,843
17 Depreciation Study Defenal - lD 86,905 86,905
18 Asset Retirement Obligations Reg. Difference 4,070,978 2fi 649,526 3,421,452
19 Greenhouse Gas Allonrance Compliance - CA 2,3fi,747 131,456,555 1 6,1 56,640 14,496,74e 678,853
20 Solar on Multifamily Afforable Housing - CA 456 14,370 2,710,67a 2,696,305
21 Solar Feed-ln Tariff Defenal - CA 1,087,425
-
464,195 623,230
22 Solar lncentive Program - UT 14,398,860 440,442,444 3,478,682 3,337,997 14,258,175
23 STEP Pilot Program - UT 5,487,979 4,016,658 8,263,224 9,734,546
24 lndependent Evaluator Costs - UT 247,437 131 139,555 107,882
25 Utah Home Energy Lifeline 1,578,414 I 288,442 220,583 1,510,555
26 Washington Loru lncome Program 1,378,081 874,054 504,027
27 Califomia Energy Savings Assistance Program 546,846 462,696 351,1 1 4 435,264
28 FERC Rate True-up - 0R (3)24,797,198 456 4,306,685 9,965,3s'30,455,865
29 BPA Balancing Account - lD 3,s83,616 440,442 220,266 3,363,3s0
30 BPA Balancing Account - WA M3,076 440,442 173,'130 469,946
3'1 Blue Sky - CA 279,970 440,442 65,538 214,432
32 Blue Sky - 0R 2,'138,183 425,n2 2,563,475
33 Blue Sky - lD 196,171 45,363 241,534
34 Blue Sky - UT 8,521,4U 1,469,54€9,991,032
35 Blue Sky - WA 265,908 1 14,994 380,902
36 Blue Sky - WY 432,112 u,231 466,343
37 Depreciation Defenal - OR 4,014,249 1,209,09€5,223,348
38 Defened Steam Accel. Depreciation - WA 14,422,807 12,61 1,581 27,034,388
39 Menivin Fish Collector Project - WA 3,432 3,432
40 Direct Access 5-Year Opt Out - OR (10)1,943,382 442 1,729,274 3,419,751 3,633,8s9
41 TOTAL 2,1 01,876,268 722,023,325 664,386,963 2,044,239,906
FERC FORM NO. 1/3-Q (REV 02-04)Page 278
Defened Excess Net Polver Costs - WA
Defened Excess Net Porer Costs - \{Y
lnvestment Tax Credit Requlatorv Liability
Deferred lncome Tax Electric
Ofier Postrelirement
Name of Respondent
PacifiCorp
This Reoort ls:(1) []An original(2) EA Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
1. Report below the particulars (details) called for concqrning 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.
Description and Purpose of
Other Regulatory Liabilities
(a)
Balance at Begining
of Current
Quarterl/ear
(b)
DEBITS
Credits
(e)
Balance at End
of Current
Quarterl/ear
(D
Account
Credited
(c)
Amounl
(d)
1 Transportation Elec'trification Program - CA 457,60(457,600
2 Oregon Clean Fuels Program 487,50(487,500
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
38
39
40
41 TOTAL 2,1 01,876,268 722,023,325 664,386,963 2,044,239,906
FERC FORM NO. 1/3-Q (REV 02-04)Page 278'1
Line No.:8 Column: aweighteaverage remaining life is approximately t.hree years or excess net power
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
FOOTNOTE DATA
278 Line No.:9 Column: a
cost mechanisms be amortized.
Weighte average remaining life is approximately one year for excess net powercost mechani-sms be amortized
We e s 39
Amounts mar 1y represent ome tax 1 es related to the federal tax rate changefrom 35t to 2lZ t.hat are probable to be passed on to customers, offset by income taxbenefits related to certain property-related basis differences and other various
differences that were previously passed on to customers and will be included in regulatedrates when the differences reverse.
we].te average remaining life of portion being amort ze s 13 years tantrepresents amounts not yet recognized as a component of net periodic benefit cost that arected to be included in rates when rec zed.
Other postret rement costs are associated with labor and generally charged to operations
and maj-ntenance expense and construction work j-n progress. Other postretirement
remeasurement date changes and wyoming's share of settlement losses are charged to Account
926,e sions and benefits.
t
Account
Account
Account
Account
L82.3, Other regulatory assets
440, Residential sales
442, Commercial and industrial sales
Schedule Page:278 Line No.: 12 Column: a
yehted average remaininq life i
Schedule Page:278 Line No.: 13 Column: a
278 Line No.: 16 Column: a
278 Line No.: 16 Column: c
278 Line No.: 21 Column: c
444 Public street and hi 1i
Account
Account
Account
Account
107 ,440,
442,
Construct wo progress
Residential sales
Commercial and industriaf safes
278 Line No.: 23 Column: c
Account 131-,
Account 440,
Account 442,
Account 444,
444 Public street and hi 1i
CashResidential sales
Commercial and industrial sales
278 Line No; 25 Column: c
Public street and 1
Account 131-,
Account. 440,
Account 442,
CashResidential sales
Commercial and industrial sales
278 Line No.:26 Column: c
Account 444 Public street and hi 1i
Account 131, Cash
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
278 Line No; 27 Column: c
FERC FORM NO. 1 (ED. 12.871 Page 450.1
Name of
PacifiCorp (2)Resubmission
Oate of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
ELECTRIC OPERATING REVENUES I
1 . The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (0, and (g). Unbilled revenues and MWH
related to unbilled revenues need not be reported separately as required in the annual version of these pages.
2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3. Report number of customers, columns (0 and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are
added for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the
close of each month.
4. lf increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
5. Disclose amounts of $250,000 or greater in a footnote for accounts 451 , 456, and 457 .2.
Line
No.
Title of Account
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no Quarterly)
(c)
1 Sales of Electricity
2 (440) Residential Sales 1,774,237 ,100 1,884,431 ,867
3 (442) Commercial and lndushial Sales
4 Small (or Comm.) (See lnstr.4)1,541,492,719 1,569,999,446
5 Large (or lnd.) (See lnstr. 4)1,322,455,444 1,373,506,114
6 (4,14) Public Street and Highway Lighting 18,155,451 19,817,707
7 (445) Other Sales to Public Authorities 3,322,249
8 (446) Sales to Railroads and Railways
I (448) lnterdepartmental Sales
10 TOTAL Sales to Ultimate Consumers 4,656,340,7',14 4,851 ,077,383
11 (447) Sales for Resale 254,214,730 217,427,479
12 TOTAL Sales of Electricity 4,910,555,444 5,068,504,862
13 (Less) (449.1) Provision for Rate Refunds
't4 TOTAL Revenues Net of Prov. for Refunds 4,910,555,444 5,068,504,862
15 Other Operating Revenues
16 (450) Forfeited Discounts 9,81 I ,199 10,272,123
17 (451) Miscellaneous Service Revenues 5,342,009
18 (453) Sales of Water and Water Power 54,615 54,199
19 (454) Rent from Electric Property 17,246,955 18,455,411
20 (455) lnterdepartmental Rents
21 (456) Other Electric Revenues 25,295,388
22 (456.1) Revenues from Transmission of Electricity of Olhers 116,616,886 115,041 ,634
23 (457.1) Regional Conlrol Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 179,803,512 174,460,764
27 TOTAL Electric Operating Revenues 5,090,358,956 5,242,965,626
FERC FORM NO. 1/3.Q (REV. r2-05)Page 300
6,172,987
29,900,870
Name of Respondent
PacifiCorp (2\Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
6. Commercial and industrial Sales, Account 442, may be classified according to the basis of dassification (Small or Commercial, and Large or lndustrial) regularly used by
therespondentifsuchbasisofclassificationisnotgenerallygreaterthanl000Kwofdemand. (SeeAccount442oftheUniformSystemofAccounts. Explainbasisof
classification in a footnote.)
7. See pages 1 08-1 09, lmportant Changes During Period, for important new territory added and important rate increase or decreases.
8. ForLines2,4,5,and6,seePage304foramountsrelatingtounbilledrevenuebyaccounts.
9. lnclude unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD AVG.NO. CUSTOMERS PER MONTH Line
No.Year to Date Quarterly/Annual
(d)
Amount Previous year (no Quarterly)
(e)
Cunent Year (no Quarterly)
(0
Previous Year (no Quarterly)
(s)
1
16,227,117 16,625,426 '1 ,651,326 1,622,276 2
3
18,078,160 17,665,137 211,800 208,378 4
20,679,901 20,756,851 33,1 86 33,200 5
130,278 141,243 3,50'1 3,470 6
61 ,165 7
8
I
55,115,456 55,249,822 1,899,813 1,867,324 10
8,309,472 7,218,497 11
63,424,928 62,468,319 1,899,813 1,867,324 12
13
63,424,928 62,468,319 1,899,813 1,867,324 14
Line 12, column (b) includes $
Line 12, column (d) includes
229,061 ,000
2,887,422
of unbilled revenues.
MWH relating to unbilled revenues
FERC FORM NO. 1/3.Q (REV. 12-05)Page 301
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
300 11 Column: fForacete^!
this Form No. 1.
t r customers see pages 310-311,CS r resa e, 1n
300 Line No.: 11 Column
For aPacifi ete st t customers see pages 310-311, S
1-
es re e,
31 2017 FERC Form No.
Account 451,aneous serv ce revenues,
Account service charges - application fees,disconnects, reconnects and returned check charges
Customer contract flat rate billings and facility
ow ng tems t t were
Account 455, Other electric revenues, includes the following items that were $250,000 orgreater during the years ended December 31:
2 018 20L7
Wind-based ancillary services $Amortization of California greenhouse gas
allowance revenueFlyash/by-product sales
Renewable energy credit sa1es, includingamortization and deferraf s
Revenue from generation interconnection andtransmission service request studies
Phase shifting equipment fee from
Western Electricity Coordinating Council
Steam sales
Timber sales
Energy exchange credits
Maintenance charges for work on transmission facilities
Revenue from other requested customer studies
Net profit on sales of materials and supplies inventory
Service territory fixed cost recovery feeDeferral of Oregon retail customers' allocated share ofthe incremental Open Access Transmission Tariff revenuesassociated with FERC Docket No. ER11-3543-000, net ofamortization
1l_, L69, 083 $ 9,781-,935
3 ,300 ,207
1, , 559 ,7 64
(4 ,1-29 ,687 )(3,978,799)
(a) Amount is less than $250,000.
2 018
$ 5, 274 ,993
873, 885
9 ,59A ,652
4 ,258 ,230
l-, 3go, 032
689, 855
505,102
453,590
432 ,87 4
266,616
(a)
(a)
20L7
$ 4,304,054
999 ,499
8, 113,014
4 ,49r,627
1, 088, 549
1 ,7 84 ,329
(a)
483 ,973
L,269 ,886
395, 600
676,l.98
(a)
578, 093
303 ,473
300 Line No.:17 Column: b
300 Line No.: 21 Column: b
FERC FORM NO.1 (ED. 12-871 Page 450.1
$250,000 or greater during the years ended December 31:
PacifiCorp (1)
(2)
Original
Resubmission
Date of ReDort
(Mo, Da, Yi)Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year lhe MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 31 0-31 1.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Elechic Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue accounl, List the rate schedule and sales data under each
applicable revenue account subheading.
3. V1/here the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), lhe entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year ('12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjuslment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Llne
No.
NUmDer ano ilIte oT KaIe scneoute
(a)
MVVn 50tO
(b)
Kevenue
(c)
KWNPer (Kevenue HerKWh Sold
(D
1 RESIDENTIAL SALES
2 CALIFORNIA
3 OGCHCKOOOR - CA RES CHECK M 1
4 O6LNXOO31 1 - LINE EXT 80% Gry 1,636
5 O6NETMT135 - CA RES NET MTR 't,824 213,444 353 5,'r67 0.1170
6 O6OALTO1SR - OUTD AR LGT SR 271 77,727 291 931 0.2868
7 OoRESDOOOD - RES SRVC 164,209 21,708,852 17,349 9,465 0.1322
I OGRESDOODN - DEL NORTE CTY 72,950 9,757,412 6,756 10,798 0.1 338
I O6RESDODM9 - MULTI FAMILY 162 17,412 7 23,143 0.1075
1C OoRESDODSS - MULT FAM SBMET 1,631 175,285 16 101 ,938 0.1 075
11 O6RESDDLO6. CA LOW INCOME 114,559 15,213,205 11,323 't0,117 0.1 328
12 O6RGNSVO25 - CA SMALL GEN 1,347 292,726 475 2,836 0.2173
13 REVENUE-ACCT ADJ -1,486,387
14 INCOME TAX DEFERRAL ADJ -1,580,276
'15 DSM REVENUE-RESIDENTIAL 1 ,1 56,912
16 BLUE SKY REV-RESIDENTIAL 132,974
17 SOLAR FEED-IN REVENUE 6,862
18 UNBILLED REV . UNCOLLECTIBLE -3,000
19 UNBILLED REVENUE 12,955 1,351,000 0.'1043
2A
21 IDAHO
22 OTLNXOOO1O - MNTHLY 8O%GTY 1,153
23 OTLNXOOO3S - ADV 8O%MO GTY 2,826
24 O7NETMT135 - ID RES NET MTR 4,197 366,486 49C 8,565 0.0873
25 OTOALCOOOT - CUST O!\N LIGHT 10 3,827 1 10,000 0.3827
26 OTOALTOTAR - SECURITY AR LG 96 39,379 124 800 0.4102
2t OTRESDOOO1 - RES SRVC 492,571 56,089,904 52,204 9,436 0.1 't 39
28 O7RESDOO36. RES SRVC-OPTIO 194,244 19,047,622 11,629 16,703 0.0981
29 OTRGNSVOoA - LRG GEN SVC-RES 219 17,130 2 109,500 0.0782
30 O7RGNSV23A. SM GEN SVC-RES 9,053 1,016,6'1 '1 1,059 8,549 0.1't23
31 07RNM23.135 - NET MTR SMALL 68 5,404 ,l 22,667 0.0795
5t REVENUE-ACCT ADJ -234,719
2t INCOME TAX DEFERRAL ADJ -789,050
34 DSM REVENUE-RESIDENTIAL 2,006,223
2E BLUE SKY REV-RESIDENTIAL 11,825
36 UNBILLED REV - UNCOLLECTIBLE -7,000
37 UNBILLED REVENUE 2,786 50,000 0.0179
38
eo OREGON
4A OlCHCKOOOR - RES CHECK MTR 1
41 TOTAL Billed 55,333,51:4,748,894,747 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,05i -26,093,000 0 (0.1197
43 TOTAL 55,1 15,45(4,722,801,747 1,899,813 29.011 0.0857
FERC FORM NO.1 (ED. 12-95)Page 304
odltSitomer
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]nn orisinat(2) [A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. \Mrere the same customers are served under more than one rate schedule in the same revenue accounl classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by lhe number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
NumDer ano lrfle oI Kate scneoule
(a)
MWN I,OIO
(b)
Kevenue
(c)
KWNPer (IffiSuo16"
(D
1 01cosT0004 - 01 RESD0004 4,940,665 301 ,985,312 0.061 1
2 OlCOSTRO23 - RES GEN SRV CST 94,177 5,801,649 0.0616
t OlCOSTRO2S - OR RES GEN SVC 49,277 3,028,023 0.0614
4 OlFXRENEWR. FIXED
4 01 HAB|T004 - 0'l RESD0004 53,124 3,',t88,792 0.0600
6 OlHABTRO23 - RES GEN SVC HAB 202 12,777 0.0633
7 OlLNXOO102 - LINE EXT 80% G '10,013
8 01LNXOO109. REF/NREF ADV +4,727
I 011NX00300 - LINE EXT 80o/o GTY 168
10 01 NETMT1 35 - NET METERING 2,226,588 5,250
11 01NMTOU135 - TOU NET 61,786 27
12 OlOALTB1SR - OR OUTD AR LGT 2,105 346,256 2,432 866 0.1645
13 01 PTOU0004 - 01 RESD0004 15,688 991 ,013 0.0632
't4 O1 PTOUOOOs . 01 RESEVOsT TOU E 255 0.0510
15 01 RENEWOO4 - OlRESDOOO4 381,112 22,s36,235 0.0591
16 OlREN\A/R023 - RENEW USAGE 706 42,828 0.0607
17 OlRESDOOO4 - RES SRVC 292,237,279 497,292
18 OlRESDOO4T. RES TIME OPT 755,445 1,045
19 OlRESEVOST - RES ELECT 332 1
20 01 RGNSBO23 . SMALL GENERAL 7,217,335 16,879
21 01RGNSBO28. GENERAL SVC > 30 1,356,985 216
22 OlRGNSBO23 - SMALL GENERAL 43,626 110
23 OlRGNSBO2S - GENSVC > 30 KW 50,498 2
24 OlUPPLOOOR - BASE SCH FALL 2
25 01VIRO4136 - VOLUME INCENTIVE 377,104 471
26 REVENUE_ACCT ADJ -3,224,728
27 INCOME TAX DEFERRAL ADJ -20,274,474
28 OR GAIN ON SALE OF ASSET t,23A
29 DSM REVENUE-RESIDENTIAL 18,829,173
30 BLUE SKY REV.RESIDENTIAL 402,126
31 SOLAR FEED-IN REVENUE 2,028,145
32 UNBILLED REVENUE 19,163 1,634,00C 0.0853
33
34 UTAH
35 OSBLSKYO1R - BLUESKY ENERGY -9
36 OSCFROOOO1 - MTH FACILITY S 735
37 O8CGENR136 - UT RES TRANS 644 68,058 175 3,68C 0.1057
38 O8CGNO3136 - UT LOW INC RES 7 738 2 3,50C 0.1054
eo OSCGRO1 136 - UT RES TRANS 6,974 737,812 962 7,249 0.1058
40 O8CGRO2136 - UT RES TOU TRANS 3 368 1 3,00c 0.'t227
41 TOTAL BiIIed 4,748,894,747 1 ,899,81:29,124 0.0858
42 Total Unbilled Rev.(See lnstr.6)-218,057 -26,093,000 (c 0.1 1 97
43 TOTAL 55,1 1 5,45€4,722$01 ,747 1 ,899,8't 3 29,011 0.0857
FERC FORM NO. 1 (ED. 12-9s)Page 304.{
Jatesitomer
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn original(2) fiA Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the yeat (12 i'f
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Lrne
No.
r\umoer ano ilIte oI KaIe scneoute
(a)
MVVn JOIO
(b)
Kevenue
(c)of
KVVn
Per (
(
.1ftX?f,'$?6*
(0
1 O8CGRO3136 - UT LOW INC RES 89 9,378 11 8,091 0.1054
2 08CGR23136. RES SM GEN SVC 13 1,320 0.10't 5
3 OsCHCKOOOR - UT RES CHECK M 1
4 OSCOOLKPRR - COOL KEEPER 98,254
5 OSLNXOOOO1 - MTHLY 80% GUAR 2,917
6 OSLNXOOOOs - MTHLY MIN GUAR 396
7 OSLNXOOO13 - 80% MNTHLY MIN 26,974
8 OSLNXOOlOS - ANN COST MTHLY 1,656
I OSMHTPOOOo - MOBILE HOME &12,093 900,548 I 1,511,625 0.0745
10 OSMHTPOO23 - MOBILE HOME &124 9,715 1 124,000 0.0783
11 O8NETMT135 - NET MTR 109,999 13,105,091 28,984 3,795 0.1191
12 O8NMTO3135. LOW INC RES 880 96,183 173 5,087 0.1 093
13 OSOALTOOTR - SECURITY AR LG 2,321 644,715 2,356 985 0.2778
14 OEPTLDOOOR - POST TOP LIGHT 1 105 2 500 0.1050
15 08RCG23136. RES NET MTR, SM 4 43S 1 4,000 0.1098
16 OSRESDOOO1 - RES SRVC 6,586,081 707,53',t,284 750,967 8,770 0.1074
17 OSRESDOOO2 - RES SRVC-OPTIO 3,241 345.112 383 8,462 0.1065
18 OSRESDOOO3 - LIFELINE PRGRM 169,849 17,968,836 22,827 7,441 0.1058
19 OSRESDOO2E - RES ELECT 2.012 172,491 147 13,687 0.0857
20 OsRGNSVOO6 - GEN SRVC-RES 116,776 8,710,631 270 432,504 0.0746
21 OSRGNSVO23 - GEN SRVC-RES 99,540 10,702,826 13.487 7,380 0.1075
22 OSRGNSVO6A - UT SM GEN SVC 1 0,140 881,237 26 390,000 0.0869
23 OSRGNSVO6B - UT SM GEN SVC 33 4,143 I 33,00c 0.'1255
24 O8RNMO6135 - UT NET MTR, GEN 3,657 3',t3,718 13 281 ,308 0.0858
25 08RNM23135. UT NET MTR, GEN 1,062 147,383 414 2,565 0.1 388
26 O8RNM6A135 - RES GEN SVC NET 3 1,795 1 3,00c 0.5983
27 OSSSLROOO1 - RES SUBSCRB 29,395 3,299,477 0.1122
28 OSSSLROOO3 - LOW INCOME 289 31 ,652 26 11,115 0.1095
29 O8SSLRRG23. SM GEN SUBSCR 56 7,616 16 3,50C 0.1360
30 OSUPPLOOOR - BASE SCH FALL 4
31 REVENUE-ACCT ADJ -1,070,429
32 REVENUE ADJ - DEF NPC 520,102
33 DSM REVENUE-RESIDENTIAL 2,187,064
34 BLUE SKY REV-RESIDENTIAL 1,254,71C
35 SOLAR FEED-IN REVENUE 1,912,182
36 UNBILLED REV - UNCOLLECTIBLE 23,00c
37 UNBILLED REVENUE -62,147 -7,909,00c 0.1273
38
39 WASHINGTON
40 O2BLSKYO1R - BLUESKY ENERGY -l
41 TOTAL BiI|ed 55,333,513 4,748,894,747 1 ,899,813 29,12t 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,057 -26,093,00C 0 (0.1 197
43 TOTAL 55,1 15,456 4,722,801,747 1,899,813 29,011 0.0857
FERC FORM NO.1 (ED. 12-95)Page 304.2
DAIES
ttomer
PacifiCorp Original
Resubmission
Date of Report(Mo, Da, Yr)
lt
Year/Period of Report
End of 2018/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
cuslomer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue accounl subheading.
3. Vvhere the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Ltne
No.
t\umDer ano I tlte oI KaIe scneoute
(a)
MVVn St)to
(b)
Kevenue
(c)of
KWNPer (Kevenue HerKWh Sold(D
1 O2LNXOO109 - REF/NREF ADV +1,839
2 O2NETMT135 - WA RES NET MTR 9,231 943,625 953 9,686 0.1022
3 O2OALTBI5R - WA OUTD AR LGT oq?'151,628 1,050 908 0.1 591
4 O2RESDOO16 - WA RES SRVC 1,453,252 139,892,718 101,774 14,279 0.0963
E O2RESDOO1T - BILL ASSISTANC 72,685 6,997,352 4,903 14,825 0.0963
b O2RESDOOIS - WA 3 PHASE RES 2,085 221 ,147 80 26,063 0.1 061
7 O2RESDO1SX - WA 3 PHASE RES 331 34,409 14 23,643 0.1 040
8 O2RGNSBO24. WA SM GEN SVC 20,300 2,506,226 3,428 5,922 0.1 235
I O2RGNSBO36 - RES LRG GEN SVC 1,448 116,399 2 724,000 0.0804
10 02RNM24135 - RES NET MTR SM 73 9,735 17 4,294 0.1 334
11 O2ZZMERGCR - MERGER CREDITS 4
12 REVENUE-ACCT ADJ -9,629,568
13 REVENUE ADJ - DEF NPC 60,142
14 INCOME TAX DEFERRAL ADJ -3,342,707
15 ALT REVENUE PROGRAM ADJ 217,345
'16 DSM REVENUE-RESIDENTIAL 4,810,524
17 BLUE SKY REV-RESIDENTIAL 131,576
18 UNBILLED REV - UNCOLLECTIBLE 14,000
'19 UNBILLED REVENUE -40,010 -5,588,000 0.1397
2C
21 \
^/oMtNG22O5LNXOO102 - LINE EXT 8OO/O G 792
23 OsLNXOO109 - REF/NREF ADV +5t
24 OsNETMTl35 - EXP PARTIAL REO 1,758 210,387 20'l 8,746 0.1 197
25 OSOALTO15R - OUTD AR LGT SR 835 I 15,80C 987 846 0.1 387
26 OsRESDOOO2 - WY RES SRVC 876,499 95,456,624 101 ,984 8,594 0.1089
27 OsRGNSVO2s - VUY SM GEN SVC 9,236 1,127 ,892 1,521 6,072 0.1221
28 OgOALT2O7R. SECURIW AR LG 156 1
29 REVENUE_ACCT ADJ 178,219
30 REVENUE ADJ - DEF NPC -80,632
31 INCOME TAX DEFERRAL ADJ -766,459
32 DSM REVENUE-RESIDENTIAL 926,228
33 DSM REVENUE-RES GEN SVC 37,350
u BLUE SKY REV-RESIDENTIAL 144,740
35 UNBILLED REV - UNCOLLECTIBLE -21,000
36 UNBILLED REVENUE -'t3,718 -1,923,000 0.'t402
37 OsNETMT135 - EXP PARTIAL REQ 377 44,552 37 1 0,1 89 0.1',!82
38 O5OALTO1SR - OUTD AR LGT SR 1 85 1 1,000 0.0850
?o OsRESDOOO2. \A/Y RES SRVC 110,114 12,136,263 12,462 8,836 o.1102
4A OsRGNSVO2S - WY SML GEN SVC 440 74,192 143 3,077 0.1686
4',!TOTAL BiIIed 55,333,513 4,748,894,747 1 ,899,813 29,12e 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,05i -26,093,00C c (0.1 197
43 TOTAL 55,1 1 5,45€4,722,801,747 1 ,899,813 29,0'1 1 0.0857
FERC FORM NO. 1 (ED. 12-95)Page 304.3
This ReDo(1) EA(2) TIA
odrc5ilomer
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]en origlnal(2) fiA Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. lfthesalesunderanyratescheduleareclassifiedinmorethanonerevenueaccount,Listtheratescheduleandsalesdataundereach
applicable revenue account subheading.
3. Where the same customers are served under more lhan one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year ('12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
NUmDer ano lrue ol Rate schedule
(a)
MVVn OO|Q
(b)
Kevenue
(c)of
Kevenue HerKWh Sold
(D
1 OgOALT2OTR - SECURITY AR LG 71 17,146 u 845 o.2415
2 09RE500002 ,|
2 O9RESDOOO2 4
4 DSM REVENUE-RESIDENTIAL 161,953
E DSM REVENUE-RES GEN SVC 2,815
6 BLUE SKY REV-RESIDENTIAL 19,720
7 UNBILLED REVENUE -1,355 -162,000 0.1 196
I
I LESS MULTIPLE BILLINGS -'t23,641
10
11 TOTAL RESIDENTIAL SALES 16,227,117 1,774,237,100 1,651 ,326 9,827 0.1093
't2
13 COMMERCIAL SALES
14 CALIFORNIA
'15 O6GNSVOO25 - CA GEN SRVC 52,392 9,512,511 6,530 8,023 0.1 81 6
16 O6GNSVO25F - GEN SRVC.< 20 916 181,665 85 10,776 0.1 983
17 O6GNSVOA32 - GEN SRVC-2o KW 83,784 13,013,640 't,045 80,176 0.1 553
18 O6LGSVO4ST - LRG GEN SERV 28,559 2,955,1'.t4 I 3,569,875 0.1 035
19 O6LGSVOA36 - LRG GEN SRVC-O 61,821 8,119,831 152 406,717 0.1313
20 O6LNXOO102 - LINE EXT 8OO/O G 5,646
2',!O6LNXOO109 - REF/NREF ADV +'t02,73C
22 O6LNXOO1 1O - REF/NREF ADV +13
23 06LNX0031'1 - L|NE EXT 80%28,048
24 06NMT25135 - GEN SVC NET 89 16,672 14 6,357 0.1873
25 06NMT32135 - GEN SVC NET 1,819 301,801 23 79,087 0.1659
26 06NMT36135. GEN SVC NET 2,319 314,576 5 463,800 0.1357
27 06NMT48135. GEN SVC NET 2,664 27',t,432 1 2,604,000 0.1 01 9
28 O6OALTO15N - OUTD AR LGT SR 651 188,660 471 1,382 0.2898
29 O6RCFLOO42 . AIRWAY & ATHLE 152 35,012 37 4,108 0.2303
3C REVENUE-ACCT ADJ -938,1 25
31 INCOME TAX DEFERRAL ADJ -988,16't
JI DSM REVENUE.COMMERCIAL 730,817
33 BLUE SKY REV-COMMERCIAL 12,000
34 SOLAR FEED-IN REVENUE 6,483
tE UNBILLED REVENUE -2,714 -485,000 0.1787
36
37 IDAHO
38 07c1sH0019 - coMM & tND SPA 4,837 417,536 89 54,348 0.0863
2C OTGNSVOOOo - GEN SRVC-LRG P 246,923 20,045,205 1,016 243,034 0.08'12
4C OTGNSVOOOg - GEN SRVC-HI VO 43,034 2,706,666 2 21,5',t7,004 0.0629
41 TOTAL BiIIed 55,333,513 4,748,894,747 1,899,813 29,126 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,057 -26,093,000 0 0 0.1 1 97
43 TOTAL 55,1 15,456 4,722,80',t,747 1,899,813 29,011 0.0857
FERC FORM NO.1 (ED. 12-9s)Page 304.4
nvvl
Per DAIESstomer
Name of Respondent
PacifiCorp
This Report ls:(1) [An Original(2) l-lA Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICIry BY RATE SCHEDULES
1. Report below for each rate schedule in effecl during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Wrere the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
NUmDer ano ilIte oI Hate scneoure
(a)
MWn 50to
(b)
Kevenue
(c)ot Kvvn or DaEsPer Qustomer(e)
Kevenue retK\Ntr Sold
(D
1 OTGNSVOO23 - GEN SRVC-SML P 152,010 15,065,21 1 6,939 21,907 0.0991
2 OTGNSVOO3s - GEN SRVCOPTION 261 15,982 2 130,500 0.0612
I OTGNSVOO6A - GEN SRVC-LRG P 24,600 2,156,662 18'1 135,912 0.0877
4 OTGNSVO23A - GEN SRVC.SML P 27,776 2,730,404 't,279 21,7',t7 0.0983
q O7GNSVO23F. GEN SRVC SML P 7 1.794 4 '1,750 0.2563
6 OTLNXOOO1O - MNTHLY 8O%GUAR 20,892
7 071NX00015 - ANNUAL 8Oo/oGUAR 528
I OTLNXOOO3s - ADV 8O%MO GUAR 239,1 05
I 071NX00040 - ADV+REFCHG+80%36,706
10 OTLNXOO3OO. 80% MONTHLY MIN 3,632
11 071NX00311 - L|NE EXT 80%33,329
12 O7LNXOO312 - ID LINE EXT 26,681
13 O7NMTO6135. ID NET MTR - LG 1,730 140,794 ,l 576,667 0.0814
14 07NMT23135 - ID NET MTR - SM 1,168 89,439 27 43,259 0.0766
15 OTOALTOOTN - SECURIry AR LG 252 98,096 169 1,491 0.3893
16 OTOALTOTAN - SECURITY AR LG 't0 3,913 '10 1,00c 0.3913
17 REVENUE-ACCT ADJ -13s,678
18 INCOME TAX DEFERRAL ADJ -560,569
19 DSM REVENUE-COMMERCIAL 1 ,131 ,489
20 BLUE SKY REV-COMMERCIAL 1,182 1
21 UNBILLED REVENUE 8,512 601 ,000 0.0706
22
)'1 OREGON
24 01COSTOO23. OR GEN SRV 1,007,550 59,877,993 0.0594
25 01cosT0048 - 01 LGsv0048 1 ,1 06,604 54,414,539 0.0492
26 OlCOSTO23F - OR GEN SRV 2,868 181,246 0.0632
27 OlCOSTBO23 - OR GEN SRV 23,968 1,453,872 0.0607
28 OlCOSTEV4S - ELECT VEH DC 97 6,036 0.0622
ac OlCOSTLO3O - OR LRG GEN SRV 1,137,902 60,073,225 0.0528
30 OlCOSTSO2S - OR GEN SERV 1,925,524 1 18,556,81C 0.0616
31 01GNSBOO23. OR GEN SRV BPA 1,607,346 2,869
32 01GNSBOO28. OR GEN SRV, BPA 1,969,753 289
33 01GNSBO23T. OR GEN SRV - TOU 28,123 48
34 OlGNSEV4ST - ELECT VEH DC 19,928 't2
35 OlGNSVOO23 - OR GEN SRV, < 30 54,429,438 58,101
36 O1GNSVOO2S - OR GEN SRV > 30 57,360,041 9,056
37 OlGNSVO23F - OR GEN SRV - FLAT 10,264 1,634,929 777 13,214 0.1 593
38 OlGNSVO23M - OR GEN SRV,80 8,106 2 40,00c 0.1013
39 01GNSVO23T. OR GEN SRV, TOU 164,043 196
4A 01GNSVO723 - OR GEN SVC DIR 5,702 z
41 TOTAL Billed 55,333,513 4,748,894,747 1,899,813 29Jze 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,057 -26,093,000 0 c 0.1197
43 TOTAL 55,115,456 4.722.801.747 1 ,899,813 29,011 0.0857
FERC FORM NO. r (ED. 12.95)Page 304.5
Name of Respondent
PacifiCorp
This Reoort ls:(1) fiRn Originat(2) fiA Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 31 0-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. \Mrere the same cuslomers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Ltne
No.
r\umoer anq ilIre oT KaIe scneoute
(a)
tMvvn oorc
(b)
Kevenue
(c)of
Kevenue Ferl(\/vh SoId(0
1 01GNSVO728. OR GEN SVC DIR u,401 6
2 OlGNSVOT3O - OR GEN SVC DIR 1,902,534 14
O.1GNSVO748 - LG GEN SVC DIR 8,855,568 3
4 01 HABTOO23 - OR HABITAT 3,65S 218,600 0.0597
q 01 HABTBO23 - OR HABITAT 2',|1,304 0.0621
6 OlLGSBOO3O - GEN DEL SRV, > 2OO 877,338 '19
7 01 LGSBOO4S - LG GEN SVC > 1 OOO 83,1 83 1
I 01 LGSVOO3O . OR LRG GEN SRV, >30,033,555 653
o OlLGSVOO4S - 1OOOKWAND OVR 18,828,687 90
10 01LGSV028M - OR LGSV, <1000 Kw 522 46,903 1 522,004 0.0899
11 01LGSVO48M. LRG GEN SRVC 1 60,556 3,833,1 90 1 60,556,000 0.0633
12 OlLNXOO1OO - LINE EXT 60% G 1,841
13 OlLNXOO102 - LINE EXT 80% G 742,408
14 011NX00103 - LINE EXT 80o/o G 8,706
15 01LNXOO105. CNTRCT $ MIN GTY 1't,371
16 OlLNXOO109 - REF/NREF ADV +1,189,'t52
17 OlLNXOO1 1O - REF/NREF ADV +7,104
18 OlLNXOO120 - LINE EXT 60% GTY 1,353
19 011NX00300 - L|NE EXT 80% cTY 257,553
20 01LNXOO311 - LINE EXTSO% GTY 201,338
21 OlLPRSO4TM - PART REQ SRVC 4',t,592 4,179,797 5 8,318,400 0.1 005
22 01NM23T135 - OR NET MTR TOU 569
23 01NMT23135 - OR NET MTR, GEN,317,149 372
24 01NMT28135 - OR NET MTR, GEN,1,494,761 204
25 01NMT3O135 - OR NET MTR, GEN,1,428,438 30
26 01NMT48135 - NET MTR GEN SVC 410,990 '1
27 OlOALTO.I5N - OUTD AR LGT NR 5,289 787,514 2,764 1,914 0.1489
28 OlOALTBI5N - OR OUTD AR LGT 1,414 239,290 1,028 1,375 0.1692
29 01 PTOUOO23 - OR GEN SRV, TOU 2,982 178,579 0.0599
30 OlPTOUBO23 - OR GEN SRV, TOU 440 27,197 0.0618
31 OlRCFLOOs4 - REC FIELD LGT 1,433 142,401 105 13,648 0.0994
32 OlRENWOO23 - OR RENW USAGE 12,750 772,586 0.0606
33 OlRENWBO23 - OR RENEWABLE 54 3,408 0.0631
34 OlSTDAYO23 - OR DAY STD OFR,3,626 230,650 0.0636
35 OlSTDAYO2S - OR DAY STD OFF,14,482 931,090 0.0043
36 OlSTDAYO3O - OR STD DAY OFF 5,634 324.937 0.0577
37 01V1R23136 - OR VOL INC <= 30 193,338 124
38 01v|R28136 - OR VOL INC > 30 KW 604,257 90
39 01vtR30136 - OR VOL tNC > 200 314,232 I
40 01vtR48136 - OR VOL tNC > 1000 1 18,084 1
41 TOTAL BiI|ed 55,333,51:4,748,894,747 1 ,899,813 29J2e 0.0858
42 Total Unbilled Rev.(See lnstr.6)-218,05i -26,093,000 0 (0.1197
43 TOTAL 55,115,45€4,722,801,747 1,899,813 29,011 0.0857
FERC FORM NO. 1 (ED. 12-95)Page 304.6
Per DAIES)tomer
Name of Respondent
PacifiCorp Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of cuslomer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in lhe sequence followed in "Electric Operating Revenues," Page
300-301. lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
cuslomers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the yeat (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause stale in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Ltne
No.
NUmDer ano ilIle oI KaIe scneoute
(a)
MWn \joto
(b)
Kevenue
(c)
KWNPer (!;alesstomer Revenue HerK\A/tr Sold(0
1 REVENUE-ACCT ADJ -1,008,534
2 INCOME TAX DEFERRAL ADJ -18,675,614
?OR GAIN ON SALE OF ASSET 10,313
4 DSM REVENUE-COMMERCIAL 13,154,714
C BLUE SKY REV-COMMERCIAL 505,539 100
SOLAR FEED-IN REVENUE 1,724,899
7 UNBILLED REVENUE -104,235 -8,921 ,000 0.0856
I
I UTAH
10 OSABL-NRES . APPLICANT BUILT -13,884
11 O8CFROOOS1 . MTH FAC SRVCHG 29,955
12 OSCFROOOs2 - ANN FAC SVCCHG 2
13 O8CGNO6136 - UT GEN SVC 199 19,570 1 199,000 0.0983
14 08CGN23136 - UT NET MTR SM 70 7,050 4 17,500 0.1 007
15 OSCOOLKPRN - A/C DIRECT LOAD 2,242
'16 O8GNSVOOO6 - GEN SRVC.DISTR 5,046,693 410,603,001 11,156 452,375 0.0814
17 OSGNSVOOOS. UT GEN SVC TOU >940,1 99 67,007,808 129 7,288,3U 0.0713
18 OSGNSVOOOg. GEN SRVC.HI VO 834,542 46,725,331 40 20,863,550 0.0560
19 OSGNSVOO23 . GEN SRVC-DISTR 1,245,349 120,684,728 73,254 17,000 0.0969
20 OSGNSVOOoA . GEN SRVC-ENERG 246,363 28,544,422 1,947 126,535 0.1 159
21 OSGNSVOOGB . GEN SRVC-DEM&3,397 332,910 14 242,643 0.0980
22 OSGNSVOO6M . MNL DIST VOLTG 197 1 5,1 02 1 65,667 0.0767
23 OSGNSVOOSM - UT GEN SVC TOU >'t7,317 1,41'1 ,916 a 5,772,333 0.0815
24 OSGNSVOOgA - GEN SRVC HI VO 27,185 1,774,054 2 13,592,500 0.0653
25 OSGNSVOOgM - MANL HIGH VOLT 246,182 13,783,909 1 246,182,004 0.0560
26 OSGNSVO23F - GEN SRVC FIXED 1,313 183,984 129 't0,178 0.1401
27 OSGNSVO23M - GNSV DIST VOLT 365 28,632 7 52,143 0.0784
28 OSGNSVOoAM . MNL ENERGY TOD 479 46,',!94 1 479,00C 0.09M
,o OSGNSVO6MN - GNSV DISTVOLT 34,045 2,646,215 580 58,698 0.0777
30 OSLNXOOOO2. MTHLY 8OO/O GUAR 561,844
3't OSLNXOOOO4 - ANNUAL 8O%GUAR 60,728
32 OSLNXOOOOo. FIXD MTHLY MIN 2,462
33 OSLNXOOO14 - 80% MIN MNTHLY 1,744,673
34 OSLNXOOOl 7 - ADV/REF&80%ANN 267,385
AE O8LNXOO158 - ANNUALCOST MTH 32,125
36 OSLNXOO3OO. LINE EXT 8O7O PLUS 176,493
37 OSLNXOO3IO - IRR, 80% ANNUAL 53,694
38 081NX0031 1 - LINE EXT 80o/o 287 j6A
'lo O8LNXOO312. UT IRG LINE EXT 13,126
40 OSMONLOO1 5 . MTR OUTDONIGHT 14,782 1,064,872 526 28,103 0.0720
41 TOTAL BiI|ed 55,333,513 4.748.894.747 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,057 -26,093,00C 0 c 0.1 197
43 TOTAL 55,115,45€4,722,801,747 1 ,899,813 29,011 0.0857
FERC FORM NO. r (ED. r2.95)Page 304.7
I his REDO(1) 5ln(2) l-lA
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn originat(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effecl during the year the MWH of electricity sold, revenue, average number of customer, average Kwt per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1.
2. Provide a subheading and tolal for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. lfthe sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an ofi peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 it
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Reportamountofunbilledrevenueasofendofyearforeachapplicablerevenueaccountsubheading.
Ltne
No.
r\umoel ano I tlte oI KaIe scneoute
(a)
MWN UOIO
(b)
Hevenue
(c)
AVVN OI DAESPer Customer(e)
Kevenue FetKWh Sold(0
1 O8NMTO6135 - UT NET MTR GEN 122,344 10,292,047 261 468,751 0.0841
2 O8NMTO8135 - NET MTR GEN SVC 112,048 7,837,640 12 9,337,333 0.0699
J 08NMT23135 - UT NET MTR, GEN,8,907 942,388 759 11,735 0.1058
4 O8NMT6A135 - NET MTR GEN SVC 9,',t27 1,218,024 83 109,964 0.1335
5 OSOALTOOTN - SECURITY AR LG 7,464 1,702,529 3,975 1,878 0.2281
6 OSPOLEOOTS - POLES WLIGHT 141 1
7 OSPRSVO31M - BKUP MNT&SUPPL 1 15,648 7,355,799 4 28,912,000 0.0636
8 OSPTLDOOON - POST TOP LIGHT 6 452 2 3,000 0.0753
I OsSSLROOO6 - GEN SVC SUBSCR 3,834 437,376 11 348,545 0.1141
'10 OSSSLROO23 - SM GEN SVC 3,484 380,511 0.1092
11 OSSSLROOoA - GEN SVC TOU 42,492 4,048,415 309 137,515 0.0953
12 08TOSS0015 - TRAF &amp; OTHER 3,029 314,158 1,035 2,927 0.'t 037
13 O8TOSSO15F. TRAFFIC SIG NM 171 15,257 20 8,550 0.0892
14 REVENUE-ACCT ADJ -769,265
'15 REVENUE ADJ - DEF NPC 676,337
16 DSM REVENUE-COMMERCIAL 2,809,040
17 BLUE SKY REV-COMMERCIAL 245,758
18 SOLAR FEED-IN REVENUE 2,488,770
19 UNBILLED REVENUE 4,761 -1,271 ,000 -0.2670
20
21 WASHINGTON
22 O2GNSBOO24 . WA GEN SRVC DO 28,460 2,860,111 1,510 18,848 0.1 005
23 O2GNSBO24F - GEN SRVC DOM/F 154 20,454 6 25.667 0.1 328
24 O2GNSB24FP - WA GEN SVC 178 84,000 76 2.342 0.4719
25 O2GNSVOO24 - WA GEN SRVC 480,239 45,912,256 14,246 33,710 0.0956
26 O2GNSVO24F - WA GEN SRVC-FL 1,070 153,783 104 10,288 0.1437
27 O2LGSBOO36 - LRG GEN SVC IRG 58,621 4,936,584 96 610,635 0.0842
28 O2LGSVOO36. WA LRG GEN SRV 776,241 63,446,762 860 902,606 0.08'17
29 O2LGSVO48T. LRG GEN SRVC 1 192,658 14,504,460 35 5,504,514 0.0753
30 021NX00102 - L|NE EXT 80% c 53,457
31 O2LNXOO103 - LINE EXT 80% G 10,724
32 021NX00105 - CNTRCT $ MtN G 'l,742
33 O2LNXOO109. REF/NREF ADV +278,734
34 O2LNXOO1 1O - REF/NREF ADV +31 ,164
35 O2LNXOO1 12 - YR INCURRED CH 669
36 021NX00300 - L|NE EXT 80% c 7,766
37 O2LNXOO311 - LINE EXT 8OO/O GTY 51,2',t5
38 O2LNXOO312 - WA IRG LINE EXT 12,500
39 02NM824135 - WA NET METERING 16 2,803 6 2,667 0.1752
40 02NMT24135 - NET MTR, WA 3,300 323,122 89 37.079 0.0979
41 TOTAL BiIIed 55,333,513 4,748,894,747 1 ,899,81:29,12e 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,05't -26,093,000 (c 0.1 1 97
43 TOTAL 55,115,45€4,722,801,747 1 ,899,81:29,01 1 0.0857
FERC FORM NO.1 (ED. 12-95)Page 304.8
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn orisinal(2) -A Resubmission
Date of Reoort(Mo, Da, Yi)
tt
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. \Mere lhe same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year ('12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
NUmDer ano lme oI RaIe scneoule
(a)
MVVn 50tO
(b)
F<evenue
(c)
KWNPer (salesstomer KEVENUE PETl(Vvh Sold(D
1 02NMT36135 - WA NET MTR LRG 10,756 935,602 14 768,286 0.0870
2 02NMT48135 - WA LG SVC NET 10,591 795,715 2 5,295,500 0.0751
?O2OALTOISN . WA OUTD AR LGT 1,457 215,657 770 1,892 0.1480
4 O2OALTBISN - WA OUTD AR LGT 510 82,571 467 1,092 0.'1619
E O2RCFLOOS4 - WA REC FIELD L 280 26,775 27 10,370 0.0956
6 REVENUE_ACCT ADJ -9,563,913
7 REVENUE ADJ. DEF NPC 56,695
I INCOME TAX DEFERRAL ADJ -3,056,273
c ALT REVENUE PROGRAM ADJ -2,552,754
1C DSM REVENUE-COMMERCIAL 4,231,357
1',l BLUE SKY REV.COMMERCIAL 15,505 ,|
12 UNBILLED REVENUE 3,152 275,00C 0.0872
13
14 WYOMING
15 OSCHCKOOON - \AAT NRES CHECK 1
16 OsGNSVOO2s - \^ll/ GEN SRVC 220,598 21,629,435 17,915 't2.314 0.0980
't7 OsGNSVOO2S - GEN SVC > 15 KW 854.347 71,792,687 3,177 268,916 0.0840
18 OsGNSVO2sF - GEN SRVC-FL RA 996 159,475 174 5,724 0.1601
19 O5LGSVOO46 - \AA/ LRG GEN SRV 159,566 11,341,707 14 11,397 ,571 0.0711
20 OsLGSVO4ST - LRG GENSRV TIM 11,480 905,538 1 11,480,000 0.0789
21 OsLNXOOlOO - LINE EXT 60% GTY 14,972
22 OsLNXOO102. LINE EXT 80% GTY 590,699
23 051NX00103 - LINE EXT 80o/o GTY 128
24 O5LNXOO1Os - CNTRCT $ MIN GTY 5,350
25 OsLNXOO109. REF/NREF ADV +394,435
26 O5LNXOO1 1O . REF/NREF ADV +5,280
27 O5LNXOO1 14. TEMP SVC 12MO>u1
28 OSLNXOO3OO. LINE EXT 80% GTY 125,219
29 OsLNXOO31O. LINE EXT 5,276
30 051NX0031 1 - L|NE EXT 80% GTY 48,673
31 OsLNXOO312 - \MT IRG LINE EXT 5,330
32 05NMT25135 . WY NET MTR, GEN 338 u,212 32 10,563 0.1012
33 05NMT28135 - NET MTR SM GEN 7,853 660,620 22 356,955 0.0841
34 O5OALTOISN - OUTD AR LGT SR 2,572 359,958 1,580 1,628 0.1400
35 OSRCFLOOs4 - \MT REC FIELD L 848 58,801 5S 't4,373 0.0693
36 OgOALT2OTN . SECURITY AR LG 7
37 REVENUE-ACCT ADJ 218,710
38 REVENUE ADJ - DEF NPC -107,965
39 INCOME TAX DEFERRAL ADJ -1,026,277
4A DSM REVENUE-LARGE 60,511
41 IOTAL BiI|ed 55,333,513 4,748,894,747 1 ,899,813 29,12e 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,057 -26,093,000 0 c 0.1 19i
43 TOTAL 55,1 't 5,456 4,722,801 ,747 1 ,899,813 29,011 0.085i
FERC FORil NO. I (ED.12-95)Page 304.9
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5l1Rn orisinal(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICIW BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 31 0-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in lhe same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denole the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Ltne
No.
r\umoer ano r rue oI KaIe scneoure
(a)
MVVn OO|O
(b)
F(evenue
(c)of xIfls"o6"'
(D
1 DSM REVENUE-SMALL 2,868,730
2 BLUE SKY REV-COMMERCIAL 9,523
2 UNBILLED REVENUE 28,079 2,173,000 0.0774
4 OSGNSVOO2s - \AAT GEN SRVC 29,660 2,909,061 2,403 12,343 0.0981
5 OsGNSVOO2S - GEN SVC > 15 KW 89,653 7,595,986 387 231,661 0.0847
6 OsGNSVO2sF. GEN SRVC-FL RA 199 24,922 33 6,030 0.1252
7 O5LNXOO102 - LINE EXT 80% GTY 114,481
8 OSLNXOO109 - REF/NREF ADV +148,631
o OSLNXOO3OO - LINE EXT 80% GTY 6,603
10 O5LNXOO31 1 - LINE EXT 8OO/O GTY 6,201
11 05NMT25135 - WY NET MTR, GEN,133 10,61 1 E 26,600 0_0798
12 05NMT28135 - NET MTR SM GEN 434 37,536 2 217,000 0.0865
13 OgMONLO213 - \AAT MTR OUTD 324 18,813 12 27,000 0.0581
14 OgOALT2OTN - SECURITY AR LG 274 57.811 139 1,971 0.2110
'15 DSM REVENUE-SMALL 331,835
16 BLUE SKY REV-COMMERCIAL 605
17 UNBILLED REVENUE 2,483 199,000 0.0801
18
'19 LESS MULTIPLE BILLINGS -24,039
20
21 TOTAL COMMERCIAL SALES 1 8,078,1 60 1,541,492,719 21 1,800 85,355 0.0853
22
23 INDUSTRIAL SALES
24 CALIFORNIA
25 O6GNSVOO25 . CA GEN SRVC 564 105,958 85 6,635 0.1 879
26 O6GNSVOA32. GEN SRVC-2o KW 2,831 464,244 21 134,810 0.1640
27 O6LGSVO4ST - LRG GEN SERV 48,951 5,201,914 9 5,439,000 0.1063
28 O6LGSVOA36. LRG GEN SRVC.O 5,744 792,492 13 44',1,846 0.1380
29 REVENUE-ACCT ADJ -'139,54'1
30 INCOME TAX DEFERRAL ADJ -247,337
31 DSM REVENUE-INDUSTRIAL 87,896
32 BLUE SKY REV-INDUSTRIAL 282
33 SOLAR FEED.IN REVENUE 1,283
34 UNBILLED REVENUE -1,094 -134,000 0.1225
35
36 IDAHO
37 OTCFROOOO1 - MTH FACILITY S 2,217
38 OTCISHOO19 - COMM & IND SPA 19 1 ,810 1 19,000 0.0953
20 OTGNSVOOOo - GEN SRVC.LRG P 90,1 95 6,410,789 102 884,265 0.0711
40 OTGNSVOOOg - GEN SRVC.HI VO 74,941 4,897,655 14 5,352,929 0.0654
41 TOTAL BiIIed 55,333,51:4,748,894,747 1,899,813 29J2e 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,057 -26,093,000 c c 0.1 '197
43 TOTAL 55,1 15,45€4,722,801 ,747 1,899,813 29.011 0.0857
FERC FORM NO. I (ED. 12-95)Page 304.10
Per
Sates
stomer
PacifiCorp Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 31 0-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. lfthe sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Vvhere the same customers are seryed under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Ltne
No.
NumDer ano lrtle ol Rale scheoule
(a)
MVVn OOrq
(b)
Revenue
(c)
KWNPer (5atesstomer Kevenue Hert(Wh Sold(0
1 OTGNSVOO23 - GEN SRVC-SML P 16,923 1,598,940 312 54,240 0.0945
2 OTGNSVOO6A - GEN SRVC-LG P 3,48C 29',t,387 23 151 ,304 0.0837
3 OTGNSVO23A - GEN SRVC.SML P 2,095 216,161 140 14,964 0.1 032
4 OTGNSVO23S - ID TRAFFIC E 612 1 5,000 0.1224
5 OTLNXOO1OS . ANN COST MTHLY 1,996
6 O7LNXOO311 - LINE EXT 80% GTY 635
OTOALTOOTN . SECURITY AR LG 13 4,964 16 813 0.3818
e OTOALTOTAN - SECURITY AR LG 134
o OTSPCLOOO,I 1,524,300 93,971 ,100 1 1,524,300,000 0.0616
10 OTSPCLOOO2 1',t7,004 6,967,437 1 1 17,004,000 0.0595
11 REVENUE-ACCT ADJ 19,661
12 INCOME TAX DEFERRAL ADJ -2,010,292
13 DSM REVENUE-INDUSTRIAL 166,988
14 BLUE SKY REV-INDUSTRIAL 4
15 UNBILLED REVENUE 11,462 219,000 0.0191
'16
17 OREGON
18 01COSTOO23. OR GEN SRV CST 18,018 1,076,744 0.0598
1S 01 cosT0048 - 01 LGSV0048 1,31 1,580 65,512,880 0.0499
2A OlCOSTO23F - OR GEN SRV -1 65 0.0650
21 OlCOSTBO23 - OR GEN SRV,119 7,148 0.0601
22 OlCOSTLO3O. OR LRG GEN SRV,181,008 9,587,167 0.0530
OlCOSTSO2S - OR GEN SERV 92,06S 5,653,35C 0.0614
24 OlGNSBOO23 - OR GEN SRV, BPA 8,25C 12
25 01GNSBOO28. OR GEN SRV, BPA 7,337 2
26 OlGNSVOO23 - OR GEN SRV, < 30 1,011,389 973
27 OlGNSVOO2S - OR GEN SRV > 30 3,428,045 437
28 OlGNSVO23F - OR GEN SRV - FLAT 2 692 2 1,000 0.3460
29 OlGNSVO23M - OR GEN SRV 311 ,|
30 OlGNSVO23T - OR GEN SRV, TOU 2,863 a
3't 01GNSVO748 - LG GEN SVC DIR 2,697,222 4
32 OlLGSVOO3O - OR LRG GEN SRV, >6,962,273 129
33 OlLGSVOO4S - lOOOKWAND OVR 24,377,920 82
34 O1LGSVO4SM - LRG GEN SRVC 1 70.21e 5,210,879 23,405,333 0.0742
35 01 LNXOO102 . LINE EXT 80% GTY 126,733
36 O1 LNXOO109 . REF/NREF ADV +85
37 OlLNXOO3OO. LINE EXT 80%13,488
38 OlLPRSO4TM - PART REQ SRVC 2,280 1 ,1 40,1 83 1 2,280,000 0.5001
39 01NMT23135 - OR NET MTR, GEN,3,437 4
4A 01 NMT28135 - OR NET MTR, GEN 50,298 6
41 IOTAL BiIIed 55,333,513 4,748,894,747 1 ,899,813 29J2e 0.0858
42 Total Unbilled Rev.(See lnstr.6)-218,05i -26,093,000 c (0.'l 1 97
43 TOTAL 55,'1 '15,45€4,722,801,747 I ,899,813 29,0't 1 0.0857
FERC FORM NO.1 (ED. r2.95)Page 304.11
This Repo(1) EA(2) l-lA
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn original(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
cuslomers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Ltne
No.
r\umoer anq ilIre oT KaIe scnequre
(a)
MWn lioto
(b)
f<evenue
(c)
nvvn
Per (Kevenue rerl(Vvh Sold
(D
1 01NMT3O135 - OR NET MTR, GEN,40,720 1
2 OlOALTO1SN - OUTD AR LGT NR 273 39,675 123 2,220 0.1453
3 OlOALTB15N - OR OUTD AR LGT 2 505 4 750 0.1 683
4 OlPTOUOO23 - OR GEN SRV, TOU 45 2,U6 0.0632
5 01RENWOO23. OR RENW USAGE 46 2,888 0.0628
6 OlSTDAYO2S - OR DAY STD OFF,668 43,690 0.0654
7 01 STDAYO4S - 01 LGNSVO4S 533 24,U2 0.0457
I 01V1R23136 - OR VOL INC <= 30 973 1
I 01vtR28136 - OR VOL tNC > 30 KVV 32,175 2
10 01vtR30136 -OR VOL |NCE > 200 45,503 1
11 REVENUE-ACCT ADJ -1,653,457
12 INCOME TAX DEFERRAL ADJ -6,558,374
13 OR GAIN ON SALE OF ASSET 4,010
14 DSM REVENUE-INDUSTRIAL 936,656
'15 BLUE SKY REV-INDUSTRIAL 305,737 35
'16 SOLAR FEED.IN REVENUE 1,085,788
17 UNBILLED REVENUE -7,336 -749,000 0.1021
18
'19 UTAH
20 OSCFROOOS1 - MTH FAC SRVCHG 18,561
21 OSEFOPOO2l - ELEC FURNACE O 1,011 109,981 2 505,500 0.1088
22 OSEFOPO21M - ELEC FURNACE O 878 1 38,1 07 2 439,000 0.1 573
23 OSGNSVOOOo - GEN SRVC-DISTR 635,365 53,397,151 985 645,04'1 0.0840
24 OSGNSVOOOS - UT GEN SVC TOU >972,562 71,411,295 97 10,026,412 0.0734
25 OSGNSVOOOg - GEN SRVC-HI VO 2,916,563 159,767,222 106 27,514,745 0.0548
26 OSGNSVOO23 - GEN SRVC-DISTR 52,435 5,144,967 3,1 85 16,463 0.0981
27 OSGNSVOO6A - GEN SRVC-ENERG 52,270 6,'t50,226 233 224,335 0.1177
28 OSGNSVOO6B - GEN SRVC-DEM&2 725 0.2417
29 OSGNSVOOSM - UT GEN SVC TOU >29,305 2,405,173 4 7,326,250 0.0821
30 OSGNSVOOgA - GEN SRVC HI VO 17,358 1,533,234 7 2,479,714 0.0883
31 OSGNSVOOgM - MANL HIGH VOLT 715,006 37,247,875 10 71,500,600 0.0521
32 O8GNSVO23F. GEN SRVC FIXED 4 2,767 ,|4,000 0.6918
33 OSGNSVOoAM - MNL ENERGY TOD 242 30,610 2 121 ,000 0.1265
34 OSGNSVO6MN - GNSV DIST VOLT 1 ,1 '19 99,073 24 46,625 0.0885
35 OSLNXOOOO2 - MTHLY 80% GTY 681 ,986
36 OSLNXOOO14 - 80% MIN MNTHLY 8,035
37 OSLNXOOOl 7 - ADV/REF&80%ANN 638
38 OSLNXOO3OO - LINE EXT 80% PLUS 39,252
20 OSMONLOOl5 - MTR OUTDONIGHT 13 2,053 6 2,167 0.1579
40 O8NMTO6135 - UT NET MTR, GEN 2,244 206,122 6 373,333 0.0920
41 TOTAL BiI|ed 55 4,748,894,747 1 1 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,05i -26,093,000 C (0.1 1 97
43 TOTAL 55, 1 '15,45t 4,722,801,747 1,899,81:29,01 0.0857
FERC FORM NO.1 (ED.12-95)Page 304.'12
Jdte5itomer
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Reporl
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales dala under each
applicable revenue account subheading.
3. Wrere the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Lrne
No.
NUmOer anq I tlte oI KaIe scneoute
(a)
MVVn 50tO
(b)
Kevenue
(c)
Averaoe NumDer
of cisllomers KWnPer (
I
Kevenue Herlovh Sold
(f)
1 08NMT23135. UT NET MTR, GEN,177 20,349 16 11,063 0.1 1 50
2 O8NMT6A135. NET MTR GEN SVC 3,894 553,968 13 299,538 0.'t423
3 OSOALTOOTN - SECURITY AR LG 1,062 221,654 412 2,578,0.2087
4 OSPRSVO3lM - BKUP MNT&SUPPL 56,836 4,026,685 18,945,333 0.0708
E 08sPc10001 618,434 32,222,232 1 618,434,000 0.0521
b 08sPcL0002 781,605 35,565,034 I 781,605,000 0.0455
7 08sPcL0003 1,260,82C 59,292,818 1 1,260,820,000 0.0470
8 OSSSLROOOo. GEN SVC SUBSCR 22C 21,489 1 226,000 0.0951
o OSSSLROO23 - SM GEN SVC 156 18,428 19 8,21',!0.'1 1 81
10 OSSSLROO6A - GEN SVC TOU 12,26C 1,077,803 29 422,759 0.0879
11 08TOSS0015 - TRAF &amp; OTHER 2',l 2,420 11 1,909 0.1't52
12 REVENUE-ACCT ADJ -165,528
13 REVENUE ADJ - DEF NPC 492,340
14 DSM REVENUE-INDUSTRIAL 2,594,083
15 BLUE SKY REV.INDUSTRIAL 04,973 7
't6 SOLAR FEED-IN REVENUE 2,293,588
't7 UNBILLED REVENUE -'t45,231 -8,282,000 0.0570
18
4a WASHINGTON
2A O2GNSBOO24 - WA GEN SRVC DO 1 ,015 1 10,649 43 23,605 0.1090
21 O2GNSB24FP - WA GEN SVC 6 2,545 1 6,000 0.4242
22 O2GNSVOO24 - WA GEN SRVC 14,977 1,454,615 327 45,801 0.0971
23 O2GNSVO24F - WA GEN SRVC-FL 33 8,877 4 8,250 0.2690
24 O2LGSBOO36. LRG GEN SVC IRG 't,337 174,643 I 148,556 0.1 306
25 O2LGSVOO36 - WA LRG GEN SRV 97,456 8,306,800 96 1,015,167 0.0852
26 O2LGSVO48T. LRG GEN SRVC 1 598,035 40,172124 30 19,934,500 0.0672
27 O2LNXOO103. LINE EXT 80% Gry 25,144
28 O2OALTO1SN - WA OUTD AR LGT 96 13,175 37 2,595 0.1372
29 O2OALTB1SN - WA OUTD AR LGT 27 4,191 14 1,929 0.1552
30 O2PRSV4TTM - LRG PART REQMT 2,533 399,1 1 2 1 2,533,000 0.1576
31 REVENUE-ACCT ADJ -4,309,285
5t REVENUE ADJ . DEF NPC 30,048
33 INCOME TAX DEFERRAL ADJ -1,601 ,330
34 ALT REVENUE PROGRAM ADJ -169,071
AE DSM REVENUE-INDUSTRIAL 1 ,549,61S
36 BLUE SKY REV-INDUSTRIAL 2e,2
37 UNBILLED REVENUE -29, t 10 -2,726,00C 0.0936
38
39 WYOMING
40 OsGNSVOO2s - WY GEN SRVC 29,408 2,521,06C 1,182 24,880 0.0857
41 TOTAL BiI|ed 55,333,5'1:4,748,894,747 1 ,899,8'13 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,051 -26,093,000 c (0.1 197
43 TOTAL 55,I 1 5,45€4,722,801,747 1 ,899,813 29,011 0.085i
FERC FORtvl NO. 1 (ED. t2-95)Page 304.13
JAICSitomer
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn originatQ\ TIA Resubmissiontt
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause stale in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
NUmDer ano lrlle oI Kate scneoule
(a)
MWn 50ro
(b)
KEVCNUE
(c)
KWNPer (Kevenue PerK\M Sold(0
1 OsGNSVOO2S - GEN SVC > 15 KW 256,823 18,799,487 442 581,048 0.0732
2 OSGNSVO2SF - GEN SRVC-FL RA 26 4,283 8 3,250 0.'t647
3 OSLGSVOO46 - \Ary LRG GEN SRV 1,669,556 't 09,5't 5,760 57 29,290,456 0.0656
4 O5LGSVO46M . \AA/ LRG GEN SRV 12,108 8s4,284 1 12,108,000 0.0706
5 OSLGSVO4SM . TOU>lOOOKW MAN 297,744 16,723,638 1 297,744,000 0.0562
6 OSLGSVO4ST - LRG GENSRV TIM 1,858,845 103,730,296 11 168,985,909 0.0558
7 05LNX00100 - LINE EXT 60% GTY 23,559
I OSLNXOO102 - LINE EXT 80% GTY 1,152,983
I OSLNXOO105 - CNTRCT $ MIN GTY 44,072
'10 OSLNXOO109 - REF/NREF ADV +192,232
11 OSLNXOO1 1O - REF/NREF ADV +62A
12 OSLNXOO3OO - LINE EXT 80% GTY 81.775
13 O5LNXOO311 - LINE EXT 8OO/O GTY 16,552
14 OsOALTO15N. OUTD AR LGT SR 69 8,754 38 1 ,81€0.1269
15 OsPRSVO33M - PART SERV REQ 1,218,564 80,568,372 I 135,396,000 0.0661
16 REVENUE-ACCT ADJ 950,315
17 REVENUE ADJ . DEF NPC -526,444
18 INCOME TAX DEFERRAL ADJ -5,004,172
19 DSM REVENUE.SMALL 646,906
20 DSM REVENUE-LARGE 1,2'.t6,544
21 BLUE SKY REV.INDUSTRIAL 23
22 UNBILLED REVENUE 68,710 3,481 ,000 0.0507
23 O5GNSVOO2S - WY GEN SRVC 7,341 632,861 284 25,84e 0.0862
24 OSGNSVOO2S - GEN SVC > 15 KW 62,047 4,394,905 73 849,959 0.0708
25 OSGNSVO2SM - GEN SVC > 15 KW 5,343 311,967 3 1,781,00C 0.0584
26 OSLGSVOO46 - \A/Y LRG GEN SRV 21,925 1,524,046 3 7,308,333 0.0695
27 05LGSV048M - TOU>1000KW 152,396 9,145,222 3 50,798,667 0.0600
28 OsLGSVO4ST - LRG GENSRV TIM 1,186,921 72,40s,229 12 98,910,083 0.0610
29 O5LNXOO102 - LINE EXT 80% GTY 446,392
30 OSLNXOO109 - REF/NREF ADV +I ,990,518
31 OsPRSVO33M - PART SERV REQ 99,1 78 6,056,620 2 49,589,000 0.061 1
32 OgOALT2OTN - SECURITY AR LG (879 3 1,667 0.1758
33 DSM REVENUE.SMALL 167,605
34 DSM REVENUE-LARGE 714.553
35 BLUE SKY REV-INDUSTRIAL I
36 UNBILLED REVENUE 12,030 735,000 0.061 1
37
38 LESS MULTIPLE BILLINGS -896
39
40 TOTAL INDUSTRIAL SALES 1 9,1 99,036 '1 ,184,766,80C 9,549 2,010,581 0.0617
41 TOTAL BiI|ed 55,333,513 4,748,894,747 1,899,813 29,126 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-2't8,057 -26,093,000 c c 0.1 '1 97
43 TOTAL 55,1 t 5,45€4,722301,747 1,899,813 29,011 0.0857
FERC FORM NO. 1 (ED. 12-95)Page 304.14
odtYlitomer
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5l1Rn orisinal(2) f]A Resubmission
Date of ReDort(Mo, Da, Yi)
tt
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of cuslomer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue accounl subheading.
3. \Mtere the same customers are served under more than one rate schedule in the same revenue account classificalion (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Ltne
No.
NUmDer ano ilIte oI KaIe scneoute
(a)
MVVn 50tO
(b)
Kevenue
(c)
KWNPer (!iares
stomer
Revenue Herl(VVh Sold(0
1 IRRIGATION SALES
2 CALIFORNIA
I O6APSVOO2O - AG PMP SRVC 12,678 1,797 ,144 754 16,814 0.1418
4 O6APSVO115 - CA AGRI PUMP TOU 178 21,784 z.89,000 o.'t224
q O6APSVO2OL - AG PMP SRVC-NO 50,474 7,335,742 596 84,688 0.1453
6 O6APSV1.I5L . CA AGRI PUMP TOU 566 81,893 o 62,889 0.1447
7 O6LGSVO48T. LRG GEN SERV 829 113,795 1 829,000 0.1 373
I O6LNXOO103 - LINE EXT 80% GTY 4,515
c O6LNXOOl09 - REF/NREF ADV +649
1C OoLNXOO,I ,10 . REF/NREF ADV +41.731
1'.!061NX00310 - tRG, 800/o AN MtN +4,672
12 O6LNXOO312 - CA IRG LINE EXT 25,324
13 O6NML2O135. AGRI PUMP-NET 1,402 249,544 '18 77,889 0.1 780
14 O6NMT2O135 - AGRI PUMP-NET 1,46C 1
15 O6USBROO2O - KLAM IRG ONPRJ 4,376 732,601 268 16,328 0.1674
16 O6USBRO,I15 - CA AGR PMP TOU 26 4,275 2 13,000 0.1644
17 O6USBRO2OL - KLAM IRG ONPRJ 16,228 2,667,561 345 47,038 0.'t644
18 O6USBRI 151 - CA AGR PMP TOU 607 88,584 o 67,444 0.1459
19 INCOME TAX DEFERRAL ADJ -341,45e
20 REVENUE-ACCT ADJ -343,275
21 DSM REVENUE-IRRIGATION 271.088
22 BLUE SKY REV-IRRIGATION 4C
23 SOLAR FEED-IN REVENUE 2,97A
24 UNBILLED REVENUE 1,045 59,000 0.0565
25
26 IDAHO
27 OTAPSAO1OL. IRG & PUMP LG 366,764 33,777,36e 2,521 145.4U 0.0921
28 OTAPSAO1OS - IRG & PUMP SM 6,103 647,530 340 17,950 0.1061
29 OTAPSAL1OX. IRG & PUMP - LG 186,927 17,447,403 1,662 112,471 0.0933
30 OTAPSAS1OX. IRG & PUMP - SM 6,71S 745,258 491 't 3,684 0.1 1 09
31 OTAPSNO1OL - ID LG IRR & PUMP 5,810 531 ,815 34 170,882 0.0915
32 OTAPSNO1OS - IRR, SM 3 PH 17 2,719 4 4,250 0.1599
33 OTAPSNS1OX - IRR, SM, 3 PHASE 205 24,401 15 13,667 0.1 1 90
34 OTAPSVOOoA - LRG POWER OPT 232 21,984 1 232,000 0.0948
35 O7APSVO23A. SM POWER OPT 98 10,027 4 24,500 0.1023
36 OTAPSVCNLL - LRG LOAD CANAL 12,882 1,075,465 37 348,162 0.0835
37 OTAPSVCNLS. SM LOAD CANAL 27 4,504 11 2,455 0.1668
38 O7GNSVO23A. GEN SRVC-SM 128 11,537 1 128,000 0.0901
39 071NX00015 - ANN 80o/o GTY 72,426
40 071NX00035 - ADV 800/o MO GTY 1,847
41 TOTAL BiIIed 4.748.894,747 29,12f 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,05i -26,093,000 c (0.1 197
43 TOTAL 55,1 1 5,45(4,722,801,747 1,899,81:29,01 0.0857
FERC FORM NO. r (ED. 12.95)Page 304.15
55,333.51
PacifiCorp (1)
(2',)Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. \Mere the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Ltne
No.
r\umoer ano ilIte oI KaIe scneoute
(a)
MVVn DO|O
(b)
Kevenue
(c)
Average NumDer
of C1s;fiomers
KWnPer (t,atesstomer Kevenue Herl(VVh Sold
(D
1 OTLNXOOO4O - ADV+REFCHG+80%132,200
2 O7LNXOO312 - ID LINE EXT 61,782
2 REVENUE-ACCT ADJ -170,806
4 INCOME TAX DEFERRAL ADJ -6'17,683
5 DSM REVENUE-IRRIGATION 1,428,635
6 BLUE SKY REV.IRRIGATION 23
7 UNBILLED REVENUE 82 4,000 0.0488
8
o OREGON
'10 O1APSVOO41 . AG PMP SRVC BP 1,476,626 2,647
11 O1APSVO215. OR IRR TOU PILOT 't9,707 11
12 O1APSVO41L. OR PUMP SRV 2,383,552 753
13 O1APSVO4IT - AGR PUMP 30,766 55
14 O1APSVO41X - AG PMP SRVC 1,173,982 2,257
15 O1APSV41XL - OR PUMP SRV no 1,841,058 423
16 01cosT0041 - AG PMP 137,140 8,246,356 0.0601
17 01 cosT0048 - 01 LGSV0048 114,827 5,796,631 0.050s
18 01cosT0215 - oR TOU PTLOT 4,067 182,953 0.0450
19 OlCSTUSB4l - USBR IRR 65,405 3,927,323 0.0600
20 OlGNSVO23T - OR GEN SRV, TOU 453 1
21 OlHABITO4I - OlAPSVOO41 AG o 543 0.0603
22 O1LGSBOO4S - LG GEN SVC >1,024,400 3
23 OlLGSVOO4S - lOOOKWAND OVR 1,345,489 3
24 OlLNXOO103 - LINE EXT 80% GTY 29,727
25 OlLNXOOl09 - REF/NREF ADV +7e
26 O1 LNXOOl 1 O - REF/NREF ADV +142,944
27 OlLNXOO31O - LINE EXT 13,461
28 01LNXOO312 - OR IRG LINE EXT 31,4',t7
29 01NMT41135 - NETMTR AG PMP 26,821 23
30 01NMU41 135 - OR NET MTR -29,915 't2
3t OlPTOUOO23 - OR GEN SRV, TOU 7 449 0.0641
32 01PTOU0041 - 01APSV0041 AG 610 36,338 0.0596
33 OlRENEWO41 - O1APSVOO41 AG 158 9,691 0.0613
34 OlSTDAYO41 - DAILY STANDARD 159 11,087 0.0697
35 01USBRO215 - OR IRG TOU PILOT 147,546 lb
36 O1USBRGV41 - IRG TOU WO BPA 52,187 I
37 OlUSBROF41 - KLAMATH BASIN 1,250,657 479
38 OlUSBRON41 - KLAMATH BASIN 1,710,245 1,115
39 01vlR41 136 - OR VOLTNC-AGR|56,256 26
40 01VRU41136 - OR VOL INCE USB 354,847 104
4',!TOTAL BiIIed 55,333,513 4,748,894,747 1 ,899,813 29,12e 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,057 -26,093,00C c (0.1 1 97
43 TOTAL 55,115,456 4,722301,747 1,899,813 29,9'.t1 0.0857
FERC FORM NO. I (ED. 12-95)Page 304.16
ort ls:
An Original
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]nn originat(2) [A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricily sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. \Mere the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year ('12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Reportamountofunbilledrevenueasofendofyearforeachapplicablerevenueaccountsubheading.
Line
No.
NUmDer ano ilIte oI KaIe scnequre
(a)
MWn 50to
(b)
Kevenue
(c)of
AWN OI DAleSPer Customer(e)WffiS%fd''(0
1 01VRU41215 - OR VOL INC USB 37,912 6
2 REVENUE-ACCT ADJ -83,854
3 INCOME TAX DEFERRAL ADJ -1,083,348
4 OR GAIN ON SALE OF ASSET 128
5 DSM REVENUE.IRRIGATION 658,311
6 BLUE SKY REV-IRRIGATION 269
7 SOLAR FEED-IN REVENUE 47,272
8 UNBILLED REVENUE 17,394 1,822,000 0.1047
o
10 UTAH
11 OSAPSVOO1O - IRR & SOIL DRA 231,433 16,482,207 3,045 76,004 0.0712
12 OSAPSV1ONS - IRR LG SOIL DRAIN 34,913 2,386,353 265 131,747 0.0684
13 081NX00004 - ANN 80% GTY 7,572
14 OSLNXOOO14 - 80% MIN MNTHLY 6,1 98
15 OSLNXOOOl 7 - ADV/REF&8o%ANN 176,274
16 OSLNXOO31O - IRR, 80% ANNUAL 24,584
17 081NX0031 1 - L|NE EXT 80% GTY 496
18 O8LNXOO312. UT IRG LINE EXT 19,977
,tc OSNMTO1ONS - IRR & SOIL DRAIN 329 29,331 3 109,667 0.0892
20 O8NMT10135 - UT IRR.SOIL DRNG 7,800 567,004 45 173,333 0.0727
21 REVENUE-ACCT ADJ -13,852
22 REVENUE ADJ - DEF NPC 17,44C
23 DSM REVENUE-IRRIGATION 73,003
24 SOLAR FEED-IN REVENUE 64,505
25 UNBILLED REVENUE -495 -37,000 0.0747
26
27 WASHINGTON
28 O2APSVOO4O. WA AG PMP SRVC 106,59C '10,101,606 2,942 36,230 0.0948
29 O2APSVO4OX - WA AG PMP SRVC 59,745 5,729,113 2,2't7 26,94e 0.0959
30 021NX00102 - LINE EXT 80o/o GTY 2.711
31 O2LNXOO103 - LINE EXT 8OO/O GTY 7,567
32 O2LNXOO105 - CNTRCT $ MIN Gry 76
33 O2LNXOO109 - REF/NREF ADV +2,601
34 O2LNXOO1lO - REF/NREF ADV +173,417
.E 021NX00310 - lRG, 80% ANN MIN +3,599
36 O2LNXOO3.l2 - WA IRG LINE EXT 29,402
37 O2NMT4O135 - WA NET MTR-IRG 226 22,370 o 25,',!11 0.0990
38 O2NMX4O135. WA NET MTR.IRG 2 837 I 1,000 0.4185
ec REVENUE_ACCT ADJ -1,176,625
4C REVENUE ADJ - DEF NPC 5,&44
41 TOTAL BiIIed 4,748.894.747 1 ,899,813 29j2e 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,osi -26,093,000 c (0.1197
43 TOTAL 55,115,45(4,722,801,747 1,899,813 29,O11 0.0857
FERC FORM NO. 1 (ED.12-95)Page 304.17
PacifiCorp (1)
(2)Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICIry BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 31 0-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Ltne
No.
r\umoer ano ilIte oI KaIe scneoute
(a)
MVVn JO|O
(b)
Kevenue
(c)
KWNPer (\jatesstomer Revenue PerK\Mr Sold(D
1 INCOME TAX DEFERRAL ADJ -279,766
2 ALT REVENUE PROGRAM ADJ -315,686
2 DSM REVENUE.IRRIGATION 501,827
4 BLUE SKY REV.IRRIGATION 234
E UNBILLED REVENUE -474 -32,000 0.0681
6
7 WYOMING
8 OSAPSOOO4O. AG PUMP SVC 18,593 1,578,61 1 702 26,486 0.0849
o O5APSNSO4O - AG PUMP SVC 1,335 105,733 21 63,571 o.0792
10 OSLNXOO103 - LINE EXT 80% GTY 2,326
11 OSLNXOOI09 - REF/NREF ADV +325
12 OSLNXOO1 1O - REF/NREF ADV +36,949
13 O5LNXOO31O - LINE EXT 554
14 O5LNXOO312. WY IRG LINE EXT 4,886
'15 O9APSNS21O. IRR & SOIL DRA I 1,459 1 9,000 0.1621
'16 REVENUE-ACCT ADJ 3,385
17 REVENUE ADJ - DEF NPC -'1 ,989
18 INCOME TAX DEFERRAL ADJ -18,910
19 DSM REVENUE-IRRIGATION 55,832
20 BLUE SKY REV-IRRIGATION 20
21 UNBILLED REVENUE 17 1,000 0.0588
22 OSAPSOOO4O - AG PUMP SVC 132 10,928 4 33,000 0.0828
23 OsLNXOOllO - REF/NREF ADV +12,876
24 OSLNXOO31O - LINE EXT 1,746
25 O9APSNS21O - IRR & SOIL DRA 468 41,853 3 156,000 0.0894
26 O9APSVO2IO - IRR & SOIL DRA 6,056 468,570 94 u,426 0.0774
27 DSM REVENUE-IRRIGATION 17,201
28 UNBILLED REVENUE 3
29
30 LESS MULTIPLE BILLINGS -845
3'1
32 TOTAL IRRIGATION SALES 1,480,865 137,688,644 23,637 62,650 0.0930
33
34 PUBLIC STREET & H\AAT LIGHTING
35 CALIFORNIA
36 O6CUSLO53E - SPECIAL CUST O 1,',t22 198,25',1 105 10,686 0.1767
37 O6CUSLO58F. CUST OWND STR 52 10,334 20 2,60C 0.1 987
38 O6OALTO1SN - OUTD AR LGT SR 243 1
39 O6SLCOOO51 - COMPANY O!\NED 673 216,292 77 8,740 0.3214
40 REVENUE-ACCT AOJ -12,144
41 TOTAL BiI|ed 55,333,513 4,748,894,747 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,057 -26,093,00C c c 0.1 197
43 TOTAL 55,115,456 4,722,801,747 1 ,899,813 29,011 0.0857
FERC FORM NO. 1 (ED. 12-95)Page 304.18
ort Is:
An Original
Name of Respondent
PacifiCorp An
(2)A Resubmission
Date of
(Mo, Da
tt
Report
r, Yr)
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales dala under each
applicable revenue account subheading.
3. \Mere the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rale schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No
NUmDer ano lrlle oI F(ate scneoule
(a)
MWn ltoto
(b)
f<evenue
(c)of
AVVnPer (DAICS
stomer
Revenue PerKWh SoId(0
1 INCOME TAX DEFERRAL ADJ -8,464
2 DSM REVENUE-PUB ST & HWY LT 10,302
2 SOLAR FEED.IN REVENUE 89
4 UNBILLED REVENUE -339 -74,000 0.2183
E
6 IDAHO
7 OTGNSVO23S - ID TRAFFIC 146 17,869 24 6,083 0.1224
8 OTSLCOOO1 1 - STR LGT CO.O\^/N 143 67,061 65 2,200 0.4690
o OTSLCUO12E - ENGY STR LGT 396 43,527 39 10,154 0.1 099
10 OTSLCUO12F - FULL MNT STR LGT 1,815 361 ,112 186 9,758 0.1 990
11 O7SLCUO12P. PART MNT STR LGT 194 28,072 16 12,125 0.1447
12 REVENUE-ACCT ADJ -2,559
13 INCOME TAX DEFERRAL ADJ -3,114
't4 DSM REVENUE-PUB ST & HWY LT 13,726
15 UNBILLED REVENUE -49 -9,000 0.1837
16
't7 OREGON
18 01COSLOOs2. STR LGT SRVC C 370 57,083 35 10,571 0.1 543
19 OlCOSTO23F - OR GEN SRV 668 42,335 0.0634
2C OlCUSLOOs3 - CUS-OWNED MTRD 522 39,100 73 7,151 0.0749
21 OlCUSLOS3E - STR LGT SVC 11,324 848,032 22',!s',t,244 0.0749
22 OlCUSLOs3F - STR LGT SRVC C 116 11,244 I 12,88S 0.0969
ZJ O1GNSVO23F - OR GEN SRV - FLAT 120,589 39
24 OlHPSVOO51 - HI PRESSURE SO 19,014 4,045,6't 5 754 2s,218 0.2128
25 OlLEDSLOSI . OR LED PILOT 533 186,6s1 75 7,107 0.3502
26 OlMVSLOOSO. MERC VAPSTR LG 7,329 979,1 15 231 31,727 0.1336
27 O1OALTO15N - OUTD AR LGT NR 33 5,979 15 2,20C 0.1812
28 OlOALTB15N - OR OUTD AR LGT 4 791 3 1,667 0.1582
29 REVENUE-ACCT ADJ -15,884
30 INCOME TAX DEFERRAL ADJ -142,291
31 OR GAIN ON SALE OF ASSET 542
32 DSM REVENUE-PUB ST & HW/ LT 182,322
33 SOLAR FEED-IN REVENUE 10,268
34 UNBILLED REVENUE -3,280 -512,000 0.1 561
35
36 UTAH
37 08cFR00012 - sTR LGTS (CONV 54
38 OSCFROOO51 - MTH FAC SRVCHG 4,529
39 OSCFROOO62 - STREET LIGHTS 79
40 OSMONLOOlS - MTR OUTDONIGHT 904 73,246 92 9,826 0.0810
41 IOTAL BiI|ed 55,333,513 4,748,894,747 1 ,899,813 29.12C 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,057 -26,093,000 0 c 0.1 197
43 TOTAL 55,1 15,456 4,722,801 ,747 1 ,899,813 29,011 0.0857
FERC FORM NO. I (ED. 12-95)Page 304.19
Name of Respondent
PacifiCorp
This ReDort ls:(1) 5l1Rn originat(2) f]A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 31 0-31 1.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. lfthe sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Wlrere the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rale schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
NUmDer ano lrlle oI Kate scneoule
(a)
MWn UO|O
(b)
Kevenue
(c)
KWnPer (SAlesslomer Kevenue FerK\M Sold(D
1 OSOALTOOTN . SECURITY AR LG 161 42,234 67 2,403 0.2623
2 08sLco001 I - sTR LGT CO-O\ N 13,640 4,104,796 708 19,266 0.3009
1 08SLCU012E - DECOR CUST-O\i\N 43,694 2,788,2',t5 941 46,4U 0.0638
4 OSSLCUO12F - STR LGT CUST-O 1,031 135,848 71 14,52',1 0.1 31 8
G O8SLCUO12P. STR LGT CUST-O 3,114 383,68C 173 18,000 0.1232
6 08TOSS0015 -TRAF &amp; OTHER 3,157 355,687 1,497 2,109 0.1127
7 OSTOSSOlSF - TRAFFIC SIG NM 1,155 101,823 121 9,545 0.0882
I REVENUE-ACCT ADJ -19,17 1
I REVENUE ADJ - DEF NPC 5,659
10 DSM REVENUE-PUB ST & HW/ LT 23,785
11 SOLAR FEED-IN REVENUE 20,667
12 UNBILLED REVENUE 1,307 159,000 o.12't7
13
14 WASHINGTON
15 O2CFROOO12 - STR LGTS 91
'16 O2COSLOOs2 - WA STR LGT SRV 't43 31 ,097 14 10,214 0.2175
17 O2CUSLOs3F - WA STR LGT SRV 2,961 224,071 120 24,675 0.0757
18 O2CUSLOs3M - WA STR LGT SRV 742 55,574 111 6,685 0.0749
19 O2MVSLOOST - WA MERC VAPSTR 1,594 212,103 40 39,850 0.1 331
20 O2SLCOOOS1 -WACOMPANY 3,840 828,618 2',t1 1 8,1 99 0.2158
21 REVENUE-ACCT ADJ -66,463
22 INCOME TAX DEFERRAL ADJ -23.178
23 DSM REVENUE-PUB ST & H\AAT LT 24,566
24 UNBILLED REVENUE -692 -100,000 0.1445
25
26 WYOMING
27 05cos10057 - co-o\ /t\lD sTR LG 243 48,922 15 16,200 0.2013
28 OsCUSLOOsS - CUST O!\ND STR 58 3,284 11 5,273 0.0566
29 OsCUSLOEsS - WY CUST O\^AED 1,090 61,580 33 33,030 0.0565
30 OsCUSLOMSS - CUST O!\NED ST 44 3,037 2 't4,667 0.0690
31 OSHPSVOOsl . HI PRESSURE SO 5,778 1,087,029 186 31,065 0.1 881
32 OsMVSOOOs3 - MERCURY VAPOR 3,609 416,745 229 15,760 0.1 1 55
33 O5OALTO1sN - OUTD AR LGT SR 38 4,286 2 12,667 o.1128
34 REVENUE-ACCT ADJ 774
35 REVENUE ADJ - DEF NPC -955
36 INCOME TAX DEFERRAL ADJ -9,082
37 DSM REVENUE-PUB ST & HWY LT 48,564
38 UNBILLED REVENUE 59 6,000 0.1017
39 OgMONLO213. !AA/ MTR OUTDOOR 27 2,654 1 27,004 0.0983
40 OgSLCOO2,I 1 - STR LGT CO.O\AN 1,495 334,768 50 29,900 0.2239
41 TOTAL Billed 55,333,51:4.748.894.747 ,|0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,05i -26,093,000 0 (0.1 1 97
43 TOTAL 55,1 '1 5,456 4,722,801,747 1 ,899,813 29,011 0.0857
FERC FORiI NO. I (ED.12-95)Page 304.20
PacifiCorp (1)
(2)
Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
cuslomer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 31 0-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. lf the sales under any rale schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue accounl classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
une
No.
r\umoer ano r rlre or KaIe Scneoure
(a)
MVVn UO|O
(b)
Kevenue
(c)of
nvvn oI Dates
Per Customer(e)
h(evenue PerK\M SoId(0
1 OgSLCUP212 - CUST O!\NED ST 34 4,932 5 6,800 0.1451
2 09TOSS0213 - \
^r
TRAFFTC &47 2,352 15 3,1 33 0.0500
2 DSM REVENUE-PUB ST & HWY LT 10,863
4 UNBILLED REVENUE 218 46,000 0.2110
E
6 LESS MULTIPLE BILLINGS -3,204
7
8 TOTAL PUBLIC STREET & H\AAT LT 130,278 18,155,451 3,501 37,212 0.1 394
o
10 FORFEITED DISCOUNTS
11 CALIFORNIA
12 O6LPAYO3OO . RES-LATEFEE 219,185
13 O6LPAYO3OO . COM-LATEFEE 52,829
14 O6LPAYO3OO - IND-LATEFEE 56,433
15 O6LPAYO3OO - OTHER-LATEFEE 411
16
17 IDAHO
18 OTLPAYO3OO . RES-LATEFEE 217,156
19 OTLPAYO3OO . COM-LATEFEE 32,011
20 OTLPAYO3OO . IND-LATEFEE 141,276
21 OTLPAYO3OO - OTHER-LATEFEE 't,925
22
23 OREGON
24 OlLPAYO3OO - RES-LATEFEE 3,321,828
25 O1 LPAYO3OO . COM-LATEFEE 809,683
26 O1 LPAYO3OO . IND-LATEFEE 235,865
27 01 LPAYO3OO - OTHER-LATEFEE 37,2U
28
29 UTAH
30 OSLPAYO3OO - RES-LATEFEE 2,336,882
31 OSLPAYO3OO - COM-LATEFEE 681,384
32 OSLPAYO3OO - IND-LATEFEE 250,814
33 OSLPAYO3OO . OTHER-LATEFEE 95,874
34 OTHER 1,486
35
36 WASHINGTON
37 O2LPAYO3OO - RES-LATEFEE 547,035
38 O2LPAYO3OO - COM-LATEFEE 132,139
20 O2LPAYO3OO - IND-LATEFEE 28,491
40 02LPAYO3OO - OTHER-LATEFEE 3,794
41 TOTAL BiIIed 55,333,513 4,748,894,747 1,899,813 29J2e 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-2',t8,057 -26,093,000 c C 0.1 197
43 TOTAL 55,1 1 5,45€4,722,801 ,747 1 ,899,813 29,011 0.0857
FERC FORM NO. 1 (ED.12-95)Page 304.21
Name of Respondent
PacifiCorp
(1)
(2)
Original (Mo, Da,
Resubmission
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale Mtich is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Elechic Operating Revenues," Page
300-301. lfthe sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Wtrere the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), lhe entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnole the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
NUmDer ano lrtle oI RaIe scneoule
(a)
MWn liotq
(b)
Kevenue
(c)
Averaoe NumDer
of cI,trlomers
KWNPer (l'aresstomer KEVENUE HCTKWh Sold
(f)
1
2 WYOMING
3 OSLPAYO3OO - RES-LATEFEE 400,469
4 OSLPAYO3OO - COM-LATEFEE 102,996
5 OSLPAYO3OO . IND-LATEFEE 41,342
6 OsLPAYO3OO - OTHER-LATEFEE 2,208
7 OSLPAYO3OO - RES-LATEFEE 44,893
8 OsLPAYO3OO - COM-LATEFEE 8,O48
I OsLPAYO3OO - IND-LATEFEE 6,877
10 OsLPAYO3OO - OTHER-LATEFEE 1
11
12 TOTAL FORFEITED DISCOUNTS 9,81 1 ,199
13
't4 MISC SERVICE REVENUE
15 CALIFORNIA
16 O6CFROOOO3 - MTH MAINTENANC 'l,454
't7 06coNN0300 - cA RECONNECTTO 29,775
18 06FCBUYOUT 9,581
19 O6NMT2O135 - AGRI PUMP-NET 10
20 O6NSMTR3OO - NON-STND MTR 2,745
21 O6RCHKO3OO - CA RET CHK CHR 11,988
22 O6TAMPO3OO - CA TAMP & UNAU 1,500
23 O6TEMPO3OO - CA TEMP SRVC C 't,700
24 O6TRBLO3OO - CA TROUBLE CAL 60
25 OoXMTRTAMP - TAMP 399
26 OTHER .E
2l
28 IDAHO
29 OTCFROOOO1 - MTH FAC SRVCHG 1,451
30 OTCONNO3OO - ID RECONNECTIO 15,265
31 OTRCHKO3OO - ID RET CHK CHR 32,540
JI OTTAMPO3OO 600
2?O7TEMPOO14. TEMP SRVC CONN 34,000
34 OTXMTRTAMP - TAMP '142
AE OTHER 287
36
37 OREGON
38 OlADMINFEE - SCH 272 ANN 23,748
3S O1APSVOO41 -AG PMPSRVC BP 180
4C O1APSVO41X. AG PMP SRVC 72
41 TOTAL BiIIed 55,333,513 4,748,894.747 1 ,899,813 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,057 -26,093,00C c c 0.1197
43 TOTAL 55,1 15,456 4,722,801 ,747 1 ,899,813 29.01',l 0.0857
FERC FORM NO. I (ED.12-95)Page 304.22
Name of Respondent
PacifiCorp
This ReDort ls:(1) 6]nn original(2\ 1A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 31 0-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Wtrere the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year ('12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustmenl clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Lrne
No.
NUmDer ano ilIte oT KaIe scneoute
(a)
MWn 50to
(b)
Kevenue
(c)of ^vvnPer (Kevenue rerKWh Sold(0
1 01cFR00001 - MTH FACILITY 96,028
2 OlCFROOOO3 - MTH MAINTENANC 17,804
O,ICFROOOO4 - EMRGNCY ST&BY 25,656
4 OlCFROOOOS . INTERMTNT SRVC 37,1 00
5 OlCFROOO13 - MTH MISC CHRG 51,677
6 OlCGENAFOR - CUST GEN APP 5,796
7 O1 CONNO3OO - RECONNECTION 547,545
I OlCONTSERV - OR 3RD PTY 23,011
I OlESSCO6OO - ESS CHG 900
10 OlFCBUYOUT - FAC CHG BUYOUT 256,672
11 OlGNSBOO23 - OR GEN SRV, BPA,1,877
12 O1GNSVOO23 - OR GEN SRV, < 30 3,562
13 OlGNSVOO2S - OR GEN SRV > 30 108
14 01 MTRVR3OO - METR VERIF FEE 40
15 O1NETMT135 - NET METERING 2,844
16 01NMT28,135 - OR NET MTR, GEN,72
17 OlNSMTR3OO - OR STD METER 14,703
18 OlRCHKO3OO - RET CHECK 296,1 00
19 OlRESDOOO4 - RES SRVC 135,181
2A Ol RESDOO4T - RES TIME OPT 468
2'l OlRGNSBO23 - SM GENL SVC-RES 2,484
22 OITAMPO3OO - TAMP & UNAUTH 10,650
23 OlTEMPO3OO. TEMP SRVC CHRG 192,0s5
24 OlUSBRON41 - KLA BASIN IRG ON 216
.E O1VIRO4136 - OR RES VOL INC 324
26 OlXMTRTAMP - TAMP- UNAUTH 1,787
27 OlXTHEFREV - THEFT OF SVCS E'
28 OTHER -'1 0,154
29
30 UTAH
31 OSCFROOO5I - MTH FAC SRVCHG 84,942
32 OsCFROOO52 - ANN FAC SVCCHG 424
33 OsCFROOO53 - MTHLY MAINTFEE 13,374
34 OSCFROOOS4 - NRES EMERGENCY 4.976
35 OSCFROOO63 - MTH MISC CHARG 2,358
36 OSCFROOO64 - ANN MISC CHARG 6,660
37 OSCGENFEEN - NRES CSTMR GEN 7,756
38 OSCGENFEER - RES CSTMR GEN 240,842
eo 08coNN0300 - REcoN & DtscoN 226,130
40 OSCONTSERV - 3RD PARTY O/S 93,000
41 TOTAL BiI|ed 4,748,894,747 29,126 0.0858
42 Total Unbilled Rev.(See lnstr.6)-218,057 -26,093,000 (c 0.1 1 97
43 TOTAL 55,1 1 5,456 4,722,801 ,747 1 ,899,81:29,011 0.0857
FERC FORM NO. 1 (ED. 12-95)Page 304.23
oarel'itomer
55,333.51;
Name of Respondent
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20'l8lQ4
SALES OF ELECTRICIry BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. lfthe sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Reportamountofunbilledrevenueasofendofyearforeachapplicablerevenueaccountsubheading.
Line
No.
NUmDer anQ lr$e ot RaIe scneoule
(a)
MWN UOIO
(b)
Kevenue
(c)
aoe NumDer)Istomers(d)
KVVNPer (!,aresstomer
Kevenue HerKWh Sold(0
1 OSFCBUYOUT - FAC CHG BUYOUT 1,042,420
2 OSNCONO3OO - UT FEE NRES RE 3,775
I O8NETMT135 - NET MTR 264
4 OSNSMTR3OO - UT NON 849
6 OSRCHKO3OO - UT RET CHK CHR 511,560
6 OSRCONOOO1 - CONNECT FEE 1,806,090
7 OSRESDOOO1 - RES SRVC 4,759
8 OSSOLRXFEE - SUBSCRI SOLAR 17,550
o OSSSLROOO1 - RES SUBSCRB 264
1C OSTAMPO3OO - TAMP&UNAU 3,825
11 O8TEMPOO14. TEMP SRVC CONN 695,730
12 OSVISIT3OO - UT VISIT SRV CALL 24,055
13 OSXMTRTAMP - TAMP 830
14 ENERGY FINANSER NEWCOM 1 324
't5 OTHER -960,784
16
17 WASHINGTON
18 O2CFROOOO3 - MTH MAINTENANC 1,324
19 O2CFROOOO4 . EMRGNCY ST&BY 5,892
2C O2CFROOOOs - INTERMTNT SRVC 4,303
21 O2CGENAMWA - CUST GEN APP &32,450
22 O2CONNO3OO - WA RECONNECTIO 51 ,870
23 O2FCBUYOUT - FAC CHG BUYOUT 6,1 39
24 O2NSMTR3OO - WA STD METER 480
25 O2RCHKO3OO - WA RET CHK CHR 59,340
26 O2RESDOO16. WA RES SRVC 560
27 OzTAMPO3OO - WA TAMP & UNAU 1,800
28 O2TEMPO3OO - WA TEMP SRVC C 26.924
29 O2XMTRTAMP - TAMP 677
30 OTHER 9,109
31
32 WYOMING
33 OsCFROOOO3 - MTH MAINTENANC 1,768
34 OsCFROOOO4 - EMRGNCY ST&BY 18,28C
35 OsCFROOOOs . INTERMTNT SRVC 10,071
36 OsCFROOO13. MTH MISC CHRG 3,1 86
37 OsCONNO3OO - WY RECONNECTIO 65,1 65
38 OSFCBUYOUT - FAC CHG BUYOUT 16,46C
39 OSRCHKO3OO - WY RET CHK CHR 80,760
40 O5RESDOOO2. WY RES SRVC 1,188
41 TOTAL BiIIed 55,333,513 4,748,894.747 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,057 -26,093,000 c c 0.1 197
43 TOTAL 55,1 15,45€4,722,801 ,747 1,89S,81:29,01',l 0.085i
FERC FORM NO. I (ED. 12-95)Page 304.24
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]nn orisinat
Q\ rrA Resubmissiontt
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. lfthe sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a foolnote lhe estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Lrne
No.
NUmDer ano ilIte oI KaIe scneoute
(a)
MWn 50to
(b)
Revenue
(c)
KWNPer (Saesstomer TilfiiS%8"'(D
1 OSTAMPO3OO 450
I O5TEMPO3OO - WY TEMP SRVC C 38,590
I OSXMTRTAMP - TAMP te
4 OgCFROOOOs - INTERMTNT SRVC 339
E OTHER 480
6 OsCONNO3OO - WY RECONNECTIO 7,518
7 OSRCHKO3OO - \ffT RET CHK CHR 8,310
8 OSTAMPO3OO 75
I OSTEMPO3OO - WY TEMP SRVC C 34C
10 O9CFROOOO1 - MTH FAC SRVCHG 5,001
11 OgCFROOO14. YR MISC CHRG t
12
13 TOTAL MISC SERVICE REVENUE 6,',t72,987
14
'15 SALES OF WATER & WATER PWR
16 UTAH
17 WATER & WATER P\A/R SALES 54,615
18
19 TOTAL SALES OF WATER & WTR t4,615
20
21 RENT FROM ELEC PROPERTIES
22 CALIFORNIA
23 O6CFROOOO6 - MTH RNTAL CHRG 1,710
24 RENT REVENUE-HYDRO 1,500
25 RENT REVENUE-SUBLEASES 19,200
26 JOINT USE 533,047
27
28 IDAHO
,o OTCFROOOOg - YR LSE CHRG-EQ 777
30 OTINVCHGOO - INVEST MNT CHG 151
3'1 OTPOLEOOTs - STEEL POLES US 262
32 RENT REVENUE-GENERAL 492
33 RENT REVENUE.HYDRO 60,380
34 RENT REVENUE-TRANSMISSION 14,650
35 RENT REVENUE.SUBLEASES 2,216
36 JOINT USE 167,360
37
38 OREGON
39 OlCFROOOOo - MTH RNTAL CHRG 841,229
4A RENTS - COMMON 722,958
41 TOTAL Billed 4,748,894,747 1 ,899,813 29j2e 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,051 -26,093,000 0 c 0.1 "t97
43 TOTAL 55,115,45€4,722,801 ,747 1,899,813 29,011 0.0857
FERC FORM NO. I (ED. 12.95)Page 304.25
Name Respondent Date of Report(Mo, Da, Yr)PacifiCorp (1)
(2)
An Original
A Resubmission
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during lhe year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-3'l 1.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Vvhere the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reporled
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year ('12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line
No.
NUmDer ano lrUe oI Rate scneoule
(a)
MWn 50U
(b)
Kevenue
(c)
Averaoe NumDer
of cis#mers NVVnPer (oaresstomer Kevenue Fer]ovh Sold(0
1 RENT REVENUE-DISTRIBUTION 76,904
2 RENT REVENUE-GENERAL 68,306
2 RENT REVENUE-HYDRO 26,758
4 RENT REVENUE.TRANSMISSION 325,808
6 RENT REVENUE-SUBLEASES 22,030
A MCI FOGWRE REVENUE 3,347,401
7 JOINT USE 2,801,948
8
o UTAH
10 OSCFROOO56 - MTH EQUIP RENT 33
11 O8CFROOOs8. MTH EQUIP LEAS 550,016
12 OSINVCHGON - INVEST MNT CHG 4,007
13 O8INVCHGOR - INVEST MNT CHG 222
14 OSPOLEOOT5 - STEEL POLES US 51,881
15 RENTS. NON COMMON 3,698
16 RENT REVENUE-DISTRIBUTION 757,544
17 RENT REVENUE-GENERAL 19,635
18 RENT REVENUE-HYDRO 86,705
19 RENT REVENUE-STEAM 127,585
20 RENT REVENUE.TRANSMISSION 1,291 ,880
21 RENT REVENUE-SUBLEASES 495,802
22 JOINT USE 2,981,082
23
24 WASHINGTON
25 02cFR00001 - MTH FAC|LITY 2,104
26 O2CFROOOO6 - MTH RNTAL CHRG 9,073
27 RENT REVENUE-DISTRIBUTION 21,037
28 RENT REVENUE.GENERAL 45,986
29 RENT REVENUE-HYDRO 357,959
30 RENT REVENUE-TRANSMISSION 24,784
31 JOINT USE 772,329
32
33 W/OMING
34 05cFR00001 - MTH FAC|LITY 11,524
35 O5CFROOOO6 - MTH RNTAL CHRG 2,482
36 RENTS - NON COMMON 13,200
37 RENT REVENUE-DISTRIBUTION 150
38 RENT REVENUE-GENERAL 75,009
20 RENT REVENUE.HYDRO 21,521
40 RENT REVENUE-STEAM 49,268
41 TOTAL BiI|ed 55,333,51:4,748,894,747 1,899,81!29J2e 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,051 -26,093,000 C c 0.1 197
43 TOTAL 55,1 15,45t 4,722,80',t,747 1 ,899,81:29,0'1 1 0.0857
FERC FORM NO. r (ED.12-9s)Page 304.26
Name of Respondent
PacifiCorp
This(1)
(2)
ReDort ls:
5]nn originat
[]A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effecl during the year the MWH of electricity sold, revenue, average number of customer, average Kwt per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnole the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Ltne
No.
NUmDer ano ilIte oI KaIe scneoute
(a)
MVVn 50rO
(b)
Kevenue
(c)
KWNPer (Kevenue t,erK\Nh Sold
(D
1 RENT REVENUE-TRANSMISSION 275
2 RENT REVENUE-SUBLEASES 42,009
2 JOINT USE 344,254
4 OgPOLEOOTs - STEEL POLES US 18,313
E RENT REVENUE-STEAM 28,311
6 OTHER 2,190
7
I TOTAL RENT FROM ELEC 17,246,955
o
10 OTHER ELECTRIC REVENUE
11 ENERGY EXCHANGE CREDITS 453,590
12 M&S INVENTORY REVENUE 4,006,244
13 RENEWABLE ENERGY CREDITS 3,300,207
14 WND BASED ANCILLARY SVC 1 1 ,169,083
15 MISC OTHER REVENUE 11,376
16
17 CALIFORNIA
18 3RD PARTY TRANS O&M 40,590
19 CA GHG ALLOW REV AMORT 9,591,652
2C FISH, WILDLIFE, RECR 9,362
2',l
22 OREGON
23 3RD PARry TRANS O&M 167,071
24 EIM REVENUE 14,572
25 FERC TRANSMISSION REFUND 4,',t25,687
2e oTHER ELEC (EXLUDE 3,318,126
27
28 UTAH
29 3RD PARTY TRANS O&M 157,'t76
30 ELEC INCOME-OTHER 45,665
31 FISH, WILDLIFE, RECR 3,06C
32 FLYASH SALES 1 ,936,159
33
34 WASHINGTON
35 FISH, WLDLIFE, RECR 1 1 ,0'10
36 TIMBER SALES - UTILITY 506,102
37 WASH COLSTRIP 3 -52,188
38
39 WYOMING
40 3RD PARTY TRANS O&M 68,037
4',!TOTAL BiI|ed 55,333,51:4,748,894,747 1 ,899,81 :29,126 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,05i -26,093,000 (c 0.1197
43 TOTAL 55,1 15,456 4,722,801,747 1,899,81:29,011 0.0857
FERC FORM NO. 1 (ED. 12-95)Page 304.27
OAleSitomer
Name of Respondent
PacifiCorp
This ReDort ls:(1) 5l1Rn orisinat(2\ fiA Resubmission
Dale of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf the sales under any rate schedule are classified in more than one revenue accounl, List the rate schedule and sales data under each
applicable revenue account subheading.
3. \Mrere the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Lrne
No.
r\umoer ano ilIte oT KaIe scneoute
(a)
MVVn DO|O
(b)
Kevenue
(c)of
Kevenue l-erK\/vh Sold(0
1 FLYASH SALES 2,322,071
z WY REG RECOVERY FEE 225,999
a
4 TOTAL OTHER ELEC REVENUE 33,175,277
C
6
7
8
I
'tc
11
12
13
14
'15
16
17
18
19
2C
21
22
23
24
25
26
27
28
29
3C
31
5Z
JJ
34
.E
36
37
38
?c
4C
41 TOTAL Billed 55,333,513 4,748,894,747 1 ,899,813 29,126 0.0858
42 Total Unbilled Rev.(See lnstr. 6)-218,057 -26,093,000 c c 0.1 1 97
43 TOTAL 55,1 15,456 4,722,801,747 1 ,899,813 29,01 1 0.0857
FERC FORM NO. r (ED.12-95)Page 304.28
Per oateSitomer
Name of Respondent
PacifiCorp
orl ls:
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)tt
Year/Period of Report
End of 20181Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or 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
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 supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means flve 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 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 service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
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 flve years.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (M\Al)
(d)
Actual Demand
(e)
1 Requirement Sales:
2 Helper City RQ T-6 1 1 1
3 Helper City Annex RQ T-6 1 1 1
4 Navajo Tribal Utility Authority RQ T-12 34 AE 33
E RQ T-6 0 c 0
6 RQ T-6 2 z 1
7 Accrual RQ NA NA NA NA
8
o Non-Requirement Sales :
10 Arizona Electric Power Cooperative, lnc SF T-'t2 NA NA NA
11 Arizona Public Service Company SF r-12 NA NA NA
12 Arizona Public Service Company SF WSPP-Q NA NA NA
13 Avangrid Renewables, LLC SF 1-12 NA NA NA
14 Avangrid Renewables, LLC SF T-13 NA NA NA
Subtotal RQ c 0 0
Subtotal non-RO c 0 0
Total 0 0 0
FERC FORM NO. r (ED. 12-90)Page 3{0
AveraoeMonthly CPDemanr
(0
Navajo Tribal Util. Auth. (Mexican Hat)
Navajo Tribal Util. Auth. (Red Mesa)
PacifiCorp
(1)
(2\
Original
Resubmission
Date of Report(Mo, Da. Yr)tt
Year/Period of Report
End of 20181Q4
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. 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 provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the 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.
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 (t). Explain in a footnote all components of the amount shown in column O. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Megawatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(D
Other Charges
($)
(i)
1
6,033 105,715 107,290 213,005 2
3,568 70,049 63,055 1 33,1 04 3
287,015 5,605,229 9,312,805 13,803,253 4
865 16,690 15,061 31,751 5
9,410 144,584 163,924 308,508 6
1,422 36,708 7
8
I
'158,207 4,296,519 4,296,519 10
24,062 832,411 832,411 11
1,600 43,600 43,600 't2
1,255,520 36,948,615 36,948,615 13
16 85€14
308,313 5,942,267 9,662,135 -1,078,073 14,526,329
8,001,159 7,490,743 463,953,015 -231,755,357 239,688,401
8,309,472 13,433,010 473,61 5,1 50 -232,833,430 2il,214,730
FERC FORM NO.1 (ED. 12.90)Page 311
-1,114,78'
36,70{
85(
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or 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
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 supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 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 service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
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 flve years.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifl-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW1
(d)
Actual Demand (MW)
AVeraoe
Monthly NCP Deman<
(e)
Averaoe
Monthly CPDemand
(0
1 Avista Corporation SF T-12 NA NA NA
2 Avista Corporation SF T-1 3 NA NA NA
3 Basin Electric Power Cooperative, lnc.SF r-12 NA NA NA
4 Black Hills Power, lnc.441 NA NA NA
5 Black Hills Power, lnc.441 5C 50 45
6 Black Hills Power, lnc.SF r-12 NA NA NA
7 Black Hills Power, lnc.SF WSPP-Q NA NA NA
8 Bonneville Power Administration NA NA NA
I Bonneville Power Administration LU NA NA NA
10 Bonneville Power Administration SF T-12 NA NA NA
1',!Bonneville Power Administration SF T-13 NP NA NA
12 Bonneville Power Administration SF WSPP-O NA NA NA
13 BP Energy Company r-12 NA NA NA
14 BP Energy Company SF T-12 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 3'10.1
)on ls:
AD
LF
AD T-12
T-',t2
AD
Name of Respondent
PacifiCorp (1)
(2)
An Original
Resubmission
Date of Report(Mo, Da, Yr)lt
Year/Period of Report
End of 20181Q4
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 ol
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. ln Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tarifb under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (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 supplier'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.
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 O. Explain in a footnote all components of the amount shown in column O. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Megawatt Hours
Sold
(g)
REVENUE Total ($)
(h+i+i)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
Other Charges
($)
(i)
72,595 1,704,350 1,704,35C 1
17 481 2
20,146 629,471 629,471 3
54,609 4
289,593 7,490,743 6,250,247 13,740,99C 5
105,792 2,664,278 2,664.,278 6
450 1'1 ,300 11,30C 7
-2 '137,48C I
40,029 2,655,524 2,65s,524 o
81,651 2,543,009 2,543,009 10
156 2,563 11
66,173 2,011 ,607 2,011,607 12
525 19,756 13
439,781 12,630,744 12,630,744 14
308,313 5,942,267 9,662,135 -1,078,073 14,526,329
8,001,159 7,490,743 463,9s3,015 -231,755,357 239,688,401
8,309,472 r3,433,010 473,6{ 5,1 50 -232,833,430 zil,214,730
FERC FORM NO. 1 (ED. 12.90)Page 311.1
48',,
54,60(
137,48(
2,56:
19,75(
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or 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
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 supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 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 service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
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
(Footnote Afiiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly BiIing
Demand (MW1
(d)
Actual Demand (MVlr)
naontniy tib?-oeman
(e)
Averaoe
Monthly CPDemand
(D
1 SF T-13 NA NA NA
2 Brookfield Energy Marketing LP SF r-12 NA NA NA
3 T-12 NA NA NA
4 California lndependent System Operator SF r-12 NA NA NA
5 Calpine Energy Services, L.P SF r-12 NA NA NA
6 Calpine Energy Services, L.P SF WSPP-Q NA NA NA
7 Cargill Power Markets, LLC T-12 NA NA NA
8 Citigroup Energy, lnc.SF T-12 NA NA NA
I City of Burbank SF T-12 NA NA NA
10 City of Burbank SF WSPP-Q NA NA NA
11 Cig of Glendale SF T-12 NA NA NA
12 City of Hurricane IF 560 NA NA NA
13 City of Hurricane T-12 NA NA NA
14 City of Hurricane SF T-12 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90)Page 310.2
British Columbia Hydro and Power
California lndependent System Operator AD
AD
AD
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
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 ol
the service in a footnote.
AD - for Outof-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. 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 provided.
6. For requirements RQ sales and any gpe of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (0. 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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column O. Explain in a footnote all components of the amount shown in column O. 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 Jine of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401 ,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(D
Other Charges
($)
fi)
51 948 1
2,528 42,331 42,331 2
426 -111,805 3
21,409 755,425 755,424 4
51,875 906,516 906,516 5
5 't13 1't3 6
100 2,400 7
1,057,627 31,792,',t01 31,792,101 8
27,144 849,060 849,060 I
8,096 205,169 205,169 10
800 19,600 19,600 11
145 7,306 7,306 12
-19 -919 13
39 1,715 1,715 14
308,313 5,942,267 9,662,135 -1,078,073 14,526,329
8,001,159 7,490,743 463,953,015 -231,755,357 239,688,401
9,309,472 13,433,010 473,615,,l50 -232,833,430 2*,214,730
FERC FORM NO. 1 (ED. t2-90)Page 311.2
94{
-1 1 1,80(
2,40(
-91(
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Reporl(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchangesduringtheyear. Donotreportexchangesofelectricity(i.e.,transactionsinvolvingabalancingofdebitsandcreditsfor
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. 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 resource planning). ln addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 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 service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
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
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand
Monthly
(e)
1 City of Redding SF T-12 NA NA NA
2 City of Roseville SF r-12 NA NA NA
3 Clatskanie People's Utility District SF T-12 NA NA NA
4 ConocoPhillips Company SF T-12 NA NA NA
5 Direct Energy Business Marketing, LLC SF T-12 NA NA NA
6 DTE Energy Trading, lnc.SF T-12 NA NA NA
7 EDF Trading North America, LLC SF T-12 NA NA NA
8 EDF Trading North America, LLC SF WSPP-Q NA NA NA
I El Paso Electric Company SF r-12 NA NA NA
10 Eugene Water & Electric Board SF r-12 NA NA NA
11 Exelon Generation Company, LLC r-12 NA NA NA
12 Exelon Generation Company, LLC SF T-12 NA NA NA
13 Exelon Generation Company, LLC SF WSPP-Q NA NA NA
14 Gridforce Energy Management, LLC SF T-13 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Tota!0 0 0
FERC FORM NO. I (ED. 12-90)Page 310.3
/\ve AveraoeMonthly CP-Deman<
(D
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
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 ol
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. 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 provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (0 must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column O. Explain in a footnote all components of the amount shown in column O. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
G)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(D
Other Charges
($)
0)
44,319 1,157,460 1,157 ,464 1
71,363 1,710,U3 1,710,U3 2
7,295 247,676 247.676 3
60,349 2,398,192 2,398,192 4
1 10,41 3 3,374,954 3,374,954 5
't64,525 5,526,263 5,526,263 6
1,180,286 33,973,960 33,973,960 7
50 2,040 2,044 8
5,777 410,185 41 0,1 85 I
17,718 566,040 566,040 10
1,984 57,241 11
842,579 21,839,373 21,839,373 12
3,618 79,001 79,001 13
696 28,204 't4
308,313 5,942,267 9,662,135 -1,078,073 14,526,329
8,001,159 7,490,743 463,953,015 -231,755,357 239,688,401
8,309,472 13,433,0't0 473,615,150 -232,833,430 2il,214,730
FERC FORM NO. r (ED. 12-90)Page 3'l'1.3
57,241
28,20t
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Reoort(Mo, Da, Yi)tl
Year/Period of Report
End of 20181Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchangesduringtheyear. Donotreportexchangesofelectricity(i.e.,transactionsinvolvingabalancingofdebitsandcreditsfor
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. 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 resource planning). ln addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 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 service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
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
(Footnote Afiiliations)
(a)
Statistical
Classifi-calion
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (M!V1
(d)
Actual Demand (MW)
AVeraoe
Monthly NCP Demanr
(e)
AveraoeMonthly CPDemand
(0
,|ldaho Power Company SF T-13 NA NA NA
2 ldaho Power Company SF WSPP-O NA NA NA
3 lmperial I rrigation District SF r-12 NA NA NA
4 SF r-12 NA NA NA
5 Macquarie Energy LLC SF r-12 NA NA NA
6 Macquarie Energy LLC SF WSPP-O NA NA NA
7 Modesto lrrigation District SF T-12 NA NA NA
8 Morgan Stanley Capital Group, lnc.SF r-12 NA NA NA
I Morgan Stanley Capital Group, lnc.SF WSPP-Q NA NA NA
10 Municipal Energy Agency of Nebraska SF r-12 NA NA NA
11 NaturEner Power Watch, LLC T-13 NA NA NA
12 NaturEner Power Watch, LLC SF T-13 NA NA NA
13 SF WSPP-O NA NA NA
14 NextEra Energy Marketing, LLC SF T-12 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310.4
Los Angeles Dept. of Water and Power
AD
Nevada Power Company
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
OS - for other service. use this category only for those services which cannot be placed in the above.defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. 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 provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column O. Explain in a footnote all components of the amount shown in column O. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+i)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(D
Other Charges
($)
o
70 1,827 ,|
23,879 749,649 749,649 2
4,538 162,638 162,638 3
52,554 1,774,424 1,774,424 4
610,749 17,518,499 17,518,499 5
150,261 4,045,482 4,045,482 6
118,181 2,945,097 2,945,097 7
515,633 14,871,738 14,871,738 8
126,872 3,268,316 3,268,316 9
16,002 425,845 425,845 10
84 't1
63 967 12
12,956 414,555 454,555 13
800 28,200 28,200 14
308,313 5,942,267 9,662,135 -1,078,073 14,526,329
8,001,159 7,490,743 463,953,015 -231,755,357 239,688,401
8,309,472 {3,433,010 473,6r 5,1 50 -232,833,430 2il,214,730
FERC FORM NO. 1 (ED. 12-90)Page 311.4
't,82',
8.
96:
Name of Respondent
PacifiCorp
ort ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or 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
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 supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 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 service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longerthan one year but Less than five years.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (M!V)
(d)
Actual Demand (M!V)
AVetaoe
Monthly NCP Deman<
(e)
AveraoeMonthly CP-Demand
(0
1 NorthWestern Corporation WSPP-O NA NA NA
2 Northwestern Corporation SF T-13 NA NA NA
3 Northwestern Corporation SF WSPP-Q NA NA NA
4 Portland General Electric Company SF T-12 NA NA NA
5 Portland General Electric Company SF T-13 NA NA NA
6 Portland General Eleclric Company SF WSPP-Q NA NA NA
7 Powerex Corporation T-12 NA NA NA
8 Powerex Corporation SF T-12 NA NA NA
I Powerex Corporation SF WSPP.Q NA NA NA
10 Public Service Company of Colorado T-12 NA NA NA
11 Public Service Company of Colorado SF NA NA NA
12 Public Service Company of New Mexico SF T-12 NA NA NA
13 SF T-13 NA NA NA
14 SF r-12 NA NA NA
Subtotal RQ c 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO. r (ED, 12-90)Page 310'5
AD
AD
AD
T-12
PUD No. 'l of Chelan County
PUD No. I ofDouglas County
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
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 ol
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. 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 provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (J). Explain in a footnote all components of the amount shown in column O. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+D
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(D
Other Charges
($)
o
64 1
333 8,8'17 2
11,3',t2 424,732 424,732 3
209,176 5,774,320 5,774,320 4
106 4,763 5
12,828 573,906 573,906 6
56 3,062 7
160,233 3,314,222 3,314,222 I
270 10,080 10,080 I
1,002 21,352 10
4,921,799 128,518,984 128,518,984 11
80,606 2,578,697 2,578,697 12
15 658 13
1 ,'1 83 31,439 31,439 14
308,313 5,942,267 9,662,135 -1,078,073 14,526,329
8,001,159 7,490,743 463,953,015 -231,755,357 239,688,401
8,309,472 13,433,010 473,61 5,1 50 -232,833,430 2il,214,730
FERC FORM NO. 1 (ED. 12-90)Page 311.5
6r
8,81i
4,76i
3,06'
21,351
65r
PacifiCorp (1)
(2\
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
tt
Year/Period of Report
End of 20181Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or 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
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-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 from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
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 commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
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
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC RaIe
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW
(d)
Actual Demand (MW
AVeraoe
Monthly NCF Demanr
(e)
AveraoeMonthly CPDemand
(f)
,|SF r-12 NA NA NA
2 SF T-1 3 NA NA NA
3 Puget Sound Energy, lnc.SF T-12 NA NA NA
4 Puget Sound Energy, lnc.SF T-1 3 NA NA NA
5 Rainbow Energy Marketing Corporation SF T-12 NA NA NA
6 Rainbow Energy Marketing Corporation SF WSPP-Q NA NA NA
7 Sacramento Municipal Utility District SF T-12 NA NA NA
8 Sacramento Municipal Utility District SF T-13 NA NA NA
I Salt River Project SF r-12 NA NA NA
'10 Seattle City Light SF r-12 NA NA NA
11 Seattle City Light SF T-1 3 NA NA NA
12 Sempra Gas & Power Marketing, Llc T-12 NA NA NA
't3 Sempra Gas & Power Marketing, Llc SF r-12 NA NA NA
14 Shell Energy North America (US), L.P r-12 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310'6
PUD No. 1 of Snohomish County
PUD No.2 of Grant County
AD
AD
Name of Respondent
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 2018/Q4
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 ol
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. 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 provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (fl. 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 (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column O. Explain in a footnote all components of the amount shown in column O. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401 ,iine 24.
'10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(s)
REVENUE
Total ($)
(h+i+j)
(k)
Line
Demand Charges
($)
(h)
Energy Charges
($)
(D
Other Charges
($)
(i)
2,540 81 ,818 81 ,818 1
60 901 2
70,859 1,939,448 1,939,448 3
114 4,254 4
't,071 24,270 24,274 5
3,200 77,600 77,600 6
22,515 355,231 35s,231 7
37 1,846 8
6,284 362,644 362,644 9
19,355 683,61s 683,61s 10
I 291 11
'124 4,352 12
1 ,1 1 9,343 31,221 ,924 31,221,924 13
21,351 14
308,313 5,942,267 9,662,135 -1,078,073 14,526,329
8,001,159 7,490,743 463,953,015 -231,755,357 239,688,401
8,309,472 13,433,01 0 473,61 5,1 50 .232,833,430 2U,214,730
FERC FORM NO. I (ED. 12-90)Page 311.6
No.
90'
4,25t
1,84(
291
4,35i
21,35'
Name of Respondent
PacifiCorp
,ort ls:
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
Iexchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for I
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
IPurchased Powerschedule (Page 326-327). I2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
Iownership interest or affiliation the respondent has with the purchaser.
I3. 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 resource planning). ln addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means flve 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 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 service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
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
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Biiling
Demand (M\A/)
(d)
Actual Demand (MW1
AVeraoe
Monthly NCP Demanr
(e)
AveraoeMonthly CP'Demand
(D
1 Shell Energy North America (US), L.P SF r-12 NA NA NA
2 Shell Energy North America (US), L.P SF WSPP-Q NA NA NA
3 SF T-1 3 NA NA NA
4 Southern California Edison Company SF T-',t2 NA NA NA
5 Tacoma Power SF r-12 NA NA NA
6 Tenaska Power Services Co.SF T-12 NA NA NA
7 Tenaska Power Services Co.SF WSPP-Q NA NA NA
I The Energy Authority, lnc.SF r-12 NA NA NA
I TransAlta Energy Marketing (U.S.) lnc.r-12 NA NA NA
't0 TransAlta Energy Marketing (U.S.) lnc.SF 1-12 NA NA NA
1',!TransAlta Energy Marketing (U.S.) lnc.T-12 NA NA NA
12 TransCanada Energy Sales Ltd SF r-12 NA NA NA
13 r-12 NA NA NA
14 Tri-State Gen. and Trans. Assoc.SF r-12 NA NA NA
Subtotal RO 0 0 0
Subtotal non-RO 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90)Page 3'10.7
Sierra Pacific Power Company
AD
OS
Tri-State Gen. and Trans. Assoc.AD
Name of Respondent
PacifiCorp (1)
(2\
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 2O18lQ4
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Outof-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. 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 provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the 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.
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 O. Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWalt Hours
Sold
(s)
REVENUE rotal ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
Other Charges
($)
(i)
440,723 12,162,451 12,162,451 1
161,920 4,045,038 4,045,038 2
175 5,260 3
451,U4 12,415,059 't2,415,059 4
17,957 497,472 497,472 5
30,460 945,850 945,850 6
132,012 3,610,835 3,610,835 7
115,2s6 4,042,946 4,042,946 8
-9,037 I
175,449 5,292,536 5,292,536 10
500 11
4,400 145,600 145,600 12
-60 13
34,683 714,146 714,146 14
308,313 5,942,267 9,662,'t 35 -1,078,073 14,526,329
8,001,159 7,490,743 463,953,015 -231,755,357 239,688,401
8,309,472 13,433,010 473,51 5,1 50 .232,833,430 254,214,730
FERC FORM NO. 1 (ED. r2-90)Page 311..7
5,26(
-9,03;
50(
-6(
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tl
Year/Period of Report
End of 20181Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchangesduringtheyear. Donotreportexchangesofelectricity(i.e.,transactionsinvolvingabalancingofdebitsandcreditsfor
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. 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 resource planning). ln addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 which meets the deflnition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the eadiest 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 flrm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
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
(Footnote Affiliations)
(a)
Statistical
Classifi-cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (M!V)
(d)
Actual Demand (MW
nltontniy tiCFbemanr
(e)
AveraoeMonthly CP-Demand
(0
1 Tucson Electric Power Company SF r-12 NA NA NA
2 Tucson Electric Power Company SF WSPP-Q NA NA NA
3 Turlock lrrigation District SF T-12 NA NA NA
4 Turlock lrrigation District SF T-13 NA NA NA
5 UNS Electric, lnc.SF T-12 NA NA NA
6 Utah Associated Municipal Power Systems SF T-12 NA NA NA
7 Ulah Associated Municipal Power Syslems SF WSPP.Q NA NA NA
8 Utah Municipal Power Agency SF r-12 NA NA NA
I Utah Municipal Power Agency SF WSPP-Q NA NA NA
'10 Vitol lnc.SF r-12 NA NA NA
11 Westar Energy, lnc.SF r-12 NA NA NA
12 Western Area Power Administration SF T-12 NA NA NA
13 Transmission Loss Sales Revenue T-1 1 NA NA NA
14 Transmission Loss Sales Revenue r-11 NA NA NA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90)Page 310.8
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da. Yr)tt
Year/Period of Report
End of 20181Q4
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. 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 provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (t). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
'10. Footnote entries as required and provide explanations following all required data.
Megawatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(D
Other Charges
($)
0)
183,097 5,916,407 5,916,407 I
50 1,850 1,850 2
84,1 1 3 2,051,108 2,05'l ,108 3
5 't46 4
87,251 2,410,485 2,4'.t0,485 5
400 11,868 11,868 6
56,374 1,568,041 1,568,041 7
12 558 558 8
8,805 152,806 157,024 9
2,400 44,100 44,100 10
679 24,036 24,036 11
203,719 6,595,452 6,595,452 12
1,545 41,516 13
228,183 6,660,567 14
308,313 5,942,267 9,662,135 -1,078,073 14,526,329
8,001 ,1 59 7,490,743 463,953,015 -231,755,357 239,688,401
8,309,472 13,433,010 473,6't5,150 -232,833,430 2il,214,730
FERC FORM NO. r (ED. 12-90)Page 311.8
SALET
141
4,211
41,511
6,660,56:
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or 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
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 supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 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 service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
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
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (M!V)
(d)
Actual Demand (MW1
uontniy liCFbeman<
(e)
AveraoeMonthly CPDemand
(0
1 Netting - Bookouts NA NA NA NA
2 Netting - Trading NA NA NA NA
3 Accrual NA NA NA NA
4
5
6
7
8
I
't0
11
'12
13
14
Subtotal RQ c 0 0
Subtotal non-RQ c 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90)Page 310.9
PacifiCorp (1)
(2')
Original
Resubmission
Date of ReDort(Mo, Da, Yi)Year/Period of Report
End of 20181Q4
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-flrm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total"
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. 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 provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f1. 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 supplieis 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.
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 (i). Explain in a footnote all components of the amount shown in column O. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,line 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
($)
(h)
Energy Charges
($)
(D
Other Charges
($)
0)
-8,968,222 -236,899,122 1
-2,786,566 2
34,224 960,822 3
4
5
6
7
8
I
10
11
12
13
14
308,313 5,942,267 9,662,135 -1,078,073 14,526,329
8,001,159 7,490,743 463,953,015 -231,755,357 239,688,401
8,309,472 13,433,010 473,61 5,1 50 .232,833,430 254,2',14,730
FERC FORM NO. ' (ED. t2-90)Page 311.9
-236,899,12;
-2,786,566
960,82:
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
780,985
8,989(342,78s)
l-ete name S oTr UT Autho (Red Mesa
retent payment
Settlement adjustment
Customer service charges related to:- Schedule 94, Energy balancing account- Schedule 98, Renewable energy adjustment- Schedule 195, Utah Sustainable Transportation and Energy Plan
1 t
Represents the difference between actuaf requirement sales revenues for the pe asreflected on the individual line items within this schedule and the accruals charged to
Account 447, Sales for resale, duri the riod.
Reserve share
;(t_,1_t_4,781
ete name can HatSttColumn: a
UT
310 Line No.: 5oTr
310
310
Line No.:6
Line No.:7
Column: a
Column:
310 Line No; 14 Column:
Schedule Pase:310.1 Line No.: 2 Column: iReserve share
Set ement ustment
Settlement ustment
B H s Power Inc. - contract term na on te 31 2023.
Sett.lement ustment
310.1 Line No.:4 Column: b
310.1 Line No.:4 Column:
310.1 Line No; 5 Column: b
310.1 Line No.: 8 Column: b
310.1 Line No.: I Column: c
Service 37
310.1 Line No.: I Column:
Set.tlement Ad'ustment.
310.1 Line No.:9 Column: c
310.1 Line No.: 11 Column:
Service )l
Reserve re.
Sett ement ustment
Sett ement ustment
lete name t sh Col a and Power Autho t
Reserve share
Schedule Pase: 310.2 Line No.: 3 Column: aThis footnote applies to all occurrences of I'California fndependent System Operator" on
310 - 31_ 1 ete name is California r_on.
Settlement ad ustment
Settlement ustment
310.1 Line No.: 13 Column: b
310.1 Line No.: 13 Column:
310.2 Line No.: 1 Column: a
310.2 Line No.:1 Column:
310.2 Line No.:3 Column: b
310.2 Line No; 3 Column:
310.2 Line No;7 Column: b
Sett t ustment
endent tem tor
FERC FORM NO. I ED. I 450.1
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Settlement ustment.
Set ement ustment
Settlement ad ustment
Settlement ad ustment
Settlement.ustment.
Reserve s
310.2 Line No;7 Column:
310.2 Line No.: 13 Column: b
310.2 Line No.:13 Column
310.3 Line No.: 11 Column: b
310.3 Line No.: 11 Column:
310.3 Line No.: 14 Column:
310.4 Line No.: 1 Column:
Reserve s
Schedule Page: 310.4 Line No.:4 Column: a
310.4 Line 1 1 Column: b
ete name is Los 1es t of Water and Power.
Set.tlement ad ustment
Settlement ustment.
Reserve s
Power Company sa y owne NV Energy, Inc.,an
who11y owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
Settlement ustment.
Set ement ustment.
Reserve share
310.4 Line No.:11 Column:
310.4 Line No.:12 Column:
310.4 Line No.: 13 Column: a
310.5 Line No.: 1 Column: b
310.5 Line No.: 1 Column:
310.5 Line No.: 2 Column:
310.5 Line No.:7 Column: b
310.5 Line No.:7 Column:
310.5 Line No; 10 Column: b
310.5 Line No;10 Column
Schedule Page: 310.5 Line No.: 5 Column: j
Reserve share
Settlement ustment.
Settlement ustment.
Set ement ustment.
Settlement ad ustment.
ete name is Publ cUt ct No. 1 of Chelan
310.5 Line No;13 Column
Reserve share.
ete name Public Urili st ct No. 1 of as Coun
ete name c utili District No. l- of Snohomish Coun
ete name cUt t DiST
310.5 Line No.: 14 Column: a
310.6 Line No.: 1 Column: a
310.6 Line No.: 2 Column: a
310.6 Line No.:2 Column:
Reserve share
ct No. 2 Grant Coun
FERC FORM NO.1 (ED. 12471 Page 450.2
13 a
Name of Respondent
PacifiCorp
This Report is:
(1) XAn OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
310.6 Line No.:4 Column:Reserve s
9chedule Page:310.6 Line No.: 8 Column: j
Reserve share
310.6 Line No.:11 Column:
Reserve share
Schedule Pase:310.6 Line No.:12 Column: bSettlement ad ustment
Settl-ement ustment.
Sett t ustment
Sett t ustment
J 'a Pac f Power Company s a who11y owned s ary of NV Energy, Inc.,ch sanindirect who11y owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp'sindirect
Reserve
Sett ustment
Settlement ustment -
Pond sales
Schedule Pase:310.7 Line No.: 11 Column: j
Pond sa1es.
This footnote applies to a1 occurrences o ttTr -State Gen Trans. Assoc. " on pages
310 - 311 .lete name is Tri-State Generation and Transmission Association
Settlement ad'ustment.
Settlement ad ustment.
Reserve
t
Settlement ustment
Settlement ad ustment
Transmission loss sales revenuesservice customers.
rom Pac Corprs party transm
ssion loss sales revenues c ect rom Pacservice customers
Reflects transactions that did not icaI1 sett
Reflects trans ons t not
FERC FORM NO. r (ED. 12471 Paqe 450.3
310.6 Line No.:12 Column:
310.6 Line No.: 14 Column: b
310.6 Line No.: 14 Column:
310.7 Line No.: 3 Column: a
310.7 Line No.: 3 Column:
310.7 Line No.:9 Column: b
310.7 Line No.:9 Column:
310.7 Line No.:11 Column: b
310.7 Line No.:13 Column: a
310.7 Line No.:13 Column: b
310.7 Line No.:13 Column:
310.8 Line No.:4 Column:
310.8 Line No.:9 Column:
310.8 Line No.: 13 Column: b
310.8 Line No.: 13 Column:
310.8 Line No.:14 Column: b
310.8 Line No.:14 Column:
310.9 Line No.:1 Column:
)!L
310.9 Line No.:2 Column:
310.9 Line No.: 3 Column:
sett e
Corprs party tran
Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Represents the difference between actual non-requirement sales revenues for the period asrefl-ected on the individual line items within this schedule and the accruals charged to
Account 447, Sales for resale, during the period.
FERC FORM NO.1 (ED. 12.871 Page 450.4
Name of Respondent
PacifiCorp
This ReDort ls:(1) 5]Rn original(2\ EA Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 2018/Q4
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount forCurrent Year
(b)
Amount forPrevious Year
(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering 17 18,564,129
5 (501) Fuel 815,215,918 836,254,849
6 (502) Steam Expenses 75,578,998
7 (503) Steam from Other Sources 4,714,446 4,677,095
I (Less) (504) Steam Transferred-Cr,
I (505) Electric Expenses 1,538,384 1 ,215,091
10 (506) Miscellaneous Steam Power Expenses 24,373,827 12,187,163
11 (507) Rents 488,625 549,31s
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12)944,831,428 949,026,640
14 Maintenance
15 (510) Maintenance Supervision and Engineering 7,987,432 7,999,631
16 (51 1) Maintenance of Structures 26,949,381 30.784.444
17 (512) Maintenance of Boiler Plant 94,244,196 87,947,278
18 (513) Maintenance of Electric Plant 40,477,428 30,041,778
19 (514) Maintenance of Miscellaneous Steam Plant 9,735,906 12,751,402
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)179,394,343 169,524,533
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)1,124,225,771 1,118,551,173
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Enqineerinq
25 (518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr,
30 (523) Electric Expenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24lhtu 32\
34 Maintenance
35 (528) Maintenance Supervision and Engineering
36 (529) Maintenance of Structures
37 (530) Maintenance of Reactor Plant Equipment
38 (531) Maintenance of Electric Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 C. Hvdraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering 8,478,869 8,658,615
45 (536) Water for Power 38,379 120,631
46 (53il Hvdraulic Expenses 4,538,642 3,938,899
47 (538) Electric Expenses
48 (539) Miscellaneous Hydraulic Power Generation Expenses 17,012,228 15,714,600
49 (540) Rents 1,222,268 1,898,750
50 TOTAL Operation (Enter Total of Lines 44 thru 49)31,290,386 30,331,495
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Enqineerinq 470 389
54 (542) Maintenance of Structures 717,063 732,787
55 (543) Maintenance of Reservoirs, Dams, and Waterways 1,426,368 2,O42,717
56 (544) Maintenance of Electric Plant 1,683,128 2,518,525
57 (545) Maintenance of Miscellaneous Hvdraulic Plant 3,880,263 3,269,988
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)7,707,292 8,564,406
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)38,997,678 38,895,901
FERC FORM NO.1 (ED. 12.93)Page 320
PacifiCorp (1)
(2)Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount forCurrenl Year
(b)
Amount forPrevious Year
(c)
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Enqineerinq 285,602 343,362
63 (547) Fuel 13'l 214,054,042
64 (548) Generation Expenses 17,616,683 16,194,3s1
65 (549) Miscellaneous Olher Power Generation Expenses 5,107,905 5,434,018
66 (550) Rents 4,360,755 3,717,449
67 TOTAL Operation (Enter Total of lines 62 thru 66)266,s02,760 239,743,222
68 Maintenance
69 (551) Maintenance Supervision and Engineering
70 (552) Maintenance of Structures 4,396,956 2,717,666
71 (553) Maintenance of Generating and Electric Plant 17,759,259 15,757,596
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 3,138,006 3,063,915
73 TOTAL Maintenance (Enter Total of lines 69 thru 72)25,294,221 21,539,177
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)291 ,796,981 261,282,399
75 E. Other Power Supplv Expenses
76 (555) Purchased Power 667,434,104 639,445,881
77 (556) System Control and Load Dispatching 1 ,211,514 1,310,5'15
78 (557) Other Expenses 41 ,691,162 43,501,285
79 TOTAL Other Power Supply Exp (Enter Tolal of lines 76 thru 78)710,336,780 684,257,681
80 TOTAL Power Production Expenses (Total of lines 21, 41 , 59, 74 &79)2,165,357,210 2j02,987,154
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering 6,772,651 6,U7,8U
84
85 (561.1 ) Load Dispatch-Reliability
86 (561.2) Load Dispatch-Monitor and Operate Transmission System 7,234,514 6,954,702
87 (561.3) Load Dispatch-Transmission Service and Scheduling
88 (561.4) Scheduling, System Control and Dispatch Services 't,384,344 2,007,912
89 (561.5) Reliability, Planning and Standards Development 1,968,543 1,674,277
90 (561.6) Transmission Service Studies 102,948 72,957
91 (561.7) Generation lnterconnection Studies 1,755,384 1,696,771
92 (561.8) Reliability, Planning and Slandards Development Services 7,447,677 7,484,166
93 (562) Station Expenses 2,901,944 3,4',t3,321
94 (563) Overhead Lines Expenses 864,557 505,147
95 (564) Underground Lines Expenses
96 (565) Transmission of Electricitv bv Others 135,021,597 134,473,119
97 (566) Miscellaneous Transmission Expenses 2,859,169 2.349.109
98 (567) Rents 2,1 38,345 2,161,509
99 TOTAL Operation (Enter Total of lines 83 thru 98)170,451,673 169,140,844
100 Maintenance
101 (568) Maintenance Supervision and Engineering 1,444,581 1,062,627
102 (569) Maintenance of Structures 41,891 51,2',t8
103 (569.1) Maintenance of Computer Hardware 67,060 155,815
104 (569.2) Maintenance of Computer Software 825,322 701,841
105 (569.3) Maintenance of Communication Equipment 5,238,837 4,91 '1,057
'106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment 11,984,857 'I 1 ,826,1 06
108 (571) Maintenance of Overhead Lines 16,147,738 16,851,778
109 (572) Maintenance of Underground Lines 81 ,815 19,786
110 (573) Maintenance of Miscellaneous Transmission Plant 222.170 84,769
'111 TOTAL Maintenance (Total of lines 101 thru 1 10)36,054,271 35,664,997
112 TOTAL Transmission Expenses (Total of lines 99 and 1'1 1)206,505,944 204,805,84'.1
FERC FORM NO. 1 (ED. 12-93)Page 321
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
lf the amount for previous year is not derived from previously repoded figures, explain in footnote
Line
No.
Account
(a)
Amount forPrevious Year
(c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Day-Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Rights Market Facilitation
118 (575.4) Capacity Market Facilitation
119 (575.5) Ancillary Services Market Facilitation
120 (575.6) Market Monitorinq and Compliance
121 (575.7) Market Facilitation, Monitoring and Compliance Services
122 (575.8) Rents
123 Total Operation (Lines 1 15 lhru 122\
124 Maintenance
125 (576.1) Maintenance of Structures and lmprovements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Soft\ /are
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 1 30)
132 4, DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Enqineerinq 8,848,063 8,961,333
135 (581) Load Dispatching '11 ,541,737 10,667,212
136 (582) Station Expenses 4,076,355 3,986,742
137 (583) Overhead Line Expenses 9,211,450 7,809,454
138 (584) Underqround Line Expenses 2,063 787
139 (585) Street Lighting and Signal System Expenses 247,796 't52,074
140 (586) Meter Expenses 2,790,673 4,220,933
'141 (587) Customer lnstallations Expenses 14,205,310 13,556,316
142 (588) Miscellaneous Expenses 1 ,1 96,1 49 1,975,285
143 (589) Rents 3,'t82,216 3,178,795
144 TOTAL Operation (Enter Total of lines 134 thru 143)55,301,812 t4,508,931
145 Maintenance
146 (590) Maintenance Supervision and Enqineerinq 5,835,359 5,400,066
147 (591) Maintenance of Structures 2,142,078 2,463,160
148 (592) Maintenance of Station Equipment 9,062,978 9,002,066
149 (593) Maintenance of Overhead Lines 89,351,304 86,667,266
150 (594) Maintenance of Underqround Lines 24,670,628 25,465,187
151 (595) Maintenance of Line Transformers 974,547 969,563
152 (596) Maintenance of Street Lighting and Signal Systems 2,965,826 2,930,590
'153 (597) Maintenance of Meters 225.334 138,623
154 (598) Maintenance of Miscellaneous Distribution Plant 6,728,870 10,103,297
155 TOTAL Maintenance (Total of lines 146 thru 1 54)'t41,956,924 143,139,818
156 TOTAL Distribution Expenses (Total of lines 144 and 1 55)197,258,736 197,648,749
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 2,477,399 2,362,629
160 (902) Meter Reading Expenses 19,056,668 19,666,217
161 (903) Customer Records and Collection Expenses 50,336,486 47,770,750
162 (904) Uncollectible Accounts 11,655,692 15,424,209
163 (905) Miscellaneous Customer Accounts Expenses 135,391 881,737
164 TOTAL Customer Accounts Expenses (Total of lines 1 59 thru 163)83,661,636 86,105,542
FERC FORM NO. 1 (ED. r2-93)Page 322
Name of Resprsndsnl
PacifiCorp
This Reoort ls:(1) 5l1Rn originat(2) l-lA Resubmission
Date of ReDorl(Mo, Da, Yi)tl
Year/Period of Report
End of 20181Q4
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount forCurrent Year
(b)
Amount forPrevious Year
(c)
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision 1 17,633 288,761
168 (908) Customer Assistance Expenses 90,120,906 87,894,734
169 (909) lnlbrmational and lnstructional Expenses 5,820,368 3,335,567
170 (910) Miscellaneous Customer Service and lnformational Expenses 41,342 3,182
171 TOTAL tlustomer Service and lnformation Expenses (Total 167 thru 170)96,100,249 91,522,244
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision
175 (912) Demonstratinq and Sellinq Expenses
176 (9'l 3) Aclvertising Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 1 77)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries 72,265,963 70,99't,765
182 (921) Olfice Supplies and Expenses 9,971,031 9,355,736
183 (Less) (922) Administrative Expenses Transferred-Credit 31,909,798 31,',t40.474
184 (923) Orltside Services Employed 19,890,624 23,869,244
't 85 (924) Property lnsurance 14,821,125
186 (925) lniuries and Damaqes 16,740,1U 9,434,369
187 (926) Employee Pensions and Benefits s8,462,764
188 (927) Frianchise Requirements
189 (928) Regulatory Commission Expenses 22,484,361 22,853,804
190 (929) (Less) Duplicate Charges-Cr.103,489,435
191 (930.1) {ieneral Advertising Expenses 580 't,435
't92 (930.2) lrtliscellaneous General Expenses 2,225,689 2,272,508
193 (931) Re:nts 2.723.369 3,040,328
194 TOTAL Operation (Enter Total of lines 181 thru 193)111 ,837,137 120,473,169
195 Maintenirnce
196 (930 Maintenance of General Plant 23,525,832 21 ,636,566
197 TOTAL r\dministrative & General Expenses (Total of lines 194 and 196)142,109,735
198 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197)2,884,246,744 2,825,179,265
FERC FORi' NO.1 (ED. 12-93)Page 323
12,338,561
1 13.736.5S4
128.629.971
135.362.969
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
usEment to Pac Corp's
H-1, is as follows:
a rate under FERC Docket No. ERI-]--3543-000, Attachment.
Account
(a)
Ref.
Line No.
(Column)
Amount for
Current Year
(b)
(924) Property InsuranceLess: Situs property loss reserves,
Revised (924) Property Insurance
net of reimbursements (1)
185 (b) I a2,338,551
? T?5 ?NT
$ 5 ,203,260
(1) To adjust PacifiCorp's formula rate, per FERC Docket No.loss reserves, net of reimbursements.
FAI-5-4-000 for situs property
Schedule Page: 320 Line No.: 187 Column: b
As required by Commission regulations, the cost of pensi-ons, posLretirement other thanpensions and other employee benefits are reported in Account 925, Employee pensions andbenefits. Pensions and benefi-ts expense is associated with labor and generally charged to
operations and maintenance expense and construction work in progress, therefore, pursuantto FERC Docket No. FA15-4-000, these pensions and benefits are offset in AccounL 929,Duplicate charges-credit.
In accordance with PacifiCorpts formula rate settlement agreement in FERC Docket No.
ER11-3643-000, Section 3.4.2.9 states, j-n part, all regulatory asset amortizations shouldbe excluded from the calculation of the wholesale transmission revenue reguirement andcharges under the wholesale formula rates, unless approved by the Commission. During theyear ended December 31, 2018, pension and postretirement regulatory asset amortj-zation was
i(2,152,679).
Includesbenefits,the offset of pens ons ts Account 926,oyee pens onspursuant to FERC Docket No. FA15-4-000
320 Line No.: 190 Column: b
320 Line No.: 197 Column: bustments toH-1, are as foffows f Corp's formula rate under FERC Docket No. ER11-3643-000, Attachment
Ref.
L]-ne NO.
(Column)
Amoun
Curren
tf
TY
or
earAccount
(a)(b)
TOTAL Administrative & ceneral Expenses 197(b) $ L35,352,959Less: Situs property loss reserves, net of reimbursements(1) 7,135,301Less: Pension and postretirement regulatory asset amort. (2)\z 1,52 67 9)
Revised TOTAI Administrative & General Expenses $ l-30 ,380,347
(1) To adjust Account 924, Property insurance. Refer to footnote on page 320,line no. 185, column (b)(2) To adjust Account 925, Employee pensions and benefits. Refer to footnote on page 320,line no. !87, column (b)
FERC FORM NO.1 ED.1 450.1l7)
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. E:xplain 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 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 service to its own ultimate consumers.
LF - for long-,term flrm 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 from
third parties 1:o 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 intemediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for shorl-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long.term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for interrrediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than crne year but less than five years.
EX - For exclranges 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 sen'ice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service irr a footnote for each adjustment.
Line
No.
Nanre of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (M!t/)
(d)
Actual Demand (MW
Average
Monthly NCP Deman(
(e)
Average
Monthly CP Demand
(0
1 Power Purchases
2 Adams Siolar Center LLC LU NA NA NA
3 Apple, lrc.LU NA NA NA
4 SF NA NA NA
5 Arizona Public Service Company NA NA NA
6 Arizona Public Service Company SF NA NA NA
7 Arizona Public Service Company NA NA NA
8 Avangrid Renewables, LLC SF NA NA NA
I Avangrid Renewables, LLC NA NA NA
10 Avista Crrrporation SF NA NA NA
11 Ballard Hog Farms lnc.LU 0 0 0
12 Basin Eklctric Power Cooperative SF NA NA NA
13 BC Solar, LLC LU NA NA NA
14 BC Solar, LLC NA NA NA
Total
FERC FORM NO. I (ED. 12-90)Page 326
Arizona l:lectric Power Cooperative
LF
AD I
AD I
AD
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)tl
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (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 (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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 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.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No,MegaWall Hours
Received(h)
Megawatt Hours
Delivered
(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
o
Total (i+k+l)
of Settlement ($)
(m)
1
't2,011 691,66C 693,647 2
7,654 612,18S 612,189 3
7,70C 356,20C 356,200 4
47,352 1,214,03e 1,214,036 5
60,89€2,564,885 2,504,885 6
-3 7
1,907,012 65,59'1 ,36i 65,591,523 8
44 1,269 o
200,98€7,462,53e 7,470,135 10
28t 5,988 14,68:20,67',!11
193,99€10,455,542 '10,455,542 12
18,53(1,162,',t74 1,162,175 13
19€4,142 14
13,668,425 7,967,992 7,994,889 32,377,530 904,189,538 -269,132,964 667,434,104
FERC FORM NO.1 (ED. 12-90)Page 327
},UKUHA
1,98i
16'
1,269
7,59(
4,142
Name of Resprlndsnl
PacifiCorp
ort ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and cr,edits for energy, €pacity, 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 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 siecond only to, the supplier's service to its own ultimate consumers.
LF - for long,1grrn flrm service. "Long-term" means five years or longer and "flrm" 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 defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for internrediate-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 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 availabilig 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 energy, capacity, etc.
and any settk:ments for imbalanced exchanges.
OS - for othe'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 o'l
the service in a footnote for each adjustment.
Line
No.
Nanre of Company or Public Authori$
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (M!V1
(d)
Actual Demand (MV$
AVerage
Monthly NCP Deman<
(e)
AVerage
Monthly CP Demand
(0
1 Bear Creek Solar Center, LLC LU NA NA NA
2 Beaver Oity Corporation NA NA NA
J Bell Mountain Hydro, LLC LU NA NA NA
4 Beryl Solar, LLC LU 3 3 1
5 Big Top, LLC LU NA NA NA
6 Biomass One, L.P LU NA NA NA
7 Birch Power Company, lnc.LU NA NA NA
8 LU NA NA NA
I Black Hills Power, lnc.SF NA NA NA
10 Bly Solar Center, LLC LU NA NA NA
1',!Bonneville Power Administration NA NA NA
't2 Bonneville Power Adminishation SF NA NA NA
13 Bonneville Power Administration NA NA NA
14 Bourdet, Peter M LU NA NA
Total
FERC FORM NO. 1 (ED. 12-90)Page 326.1
LF
Black Cap Solar, LLC
LF
qD
NA
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tl
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
Megawatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Received
(h)
Megawatt Hours
Delivered
(i)
Demand charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
(l)
Total (i+k+l)
of Settlement ($)
(m)
5,45€268,343 268,U3 1
31 3,064 3,064 2
941 83,513 83,513 3
6,27C 422,750 319,793 742,543 4
4,121 317,57C 317,576 5
166,002 12,577,42e 14,975,176 6
12,804 816,901 816,901 7
52i 24,483 24,483 8
1't,37C 843,789 843,789 I
56i 28,588 28,588 10
72 125,232 11
770,374 21,378,59C 21,423,007 12
2 13
32e 12,06e 12,068 14
13,668,425 7,967,992 7,994,889 32,377,530 904,189,538 -269,1 32,964 667,4U,104
FERC FORM NO.1 (ED. 12-90)Page 327.1
HUKUHI
2,397,751
129,161
44,41',
Name of Respondent
PacitiCorp
ort ls:
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)lt
Year/Period of Report
End of 20181Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. 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 projr:cts 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,1sr, firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 shorl-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
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 energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ol
the service in a footnote for each adjustment.
Line
No.
Narne of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MVVI
(d)
Actual Demand
Monthly Monthly
(e)(0
1 Box Can'yon Limited Partnership LU 2 2 1
2 BP Ener{ry Company SF NA NA NA
3 Brigham Young University - ldaho IU NA NA NA
4 Brookfield Energy Marketing LP SF NA NA NA
5 Buckhorn Solar, LLC LU 3 3 1
6 Butter Creek Power, LLC LU NA NA NA
7 C Drop l-lydro, LLC LU NA NA NA
8 SF NA NA NA
9 California lndependent System Operator NA NA NA
10 Calpine [:nergy Services, L.P SF NA NA NA
11 Cargill Power Markets, LLC NA NA NA
12 Cedar Valley Solar, LLC LU J 3 1
13 Central Oregon lrrigation District LU 4 4 3
14 Chevron U.S.A. lnc.LU NA NA NA
Total
FERC FORM NO. 1 (ED. 12-90)Page 325.2
California lndependent System Operator
AD
AD
PacifiCorp (1)
(2)
Original
Resubmission
Dale of Report
(Mo, Da, Yr)tl
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 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 1 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 required data.
Megawatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POVI/ER Line
No.Megawatt Hours
Received
(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
0)
Energy Charges
($)
(k)
Other Charges
($)
(D
Total (i+k+l)
of Settlement ($)
(m)
8,75t 197,023 1,267,69(1,464,7',t3 I
2,313,42!70,194,022 70,194,022 2
38,685 2,134,001 2,134,001 3
17,912 1,8r4,441 1,8il,441 4
5,972 423,962 304,59i 728,s54 5
13,533 1,037,251 1,037,251 6
1,777 142,017 142,017 7
M,424 2,005,258 2,005,258 8
-61,987 I
90,28S 3,812,654 3,812,654 10
10c 2,40C 11
5,946 420,160 303,266 723,424 12
35,514 450,587 3,813,27e 4,263,865 13
22,804 296,057 296,057 14
13,668,425 7,967,992 7,994,889 32,377,530 904,189,538 -269,132,9U 667,4U,104
FERC FORM NO.1 (ED. 12-90)Page 327.2
TUKUHA
-61,98;
2,401
Name of Respondent
PacifiCorp
)ort ls:
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and cledits 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. Eixplain 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 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 service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 shorFterm service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long..term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, asidr: 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 cne year but less than five years.
EX - For exclranges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settl,ements 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 ol
the service ir a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (M!V1
(d)
Actual Demand (MW1
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(0
1 Chiloquin Solar LLC LU NA NA NA
2 Chopin VMnd, LLC LU NA NA NA
3 Citigroup Energy, lnc.SF NA NA NA
4 City of Albany LU NA NA NA
5 City of Anaheim SF NA NA NA
6 City of Astoria LU NA NA NA
7 City of Burbank SF NA NA NA
8 City of Glendale SF NA NA NA
I City of Hrrricane NA NA NA
't0 City of Hrrricane NA NA NA
't1 City of ldaho Falls LU NA NA NA
12 City of ldaho Falls NA NA NA
13 LU NA NA NA
14 City of Preston ldaho NA NA NA
Total
FERG FORM iro.1 (ED. 12-90)Page 326.3
LF
AD
AD
City of Portland, Water Bureau
AD
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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 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.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Received(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (i+k+D
of Settlement ($)
(m)
20,03i 831 ,88(831,886 1
31,244 1,702,414 1,702,414 2
923,39I 24,342,U!24,342,345 3
1 ,13:88,35!88,359 4
21C 1,20e 1,206 5
1S 73(730 6
2,58t 157,88t 157,888 7
'1,40(79,60(79,600 8
2,69S 1 83,1 3i 1 83,1 37 I
216 10
62,82t 1,640,364 11
11,509 12
161 12,86t 12,868 13
-325 14
13,668,425 7,967,992 7,994,889 32,377,53A 904,189,538 -269,132,964 667,434,104
FERC FORIT, NO. 1 (ED. 12-90)Page 327.3
TUKUHf
21t
1,640,36,
11,soe
-32t
Name Resp,cndent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 2018/Q4
PURCHASED POWER (Account 555)(lncluding power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. 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 projr:cts 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 flrm 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 from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service flrm 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 internrediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five yeas.
SF - for shorl-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for internrediate-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 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.
Nanre of Company or Public Authority
(Footnote Afliliations)
(a)
Statistical
Classifi-
cation
(b)
FERC RaIe
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW
Average
Monthly NCP Deman(
(e)
Average
Monthly CP Demand
(0
1 City of Preston ldaho LU NA NA NA
2 City of Redding SF NA NA NA
3 City of Roseville SF NA NA NA
4 Clatskanie People's Utility District SF NA NA NA
5 Commercial Energy Management lnc.LU NA NA NA
6 Confederate Tribes of Warm Springs LU NA NA NA
7 ConocoF'hillips Company SF NA NA NA
8 Consolidated lrrigation Company LU NA NA NA
I Cottonwood Hydro, LLC IU NA NA NA
10 Cottonwood Hydro, LLC NA NA NA
11 Crook County Solar 1, LLC LU NA NA NA
12 Deschutes Valley Water District LU 4 3 3
13 100 100 81
14 Direct Energy Business Marketing, LLC SF NA NA NA
Total
FERC FORM NO. I (ED. 12-90)Page 326.4
AD
Deseret,3eneration and Transmission LF
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Received
(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
0)
Energy Charges
($)
(k)
Other Charges
($)
o
Total (+k+l)
of Settlement ($)
(m)
2,50t 't45,M?145,643 1
1,64[60,77(60,770 2
29,52t 2,969,16(2,969,160 3
1,703 13,98i 13,987 4
2,404 136,72!136,725 5
303 11,33(11,339 6
204,293 6,658,999 6,658,999 7
2,145 't25,911 125,91',!I
3,102 't49,024 M9,024 I
12 553 10
1,2s3 48,247 48,247 11
24,468 380,796 3,320,355 3,701,1s1 12
489,799 17,689,080 11,046,121 33,300,841 13
4,674 766,743 766,743 14
13,668,425 7,967,992 7,994,889 32,377,530 904,1 89,538 -269,132,964 667,4Uj04
FERC FORM NO.1 (ED. r2-90)Page 327.4
HUKUHF
55:
4,565,64(
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20'l8lQ4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. E.xplain 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 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 service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency energy from
third parties lo 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 shorlrterm service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-.term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, asidr: 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 cne year but less than five years.
EX - For exclranges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ol
the service irr a footnote for each adjustment.
Line
No.
Nante of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW
(d)
Actual Demand
Monthly Monthly
(e)(0
1 Dorena t{ydro, LLC LU NA NA NA
2 Douglas County LU 0 0 0
3 Douglas County, lnc.LU NA NA NA
4 Draper lrrigation Company IU NA NA NA
A Dry Cre€,k LLC LU NA NA NA
6 Dry Cree,k LLC NA NA NA
7 DTE Enerrgy Trading, lnc.SF NA NA NA
8 eBay lnc.LU NA NA NA
I EDF Tra,Cing North America, LLC SF NA NA NA
10 El Paso lllectric Company SF NA NA NA
11 Elbe Sol;ar Center, LLC LU NA NA NA
12 Elbe Sol;ar Center, LLC LU NA NA NA
13 Element Markets, LLC NA NA NA
14 Enterpris,e Solar, LLC LU NA NA NA
Total
FERC FORM I'lO. 1 (ED. l2-90)Page 326.5
AD
OS
PacifiCorp (1)
(2)
Original
Resubmission
Date of
(Mo, Dalt
Report
r, Y0
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not repo( net exchange.
7. Report demand charges in column (1), 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 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 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. fhe
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 POIAER Line
No.Megawatt Hours
Received
(h)
Megawatt Hours
Delivered
(i)
Demand Charges
($)
0)
Energy Charges
($)
(k)
Other Charges
($)
(D
Total (j+k+l)
of Settlement ($)
(m)
9,322 746,803 746,803 1
2,417 51.572 368,598 420,170 2
3,74C 120,03S 120,039 3
23 1 ,618 1,618 4
12,579 773,03C 773,030 5
4,662 6
675 14,171 't4,175 7
244 19,30€'19,309 8
583,508 14,962,3s€14,962,356 I
35,08€'l,278,092 1,278,O92 10
557 11
10,62€697,02€697,025 12
35,478 13
435,132 14
13,668,425 7,967,992 7,994,889 32,377,530 904,189,538 -269,132,904 667,434,104
FERC FORM NO. r (ED. 12-90)Page 327.5
4,66:
55:
35,471
435,13:
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20'l8lQ4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. E.xplain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classiflcation Code based on the original contractual terms and conditions of the service as follows:
RQ - for requrirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes proj,ects load for this service in its system resource planning). ln addition, the reliability of requirement service must be the
same as, or r;econd only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 shoriterm service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, asid,3 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 crne year but less than five years.
EX - For exclranges 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 sen,ice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ol
the service in a footnote for each adjustment.
Line
No.
Nanre of Company or Public Authority
(Footnote Afiiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW1
Average
Monthly NCP Deman(
(e)
Average
Monthly CP Demand
(f)
1 Enterprise Solar, LLC LU NA NA NA
2 Escalanle Solar l, LLC LU NA NA NA
3 Escalanle Solar ll, LLC LU NA NA NA
4 Escalanle Solar lll, LLC LU NA NA NA
5 Eugene Water & Electric Board SF NA NA NA
6 Eurus C,:mbine Hills I, LLC LU NA NA NA
7 Exelon Generation Company, LLC SF NA NA NA
8 Exelon Generation Company, LLC NA NA NA
I ExxonMobil Production Company LU NA NA NA
10 LU NA NA NA
11 Falls Creek H.P. Limited Partnership LU 3 3 0
't2 Farm Power Misty Meadow, LLC LU NA NA NA
13 Farmers lnigation District LU NA NA NA
14 Fillmore City Corporation NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.6
AD
Fall Rive,r Rural Electric Cooperative
LF
Name of Respondent
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the 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 (9) 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 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 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 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. fhe
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)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)o
Total (,+k+l)
of Settlement ($)
(m)
22533e 12,266,33i 12,266,333 1
204,r45 10,936,59(10,936,596 2
208,002 10,565,87(10,565,876 3
206,35i 1 0,1 1 8,59i 10,118,592 4
8,1 3€162,145 162,149 5
1 13,681 5,527,15t 5,527,154 6
973,63t 23,998,72i 23,598,722
80(19,400 8
37f 7,252 7,252 I
28,29t 1 ,917,35i '1,917,357 't0
12,544 161 ,908 't,741 ,13t 1,903,046 11
4,03€322,98(322,986 12
23,42e 1,753,98t 1,753,985 13
182 19,94r 19,944 14
13,668,425 7,967,992 7,994,889 32,377,530 904,189,538 -269,132,904 667,434,101
FERC FORM NO. I (ED. 12-90)Page 327.6
HUKUHP
19,40(
Name of Respondent
PacifiCorp
,ort ls:
An Original
A Resubmission
Date
(Mo,tt
of Report
Da, Yr)
Year/Period of Report
End of 20181Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. E.xplain 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 requrirements 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 reliabili$ of requirement service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 shorl-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, asid,e from transmission constraints, must match the availability and reliability of the designated unit.
lU - for interrnediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm senrice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ol
the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MV1r)
Average
Monthly NCP Deman(
(e)
Average
Monthly CP Demand
(D
1 Finley BioEnergy, LLC LU NA NA NA
2 Flathead Electric Cooperative, lnc.NA NA NA
3 Flathead Electric Cooperative, lnc.NA NA NA
4 Foote C'eek ll, LLC LU NA NA NA
5 Foote C'eek lll, LLC LU NA NA NA
6 Four Corners Windfarm, LLC LU NA NA NA
7 Four Mile Canyon \Mndfarm, LLC LU NA NA NA
I Georgetown lrrigation Company LU NA NA NA
I Grand Valley Power NA NA NA
10 Granite [Iountain Solar East, LLC LU NA 3 NA
11 Granite Mountain Solar West, LLC LU NA NA NA
12 Granite Peak Solar, LLC LU 3 3 1
13 Greenville Solar, LLC LU 2 2 1
14 Gridforoe Energy Management, LLC SF NA NA NA
Total
FERC FORM NO.1 (ED. i2-90)Page 326.7
LF
AD
LF
PacifiCorp (1)
(2)
Original
Resubmission
Date of ReDort(Mo, Da, Yi)Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401 , line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
Megawatt Hours
Delivered
(i)
Demand Charges
($)
0)
Energy Charges
($)
(k)
Other Charges
($)
(D
Total 0+k+Dof Settlement ($)
(m)
31,494 2,452,791 2,452,791 1
371 9,70t 9,708 2
258 3
5,93€120,21t 120,214 4
73,66t 1,625,97t 1,625,978 5
28,78t 2,206,02!2,206,029 6
27,321 2,097,65€2,097,656 7
2,24t 143,501 140,990 I
at 8,22t 8,228 I
208,091 10,761,451 10,761,454 10
123,56i 6,733,08€6,733,089 11
6,08:240,355 211,82(452,181 12
4,O91 316,317 208,61€524,933 13
126 4,706 't4
13,668,425 7,967,992 7,994,889 32,377,534 904,189,538 -269,1 32,964 667,4U104
FERC FORM NO. I (EO. 12-90)Page 327.7
PUKUHF
251
-2,51'
4,701
Name of Respcndent
PacifiCorp
rort ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
1 . Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. 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 proji3cts 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 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 lo 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 shoiiterm service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intennediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than crne 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 sen,ice 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 Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW
(d)
Actual Demand (M!V)
Average
Monthly NCP Deman<
(e)
AVerage
Monthly CP Demand
(D
1 Hammerich 1 & 2 LU NA NA NA
2 Harold Foster & Robert Walker LU NA NA NA
3 LU NA NA NA
4 ldaho Power Company NA NA NA
5 ldaho Power Company SF NA NA NA
6 lron Springs Solar, LLC LU NA NA NA
7 J Bar 9 flanch, lnc.LU NA NA NA
8 Jake Anry LU NA NA NA
I Jake Anry NA NA NA
10 Joseph Community Solar, LLC LU NA NA NA
1'.!Keeton 'l & 2 LU NA NA NA
12 Kettle Butte Digester LLC LU NA NA NA
13 Klamath Falls Solar 1, LLC LU NA NA NA
14 Klamath Falls Solar 2, LLC IU NA NA NA
Total
FERC FORM NO.1 (ED.12-90)Page 326.8
Haywarcl Paul Luckey and Joanne Luckey
OS
AD
Name of Respondent
PacifiCorp (1)
(2\
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f1. Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (1), 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 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 charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
Megawatt Hours
Delivered
(i)
Demand Charges
($-)
0)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (i+k+l)
of Settlement ($)
(m)
397 14,903 14,903 1
9€3,071 3,071 2
237 13,203 13,203 3
2,59€16,399 16,399 4
312,30€8,157,782 8,159,536 5
211.79e 11,329,60i 11,329,607 6
5€1,261 1,261 7
2,18C 134,66C 134,66C 8
22 1,397 I
731 25,37i 25,377 10
384 14,55(14,55C 11
7,00t 488,241 488,247 't2
'1,104 69,17S 69,1 79 13
5,441 226,254 226,254 14
13,668,425 7,967,992 7,994,889 32,377,534 904,189,538 -269,1 32,964 667,434,104
FERC FORM NO.1 (ED. r2-90)Page 327.8
I-UKUFIA
1,75,
1,397
Name of Resprondent
PacifiCorp
rorl ls:
An Original
A Resubmission
Date of Reoort(Mo, Da, Yi)tl
Year/Period of Report
End of 20181Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. 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 reliabilig of requirement service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for longterm firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency energy from
third parties lo 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 shorliterm service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
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 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 serv'ice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service irr a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (M!V)
(d)
Actual Demand
Monthly
(e)(f)
I Klamath Falls Solar 2, LLC NA NA
2 Lacomb lrrigation District LU NA NA NA
3 Laho So ar, LLC LU 3 3 1
4 Latigo \ rind Park, LLC LU NA NA NA
5 SF NA NA NA
6 Loyd Fery LU NA NA
7 Macquarie Energy LLC SF NA NA NA
Marsh Valley Hydro Electric Company LU NA NA
9 Meadow Creek Project Company LLC LU NA NA NA
10 Middle Fork lrrigation District LU NA NA NA
11 Middle Fork lrrigation District NA NA NA
't2 Milford Flat Solar, LLC LU 0 3 I
13 Milford Flat Solar, LLC NA NA NA
14 Mink Crerek Hydro LLC LU NA NA NA
Total
FERC FORM NO. I (ED. 12-90)Page 326.9
qD NA
Los Angr:les Dept. of Water and Power
NA
8 NA
AD
{D
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Y0
Year/Period of Report
End of 20'l8lQ4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the 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 (9) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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 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 expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401 , line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF PO\A/ER Line
No.Megawatt Hours
Received
(h)
Megawatt Hours
Delivered
(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (i+k+l)
of Settlement ($)
(m)
7 ,|
4,223 100,764 164,347 2
6,413 241,235 223,304 464,539 3
155,67C 9,376,95C 9,376,950 4
23,23C 2,06't,517 2,061,517 5
283 6,31 1 6,311 6
294,951 11,795,249,'t't,795,249 7
6,86t 438,77i 438,777 8
346,1 81 25,979,53€25,979,539 9
23,13:'t,621,161 1,621,161 10
-250 1'.!
6,28t 240,992 218,937 459,929 12
-241 446,151 560,328 13
9,28€575,731 575,737 14
13,668,425 7,967,992 7,994,889 32,377,530 904,1 89,538 -269,1 32,964 667,4U,104
FERC FORM NO. 1 (ED.12-90)Page 327.9
I-UKUHA
I
63,58:
-2sc
114,17i
Name of Res,pondent
PacifiCorp
)ort ls:
lAn Original
lA Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20'l8lQ4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Eixplain 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 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 r;econd only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons anrJ 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 interntediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for shc,rr:-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long.term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, asidr: from transmission constraints, must match the availability and reliability of the designated unit.
lU - for internrediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than crne 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 sen'ice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service irr a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW
(d)
Actual Demand (MV1/1
Average
Monthly NCP Deman(
(e)
Average
Monthly CP Demand
(0
1 Monsanlo Company IU NA NA NA
2 Morgan llity Corporation NA NA NA
3 Morgan rstanley Capital Group, lnc.SF NA NA NA
4 Morgan lstanley Capital Group, lnc.NA NA NA
5 Mountain Wind Power, LLC LU NA NA NA
6 Mountain Wind Power ll, LLC LU NA NA NA
7 Municiperl Energy Agency of Nebraska SF NA NA NA
8 LU NA NA NA
I NaturEnr:r Power Watch, LLC SF NA NA NA
'10 SF NA NA NA
11 Nevada rower Company NA NA NA
12 NextEra Energy Marketing, LLC SF NA NA NA
13 NextEra Energy Power Marketing, LLC SF NA NA NA
14 Nichols Gap Limited Partnership LU 1 1 0
Total
FERC FORM I'lO. 1 (EO. 12-90)Page 326.10
LF
AD
Myron,jones
Nevada >owerCompany
AD
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 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 1 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 required data.
MegaWatt Hours
Purchased
(s)
PO\A/ER EXCHANGES COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Received(h)
MegaWaft Hours
Delivered
(i)
Demand charges
($)
0)
Energy Charges
($)
(k)
Other Gharges
($)
o
Total (i+k+l)
of Settlement ($)
(m)
20,003,760 1
t 735 735 2
930,04'35,300,441 35,300,441 3
67!40,500 4
158,793 8,823,135 8,823,"135 5
219,04t 14,112,156 't4,112,156 6
4,221 334,965 334,965 7
776 45,929 45,929 8
?87 I
25,402 836,948 836,948 10
1,722 11
2,675 96,75C 96,750 12
2,000 58,600 58,600 13
3,331 41,588 479,286 520,874 14
13,668,425 7,967,992 7,994,889 32,377,530 904,189,538 -269,1 32,964 667,434,10t
FERC FORM NO. I (ED.12-90)Page 327.10
t-uKt t-tf
20,003,76(
40,50(
8,
1,721
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
1. Report al power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and oedits 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 colunrrr (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 supplier's service to its own ultimate consumers.
LF - for longterm firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 deflnition 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 firm services, where the duration of each period of commitment for service is one
year or less.
LU - for lonlg-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 intennediate-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 exclranges 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 sen,ice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ol
the service in a footnote for each adjustment.
Line
No.
Nanre of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (M\A/)
(d)
Actual Demand (MW
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(0
1 Nichols, Gap Limited Partnership AD NA NA NA
2 Nicholson's Sunny Bar Ranch LU NA NA NA
J Nicholson's Sunny Bar Ranch NA NA NA
4 NorthWe.stern Corporation SF NA NA NA
5 NorWesl Energy 2, LLC IU NA NA NA
6 Norwesl Energy 7, LLC IU NA NA NA
7 Norwesl Energy 7, LLC NA NA NA
8 NorWest Energy I, LLC IU NA NA NA
I Nucor C0rporation IU NA NA NA
10 Obsidian Renewables, LLC LU NA NA NA
11 Old Mill {iolar, LLC LU NA NA NA
12 OR Solar 3, LLC LU NA NA NA
13 OR Solar 3, LLC NA NA NA
14 OR Solar 5, LLC LU NA NA NA
Total
FERC FORrrr NO. 1 (ED. 12-90)Page 326.11
AD I
AD t
AD
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20'l8lQ4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 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.L 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)
Megawaft Hours
Delivered
(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
(D
Total (j+k+D
of Settlement ($)
(m)
-822 -822 1
1,802 1 14,189 '1 '14,1 89 2
434 3
8,021 102,39C 109,772 4
21,651 1,356,832 1,356,832 5
18,684 1,171,283 1,171,283 6
-88 7
1,721 65,767 65,767 8
7,201,204 I
764 33,505 33,50s 't0
10,441 783,097 783,097 11
22,144 918,696 918,6S6 12
-71 13
18,491 767,252 767,252 14
13,668,425 7,967,992 7,994,889 32,377,530 904,1 89,538 -269,132,964 667,434,104
FERC FORl,l NO. 1 (ED. 12-90)Page 327.1'l
PUI.(UHF
-431
7,382
-81
7,201,201
-71
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)Year/Period of Report
End of 20181Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requrirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes prqects 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 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 1o 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 shorliterm service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intemediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service n a footnote for each adjustment.
Line
No.
Nanre of Company or Public Authority
(Footnote Afiiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW;
(d)
Actual Demand (MW
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(0
1 OR Solar 6, LLC LU NA NA NA
2 OR Solar 6, LLC NA NA NA
3 OR Solar 8, LLC LU NA NA NA
4 Oregon [invironmental lndustries, LLC LU NA NA NA
5 Oregon lnstitute of Technology LU NA NA NA
6 Oregon Solar lncentive LU NA NA NA
7 Oregon {itate University LU NA NA NA
8 Oregon l-rail Windfarm, LLC LU NA NA NA
I osLH, LlC IU NA NA NA
10 Pacific Canyon \Mndfarm, LLC LU NA NA NA
11 Pavant Solar LLC LU NA NA NA
't2 Pavant Solar ll LLC LU NA NA NA
13 Pavant Solar lll LLC LU NA NA NA
14 Pioneer\Mnd Park l, LLC LU NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.12
AD ,
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Oa, Yr)tl
Year/Period of Report
End of 20'l8lQ4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 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. Ihe
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)
Megawatt Hours
Delivered
(i)
Demand Charges
($)
(,)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total 0+k+l)of Settlement ($)
(m)
23,9s4 993,231 993,231 1
-295 2
22,13i 918,23€918,236 3
'16,864 1,213,41t 1,213,418 4
241 12,021 12,023 5
11,15S 421,59e 421,596 6
145 1,795 1,799 7
26,50:2,029,52i 2,029,522 8
20,79e 863,89r 863,894 I
20,721 1,594,475 1,594,479 10
12't ,658 4,637,21i 4,819,703 11
121,s67 3,540,48t 3,540,488 12
50,512 2,667,02e 2,667,026 13
253,252 10,195,73(10,195,730 14
13,668,425 7,967,992 7,994,889 32,377,530 904,189,538 -269,1 32,964 667,434,104
FERC FORM NO.1 (ED. r2-90)Page 327.12
PUKUHF
-29!
182,48(
Name of Respondent
PacifiCorp
ort ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Reporl
End of 20181Q4
1 . Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. E:xplain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln colurnrr (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 supplier's service to its own ultimate consumers.
LF - for long-.term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 interntediate-term firm service. The same as LF service expect that "intermediateterm" 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 availabilig and reliability of
service, asidra from transmission constraints, must match the availability and reliability of the designated unit.
lU - for internrediate-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 exclranges 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 sen'ice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ol
the service irr a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC RaIe
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MV1/)
(d)
Actual Demand (MW
AVerage
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(0
1 Platte River Power Authority SF NA NA NA
2 Portland General Electric Company NA NA NA
3 Portland General Electric Company NA NA NA
4 Portland General Electric Company SF NA NA NA
5 Power County Wind Park North, LLC LU NA NA NA
6 Power County Wnd Park South, LLC LU NA NA NA
7 Powerex Corporation NA NA NA
8 Powerex Corporation SF NA NA NA
I Powerex Corporation NA NA NA
10 Provo City Corporation NA NA NA
11 Public Service Company of Colorado SF NA NA NA
12 Public Service Company of New Mexico SF NA NA NA
13 SF NA NA NA
14 NA NA NA
Total
FERC FORi,l NO. r (ED. 12-90)Page 326.13
LF
AD
OS
AD
LF
PUD N,r. 1 of Chelan County
PUD N,:. 1 of Douglas County LF
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da. Yr)
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
Megawatt Hours
Delivered
(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (j+k+D
of Settlement ($)
(m)
4,354 125,820 1
12.754 196,398 2
-36,073 3
307,667 8,120,677 8,131,959 4
67,79€4,801,258 4,801,258 5
58,98i 4,301,88i 4,301,887 6
8C 5,20C 5,200 7
430,595 31,679,053 31,679,053 8
5€3,'t92 I
4i 4,158 4,1 58 10
2,275,102 62,78234e 62,782,U6 11
't24,842 3,263,671 3,263,671 12
95,462 5,126,564 5,128,732 13
47,25C 1,647,29C 1,647,290 14
13,668,425 7,967p92 7,994,889 32,377,530 904,189,538 -269,132,9U 667,4U,104
FERC FORM NO. I (ED. r2-90)Page 327.13
PURL;HI
125,821
196,39r
-36,07:
11,281
3,191
2,161
Name of Respondent
PacifiCorp
rort ls:
lAn Original
lA Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
1 . Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and c'edits 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. tixplain 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 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 service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 definitior 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 internrediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for interrnediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than clne 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 sen,ice 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 Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW
(d)
Actual Demand (MW
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(0
1 PUD No 1 of Douglas County LU NA NA NA
2 PUD No, 1 of Douglas County NA NA NA
3 PUD No, 1 of Douglas County SF NA NA NA
4 SF NA NA NA
5 LU NA NA NA
6 PUD No. 2 of Grant County NA NA NA
7 PUD No. 2 of Grant County SF NA NA NA
8 Puget Sound Energy, lnc.SF NA NA NA
I Quichaprr 1, LLC LU 3 3 1
10 Quichaprr 2, LLC LU 3 3 1
11 Quichapa 3, LLC LU 3 3 1
12 Rainbow Energy Marketing Corporation SF NA NA NA
13 Rock River l, LLC LU NA NA NA
14 RoseburlS Forest Products Company LU NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.14
tnts Ke(1) E(2) l-
\D
PUD No, 1 of Snohomish County
PUD No, 2 of Grant County
AD
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, br, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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 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 1 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 required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
Megawatt Hours
Delivered
(i)
Demand Charges
($)o
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (+k+l)
of Settlement ($)
(m)
179,942 2,302,403 1
-61,266 2
15,481 462,014 463,053 3
97,434 1,433,71e 1,433,718 4
98,1 01 926,725 5
392,816 6
121 4,234 7
129,98f 4,043,245 4,055,138 I
8,053 240,206 280,40t 520,614 I
7,95i 238,805 277.07i 515,882 10
7,964 240,118 277,3',t4 517,432 11
't,20c 33,84(33,840 12
138,69t 4,921,00€4,92'1 ,006 13
53,951 2,232,934 2,232,9U 14
13,668,425 7,967,992 7,994,889 32,377,534 904,189,538 -269,1 32,964 667,4U,104
FERC FORM NO. 1 (ED. 12.90)Page 327.14
PUHL;Hf
2,302,40i
-61,266
1,039
926,72!
392,81(
4,23/
11,88(
Name ResFrondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20'l8lQ4
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, €pacity, 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. tixplain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln columrr (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 pro.lects 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 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 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 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 intennediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm sen'ice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ol
the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authori$
(Footnote Afiiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (M!V)
(d)
Actual Demand (MW)
Average
Monthly NCP Deman<
(e)
Average
Monthly CP Demand
(D
1 Roseburg LFG Energy, LLC LU NA NA NA
2 Roush Hydro lnc.AD NA NA NA
3 Sacramernto Municipal Utility District SF NA NA NA
4 Salt Riverr Project SF NA NA NA
5 Sand Ranch \Mndfarm, LLC LU NA NA NA
6 Santiarn Water Control District LU 0 0 0
7 Santiam Water Control District NA NA NA
8 Seattle City Light SF NA NA NA
I Sempra ,Gas & Power Marketing, Llc SF NA NA NA
'10 Sempra ,Sas & Power Marketing, Llc NA NA NA
11 Shell Energy North America (US), L.P SF NA NA NA
12 Shell Energy North America (US), L.P NA NA NA
13 Shiloh !\hrm Springs Ranch, LLC LU NA NA NA
14 SF NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.15
AD
AD
\D
Sierra Pacific Power Company
Name of Respondent
PacifiCorp (1)
(2t
Original
Resubmission
Date of Report(Mo, Da, Yr)lt
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 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 1 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 required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
Megawatt Hours
Delivered
(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Gharges
($)
o
Total (j+k+D
of Settlement ($)
(m)
6,013 480,438 480,438 1
-898 2
2,00c 52,00c 52,00c 3
241,ile 11,094,412 11,094,412 4
25,553 1,963,83C 1,963,83C 5
1,372 12,496 174,084 186,58C 6
-28,92C 7
't07,913 3,629,684 3,634,331 8
157,99€4,596,357 4,596,357 I
-128 10
334,89I 16,976,049 16,976,04S 11
-704 12
45t 29,21t 29,218 13
2'ts 11,56€'14,730 14
13,668,425 7,967,992 7,994,889 32,377,530 904,189,538 -269,132,9U 667,4U,104
FERC FORM NO. 1 (EO. r2-90)Page 327.15
I'UKUFlI
-89r
-28,92(
4,U'
-'l2t
-701
3,1 64
Name of Respondenl
PacifiCorp
)ort ls:
lAn Original
lA Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. E:xplain 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 recluirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes prr:jects 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 interrupted for economic
reasons anrJ is |n1"nd"d 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 longterm 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 datr: that either buyer or seller can unilaterally get out of the contract.
lF - for intemediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for shoniterm service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intemrediate-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 exclranges 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 seruice regardless of the Length of the contract and service from designated units of Less than one year. Descrlbe the nature of
the service irr a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW
(d)
Actual Demand (MW)
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(0
1 Simplot Phosphates, LLC LU NA NA NA
2 Slate Creek Hydro Company, lnc.LU 2 1 0
3 Solwafl, LLC LU NA NA NA
4 Southerrr California Edison Company SF NA NA NA
5 Spanish Fork Wind Park 2, LLC LU NA NA NA
6 Sprague Hydro LLC LU 1 1 0
7 St. Anthony Hydro, LLC LU NA NA NA
8 Stahlbush lsland Farms, lnc.IU NA NA NA
I Stahlbush lsland Farms, lnc.NA NA NA
10 SunE ErEi't8, LLC LU 3 3 1
11 SunE trEi24, LLC LU 3 3 1
12 SunE S,olarXVll Project 1, LLC LU 3 J ,|
13 SunE Solar XVll Project 2, LLC LU 3 3 1
14 SunE Solar XVll Project 3, LLC LU 3 3 ,|
Total
FERC FORM NO. r (ED.12-90)Page 326.16
ThiS RE(1) E(2) r
AD
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (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 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 (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 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 1 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 required data.
Megawatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
NoMegawatt Hours
Received
(h)
Megawatt Hours
Delivered
(i)
Demand Charges
($)o
Energy Charges
($)
(k)
Other Charges
($)
(l)
Total U+k+l)
of Settlement ($)
(m)
C 122 123 1
2,453 42,735 324,40e 367,141 2
982 33,47e 33,47e 3
1€371 375 4
44.20t 2,471,90e 2.471,906 5
2,593 55,786 367,1 8S 422,975 6
5,507 352,364 352,364 7
1,071 24,75!24,755 8
5 I
7,65:374.814 425,49i 800,307 10
7,201 16s,298 250,96a 4't6,263 11
7,45a 402,5s3 380,21 :782,766 12
7,33(402,648 374,'.!54 776,801 13
7,11!222,852 247,75!470,607 14
13,668,425 7,967,992 7,994,889 32,377,530 904,'t 89,538 -269,132,9U 667,4?4,104
FERC FORM NO.1 (ED. 12-90)Page 327.16
PUI.(UHA
t
Name of Res;p,ondent
PacifiCorp
,ort ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and oedits 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. Eixplain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln columr (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 supplier's service to its own ultimate consumers.
LF - for long..term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.9., the supplier must attempt to buy emergency energy from
third parties lio maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the deflnition 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 firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long.term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, asid,s from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intennediate-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 exclranges 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 sen,ice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ol
the service irr a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (M!V1
(d)
Actual Demand (MV14
Average
Monthly NCP Demanr
(e)
AVerage
Monthly CP Demand
(0
1 Sunny Bar Ranch LP LU NA NA NA
2 Sunnyside Cogeneration Associates LU 52 54 43
3 Surprise Valley Electrifi cation Corp.LU NA NA NA
4 Swalley rrigation District LU NA NA NA
5 Sweetwater Solar LLC LU NA NA NA
6 Tacoma Power SF NA NA NA
7 Tata Chemicals (Soda Ash) Partners LU NA NA NA
8 Tenaska Power Services Co.SF NA NA
I LU NA NA NA
10 Thayn H'ydro LLC LU N/A N/A N/A
11 The Enerrgy Authority, lnc.SF NA NA NA
12 Three []uttes Wndpower, LLC LU NA NA NA
13 Three Peaks Power, LLC LU NA NA NA
14 Three Sisters lrrigation District LU NA NA NA
Total
FERC FORM NO. r (ED. 12-90)Page 326.17
NA
Tesoro Flefining & Marketing Co LLC
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplie/s system reaches its monthly peak. Demand reported in columns (e) and (D must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401 , line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
PO\A/ER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
0)
Energy Charges
($)
(k)
Other Charges
($)
(D
Total U+k+l)of Settlement ($)
(m)
95€60,975 60,975 1
412,91a 29,704,284 29,704,285 2
3
2,273 177,342 177,342 4
841 33,93i 33,932 5
65,999 5,205,80C 5,207,641 6
5,678 197,364 197,364 7
22,47e 1,497 ,511 1,457 ,911 8
't2,531 243,60€243,609 I
3,1 39 't34,233 1U,233 10
46,731 1,866,151 1,866,151 't1
309,'t 88 19,692,671 19,692,671 12
226,299 9,599,02t 9,599,028 13
2,151 120,54e 120,546 14
13,668,425 7,967,992 7,994,889 32,377,53A 904,1 89,538 -269,1 32,964 667/U,104
FERC FORM NO. I (ED. 12-90)Page 327.17
l-UKUHA
1,84'
Name of
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
1 . Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. 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 prolects 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 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 defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
lF - for internrediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availabilig and reliability of the designated unit.
lU - for interrnediate-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 excilanges 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-flrm sen,ice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ol
the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW
(d)
Actual Demand (MW
Average
Monthly NCP Deman(
(e)
Average
Monthly CP Demand
(0
1 Threemile Canyon Wind I, LLC LU NA NA NA
2 TMF Biofue|s, LLC LU NA NA NA
3 TMF Biofuels, LLC NA NA NA
4 Tooele P,rmy Depot LU NA NA NA
5 Top of the World \Mnd Energy LLC LU NA NA NA
6 TransAlt;a Energy Marketing (U.S.) lnc.SF NA NA NA
7 TransCanada Energy Sales Ltd SF NA NA NA
8 26 25 13
I Tri-State Generation and Transmission SF NA NA NA
10 Tucson E:lectric Power Company SF NA NA NA
1'.!Tumbleureed Solar LLC LU NA NA NA
12 Tumbleueed Solar LLC NA NA NA
13 Turlock I rrigation District SF NA NA NA
14 LU NA NA NA
Total
FERC FORM NO. r (ED. 12-90)Page 326.18
\D
Tri-Stale Generation and Transmission -F
qD
U.S. Dep,tof lhe lnterior
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)ll
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
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
($)
o
Total 0+k+Dof Settlement ($)
(m)
22,544 1,759,023 1,759,023 1
31,883 2,416,36C 2,416,360 2
3,685 269.U5 3
704 20,513 20,513 4
532,188 35,124,42e 37,476,505 5
195,012 9,037,231 9,037,231 6
2,20C 285,20C 285,200 7
96,83C 6,219,000 3,',t32,451 9,351,451 I
20,961 1,279,48?1,279,5',t4 9
172,91t 5,642,461 5,642,465 10
20,563 853,63(853,630 11
401 12
9,06€565,44(565,,{40 13
21 1,59(1,590 14
13,668,425 7,967,992 7,994,889 32,377,534 904,189,538 -269, I 32,904 667,4U,104
FERC FORM NO.1 (ED. 12.90)Page 327.18
|-UKUTiA
269,34{
2,352,071
3'
401
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)lt
Year/Period of Report
End of 20181Q4
1 . Report illl power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. 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 prolects 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 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 definitiorr 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 interrnediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or les$.
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 interrnediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any setUements for imbalanced exchanges.
OS - for otherr service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm senrice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ol
the service in a footnote for each adjustment.
Line
No.
Narne of Company or Public Authority
(Footnote Afiiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MV1f
(d)
Actual Demand (MW
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(f)
1 U.S. Air Force at Hill Air Force Base LU NA NA NA
2 UNS Elerctric, lnc.SF NA NA NA
3 US Magnesium LLC NA NA NA
4 US Magnesium LLC NA NA NA
5 Utah Associated Municipal Power System NA NA NA
6 Utah Associated Municipal Power System SF NA NA NA
7 Utah Municipal Power Agency SF 185 180 43
I Utah Red Hills Renewable Park, LLC LU NA N/A N/A
I Utah Retail Solar Customers LU NA NA NA
'10 Vitol lnc,SF NA NA NA
11 Wagon Trail, LLC LU NA NA NA
12 Ward BLrtte \Mndfarm, LLC LU NA NA NA
13 Weber County LU NA NA NA
14 Western Area Power Adm CO MO SF NA NA NA
Total
FERC FORM rNO. I (ED. 12-90)Page 326.19
LU
AD
LF
Name of Respondent
PacifiCorp (1)
(2')
Original
Resubmission
Date of Report(Mo, Da, Yr)tl
Year/Period of Report
End of 20'l8lQ4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
Megawatt Hours
Delivered
(i)
Demand Charges
(9)
U)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total 0+k+Dof Settlement ($)
(m)
13,7't8 753,96(753,966 1
29,778 1,190,567 1,190,567 2
5,477,029 3
-30 4
60,736 3,093,152 3,093,1 52 5
193 5,184 5,1 84 6
51,05C 2,010,000 1,403,334 3,805,203 7
209,463 12,238,945 12,238,945 8
4,92e 453,208 453,208 I
'l 17,00c 2,890,214 2,890,214 '10
7,915 609,362 609,362 11
18,228 1,396,973 1,396,973 12
91C 49,564 49,564 13
1 8,1 31 530,738 530,885 14
13,668,425 7,967,992 7,994,889 32,377,530 904,189,538 -269,132,964 667,4U,104
FERC FORM NO. I (ED. 12-90)Page 327'19
rUK\,Hf
5,477,021
-3(
391,86!
'147
PacifiCorp (1)
(2)
Original
Resubmission
Date of Repo((Mo, Da, Yr)
Year/Period of Report
End of 2018/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln column (b), enter a Statistical Classiflcation 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 pro.iects 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 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 definitiorr 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 interrnediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five yererrs.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
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 settiements for imbalanced exchanges.
OS - for otherr service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm senrice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ol
the service in a footnote for each adjustment.
Line
No.
Narne of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW
(d)
Actual Demand (M!V1
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(f)
1 Westem Area Power Adm CO River NA NA NA
2 Wolverine Creek Energy, LLC LU NA NA NA
J Woodline Solar, LLC IU NA NA NA
4 Woodline Solar, LLC NA NA NA
5 Yakima-Tieton lrrigation District LU 2 1 1
6 CA Greernhouse Gas Allowance Purchases NA NA NA
7 Net Power Cost Deferrals NA NA NA
8 Netting - Bookouts NA NA NA
I Netting - Trading NA NA NA
'10 Systenr )eviation NA NA NA
11 Accrual NA NA NA
12
13 Power Exchanges:
14 Arizona Public Service Company EX 307 NA NA NA
Total
FERC FORM NO.1 (ED. 12-90)Page 326.20
LF
AD
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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 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,
I
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Received
(h)
Megawatt Hours
Delivered
(i)
Demand Charges
($)
0)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (i+k+D
of Settlement ($)
(m)
23,882 776,972 776,972 1
171,358 10,266,064 10,266,064 2
14,s13 601,288 601 ,288 3
75 1,879 4
6,005 20,577 224,843 245,424 5
2,154,523 6
.43,809,576 7
-8,985,63C -236,899,121 I
-2,786,566 I
10
11,275,572 11
12
13
569,755 571,392 -3,685,475 14
13,668,425 7,967,992 7,994,889 32,377,530 904,1 89,s38 -269,132pU 667.4U.104
FERC FORM NO.1 (ED. 12-90)Page 327.20
HUKUHA
1,87(
2,154,52i
-43,809,57(
-236,899,121
-2,786,56t
-7,401
11,275,571
-3,685,47t
Name
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
Year/Period of Report
End of 20181Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and aedits 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. E:xplain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln columrr (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 prolects 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 lon13-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 definitic,n 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 interrqediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less;.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intennediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
Ionger 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 othe,r service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm senrice 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.
Nernre of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC RaIe
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW
(d)
Actual Demand
Monthly
(e)(0
1 Avista Corporation EX 382 NA NA NA
2 Bonnevil le Power Administration EX 237 NA NA NA
3 Bonnevil le Power Administration 237 NA NA NA
4 Bonneville Power Administration EX 519 NA NA NA
5 Bonneville Power Administration EX T-BPA NA NA NA
6 Bonne\/ille Power Administration T-BPA NA NA NA
7 Califonria lndependent Syslem Operator EX T-12 NA NA NA
8 Califomia lndependent System Operator EX T-11 NA NA NA
I California lndependent System Operator r-12 NA NA NA
10 California lndependent System Operator T-11 NA NA NA
11 Emerald People's Utility District EX 351 NA NA NA
't2 Eugene Water & Electric Board EX T-12 NA NA NA
13 ldaho Power Company EX 708 NA NA NA
't4 ldaho Power Company EX T-6 NA NA NA
Total
FERC FORM r[O. r (ED. 12-90)Page 326.21
AD
AD
AD
AD
PacifiCorp (1)
t2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (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 supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Received
(h)
MegaWatt Hours
Delivered
(i)
Demand charges
($)
U)
Energy Charges
($)
(k)
Other Gharges
($)
(t)
Total (J+k+l)
of Settlement ($)
(m)
't,708 1
8,899 2,758 s,021 2
-216 2,234 -12,867 3
94,865 82,633 4
2't8,621 7,939 255,976 5
-25 6
3,710,726 4,389,797 -84,386,188 7
17,248,769 I
2,729,583 q
-507,708 't0
848 -21,192 11
19,954 20,358 12
106,054 116,115 '13
10,602 2,000 14
13,668,425 7,967,992 7,994,889 32,377,530 904,1 89,538 -269,132,964 667,434,104
FERC FORM NO. I (ED. 12-90)Page 327.21
I-UKUIlF
5,02'
-12,86;
255,97f
-21
-84,386,18{
17,248,761
2,729,58i
-507,70{
-21,191
Name of Resrrondent
PacifiCorp
rort lS:
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 2018/Q4
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Eixplain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. ln columrr (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 supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.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 service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long'term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, asid,a 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 exclranges 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 seruice regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature ol
the service irr a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW
(d)
Actual Demand (MW1
Average
Monthly NCP Deman(
(e)
Average
Monthly CP Demand
(0
1 Los Angr:les Dept. of Water and Power EX ov-1 NA NA NA
2 Milford Wind Corridor Phase l, LLC EX ov-1 NA NA NA
3 Milford V/ind Corridor Phase ll, LLC EX ov-1 NA NA NA
4 NorthWestern Corporation EX 160 NA NA NA
5 Portland General Electric Company EX T-8 NA NA NA
6 Public Service Company of Colorado 334 NA NA NA
7 Public liervice Company of Colorado EX 334 NA NA NA
8 EX 442 NA NA NA
I Seattle City Light EX 554 NA NA NA
10 Western Area Power Administration EX LAS4 NA NA NA
1',!Western Area Power Administration LAS.4 NA NA NA
12 lmbalanr;e Energy Accrual EX T-1 1 NA NA NA
13
14
Total
FERC FORM NO. r GD.12-90)Page 326.22
AD
PUD N,c. 1 of Cowlitz County
\D
PacifiCorp (1)
(2)
Original
Resubmission
Date of
(Mo, Da
Report
r, Yr)
Year/Period of Report
End of 20181Q4
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), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 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 charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
Megawatt Hours
Purchased
(s)
PO\A/ER EXCHANGES COST/SETTLEM ENT OF PO\A/ER Line
No.MegaWatt Hours
Received
(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
U)
Energy Charges
($)
(k)
Other Charges
($)
0)
Total (+k+l)
of Settlement ($)
(m)
4,450 329,854 1
2,917 -203,174 2
1,533 -126,681 3
541 4
4,289 5
2,048 6
1,314,000 1,312,284 5,400,000 7
182,513 197,540 8
374,91',!v2,873 2,267,819 I
57,630 143,970 479,209 10
-2,802 -197,661 11
1,288,350 798,792 13,104,330 12
13
14
13,668,425 7,967,992 7,994,889 32,377,530 904,'189,538 -269,132,9M 667,434,104
FERC FORM NO.1 (ED. r2.90)Page 327.22
t'uKUtlf
329,854
-203,171
-126,68'
5,400,00(
2,267,811
479,201
-197,66'
13, tM,33(
Namer of Respondent
PacillCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
201AA4
FOOTNOTE DATA
Line No.:2 Column: I
326 Line No.:4 Column: a
326 Line No.: 5 Column: b
326 Line No.:7 Column: b
o energy c t cert f cates for renewable portfol o standard
name sAr zona Electric Power .ti.ve Inc.
z<>na Publ - contract te I e: October 31 2020
Sett1ement ad ustment.
Sett.l.ement ustment.
Res€)rve re.
Schedule Page:326 Line No.:9 Column: b
Settl.ement. ad ustment.
Settl.ement ustment.
Reserve
Sett ement ustment.
Settl.ement ustment.
Under Electric Service ement ect to te t on L not t
Non-rat on reement.
PaC Corp has an agreement with Citizens Asset Finance, Inc. to lease the Black Cap Solargenerating facility. The ]ease has a 15-year term from October 201-2 Lo October 2028 and is
accouLnt.ed for as an rat lease
e Power stration - contract Lermina on date:30 da tten not ce.
11 serv
Reserve share.
Settlement ustment
Set ement ustment.
ootnote app es to afl occurrences of ttCal f a Independent Syst.em Operatorrr on
326-327 .ete name is California I .ts tem tor tion
Sett ement ustment.
Sett ement ustment
Sett.lement ustment
Settlement ad ustment
FERC FORM NO.1 (ED. 12471 Page 450.1
326 Line No.:7 Column: I
326 Line No.:8 Column: I
326 Line No.:9 Column: I
326 Line No.: 10 Column: I
326 Line No.: 14 Column: b
326 Line No.: 14 Column: I
326.1 Line No.:2 Column: b
326.1 Line No.:6 Column: I
326.1 Line No.: I Column: a
326.1 Line No; 11 Column: b
326.1 Line No.: 11 Column: I
326.1 Line No.: 12 Column: I
326.1 Line No.: 13 Column: b
326.1 Line No.: 13 Column: I
326.2 Line No; 8 Column: a
326.2 Line No.:9 Column: b
326.2 Line No.:9 Column: I
326.2 Line No.: 11 Column: b
326.2 Line No.: 11 Column: I
326.3 Line No.:9 Column: b
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
326.3 Line No.:10 Column: b
326.3 Line No; 10 Column: I
326.3 Line No.: 11 Column: I
cir of Hurricane - contract termination date:t31 2022.
Set.tlement ustment
Set ement ustment
Labor,
Idaho.
pment and adm istrat on fees ated with a hydro p ect Idaho Fa11s,
SettLement ustment
Settlement ustment.
lete name sC t o Port Port Water Bureau.
Sett t ustment.
Set.tlement ustment.
Set.t.lement ustment.
Settlement ustment.
te name s Deseret Generat Tran Co erat ve.
Deseret Generat
30,2024.
ss Co-operat ve - contract te date: September
Re to counterparty r operat ma enance costs at a coaratf aci-1i located in Vernal Utah
Settlement ustment.
Sett ement ustment.
eo e energy cre t cert f cates for renewable portfol o standard
re rements.
Sec ec renewable att ES or non-f rm
Purchase of renewable energy cre t cert f cates for renewable porLfolio standard
re rements.
Purc e of renewable energy cre t cert f cates for renewable portfol o standardrerements
Sett ement ustment
Settlement ustment
ete name s FaI1 ver Rura] El-ectric rative
Under Electric Service ts ect to t
FERC FORM NO.1 1 450.2
326.3 Line No.: 12 Column: b
326.3 Line No.:12 Column: I
Schedule Pase:326.3 Line No.: 13 Column: a
rnd 'l =nr
326.3 Line No.: 14 Column: b
326.3 Line No.: 14 Column: I
326.4 Line No; 10 Column: b
326.4 Line No.: 13 Column: b
326.4 Line No.: 10 Column: I
326.4 Line No.: 13 Column: a
326.4 Line No.:13 Column: I
326.5 Line No.:6 Column: b
326.5 Line No.: 6 Column: I
326.5 Line No.: 11 Column: I
326.5 Line No.: 13 Column: b
326.5 Line No.: 13 Column: I
326.5 Line No.:14 Column: I
326.6 Line No.: I Column: b
326.6 Line No.: 8 Column: I
326.6 Line No.: 10 Column: a
326.6 Line No.:14 Column: b
326.7 Line No;2 Column: b
na on
Inc.
t caL on.
Name of Respondent
Pacif Corp
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
20't8lQ4
FOOTNOTE DATA
326.7 Line No.: 3 Column: b
FlaLhead Electric tive Inc. - contract termination daEe 30 2021.
Sett:Lement ustment
SetL--ement ustment
F annua t
Unde:: Electr c Serv ce t not .t
Rese::ve share.
l-ete name S Ha.Paul and ,foanne Revocable Trust of 2005.
or non-rm
Reserr:ve share
Scheclule Page: 326.8 Line No.:9 Column: b
Settl.ement ustment
Settl.ement ustment
Sett ement ustment
Sett ement ustment
F annual t
This footnote es to alf occurrences of I'Los Angeles Dept. of Water and Power" on
326-327 .ete name is Los ES t of Water and Power
Sett ement ustment.
Sett ement ustment
Settl ement ustment
Sett 1 ement ustment
on or n e service and ri reserves
ectr Serv t ect to termina on t 1 not cat
Sett ement ustment
Sett ement usEment
lete name is ,Jones, Nola Jones,a and Christie a
Reserve share.
ootnote to all occurrences of rrNevada Power Company" on pages 326-327
Nevad.a Power Company is a whoffy owned subsidiary of NV Energy, Inc. , which is an indirect
who11y owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
FERC FORM NO.1 (ED. 12.871 Page 450.3
326.7 Line No.:3 Column: I
326.7 Line No.: I Column: I
326.7 Line No.:9 Column: b
na onect to t
326.7 Line No,: 14 Column: I
326.8 Line No.:4 Column: be attributes
326.8 Line No.: 5 Column: I
326.8 Line No.: 3 Column: a
326.8 Line No.:9 Column: I
326.9 Line No.: 1 Column: b
326.9 Line No.: 1 Column: I
326.9 Line No.:2 Column: I
326.9 Line No.: 5 Column: a
326.9 Line No.: 11 Column: b
326.9 Line No; 11 Column: I
326.9 Line No.: 13 Column: b
326.9 Line No.: 13 Column: I
326.10 Line No,:4 Column: b
326.10 Line No;4 Column: I
326.10 Line No.: 8 Column: a
326.10 Line No.: I Column: I
326.10 Line No;2 Column: b
326.10 Line No.:9 Column: I
326.10 Line No.: 10 Column: a
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) - A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
2018tQ4
FOOTNOTE DATA
326.10 Line No; 11 Column: b
326.10 Line No.: 11 Column: I
c
Settlement ustment.
Settlement ad ustment.
Settlement ad ustment.
Sett ement ustment.
Sett ement ustment.
Reserve share
Schedule Page:326.11 Line No.:7 Column: b
Settlement ad ustment.
Settlement ustment
Anc ces
Set ement ustment
Settlement ad ustment
Settlement ad ustment.
Settlement ad usLmenL.
Purchase of e energy c tc cates or e port ostirements
Line loss
Portland ectr c Company - conLract term nat on date: When the Round Butteect no 1 tes for tion
tion ect
Sett t ustment
Sett t ustment
Reserve share
e attr LeS or non-
Settlement ustment
Settlement ustment
rE ctr c Serv ect to tion timel
s Publ c utr1.'l_1tr District No. 1 of Chelan Count
FERC FORM NO.1 1 450.4
326.11 Line No.:1 Column: b
326.11 Line No.:3 Column: b
326.11 Line No.:3 Column: I
326.11 Line No.:4 Column: I
326.11 Line No.:13 Column: b
326.11 Line No.:13 Column: I
326.11 Line No.:7 Column: I
326.11 Line No.:9 Column: I
326.12 Line No.:2 Column: b
326.12 Line No.:2 Column: I
326.12 Line No.:11 Column: I
326.13 Line No.:1 Column: I
326.13 Line No; 2 Column: b
326.13 Line No.:2 Column: I
za costs ouson Cove
326.13 Line No.:3 Column: b
326.13 Line No.:3 Column: I
326.13 Line No.:4 Column: I
326.13 Line No;7 Column: b
326.13 Line No.:9 Column: b
326.13 Line No.:9 Column: I
326.13 Line No.: 10 Column: b
326.13 Line No.: 13 Column: a
326.13 Line No.:13 Column: I
lete name
notification
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
326.13 Line No.: 14 Column: a
Rese:ave share
s footnote applies to all occurrences of "PUD No. 1 as County" on pages
326-327 lete name is Public Utili District No. l- of as Count
Public Uti
2018.
tyD st ct No. l- of Douglas County - Contract t t on August 31,
t SC rest amort zaL taxes
Set ement ustmenE.
Sett.l-ement ustment.
Reserve share.
eEe name cUL t D str ctNo. lo sh
ootnote appl es to a1 occurrences of "PUD No. 2 of Grant Countyt' on pages 326-327.
eLe name is Public UEilit District No. 2 of Grant
t bond st, amort zat and taxes.
Settl.ement ad ustment.
Sett l.ement ustment.
Reserve
Schedule Page:326.14 Line No.:8 Column: I
Reserve share
326.15 Line No.: 2 Column: b
Settlement. ad ustment.
Settl ement ustment.
Sett ement ustment
Sett ement ustment
Reserve share.
Settlement ustment.
Settlement ustment.
Settlement ustment
Sett ustment
s erra Pac f c Power Company SA y owned subs of NV Energy, Inc.,chindirect who11y owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp'sindirectrent
FERC FORM NO.1 (ED.'t2-871 Page 450.5
326.13 Line No.: 14 Column: b
326.14 Line No.:2 Column: b
326.14 Line No.:2 Column: I
326.14 Line No.: 1 Column: I
326.14 Line No.:3 Column: I
326.14 Line No.:4 Column: a
326.14 Line No.: 5 Column: a
326.14 Line No.: 5 Column: I
326.14 Line No.:6 Column: b
326.14 Line No.:6 Column: I
326.14 Line No.:7 Column: I
326.15 Line No;2 Column: I
326.15 Line No.:7 Column: b
326.15 Line No.:7 Column: I
326.15 Line No.:8 Column: I
326.15 Line No.: 10 Column: b
326.15 Line No.: 10 Column: I
326.15 Line No; 12 Column: b
326.15 Line No.: 12 Column: I
326.15 Line No.: 14 Column: a
326.15 Line No.: 14 Column: I
Reserve
san
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
2018tQ4
FOOTNOTE DATA
326.16 Line No;9 Column: b
326.16 Line No.:9 Column: I
Settlement ustment.
Settlement ad ustment
Reserve s
ete name s Tesoro &LLC
Settlement ustment
Settfement ad ustment
Non-on I
ootnote app estoa occurrences o ItTr -State Genera on SS onrr on
326-327 .fete name is Tri-State Generation and Transmission Association Inc
Tr -State GeneraL Transm ASSoc t , Inc. - contract t na on te
Deceriber 31 2020.
L ss
Settlement ustment
326.18 Line No.:12 Column: I
Settlement ustment
lete name s U.S.rtment of the Inte or - Bureau of Land
US um LLC - contract te t dat.e: December 31, 20]-9
Aric i 1 servlces.
Settlement ad'ustment.
Sett ement ustment.
Utah Assoc ated Power tem - contract te date: March 31, 2022.
Costs related to the West Va1ley To11
$ 54,818 Station service
Agreement:
337 051 CT run rate charge
391 859
Reserve s
Western Area Power strat on - contract nat 10n date:31, 2022.
Settlement usLment
Settlement ad ustment
Purchases of greenhouse gas allowances forBoard greenhouse gas cap-and-trade program
FERC FORM NO.1 (ED. 12ATl Page 450.6
326.17 Line No.:6 Column: I
326.17 Line No.:9 Column: a
326.18 Line No.:3 Column: b
326.18 Line No.:3 Column: I
326.18 Line No.: 5 Column: I
326.18 Line No.:8 Column: a
326.18 Line No.:8 Column: b
326.18 Line No;9 Column: I
326.18 Line No.:12 Column: b
326.18 Line No.:14 Column: a
326.19 Line No;3 Column: b
326.19 Line No.:3 Column: I
326.19 Line No.:4 Column: b
326.19 Line No.:4 Column: I
326.19 Line No.: 5 Column: b
326.19 Line No.:7 Column: I
326.19 Line No.:14 Column: I
326.20 Line No.: 1 Column: b
326.20 Line No.:4 Column: b
326.20 Line No;4 Column: I
326.20 Line No.:6 Column: I
ance the ifornia Air Resources
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
326.20 Line No.:7 Column: I
Schedule Page:326.20 Line No,:8 Column: I
Schedule Pase:326.20 Line No.:9 Column: I
326.20
326.20
Line No.: 10
Line No.:11 Column: I
Column:
Var s to es to Volume 11 Point-to-Po nt Transm ss on Tar
Reflects transact ons t not sett
Reflects transactions that d not ca1 I settle
Sett ,t or reserve removal of tial ,t
Repr:esents the erence ween actua expenses or per as re ect onthe:-ndividual l-ine iEems within this schedule and the accruals charged to Account 555,
Purchased r duri this iod
c t
Stor:a and
Settl-ement ad ustment
Sett t ustment
Stor
Sett.l.ement ad ustment
326.21 Line No.:6 Column: I
Settl.ement ad usEment
Ene e ("EIM" )ri resource settlements in EIM
EfM ent settlements n ETM
Settl.ement ad'ustment
Settlement ad'usLment
Settl.ement ustment.
Sett t ustment
ene cred t
Stati.on service for third nd ect
Re mbursement for stat on serv ce to th rd ect.
326.22 Line No.:3 Column: I
Reimtrursement or idi stat serv ce to third ect.
Settlement ustment
e ene
lete name s Publ UT t D tr
FERO FORM NO. I 1 450.7
326.20 Line No.: 14 Column: I
326.21 Line No.:2 Column: I
326.21 Line No.:3 Column: b
326.21 Line No.: 3 Column: I
326.21 Line No.: 5 Column: I
326.21 Line No.:6 Column: b
326.21 Line No.:7 Column: I
326.21 Line No.: I Column: I
326.21 Line No.:9 Column: b
326.21 Line No.:9 Column: I
326.22 Line No.:9 Column: I
326.21 Line No.: 10 Column: b
326.21 Line No.: 10 Column: I
326.21 Line No.: 11 Column: I
326.22 Line No.: 1 Column: I
326.22 Line No.:2 Column: I
326.22 Line No.:6 Column: b
326.22 Line No;7 Column: I
326.22 Line No.:8 Column: a
Excha.nge energy expense
tNo. l-o tz Count
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
2018/Q4
FOOTNOTE DATA
326.22 Line No.: 10 Column: I
326.22 Line No.: 11 Column: b
326.22 Line No.:11 Column: I
326.22 Line No.:12 Column: I
ance energy sett ements tween Pac f Corp merchant funct party
transmission iders.
Sett ement ustment
Settlement ustment
Imbalance energy settlements between PacifiCorp, the transmission provider and third party
transmission customers .
FERC FORM NO. 1 D.1 450.8
of
PacifiCorp
(1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
TRANS
(as ,ccount 456.1)
I
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 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 lull 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 lletwork 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-flrm 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 Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 3 Phase Renewables, LLC Bonneville Power Adminislration Oregon Direct Access FNO
2 Arizona Public Service Company Arizona Public Service Company OS
3 Avangrid Renewables, LLC NF
4 Avangrid Renewables, LLC AD
5 Avangrid Renewables, LLC SFP
6 Avangrid Renewables, LLC AD
7 Avangrid Renewables, LLC Avangrid Renewables, LLC OS
I Avangrid Renewables, LLC Avangrid Renewables, LLC AD
I Avangrid Renewables, LLC Exxon Mobil Nevada Power Company LFP
10 Avangrid Renewables, LLC Exxon Mobil Nevada Power Company AD
11 Avangrid Renewables, LLC Bonneville Power Administration Oregon Direct Access FNO
12 Avangri<l Renewables, LLC Avangrid Renewables, LLC AD
13 Avista Corporation NF
14 Basin ljlectric Power Cooperative, lnc.Western Area Power Administration Powder River Energy Corporation FNO
15 Basin Electric Power Cooperative, lnc.Western Area Power Administration Powder River Energy Corporation AD
16 Basin Electric Power Cooperative, lnc.Western Area Power Administration Powder River Energy Corporation NF
17 Basin Electric Power Cooperative, lnc.Western Area Power Administration Powder River Energy Corporation AD
18 Basin Elechic Power Cooperative, lnc.Western Area Power Administration Powder River Energy Corporation SFP
19 Basin Electric Power Cooperative, lnc.Western Area Power Administration Powder River Energy Corporation AD
20 Black t{ills/Colorado Electric Utility Company NF
21 Black Hills/Colorado Electric Utility Company AD
22 Black Hills/Colorado Electric Utility Company SFP
23 Black t{ills/Colorado Electric Utility Company AD
24 Black t{ills Corporation PacifiCorp Montana-Dakota Utilities FNO
25 Black Hills Corporation PacifiCorp Montana-Dakota Utilities AD
26 Black Hills Corporation PacifiCorp Black Hills Corporation LFP
27 Black Hills Corporation PacifiCorp Black Hills Corporation AD
28 Black Hills Corporation NF
29 Black l.lills Corporation AD
30 Black Hills Corporation SFP
31 Black Hills Corporation AD
32 Black Hills Power Marketing NF
33 Black Hills Power Marketing AD
34 Black Hills Power Marketing SFP
TOTAL
FERC FORM NO. { (ED.12-90)Page 328
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da. Yr)tt
Year/Period of Report
End of 20181Q4
as
r 4coxuonnnueo)
5. ln column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (0, 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 specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received
(D
Megawatt Hours
Delivered(i)
SA 876 Various 1 85 8:1
RS 436 Borah/Brady Sub 2
SA 121 Various Various 191,646 191 ,64(3
SA 121 Various Various 25,174 25,174 4
s4122 Various Various 62,738 62,738 5
s4122 Various Various 8,246 8,246 6
SA 476 7
sA 476 8
SA 279 Trona Substation Red Butte/Mona Sub 31 68,645 68,445 I
SA 279 Trona Substation Red Butte/Mona Sub 31 9,433 9,433 10
sA742 Ponderosa Substation Various 31 242,578 242,578 11
sA742 Ponderosa Substation Various 21,310 21 314 12
sA 886 Various Various 856 856 13
SA 505 Yellovvtail Sub Sheridan Substation 10 69,455 69,455 14
SA 505 Yellolvtail Sub Sheridan Substation 7,125 7,125 '15
SA 607 Various Various 128,235 128.235 16
SA 607 Various Various 471 471 17
SA 606 Various Various 37,472 37.472 18
SA 606 Various Various 49 49 19
SA 563 Various Various 2,622 2,622 20
sA 563 Various Various 21
SA 562 Various Various 22
SA 562 Various Various 23
SA 347 Various Sheridan Substation 52 255,967 255,96i 24
SA 347 Various Sheridan Substation 29,088 29,088 25
SA 67 Various Vwodak Substation 52 80,393 80,393 26
SA 67 Various V[odak Substation 52 1,030 't,03c 27
SA 768 Various Various 8,852 8,85'28
SA 768 Various Various 45 4l 29
SA 767 Various Various 38,046 38,04€30
SA 767 Various Various 31
SA 43 Various Various 4,101 4,101 32
SA 43 Various Various 173 173 33
SA 714 Various Various 1,677 1,671 u
4,246 '16,159,593 16,047,74i
FERC FORM NO.1 (ED. 12-90)Page 329
Bonneville Power Adm
Name of Rer;pondent
PacifiCorp (1)
(2',)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
as
9. ln colunrn (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the amount
of energy transferred. 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 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. Footnotr: entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Denrand Charges
($)
(k)
Energy Charges
($)
(l)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
une
No.
348 412 1
2
1 ,719,565 2,366,567 3
202,208 4
692,733 721,426 5
152,053 6
-18,755 7
-599,702 o
919,866 958,084 9
66,699 't0
469,305 570,612 11
233,847 12
6,020 6,27',\'13
289,061 335,982 14
76,901 15
804,220 837,293 16
-3,064 17
251,181 261,523 18
196 19
15,320 15,971 20
-366 2',\
201 209 22
243 23
1,185,985 1,240,228 24
83,1 97 25
1 ,533,1 09 1,596,808 26
483,824 27
54,282 56,546 28
-1,819 29
475,083 494,573 30
-'t1,261 31
21,590 22,485 32
209 33
1,989 2,072 34
68,41 1,419 17,764,076 30,'[4'1,391 1{ 6,616,886
FERC FORM NO.1 (ED.12-90)Page 330
UF ELEU IKIUI IY t
6l
u7,002
202,20t
28,69:
152,05:
-18,75t
-599,70i
38,21t
66,69€
101,30;
233,841
251
46,921
76,901
33,07:
-3,064
10,34i
19(
651
-36(
€
243
54,24i
83,1 9i
63,69(
483,824
2,2il
-1,81(
19,49(
-1't,261
89t
20(
8:
Name of
PacifiCorp (1)
(2t
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 2018/Q4
TRANS
AS
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 distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. 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" 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 Afiiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Afiiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Black Hills Power Marketing
2 Bonneville Power Administration
3 Bonneville Power Administration Bonneville Power Administralion Bonneville Power Administration
4 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
R Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
b Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
7 Bonneville Power Administration Bonneville Power Administration Umpqua lndian Utility Cooperative
8 Bonneville Power Administration Bonneville Power Administration Umpqua lndian Utility Cooperative
I Bonneville Power Administration Bonneville Power Administration
10 Bonneville Power Administration Bonneville Power Administration Benton REA
11 Bonneville Power Administration Bonneville Power Administration
12 Bonneville Power Administration Bonneville Power Administration Umatilla Electric and Columbia
13 Bonneville Power Administration Bonneville Power Administration
14 Bonneville Power Administration U.S. Bureau of Reclamation Bonneville Power Administration
15 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
16 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
17 Bonneville Power Administration Bonneville Power Administration Yakama Power
18 Bonneville Power Administration Bonneville Power Administration Yakama Power
19 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
20 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
22 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
23 Bonneville Power Administration
24 Bonneville Power Administration Bonneville Power Administration Bonneville Power Adminislration
25 Bonneville Power Administration
26 Bonneville Power Administration
27 Bonneville Power Administration
28 Bonneville Power Administration Bonneville Power Administration
29 Bonneville Power Administration Bonneville Power Administration PUD No. '1 of Clark County
30 Brookfield Energy Marketing LP
3'l Brookfield Energy Marketing LP
32 Calpine Energy Solutions, LLC Bonneville Power Administration Oregon Direct Access
33 Calpine Energy Solutions, LLC Bonneville Power Administration Oregon Direct Access
34 Cargill Power Markets, LLC
TOTAL
FERC FORM NO. r (ED. 12-90)Page 328.1
sCOUnr 45O.1)
AD
OS
OS
AD
LFP
AD
FNO
AD
Benton REA FNO
AD
Umatilla Electric and Columbia FNO
AD
U.S. Bureau of Reclamation LFP
AD
OS
AD
FNO
AD
FNO
AD
21 FNO
AD
NF
AD
SFP
FNO
AD
PUD No. 1 of Clark County FNO
AD
NF
AD
FNO
AD
AD
Name of ResF,ondent
PacifiCorp
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 2018/Q4
AS
5. ln columrr (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (0, report the
designation lbr the substation, or other appropriate identification for where energy was received as specified in the contract. ln column
(g) report ttrer designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received
(D
Megawan Hours
Delivered(i)
SA 714 Various Various 1
RS 369 Midpoint Substation Summer Lake Sub 2
RS 237 Various Various 357 1,',t12,760 1,112,76C 3
RS 237 Various Various 354 101,532 101,532 4
SA 656 Lost Creek Hydro Plt Alvey Substation 58 183,005 183,005 5
SA 656 Lost Creek Hydro Plt Alvey Substation 58 19,394 19,394 6
sA229 Bonneville Power Adm Gazley Substation 4 23,554 23,554 7
SA 229 Bonneville Power Adm Gazley Substation 2,315 2,315 I
SA 539 Bonneville Power Adm Tieton Substation 1 5,1 06 5,1 06 I
SA 539 Bonneville Power Adm Tieton Substation 913 913 10
SA 538 McNary Substalion Hinkle Substation 1 770 77C 11
SA 538 McNary Substation Hinkle Substation 1 152 '152 12
SA 179 USBR Green Springs Bonneville Power Adm 19 66,26,4 66,264 13
SA 179 USBR Green Springs Bonneville Power Adm 4,509 4,50S 14
RS 368 Malin Substation Malin Substation 663,088 663,088 15
RS 368 Malin Substation Malin Substation 45,833 45,833 16
SA 328 Bonneville Power Adm 7 40,285 40,285 17
SA 328 Bonneville Power Adm 4,091 4,091 18
SA 827 Bonneville Power Adm Neff Substation 1 463 463 19
sA 827 Bonneville Power Adm Neff Substation 196 19€20
SA 746 Goshen Substation Various 168 1,223,570 1,223,57C 21
SA 746 Goshen Substation Various 155,757 155,757 22
SA 44 Various Various 177,315 177,31C 23
SA 44 Various Various 24
SA 720 Various Various 177,530 177,53C 25
s4747 Goshen Substation Various 81 506,725 506,721 26
s4747 Goshen Substation Various 53,964 53,964 27
SA 735 Cardwell-Merwin 15 1 10,858 1 10,858 28
SA 735 Cardwell-Merwin 16,058 16,058 29
SA 757 Various Various 56,449 56,449 30
SA 757 Various Various 355 35€31
SA 299 Bonneville Power Adm Various 26 143,851 143,851 32
sA 299 Bonneville Power Adm Various 11,871 11,871 33
SA 263 Various Various 34
4,246 16,159,593 16,047,747
FERC FORM I'lO. I (ED. 12-90)Page 329.{
I 45ei)(UOnIrnueo)
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
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 billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the amount
of energy transferred. 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 (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 ELECTRICIry FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
o
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
't 0,193 1
2
4,075,s15 4,051,',157 3
366,404 4
1,7't7 ,083 1,733,006 5
119,324 b
97,838 250,1 03 7
103,587 8
20,615 23,506 I
6,362 't0
4,601 5120 11
993 12
551 ,91S 556,723 13
38,764 14
232,4s2 '15
21,132 '16
'190,2 1 1 31 5,309 17
54,194 18
633 875 19
1,322 20
5,571,905 6,835,694 21
685,998 22
1,219,910 1,270,264 23
-1,520 24
325,387 339,079 25
2,217,710 2,595,042 26
1,599,069 27
575,381 652,039 28
165,941 29
287,454 299,493 30
2,016 31
351 ,6s5 420,543 32
116,555 33
-18,123 34
58,41 1,419 17,764,076 30,441,391 'l I 6,616,886
FERC FORM NO.1 (ED. {2-90)Page 330.1
1 0,1 9:
-24.35t
366,40r
15,92:
119,321
152,26!
103,58i
2,89r
6,36i
51(
oo.
4,80,r
38,76r
232,451
21.131
125.09t
54,191
241
1,32i
1,263,78(
685,99r
50,31
-1,52(
13,692
377,332
't,599,06S
76,658
165,941
12,035
2,Ue
68,888
116,555
-'t 8,'123
PacifiCorp (1)
(2)
An Original
Resubmission
Date of Report(Mo, Da, Yr)tl
Year/Period of Report
End of 20181Q4
IRANS
(to 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 se;larate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. ln column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm tletwork Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. liee General lnstruction for deflnitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 City of .Anaheim AD
2 City of Anaheim SFP
3 City of Anaheim AD
4 City of Roseville City of Roseville Cig of Roseville LFP
5 Clatskanie People's Utility District Clatskanie People's Utility Distr Clatskanie People's Utility Distr LFP
6 Clatskanie People's Utility District Clatskanie People's Utility Distr Clatskanie People's Utility Distr AD
7 Deseret Generation and Transmission Gen and Deseret Gen and Trans OS
8 Deseret Generation and Transmission Deseret Gen and Trans Deseret Gen and Trans AD
I Deseret Generation and Transmission NF
10 Deseret Generation and Transmission AD
11 Eagle E:nergy Partners I LP AD
12 Energy l.leepers, lnc.NF
13 Eugene ty'y'ater & Electric Board NextEra Energy Resources, LLC LFP
14 Eugent:tNater & Electric Board NextEra Energy Resources, LLC PUD No.2 of Grant County AD
15 Eugene'y'y'ater & Electric Board NextEra Energy Resources, LLC SFP
16 Enel Core Fort, LLC Enel Cove Fort, LLC AD
17 Evergreen Biopower LLC NextEra Energy Resources, LLC LFP
18 Exelon Gieneration Company, LLC Bonneville Power Administration Oregon Direct Access FNO
19 Exelon Cieneration Company, LLC Bonneville Power Administration Oregon Direct Access AD
20 Exelon Cieneration Company, LLC NF
21 Exelon Cieneration Company, LLC AD
22 Exelon Generation Company, LLC NF
23 Fall River Rural Electric Cooperative, lnc.Marysville Hydro Partners ldaho Power Company os
24 Fall River Rural Electric Cooperative, lnc.Marysville Hydro Partners ldaho Power Company AD
25 Foote Creek lll, LLC Foote Creek lll, LLC PacifiCorp OS
26 Foote Creek lll, LLC Foote Creek lll, LLC PacifiCorp AD
27 ldaho Power Company Exxon Mobil Nevada Power Company LFP
28 ldaho F'ower Company Exxon Mobil Nevada Power Company AD
29 ldaho Power Company NF
30 ldaho Power Company AD
31 JP Morgan Ventures Energy Corporation AD
32 Los Angeles Department of Water & Power AD
33 Los Angeles Department of Water & Power SFP
34 Macquarie Energy LLC NF
TOTAL
Page 328.2FERC FORM NO.1 (ED. 12-90)
PacifiCorp (1)
(2)
Original
Resubmission tt
Year/Period of Report
End of 20181Q4
5. ln column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. 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 specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and U) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(D
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW
(h)
TRANSFER OF ENERGY Line
No.Megawa[ Hours
Received
(D
Megawa[ Hours
Delivered
0)
SA 798 Various Various 4,229 4,225 1
SA 797 Various Various 2,419 2,411 2
sA 797 Various Various 19,908 19,90t 3
SA 881 Malin 500 Substation Round Mountain Sub 52 4
SA 899 Troutdale Substation Troutdale Substation 19 126,561 126,561 5
SA 899 Troutdale Substation Troutdale Substation 19 16,723 16,72i 6
RS 280 Various Various 135 u8,231 848,231 7
RS 280 Various Various 44,1 90 44J94 8
SA 156 Various Various 3,064 3,064 I
SA 156 Various Various 3,804 3,804 10
SA 569 Various Various 11
SA 569 Various Various 388 388 12
SA 780 Various Various 26 13
SA 780 Various Various 14
SA 719 Various Various 15
SA711 Enel Cove Fort, LLC Red Butte Substation 't6
SA 874 Various Various 43,670 43,67C 17
SA 847 Bonneville Power Adm Various 1 4,411 4,4',11 18
SA 847 Bonneville Power Adm Various 41 41 19
SA 759 Various Various 619 61€20
SA 759 Various Various 21
SA 760 Various Various 22
RS 322 Targhee Substation Goshen Substation 23
RS 322 Targhee Substation Goshen Substation 24
SA 761 Foote Creek Sub Various 25
SA 761 Foote Creek Sub Various 26
s4212 Trona Substation Red Butte/Mona Sub 78 't,765 1,768 27
s4212 Trona Substation Red Butte/Mona Sub 28
sA 725 Various Various 2,479 2,474 29
SA 725 Various Various 30
SA 335 Various Various 3'r
sA 142 Various Various 32
SA 143 Various Various 7,121 7,121 33
SA 755 Various Various 22,934 22,934 34
4,246 16,159,593 16,047,747
FERC FORM NO.1 (ED. 12-90)Page 329.2
t 456)(Uonilnueo)
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
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 billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the amount
of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjuslments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bil s 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 energy or service rendered.
10. The total amounts in columns (i) and U) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnoter entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICIry FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(D
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Lrne
No.
31 ,1 '1 8 1
14,346 14,947 2
110,407 3
1,107 ,19',1 1 ,139,213 4
1,173,516 1,222,189 5
306,852 b
2,558,618 3,687,889 7
-199,806 o
20,486 21,589 I
26,058 't0
-59 11
2,851 2,970 't2
217,914 't3
167,790 14
580,506 15
-1,219 16
306,623 349,873 17
10,028 't2,596 18
117 '19
122.817 1,465,884 20
-130,288 21
-312 -312 22
138,699 23
12,609 24
62,312 25
10.464 26
1 ,045,190 1,088,062 27
73,213 28
24,814 25,859 29
-10,171 30
-19,857 31
-1,386 32
47,055 49,021 33
216,779 225,706 34
68,41 1,419 17,764,076 30,441,391 116,616,886
FERC FORM NO. r (ED. 12-90)Page 330.2
31,11[
601
110,407
32.022
48,67i
306,852
1,129,271
-1 99,80r
1,103
26,05t
-5S
11!
217,914
167,79C
580,506
-1,211
43,25C
2,56t
11i
1,343,06'
-130,28t
138,69!
12,60(
62,312
10,4il
42,872
73,21i
1,04t
-10,171
-19,85i
-1,38(
1,96(
8,92i
Name of Respondent
PacifiCorp
This
(1)
(2)
Reoort ls:
[]Rn originat
l-lA Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
I RANS
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 distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. 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 servire, 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 Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Macquarie Energy LLC AD
2 Macquarie Energy LLC SFP
3 MAG Energy Solutions, lnc.NF
4 Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association OS
5 Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association AD
6 Morgan Stanley Capital Group, lnc.NF
7 Morgan Stanley Capital Group, lnc.AD
I Morgan Stanley Capital Group, lnc.SFP
I Municipal Energy Agency of Nebraska NF
10 Municipal Energy Agency of Nebraska AD
11 Municipal Energy Agency of Nebraska SFP
12 Navajo Tribal Utility Authority Navajo Tribal Utility Authority Navajo Tribal Utility Authority FNO
13 Nevada Power Company NF
14 Nevada Power Company AD
15 Nevada Power Company SFP
16 NextEra Energy Resources, LLC NextEra Energy Resources, LLC PUD No. 2 of Grant County LFP
't7 NextEra Energy Resources, LLC NextEra Energy Resources, LLC PUD No. 2 of Grant County AD
18 NextEra Energy Resources, LLC NF
19 NextEra Energy Resources, LLC AD
20 Pacific Gas & Electric Company OS
21 Pacific Gas & Electric Company NF
22 Pacific Gas & Electric Company AD
23 Portland General Electric Company os
24 Portland General Electric Company
25 Powder River Energy Corporation Western Area Power Administration Sheridan-Johnson Rural Elect.OS
26 Powder River Energy Corporation Western Area Power Administration Sheridan-Johnson Rural Elect.AD
27 Powerex Corporation Bonneville Power Administration CAISO LFP
28 Powerex Corporation Bonneville Power Administration CAISO AD
29 Powerex Corporation Powerex Corporation CAISO LFP
30 Powerex Corporation Powerex Corporation CAISO AD
3'1 Powerex Corporation Powerex Corporation CAISO LFP
32 Powerex Corporation Powerex Corporation CAISO AD
33 Powerex Corporation Powerex Corporation CAISO LFP
34 Powerex Corporation Powerex Corporation CAISO AD
TOTAL
FERC FORM NO. 1 (ED. 12.90)Page 328.3
AD
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
AS
5. ln column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designationsi under which service, as identified in column (d), is provided.
6. Report re,ceipt 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 tlre 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 c,olumn (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 Numbel
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received
(D
Megawatt Hours
Delivered
0)
SA 755 Various Various 212 212 1
SA 754 Various Various 1,056 1,05€2
SA 903 Various Various 6 €3
RS 302 Duchesne Duchesne 17,177 17,177 4
RS 302 Duchesne Duchesne 1,432 1,432 5
SA 157 Various Various 911,756 911,756 6
sA 157 Various Various 2,274 2,274 7
SA 160 Various Various 8,316 8,31€I
SA 307 Various Various 2,921 2,921 I
SA 307 Various Various 20 2C 10
SA 307 Various Various 500 50c 11
sA 894 Four Corners Pinto-Four Corners 1 5,335 5,335 12
SA 455 Various Various 7,858 7,858 13
SA 455 Various Various 14
SA 454 Various Various 90,574 90,574 15
sA 733 Wallula Substation Wala-MIDC path 103 39,872 39,872 16
SA 733 Wallula Substation Wala-MIDC path 103 17
SA 236 Various Various 20 2C 18
sA 236 Various Various 19
RS 607 20
sA 338 Various Various 814 814 21
SA 338 Various Various 22
RS 137 Various Various 23
SA8 Various Various 24
RS 704 Various Buffalo Substation 25
RS 704 Various Buffalo Substation 26
SA 169 Bonneville Power Adm CRAG View Substation 83 426,048 426,048 27
SA 169 Bonneville Power Adm CRAG View Substation 83 35,353 35,353 28
SA 7OO Malin 500 Substation Round Mountain Sub 67 29
SA 7OO Malin 500 Substation Round Mountain Sub 67 30
SA 701 Malin 500 Substation Round Mountain Sub 67 31
SA 701 Malin 500 Substation Round Mountain Sub 67 32
SA 702 Malin 500 Substation Round Mountain Sub 66 33
SA 702 Malin 500 Substation Round Mountain Sub 66 34
4,246 1 6, I 59,593 16,047,747
FERC FORM NO.1 (ED. 12-90)Page 329.3
I 45O)(UontrnueO)
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)tl
Year/Period of Report
End of 20181Q4
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 billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the amount
of energy transferred. 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 energy or service rendered.
10. The total 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
($)
(k)
Energy Charges
($)
o
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
491 ,|
't 0,179 10,595 2
48 50 3
17,655 4
'r,605 5
4,857,423 5,058,926 6
-21,979 7
67,3',t4 70,078 I
17,696 18,435 I
151 10
2,683 2,794 11
23,634 27,707 12
6,148 9,500 13
-1,035 14
482,',t23 502,007 15
2,004,216 2,744,637 '16
369,719 17
242,638 252,682 18
1 ,813 19
149,118 20
6,958 7,249 2',!
-263 22
3,314 23
-2,093 24
-730 25
32 26
2,4s2,976 2,554,894 27
500,838 28
2,935,586 3,007,1 38 29
604,415 30
2,935,586 3,007,138 31
604,415 32
2,935,586 3,007,138 33
598,279 34
68,411,419 17,764,076 30,,141,391 116,616,886
FERC FORM NO. I (ED. 12-90)Page 330.3
-491
41e
I
17,655
1,60€
201,50:
-21,975
2,764
739
151
111
4,071
3,352
-1,035
19,884
740,421
369,71!
10,044
1,81:
149,1 1 t
291
-26i
3,314
-2,09:
-73C
32
101,91t
500,83t
71,552
604,41t
71,552
604,415
71,551
598,27(
Name of Respondent
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 2018/Q4
IRANS
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 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 rlull name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownerstrip 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 ltletwork Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General lnstruction for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Powerex Corporation Powerex Corporation CAISO LFP
Powerex Corporation Powerex Corporation CAISO AD
3 Powerex Corporation Powerex Corporation CAISO LFP
4 Powere>r Corporation Powerex Corporation CAISO AD
5 Powerex Corporation NF
6 Powerex Corporation AD
7 Powere>r Corporation r SFP
8 Public Service Company of Colorado NF
I Public Service Company of New Mexico AD
10 Puget lSound Energy, lnc.AD
11 PUD No. 1 of Cowlitz County PUD No. 1 of Cowlitz County Bonneville Power Administration OS
PUD No, 1 of Cowlitz County PUD No. 1 of Cowlitz County Bonneville Power Administration AD
13 Rainbou, Energy Marketing Corporation NF
14 Rainbou, Energy Marketing Corporation AD
15 Sacramento Municipal Utility District Sacramento Municipal Utility Dist Sacramento Municipal Utility Dist LFP
16 Sacranlento Municipal Utility District Sacramento Municipal Utility Dist Sacramento Municipal Utility Dist AD
17 Salt Riverr Project Salt River Project Salt River Project LFP
't8 Salt River Project Salt River Project Salt River Project AD
19 Salt River Project NF
20 Salt Riverr Project AD
21 Seattle City Light AD
22 Shell Enrergy North America (US), L.P NexlEra Energy Resources, LLC PUD No. 2 of Grant County LFP
23 Shell Enr:rgy North America (US), L.P NextEra Energy Resources, LLC PUD No. 2 of Grant County AD
24 Shell Energy North America (US), L.P NF
25 Shell Enr:rgy North America (US), L.P AD
26 Shell Energy North America (US), L.P SFP
27 Shell Energy North America (US), L.P AD
28 Sierra Pacific Power Company
-
os
29 Sierra Pacific Power Company AD
30 Sierra Pacific Power Company AD
31 Simplol I)hosphates, LLC Simplot Phosphates, LLC Simplot Phosphates, LLC os
32 Simplol Phosphates, LLC Simplot Phosphates, LLC Simplot Phosphates, LLC AD
33 Southerr, California Edison Company OS
34 Southern California Edison Company NF
TOTAL
FERC FORM NO. r (ED. 12-90)Page 328.4
2
12
PacifiCorp (1)
(2',)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
AS
5. ln column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. 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 specifled 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 (1) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW
(h)
TRANSFER OF ENERGY Line
No.Megawatt Hours
Received
(D
Megawan Hours
Deliveredo
SA 748 Malin 500 Substation Round Mountain Sub 50 1
SA 748 Malin 500 Substation Round Mountain Sub 50 2
SA 749 Malin 500 Substation Round Mountain Sub 1s0 3
SA 749 Malin 500 Substation Round Mountain Sub 50 4
SA 47 Various Various 114,423 114,423 5
SA 47 Various Various 1,58S 1,589 6
SA 151 Various Various 63,509 63,509 7
SA 664 Various Various 8
SA 665 Various Various I
SA 693 Various Various 10
RS 234 Swift Unit No.2 Woodland Substation 11
RS 234 Swift Unit No.2 Woodland Substation 't2
sA 316 Various Various 2',1,087 21,087 13
SA 316 Various Various 14
sA 863 Malin Substation Malin Substation 31 '100,013 100,013 15
SA 863 Malin Substation Malin Substation 31 10,257 't0,257 16
SA 809 Enel Cove Fort Red Butte Substation 26 136,034 136,034 17
SA 809 Enel Cove Fort Red Butte Substation 2A 16,676 16,67€18
SA 557 Various Various 33 aa 19
SA 557 Various Various 20
SA 289 Wallula substation Wallula substation 21
sA 791 Wallula Substation Wala-MIDC path 89,587 89,58i 22
SA 791 Wallula Substation Wala-MIDC path 8,469 8,46S 23
SA 23 Various Various 260,863 260,863 24
sA 23 Various Various 4,373 4,373 25
SA 162 Various Various 64,581 64,581 26
SA 162 Various Various 159 15S 27
RS 674 Sigurd Substation Utah-Nevada Border 28
RS 674 Sigurd Substation Utah-Nevada Border 29
SA 732 Various Various 30
31
32
RS 298 Sigurd-Glen Canyon Pinto-Four Corners 33
SA 642 Various Various 25,680 25,680 34
4,246 16,159,593 16,047,741
FERC FORM NO. r (ED.12-90)Page 329.4
t 456XL;ontrnued)
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
as
9. ln columrr (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the amount
of energy transferred. ln column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjusllments. 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 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 (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
Denrand Charges
($)
(k)
Energy Charges
($)
o
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
1,467,794 1,503,570 1
321,843 2
4,403,380 4,510,708 3
965,529 4
515,403 536,944 5
-124,889 6
306,1 58 318,745 7
24 -56 o
-2 I
-1 59 10
160,583 11
14,318 12
124,630 129,779 13
-'1,922 't4
582,597 606,804 15
152,759 16
766,570 798,418 17
169,882 18
1,153 1,202 19
-1,601 20
-273 21
22
23
1,507,090 2,148,135 24
16,486 25
312,499 325,286 26
1,509 27
33,147 28
3,013 29
-1,545 30
13,605 31
3,784 32
149,118 33
2,496,8U 3,574,482 34
68,41 1,419 17,764,076 30,44'1,391 1{ 6,616,886
FERC FORM NO.1 (ED. 12.90)Page 330.4
35,77t
321,84i
107,32t
965,52!
21,541
-124,885
12.58i
-8(
-1 5!
160,58:
14,3',1t
5,14S
-1,92i
24,20i
152,751
31,84€
169,88i
49
-1,601
-27i
641,04t
16,48e
12,781
1,50!
33,14i
3,01:
-1,544
13,60t
3,784
149,11t
1,077,64t
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 2018/Q4
TRANS transa as
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 distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. 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" 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 Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Afiiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Southern California Edison Company AD
2 Southern California Public Power Authority Powerex Corporation Soulhem California Public Power NF
3 Southern California Public Power Authority Powerex Corporation Southern California Public Power AD
4 State of South Dakota Western Area Power Administration Black Hills Corporation LFP
E State of South Dakota Western Area Power Adminishalion Black Hills Corporation AD
6 Talen Energy Marketing, LLC AD
7 Tenaska Power Services Co.NF
I Tenaska Power Services Co.AD
o Tenaska Power Services Co.SFP
10 The Energy Authority, lnc.NF
11 The Energy Authority, lnc.AD
12 Thermo No. 1 BE-01, LLC Thermo Geothermal Project LFP
13 Thermo No.1 BE-01. LLC Thermo Geothermal Project AD
14 TransAlta Energy Marketing (U.S.) lnc.NF
15 TransAlta Energy Marketing (U.S.) lnc.AD
16 TransAlta Energy Marketing (U.S.) lnc.SFP
17 Tri-State Geneneration and Transmission Tri-State Gen and Trans FNO
18 Tri-State Geneneration and Transmission Tri-State Gen and Trans AD
19 Tri-State Geneneration and Transmission NF
20 Tri-State Geneneration and Transmission AD
21 Tucson Power Company AD
22 U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation FNO
23 U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation AD
24 U.S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv OS
25 U.S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.AD
26 U.S. Bureau of Reclamation Bonneville Power Administralion Crooked River lrrigation District os
27 Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power OS
28 Utah Associated Municipal Power Systems Utah Associated Municipal Power Utah Associated Municipal Power AD
29 Utah Associated Municipal Power Systems
30 Utah Associated Municipal Power Systems
31 Utah Associated Municipal Power Systems SFP
32 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency OS
33 Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency AD
34 Warm Springs Power Enterprises Warm Springs Power Enterprises PGE os
TOTAL
FERC FORM NO. I (ED. 12-90)Page 328.5
SCOUnI 4CO.r)
NF
AD
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
AS
rI 45O)(UOntrnueo)
5. ln colunrn (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (f), report the
designation lbr the substation, or other appropriate identification for where energy was received as specified in the contract. ln column
(g) report ttrer designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report irn column (h) the number of megawatts of billing demand that is specifled in the flrm 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 (t) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(D
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawau Hours
Received
(D
Megawall Hours
Delivered(i)
SA 442 Various Various 1,488 1,48t 1
SA 629 Tieton Substation Various 32 3i 2
SA 629 Tieton Substation Various 3
SA 779 Yellowtail Sub V[odak Substation 4 15,686 15,686 4
SA 779 YelloMail Sub \Afodak Substation 4 1,750 't,75C 5
SA 255 Various Various 6
SA 125 Various Various 15,467 15,46i 7
SA 125 Various Various 410 41C I
SA 126 Various Various 3.474 3,47 I
SA 310 Various Various 3,502 3,50i 10
SA 310 Various Various 500 50(11
SA 568 South Milford Sub Mona Substation 't'l 58,521 58,521 12
SA 568 South Milford Sub Mona Substation 11 6,299 6,29!13
SA 127 Various Various 43,363 43,363 't4
SA 127 Various Various 15
s4127 Various Various 507 507 16
SA 628 Dave Johnston Sub Thermopolis Sub 16 1 18,688 1 18,688 17
SA 628 Dave Johnston Sub Thermopolis Sub 10,638 10,638 18
SA 33 Various Various 72 72 19
SA 33 Various Various 20
SA 180 Various Various 21
SA 506 Walla Walla Sub Burbank Pumps 1 2,484 2AU 22
SA 506 Walla Walla Sub Burbank Pumps E 5 23
RS 286 Various Various 27,685 27,685 24
RS 286 Various Various 937 937 25
RS 67 Redmond Substation Crooked River Pumps 10,029 10,02s 26
RS 297 Various Various 792 3,034,539 3,034,539 27
RS 297 Various Various 248,981 248,981 28
SA9 Various Various 21 21 29
SA9 Various Various 58 58 30
sA722 Various Various 400 40c 31
RS 637 Various Various 145 667,838 667,838 32
RS 637 Various Various 52,925 52,925 33
RS 591 Pelton Reregulating Round Butte Sub 54,889 54,88S u
4,246 16,159,593 16,047,747
FERC FORM NO.1 (ED. t2-90)Page 329.5
Name of
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
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 billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the amount
of energy transferred. 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 energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
o
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
75,528 1
36,810 2
-1,484 3
122,649 127,745 4
24,734 5
-2,222 6
111,504 374,028 7
-10,456 8
25,266 26,320 9
21,673 22,568 10
1,527 11
337,298 380,756 12
71 ,177 13
273,826 285,216 14
-7,040 15
4,467 23,638 '16
467,461 522,451 17
111,567 '18
4,748 4,941 19
-3,008 20
-51 21
9,369 21,157 22
711 23
27,685 24
937 25
10,538 10,538 26
15,712,064 18,089,718 27
2,296,3',t1 28
110 114 29
416 30
3,217 3,347 31
2,859,672 3,238,399 32
451,154 33
109,725 34
68,41 I ,419 17,764,076 30,.14'1,391 I { 6,6't 6,886
FERC FORM NO. 1 (ED.12-90)Page 330.5
75,52t
36,81(
-1,44
5,09(
24.7y
-2,221
262,521
-10,456
1,054
89{
1,521
43,45t
71,177
11,39(
-7,04(
19,17'.'
54,990
1 1 1,567
193
-3,008
-51
11,78e
711
27,681
93i
2,377,654
2,296,311
4
41e
13(
378,72i
451,154
109,72!
Name ResFrondent
PacifiCorp
(1)
(2)
Original
Resubmission
Date of ReDorl
(Mo, Da, Yi)tt
Year/Period of Report
End of 20181Q4
I RANS
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 utilig suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authorig that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the lull name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownersl^rip 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 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 Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Warm Springs Power Enterprises Warm Springs Power Enterprises PGE
2 Weslar linergy, lnc.
3 Western Area Power Administration Westem Area Power Administration
4 Western Area Power Administration Westem Area Power Administration
5 Weslern Area Power Administration Westem Area Power Administration
6 Western Area Power Administration Westem Area Power Administration
Weslern Area Power Administration Westem Area Power Administration
8 Western Area Power Administration Westem Area Power Administration Western Area Power Administration
I Western Area Power Administration Western Area Power Administration
10 Westem Area Power Adm CO River Westem Area Power Adm CO River
11 Western Area Power Adm CO River Westem Area PowerAdm CO River
12 Westem Area PowerAdm CO River
13 Accrual
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
TOTAL
FERC FORM NO.1 (ED. r2-90)Page 328.6
AD
NF
OS
AD
OS
AD
OS
FNO
Western Area PowerAdm CO River AD
NF
AD
Westem Area PowerAdm CO MO NF
(1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
to as rt 4S6XContinued)
I
5. ln column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. 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 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 (l) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(D
Point of Delivery
(Substation or Olher
Designation)
(s)
Billing
Demand
(MW
(h)
TRANSFER OF ENERGY Line
No.Megawan Hours
Received
(D
Megawatt Hours
Delivered
0)
RS 591 Pelton Reregulaling Round Bufte Sub 7,895 7,89I 1
SA 813 Various Various 3,379 3,37€2
RS 262 Various Various 330 1,648,928 1,549,991 3
RS 262 Various Various 169,375 162,424 4
RS 263 Various Various 43,314 40,749 5
RS 263 Various Various 4,'111 3,8&6
RS 684 Dave Johnston Sub Various 7
SA 175 \A[oming Distribution Woming Distribution 4 13,450 13,45C I
sA 175 Various Vtrloming Distribution 6 €I
SA 132 Various Various 325 321 't0
SA 132 Various Various 11
s4724 Various Various 1,510 't,51C 12
60,633 57,48i 13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
4,246 16,,ts9,593 '|.6,047,747
FERC FORM NO. 1 (ED. 12-90)Page 329.6
Name of Respondent
PacifiCorp
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
AS
9. ln columr (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the amount
of energy transferred. 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 energy or service rendered.
10. The total amounts in columns (i) and [) 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
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
9,975 1
25,664 26,7',t5 2
2,358,272 2,908,272 3
264,317 4
44,180 5
4,047 6
7
52,265 107,101 I
3,055 I
2,802 2,920 10
-790 11
10,027 10,436 12
3,80'1,921 13
14
'15
'16
17
'18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
68,411,4't 9 17,764,076 30,441,391 116,616,886
FERC FORM NO. 1 (ED. 12-90)Page 330.6
9,97t
't,051
550,00(
2M,311
44,',t8C
4,04i
54,83€
3,05t
11t
-79(
40s
3,801,92'1
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
lYear/Period of Report
II zorelo+
FOOTNOTE DATA
328 Line No.: 1 Column: f
Schedule Pase:328 Line No.:1 Column: dTransmission service under the Open Access Transmission Tariff (Service Agreement 875) .Service provided pursuant to rules and regulations of Oregon Direct Access. Agreement
terminates upon notification pursuant to Oregon Direct Access and Open Access TransmissionTariff.
s footnote appl s to afl occurrences of "IIe Power Adm" on pages 328-330lete name is Bonneville Power Administration
Schedul , system controL and spatch ce. React ve supply and voltage controlservi-ce. Regulation and freguency response service. operating reserve - spinning reserve
servlce.rat reserve -lemental reserve service.
ous s es to the Volume 11 Po -to-Po SS Tar f
Legacy contract executed between Pac f Corp and zona Publ cSe Company concernthe exchange of transmission services over agreed-upon facilities (Restated Transmission
Service Agreement beLween PacifiCorp and Arizona Public Servi-ce Company, Rate Schedule
435) . The contract terminates October 31, 2020. See also page 332, Transmission ofelectriciothers, in this Form No. 1.
Glenn Four Corners stat
Var ous s t es to ume 11 Po -to-Po t ss on Ta
Var ous s t es to ume 11 Po -to-Po t SS on Ta
Non-rm or short-term f rmt ss on se ce under the Open Access T ss Tar ff
between various ies and ts.
Dg, system cont spat SC ce. Reac .ve v tage contro
servlce.
servlce.
servlces
Regulation and frequency response service. operating' reserve - spinning reserve
OperaEing reserve - supplemental reserve service. Refunds for transmissiont to FERC Docket No. ER17-219-002
Var tories to t.he Volume 11 Point-to-Point Transmission Tariff.
Var S1 tories to the Volume 11 Point-to-Point Transmission Tariff.
Non-firm or -term rm ss on serv ce Open Access ss
between various ies and nts.
2017 transm
refunds and
ary serv ces. 2017 annua ons ces true-upor
Var .tor sto Vo ume 11 nt-to-nt Transm Tar
tor sto VO ume 11 t-to-nt Transm Tar f
Non-rm or rt-term f transm ss ce under the Open Access ee on
between various rties and ints
e
FERC FORM NO.l (ED. 12-871 Page 450.1
328 Line No.:1 Column: m
328 Line No.:2 Column: c
328 Line No.:2 Column: d
328 Line No.:3 Column: c
328 Line No.:2 Column: f
328 Line No;3 Column: b
328 Line No.: 3 Column: d
328 Line No.:3 Column: m
328 Line No.:4 Column: b
328 Line No.:4 Column: c
328 Line No.:4 Column: d
328 Line No.:4 Column: m
328 Line No.: 5 Column: b
328 Line No.: 5 Column: c
328 Line No.: 5 Column: d
328 Line No.:5 Column: m
servr_ce.
, system contro and spatch
serv
ce. React ve supply and voLtage control
ff
Name of Respondent
PaciflCorp
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328 Line No.:6 Column: b
328 Line No.:6 Column: c
328 Line No.: 6 Column: d
Various si tories to the Volume l-L nt-to-Point Transmission Tarif f
Var s to estot Volume 11 Point-to-nt Transm on Tar
Non- l:rm or short-term f rmt SS on serv ce under the Open Access Transm SS IdL ff
betweien various es and ts.
2017 transm and anc SE ces
id Renewables LLC and Utah Assoc ated Munici Power tems
Anci.l.1ary ces under the Open Access Transmission Tar l-st Rev Serv
t 476 in effect until rseded
Ho ow WY Sw tc Station
Ho11ow, WY Sw tc Stat on
Opera ng reserve reserve se ce. Opera ng reserve - supplemental reserve
serv'r.ce
d Renewables, LLC and Utah Assoc ated Power tems
328 Line No.:8 Column: dAncil.lary serv ces under the Open Access Transmission Tar
,erseded.1st Rev ServL 476) in effect until
ow WY tc Station
1ow, WY tc Stat
2017 transmission and anc 11ary se ces. Refunds for on services pursuant to
FERC Docket No. ER17-21-9-O02.
s footnote applies to a1f occurrences of ttNevada Power Company" on pages 328-330
Nevada Power Company is a who11y owned subsidiary of Iw Energy, Inc. , which j-s an indirect
who11y owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
nt.-to-ntt ss se r Open Access ss on Tar ff (8th Rev sed
328 Line No.:6 Column: m
328 Line No.:7 Column: c
328 Line No.:7 Column: d
328 Line No.:7 Column: f
328 Line No.:7 Column:
328 Line No.:7 Column: m
328 Line No.:8 Column: f
328 Line No.:8 Column:
328 Line No.:8 Column: m
328 Line No.:9 Column: c
328 Line No.:9 Column: d
328 Line No.:9 Column: m
Servi ce L 279 terminat on 130 201,9
[9, system conLro spat se ce. React ves y and voltage contro
serv]-ce
Point.-to-ntt ssion service under the Open Access SS on Tar I Rev
Service Agreement 2?9) terminating on April 30, 20]-9.Wd201-7 transmission and ancillary services. 2017 annual transmission services true-up
ref ur:.ds or surc
Netwc,rk
Service
ss on service under the Open Access Transmission Tariff (3 Rev sed
742) terminat no earlier Ehan L2-months from notice the customer
FERC FORM NO.I (ED. 12.871 Page 450.2
328 Line No.: 10 Column: d
328 Line No.: 11 Column: d
328 Line No.: 11 Column: m
Sched.uling, system control and dispatch service. Reactive supply and voltage control
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
ll
Year/Period of Report
2018tQ4
FOOTNOTE DATA
serv]-ce
serv]-ce
Regulation and frequency response service. Operating' reserve - spinning reserve
at reserve -lemental reserve service328 Line No.: 12 Column: c
328 Line No.: 12 Column: d
Various s tories to the Volume 11 Point-to-Point. Transmission Tariff
Network tran CQ se CE r Open Access Transm Tar 3rd Revised
Service 742) terminat no earlier than 12-months from notice the customer
20t7 L SS anc ry se ces. 2017 annua Lransm ss serv true-up
refunds and/or surcharge. Refunds for transmission services pursuant to FERC Docket No.
ER17-21_9-002.
Various si tories to the Volume 11 Point-to-Po SS 'I'arr_ I I .
ous s es to ume 11 Po -to-Po t SS Tar
Non-rm or short-term f rmt ss on se ce under the Open Access Transm SS Tar ff
328 Line No.:12 Column: m
328 Line No.: 13 Column: b
328 Line No.: 13 Column: c
328 Line No.: 13 Column: d
between various arties and ts
Sc system control and
serv]-ce
spatch se ce. React ve supply and voltage control328 Line No.:13 Column: m
328 Line No.: 14 Column: d
Network t ss on se ce under the Open Access SS on Tar ff (3rd sed
Service ement 505 terminat no earlier than 12-months from notice the cusLomer.
str t on voltage s ce charge mary de1 very se ce. Schedul system control
and dispatch service. Reactive supply and voltage control service. Regulation and
frequency response service.
gchedute Pase:3n ti;; n;.1 - --- -- 1Network transmission service under the open Access Transmission Tariff (2nd Revised
Service t 505) terminati no earlier than 12-months from notice the customer.
2017 transmission and ancillary services. 2017 transmission services true-uprefunds and/or surc
Var OUS S1 tor es to the Volume 11 Point-to-Point Transmission Tariff.
Non-firm or short-term firm transmission service Open Access Transmission Tariff
328 Line No.:14 Column: m
328 Line No.:15 Column: m
328 Line No.:16 Column: c
328 Line No; 16 Column: d
between various es and nts
Scheduling, system control and dispatch service.service.
VES y and voltage control328 Line No.: 16 Column: m
328 Line No.:17 Column: d
Non- f or short-term firm transmission service under the Open Access Transmissi-on Tariff
beLween various ies and ints
2017 tran SS and ancillary services. 2017 annual transmission services true-uprefunds and/or
.tori-es to the Vo1ume l-1 Point-to-Point Transmiss Tariff .
Non-firm or short-term firm tr ssr_on se ce Open Accesst on Tar
328 Line No.: 17 Column: m
328 Line No.: 18 Column: c
328 Line No.: 18 Column: d
between various rLies and ints .
328 Line No.:18 Column: mScheduling, system control and spat SE ce. React ve supp tage contro
FERC FORM NO.1 (ED. 12-871 Page 450.3
Name of Respondent
Pacif Corp
This Report is:
(1) XAn Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
201UA4
FOOTNOTE DATA
328 Line No.: 19 Column: c
328 Line No.: 19 Column: d
Vari-ous to es to Ehe Volume 11 Point-to-Point Transmission Tariff.
Non-rm or short-term rmt ss10n s ce Open Access SS
between various es and ts
2017 transm and anc ary serv ces. 201-7 annua trans SS on serv t.rue-uprefunds and/or surc
s footnote appl es to occurrences tr H 1s ectr Ut ty
Comp.rnytton pages 328-330. Complete name is Black Hil1s/Colorado Electric Utility Company,
L. P.
Var s to estot ume 11 nt-to-nt Tr on Tar
Var S1 tories to the Volume 11 nt-to-nt Tr on Tar ff
Non-firm or rt-term firm on service under the Open Access Transmission Tariff
between various es and nts
Trar:Lsim SS on re e - purchase of point-to-point transmission. Scheduling, system control
and cl tch service. Reacti-ve s and vol-control service
Various to es to the Volume 11 Point-to-Point Transmission Tariff.
Var e to estot ume 1l-nt-to-nt on Tar
Non- f:or short-term f rmt ss on serv ce under the Open Access Tran ss ff
betv',een various es and tS
201-7 transmission and anc 11ary serv ces. 2017 annuaf tr on ces true-up
refurLds and or surc
Var C)US S tories to the Volume 11 nt-to-nt Tr on Tar ff
Various s to es to the Volume 11 Point-to-Point Transmission Tariff
Non-or short-term rm ssr_on serv ce Open Access Tran SS Tari f
between various es and nts
Transm resale - purc e nt-to-nt transm on system cont
and ilis tch service. Reactive s and vo1 control service
Various s to es to Volume 1l- Point-to-Point Transmission Tariff
Var SS to es to ume 11 Point-to-Po Transm SS on Tar
Non- f or short-term rm on serv ce Open Access Tr SS
betweren vari-ous es and nEs.
SS resale -nt-to-po'and vo1
t tran ss system cont
and iii tch service. Reactive su'control service.
FERC FORM NO.1 1 450.4
328 Line No.: 19 Column: m
328 Line No.:20 Column: a
328 Line No.: 20 Column: b
328 Line No; 20 Column: c
328 No.:20 Column: d
328 Line No.:20 Column: m
328 Line No.:21 Column: d
328 Line No.:21 Column: b
328 Line No.:21 Column: c
328 Line No;21 Column: m
328 Line No.:22 Column: b
328 Line No.:22 Column: c
328 Line No.:22 Column: d
328 Line No.:22 Column: m
328 Line No.: 23 Column: b
328 No.:23 Column: c
328 Line No.: 23 Column: d
328 Line No.:23 Column: m
328 Line No.:24 Column: d
Netwc,rk tr SS on serv ce Open Access Tran SS Tar 3 SC
ser\r:_ce.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328 Line No.:24 Column: m
Service t 347) terminat on December 31, 2023
Scheduling,service.system control and dispatch service. Reactive supply and voltage control
Network Eransmission service under the Open Access ss Tar ff (3rd Rev sed
Servi-ce 347) terminat on Decernlcer 31 , 2023
201-7 transmission and ancillary services. 2017 annual transmission serv true-up
refunds or sur
Point-to-po transmission service under the Open Access Transmission Tar ff (3rd Rev
Service reement 67) terminat on December 31 2023.
SS resale - purc e point-to-point transmission. Scheduling, sysLem control
and di ch service. Reactive and vo1 control service.
Point-to-point transmission service under the Open Access Transmission Ta ff (3rd Rev sed
ement 57) terminat on December 31 , 2023.
20t7 L ssion and anc 1lary services. 201,7 annual transmission services true-up
refunds or surc
ous s tor es to ume 11 Point-to-t Transmission Tariff.
ous s tor es to ume 11 t-to-t SS on
Non-rmors -term rm transm cc ons t open Access Transmission Tariff
between various ies and nts.
D9, system contro pa serv ce. Reac ve supply and voltage control
serv]-ce
Var ous s tor sto Vo ume 11 Point-to-nt Transmission Tariff .
Var s tor sto VO ume 11 Po nt-to-nt Trans on Tari f.
Non- f or short-term f rm tr ss serv ce under Open Access ss on
between various rties and ints.
201-7 annual tr ss se ces true-re
Va to es to the Volume 11 Po -to-Po Transm SS Tar ff
Various si ries to the Volume 11 Point-to-Point Transmission Tar ff
Non-firm or short-term irm transmission se ce under the Open Access Transm Tar ff
between various ies and ts
Scheduling, system control and dispatch service. Reactive supply and voltage control
serwice.
Schedule Page:328 Line No.: 31 Column: bVarious si tories to the Volume 11 Point-to-Point Transmission Tariff.
t
FERC FORM NO.1 (ED. 12-871 Paqe 450.5
328 Line No.:25 Column: d
328 Line No.:25 Column: m
328 Line No.:26 Column: d
328 Line No.:26 Column: m
328 Line No.:27 Column: d
328 Line No.:27 Column: m
328 Line No.:28 Column: b
328 Line No.:28 Column: c
328 Line No.: 28 Column: d
328 Line No.:28 Column: m
328 Line No.:29 Column: b
328 Line No.: 29 Column: c
328 Line No.: 29 Column: d
328 Line No.:30 Column: c
328 Line No.:29 Column: m ors328 Line No;30 Column: b
328 Line No.:30 Column: d
328 Line No.:30 Column: m
328 Line No.:31 Column: c
Var ous s gnator es to ume 11 nt-to-SS on
Service
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
20181Q4
FOOTNOTE DATA
328 Line No.:31 Column: d
328 Line No.:31 Column: m
328 Line No.:32 Column: b
328 Line No.:32 Column: c
328 Line No.:32 Column: d
Non-:iirm or short-term f tr SS under the Open Access Transmission Tariff
between various ies and ints
201-'1 Lransmission and anc 11a ces
Vari-ous s tor es to the Volume l-l- Point-to-Po Tr ss
VA s or es to vo ume l-1 Po -to-Po Tr SS ff
Non-f or short-t.erm f tran SS under the Open Access Transmission Tariff
between various ies and ints
Sche<1u1ing, sysEem control and
serv:Lce.
spatch service. Reactive supply and volt.age control
Va S ories to the Volume l-l- Point-to-Point Transmission Tari-f f .
Various s es to Volume 11 Point-to-Po Tran SS TA
Non-or short-term tran serv the Open Access ss on Tar ff
between vari-ous ies and ints.
201,7 lr on and anc 1
Var S Lories to the Volume 11 Po -to-Point Transmission Tariff .
Various s to es to the Volume 11 Point-to-Point SS Tariff.
Non-or short-term transm on serv Open Access SS on Tar
betwelen various ies and ints
system contro pa serv ce. React ve supp voltage control
serf/l-ce
Var G to es to the Vo ume 11 Po .t-to-nt Tr S Ta f f .
Var s tories to the Volume 11 Po t-to-nt SS Ld f f .
Non-firm or rt-term firm transm ion service under the Open Access Transmission Tariff
betweren various ies and ints
2017 transmission and 1 serv
Capacity and operated by each transmission provider with no receipt or delivery
of
Capa c:ty exchanged and operated by each tr ss prov th no rece pt or de1 veryof
Legac:y contract executed between Pac f and Bonnev I1e Power strat on ('BPA')
concerning the exchange of transmission services over agreed-upon facilities("Midpoint-Meridian Transmission Agreementrr, Rate Schedule 369). This agreement runs
concurrently with the AC rntertie AgreemenE (Rate Schedule 368), which terminates when thefacil.ities subject to that agreement are taken out of service. See also page 332,
FERC FORM NO.1 (ED. 12.871 Pase 450.6
328 Line No.:32 Column: m
328 Line No.:33 Column: h
328 Line No.: 33 Column: c
328 Line No.: 33 d
328 Line No.:34 Column: c
328 Line No.:33 Column: m
328 Line No.:34 Column: b
328 Line No.: 34 Column: d
328 Line No.:34 Column: m
328.1 Line No.: 1 Column: b
328.1 Line No.: 1 Column: c
328.1 Line No.: 1 Column: d
328.1 Line No.: 1 Column: m
328.1 Line No.:2 Column: b
328.1 Line No.:2 Column: c
328.1 Line No.: 2 Column: d
Name of Respondent
PacifiCorp
This Report is:
(1)XAn OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
201Ao.4
FOOTNOTE DATA
328.1 Line No.:3 Column: d
Transmission of electricit others, in this Form No. 1
Legacy contract (3rd Revised Rate Schedule 237) executed between PacifiCorp and BPA fortransmission service over agreed-upon facilities and/or subject to a sole-use orfacil-ities charge. Contract subject to terminate upon the earlier of the termination ofthe "Exchange AgreemenL[ between PacifiCorp and BPA or the time of the termination of alldeliveries as defined in the t
Charge or transm r_on servr_ce over agreed-upon f 1 t es ors ecttoas e-useor facilities
Legacy contract 3rd Rev Rate Schedule 237 executed between f Corp and BPA or
transmission service over agreed-upon facilities and/or subject to a sole-use orfacilities charge. Contract subject to terminate upon the earlier of the termination ofthe "Exchange Agreementrr between PacifiCorp and BPA or the time of the termination of alldeliveries as defined in the t
201,'7 Lransmission and ancil servlces .
Point-to-point t ss serv Open Access Tran ss 1dr 4 Rev
Service 555) terminat on t31 2030.
Reactive contro serv
Po -to-po t SE Open Access Tr SS Tar 4 Rev
Service reement 556) terminat on 31 2030.
201,7 L dc
or on anc ry se s. 2017 annua t ss se s true-up
refunds
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (9th Revised Service reement 229) terminat on ternber 30, 2028
st tion voltage service charge. Primary delivery service. Regulation and frequency
response service. React.ive supply and voltage control service. Operating reserve -
reserve servlce rat Reserve -emental reserve service.
Network t on serv ce and st on de1 very se ce under the Open Access
Transmission Tariff 9th Revised Service ement 229) terminat onS tember 30, 2028.
201,7 t cc on and anc 11ary se ces. 2017 annual transmission services true-uprefunds and/or surcharge. Refunds for transmission services pursuanL to FERC Docket No
ERI-7-219-002.
c ootnote appl es to all occurrences of "Benton REA" on pages 328-330. Complete nameis Benton Rural Electric Association
Net transm ss on serv ce and ST t on de1 very serv ce under the Open Access
Transmission Tariff 3rd Revised Service t 539 termi-nati onS ember 30 2028.
ng, system contro spatc serv ce. Regulat on and freguency responseservice. Operating reserve - spinning reserve service. Operating'reserve - supplemenEalreserve serwice.
FERC FORM NO.1 EO.12-87 450.7
328.1 Line No;3 Column: m
328.1 Line No.:4 Column: d
328.1 Line No.:4 Column: m
328.1 Line No.:5 Column: d
328.1 Line No.: 5 Column: m
328.1 Line No.: 6 Column: d
328.1 Line No.: 6 Column: m
328.1 Line No;7 Column: d
328.1 Line No.:7 Column: m
328.1 Line No.: 8 Column: d
328.1 Line No.:8 Column: m
328.1 Line No.:9 Column: c
328.1 Line No;9 Column: d
328.1 Line No.:9 Column: m
328.1 Line No.: 10 Column: d
Network tran ss str on very serv Open Access
Name of Respondent
Pacif Corp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.1 Line No.: 10 Column: m
Transmission Tariff (3rd Revised Service t 539) terminat on 30, 2028
201-1I tran SS on ancillary services. 201,7 annual transmission services true-uprefunds and/or surcharge. Refunds for transmission services pursuant to FERC Docket No
EP.17 -21,9 - 002 .
tnote app s to all occurrences of "Umati11a Electric and Columbia" on pages
328-330.
.Ei.L ec: Ir ra c
Complet.e name is Umatilla Elect.ric Cooperative Association and Columbia BasintiveInc
NeLv/o t ss service under the Open Access on Tar ff (3rd Rev
Serr':-ce reement 538) terminat on tember 30, 2028
S , system controf and dispatch service. Regulation and frequency responseservi-ce. operating reserve - spinning reserve service. Operating reserve - supplemental
regel:ve service.
Netwo t SS service under the open Access Transmission Tariff (3rd Revised
Serr,.i-ce ement 538) terminat on tember 30, 2028
201,7 t SS on anc ry se ces. 2017 annual transmission services true-up
refurrds and/or surcharge. Refunds for transmission servi-ces pursuant to FERC Docket. No
8R1,1',-219-002.
c!tnote app es to all occurrences of "U.S. Bureau of Reclamation" on pages 328-330.ete name is United States D rtment of Interior, Bureau of Reclamation
Po t:-to ttr SS service under the open Access Transmission Tariff (5th Revised
Serr,'i.ce ement 179) terminat onS tember 30, 2025
328.1 Line No.: 13 Column: m
React:ve and control service.
t-t ttr SS SE r Open Access Trans ss Tar 5 Revi
Servi,ce t 479 terminat onS tember 30 )a)q
20fi'L ssion and anc ary se ces. 2017 trans on ces true-up
refurrds and/or
Legac:y contract (5th sed Rate S e 358 executed ween Pac Corp BPA r
tran.srmission service over agreed-upon facilities and,/or subject to a sole-use or
f aci l.ities c ect to termination mutual t
Charge for transmiss on se ce over agreed-upon f 1 es or ect to a so e-useor facilities charge based on a capacity factor and/or proportional use as defined i-n the
contl:act.
Lega.cy contract 5t Revised Rate Schedule 368) executed between PacifiCorp and BPA for
transrmission service over agreed-upon facilities and/or subject to a sole-use or
f aci l.ities ect to termination mutual t
2017 transmission and anc 11 ces
Net'ss on service and str very serv ce under the Open Access
Tran.srmission Tarif f (7th Revised Service
FERG FORM NO.1 1 450.8
328.1 Line No.: 11 Column: c
328.1 Line No;11 Column: d
328.1 Line No.: 11 Column: m
328.1 Line No.: 12 Column: d
328.1 Line No.:12 Column: m
328.1 Line No.: 13 Column: b
328.1 Line No.: 13 Column: d
328.1 Line No.: 14 Column: d
328.1 Line No.:14 Column: m
328.1 Line No.: 15 Column: d
328.1 Line No.:15 Column: m
328.1 Line No.: 16 Column: d
328.1 Line No.: 16 Column: m
328.1 Line No.: 17 Column: d
328.1 Line No.: 17 Column:
on deI t 328) terminat onS ember 30 2028
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tA4
FOOTNOTE DATA
328.1 Line No; 17 Column: m
white Swan/ish Substations
Distribution voltage servj-ce charge. Primary de1 very se Regu on reguencyresponse service. Reactive supply and voltage control service. Operating reserve -
lnn reserve servr_ce at Reserve -lemental reserve service
Network tran SS serv ce and sEr ion delivery service under the Open Access
Transmission Tariff (5th Revised Service L 328) terminat on Ju1 31,2028
te Swan sh Substations
20]-7 transmission and ancirefunds and/or surcharge.
ER17 -21,9 - 002 .
services . 201,7 t ss serv true-up
Refunds for transmission servj-ces pursuant to FERC Docket No
Network transmission service under the Open Access SS Tar Rev
Service t 827) terminat on tember 30 2028.
Schedul system control and dispatch service. Reactive supp v voltage control-service. Regulation and freguency response service. operating reserve - spinning reserveservlce.'at reserve -lemental reserve service.
Network tran service under the Open Access Transmission Tariff (2nd RevisedServicereement 827) terminat on tember 30, 2028.
2017 tran SS and ancilla servr_ces.
Network tr SS se ce and str ion delivery service under the Open Access
Transmission Tariff 3rd Revised Service reement 746) terminat on .fune 30, 2028-
Schedul , system control and spatch service. Reactive supply and voltage controlservice. Regulation and frequency response service. Operating reserve - spinning reserve
serv].ce.rat reserve -lemental reserve service.
Netwo tr ss SE ce str de1 very se ce under the Open AccessTransmission Tariff (3rd Revised Service ement 746 Lerminat on ,rune 3 0 2028.
201,7 L ss anc ry se ces. 2017 annual t ss on se ces true-uprefunds and/or surcharge. Refunds for transmission services pursuant to FERC Docket No.
ER]-T -2]-9 - 002 .
Various si tories to the Volume 11 Point-to-Po t SS on Ta
Various s es Lo VO ume 1l- Po -to-Po L SS on f f .
Non-rm or -term f rmt ss se ce under the Open Access Transmission Tariff
between various arties and ints.
Sc , system control and spatch se ce. Reac ve supply and voltage controlserv1ce.
Non-rm or -term rmt SS on se ce under the Open Access on
between various ies and ts
FERC FORM NO.1 D.t 450.9
328.1 Line No.: 18 Column: d
328.1 Line No.: 18 Column:
328.1 Line No.:18 Column: m
328.1 Line No.:19 Column: d
328.1 Line No.:19 Column: m
328.1 Line No.:20 Column: d
328.1 Line No.:20 Column: m
328.1 Line No;21 Column: d
328.1 Line No.:21 Column: m
328.1 Line No.: 22 Column: d
328.1 Line No.:22 Column: m
328.1 Line No.:23 Column: b
328.1 Line No.:23 Column: c
328.1 Line No.:23 Column: d
328.1 Line No.:23 Column: m
328.1 Line No.:24 Column: d
328.1 Line No.: 24 Column: m
201,7 L ss on anc ary se ces. 2017 annual ss on se ces true-up
ff
Name of Respondent
PaciflCorp
This Report is:
(1) XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
refunds or surcha
ous s tor es to the Vo ume 11 Po -to-Po Tariff.
ous sr-tories to the Volume l-1 Po -to-Point Transmission Tarif f .
Non-firm or s -term firm transmission service under Open Access ss on Tar
328.1 Line No.:25 Column: b
328.1 Line No.:25 Column: c
328.1 Line No.:25 Column: d
328.1 Line No.: 25 Column: m
between various ies and ints
Schecluling, systemservice.and dispatch serv React ve supp and voltage control
Vari.c>us s tor es to Vo ume 1l- Po -to-Po SS 1d.ff.
S tor es to the Volume 1l- Po -to-Po Transmission Tariff.
Network transmission service and stribution delivery service Open Access
Trar:simission Tariff (2nd Revised Service L 747 ) terminat on .fune 30 2028.
Scheduling, system control and spatch service. Reactive supp y and vo tage contserv'i.ce. Regulation and freguency response service. operating'reserve - spinning reserve
servl.ce rati reserve - s emental regerve service
Va OUS S tories to the Volume l-l-nt-to-Point Transmission Tarif f .
Various s t es to the Volume l-l- Point-to-Point Tran Tar
Net tr ss on serv ce str on very serv ce under the Open Access
Transrmission Tariff 2nd Revised Service L 747 terminat on \Tune 3 0 2028.
201,7 Lrar]ss on and anc ary serv ces. 2017 annual transm SS on ces true-up
refu.r:Lds and/or surcharge. Refunds for transmission services pursuant to FERC Docket No.
ER1,7-219-002.
This ootnote es to occurrences "PUD No. 1 o C County" on pages 328-330.
r
328.1 Line No.:26 Column: b
328.1 Line No.: 26 Column: c
328.1 Line No.:26 Column: d
328.1 Line No.:26 Column: m
328.1 Line No;27 Column: b
328.1 Line No.:27 Column: c
328.1 Line No.:27 Column: d
328.1 Line No.:27 Column: m
328.1 Line No.:28 Column: c
Net
lete name is Public Utili District No. 1 of Clark Count
tran ss ons ce rt Open Access Transm on Tar ff (2nd sed
328.1 Line No.: 28 Column: d
328.1 Line No.: 28 Column:
Servi ce t 73s terminat onS 30 2028
l_15kV
.u1 , system control and spatch serv ce. Regulat and frequency responseservice. Operating reserve - spinning reserve service. Operating reserve - supplementalreserve service.
Netwc,rk tran ss on service under the Open Access Transm ss on Tar
Servi ce t 735) terminat onS 30
Chela.tchie L15
20]-7 SS anc ary services. 2017 annua transm on ces true-up
refun.ds and/or surcharge.
ERI_7-219-002.
328.1 Line No.: 28 Column: m
328.1 Line No.: 29 Column: d
328.1 Line No.: 29 Column:
328.1 Line No.:29 Column: m
Refunds for transmission services pursuant to FERC Docket No.
Scheolule Pase: 328.1 Line No.: 30 Column: b
FERC FORM NO. 1 (ED. 12.871 Paqe 450.1 0
2028.
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
20't8tQ4
FOOTNOTE DATA
Various s tories to the Volume 11 Point-to-Point Transmission Tariff
Various s tori-es to the Volume 11 Po -to-Po SS Tar f f .
Non-rm or rL - term rmt ss SC ce under the Open Access Tr ec Tar
328.1 Line No.: 30 Column: c
328.1 Line No.: 30 Column: d
between various
S
rties and ints.
, system cont spatch se ce. React ve supply vo tage controservlce.
to es to Volume 11
ous s to es to the Vo]ume 1l-
L-to-
t-to-Po
SS Tar f f .
on Ta f f .
f
t
Non- f rm or short-term firm transmission service under the Open Access Transmission Tariff
between various ies and ts
20L7 transmission and ancillary services. 2017 annual transmission services true-uprefunds and/or
on service under the Open Access Transmission tariff (l-2th Revised Service
Agreement 299). Service provided pursuant to rules and regulations of Oregon Direct.Access. Agreement terminates upon notification pursuant to Oregon Direct Access and Open
Access Transmission Tarif f .
Sc , system control and spatch serv ce .ve supply and voltage control
serv].ce
serv].ce
Regulation and frequency response service. Operating reserve - spinning reserveratireserve - s lemental reserve service
ssion service under the Open Access Transm on Tar (].2t Revised Service
Agreement 299). Service provided pursuant to rul-es and regulations of Oregon DirectAccess. Agreement terminates upon notification pursuant to Oregon Direct Access and Open
Access Transmission Tarif f .
201,7 anc I ary servlces 2017 annuaf tr on serv ces true-uponssorrefunds
Various s tor es to VO ume 11 Po - to- Po Transm SS on Tar ff
Var Eor es to the Volume 11 Po t-to-Point Transmission Tarif f
Non- f or short-term firm Lransmission service under the Open Access Transmj-ssion Tariff
between various ies and ints .
201-7 annual transm services true-refunds or
Var SS tories to the Volume l-1 Point-to-Po Transm SS Tar f
Various s tories to VO ume 1l- Po -to-Po ss Tar
Non-firm or short-term rm tr SS on se ce under the Open Access Tr ss
328.1 Line No.:30 Column: m
328.1 Line No.: 31 Column: b
328.1 Line No.: 31 Column: c
328.1 Line No.:31 Column: d
328.1 Line No.:31 Column: m
328.1 Line No.:32 Column: d
328.1 Line No;32 Column: m
328.1 Line No.:33 Column: d
328.1 Line No.:33 Column: m
328.1 Line No.:34 Column: b
328.1 Line No.: 34 Column: c
328.1 Line No.: 34 Column: d
328.1 Line No.:34 Column: m
328.2 Line No.: 1 Column: b
328.2 Line No.: 1 Column: c
328.2 Line No.:1 Column: d
refunds and/or surcharge.
SE ces. 201-7 annual t se ces true-up
Tar ff
between various
2017 transmiss
rties and ints
anc
328.2 Line No.:1 Column: m
FERC FORM NO.1 (ED. 12-871 Page 450.'l 1
Name of Respondent
Pacif,Corp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.2 Line No.:2 Column: b
328.2 Line No.:2 Column: c
328.2 Line No.: 2 Column: d
ous s tor es to the Volume lL Point-to-Point Tran SS Tar
ous s tor es to VO ume 11 Po t-to-Po Tran SS Tar f f .
Non-firm or -term f rm transm S ce under the Open Access Transmiss on Tar ff
between various ies and ints
Scheciuling, system control and dispatch service. Reactive supply and voltage control
servi-ce.
Various s tor es to the Volume 1-1 Point-to-Point Transmission Tariff.
OUS S tor es to Vol-ume 11 Point-to-Po t ss Tar
Non- l:rm or short-term f transm SS se ce under the Open Access SS on Tar ff
between various rties and ints
Scheciuling, system control and d spatch se ce. React ve supply and vol-tage control
servt.ce.
t-to-point tran ss serv ce under the Open Access Tran on ff (Serv ce
erment 881) terminat on 28 2023.
Schecluling, system control and d spatch se ce.
Page:328.2 Line No.: 5 Column: bThis footnote applies to all occurrences of "Clatskanie People's Utility DisEr" on pages
328-3,30.ete name is Clatskanie Ie's Ut.i1i District
t.-to t tran ssion service under the Open Access Transmission Tariff (Service
ement 899 terminat on December 31 , 2020.
C^system contro and di-spatch service. React ve supp v VO tage control
serv I ce .
nt.-to-p tEr ss service under the Open Access Transmission Tariff (Service
€rment 899 terminat on December 31 2020.
2017 annual t ss services true-re or sur
s footnote applies to all occurrences of "Deseret GeneraL and ss on" on pages
328-330. C ete name is Deseret Generation and Transmission Co-rative
ootnote appl stoa f occurrences of "Deseret Gen Trans'r on pages 328-330.ete name is Deseret Generation and Transmission Co erative.
Legacy contract execut tween PacifiCorp Deseret Generation TransmissionCo-operative for transmission service over agreed-upon facilities (5th Amended and
Restat.ed Transmission Service and Operating AgreemenE, Rate Schedule 280). Agreement
S ect to termination muLual reement.
328.2 Line No.:7 Column: mDistribution vo tage se ce charge. Meter errogat on se ces. Schedul D9, SyStemcontrol and dispatch service. Reactive supply and voltage control servj-ce. Regulation and
frequency response service. operating reserve - spinning reserve service. operatingreserve - supplemenLal reserve service.
FERC FORM NO.1 (ED. 12-871 Page 450.12
328.2 Line No.: 2 Column: m
328.2 Line No.: 3 Column: b
328.2 Line No.: 3 Column: c
328.2 Line No.:3 Column: d
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328.2 Line No.:4 Column: d
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328.2 Line No,: 6 Column: d
328.2 Line No.:6 Column: m
328.2 Line No.:7 Column: a
328.2 Line No.:7 Column: b
328.2 Line No.:7 Column: d
S
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.2 Line No.: 8 Column: d
328.2 Line No.:8 Column: m
Legacy contract executed between Pac f Corp and Deseret Generat and Tran SSCo-operative for transmission service over agreed-upon facilities (6th Arnended and
Restated Transmission Service and Operating Agreement, Rate Schedule 280) . Agreement
sub ect to termination mutual ement.
201,7 L SS on anc lary se ces. 2017 annual t ss SE ces true-up
refunds and/or surcharge. Refunds for transmission services pursuant to FERC Docket No.
ERL7 -2L9-OO2 -
ous s tor es to ume 11 t-to-t SS on
ous s tor es to the Volume 11 t-to-Po t SS on ff
Non- f rm or short-term f rm transmission servj-ce under the Open Access ssron ff
between various es and nts
Schedulservice ng, system control and spatch service. Reactive supply and voltage control
Var ous s tor es to the Volume 11 Point-to-Point Transmission tariff
Vari-ous si tories to the Volume 11 nt-to-nt ssion Tariff
Non-rm or -term transm on serv ce Open Access SS on
between various ies and ints
2017 transmission and ancil serv]-ces .
Various s tories to Vo ume 11 nt-to-nt on Tar
Var ss tor sto Vo ume 11 Po nt-to-nt Transm SS on Tar
Non-or t-term f rm tran ss serv under the Open Access Tr SS on Tar ff
between various rties and ints
2017 tran ss anc lary se ces. 2017 annual transm serv ces true-uprefundsor surcha
Var to es to Vo ume l-1 Po -to-Po Tran Tar ff
VA to es to the Volume 11 Po - to- Po t Tran ss Tar ff
Non- f rm or short-term f rm transmission service under the Open Access Transmission Tariff
between various arties and ints.
Schedul system control and spatch service. Reactive supply and voltage control
servlce.
ous s t es to t.he Volume 11 Po -to-Po SS on Tar ff.
SS on resale serv ce under the Open Access Transmission Tariff (Service Agreement
Termination mutual consent.
FERC FORM NO.1 (ED.'.t2-871 Page 450.13
328.2 Line No.:9 Column: b
328.2 Line No.:9 Column: c
328.2 Line No.:9 Column: d
328.2 Line No;9 Column: m
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328.2 Line No.: 11 Column: b
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328.2 Line No.:12 Column: b
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328.2 Line No.: 13 Column: c
328.2 Line No.: 13 Column: d
328.2 Line No.:13 Column: m
780
on resale - purchase of point-to-point transmission. Scheduling, system control
Name of Respondent
Pacif Corp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
and dispatch service Reactive supply and voltage control service. Generation regulationservice.re
ootnote appl estoa occurrences o "PUD No. 2 of Grant County" on pages 328-330.
328.2 Line No.:14 Column: c
l-ete name is Public Utilit District No. 2 of Grant Count
Trans,m SS resale serv Open Access Transm SS Tar ff (se ce Agreement
328.2 Line No.:14 Column: d
328.2 Line No.: 14 Column: m
780 Termination mutual consent
2017 transm ssion and anc 11ary serv ces. 2017 annual transm on se ces true-uprefundsor
Var S tories to the Volume 11 nt-to-Point Transmission Tarif f .
Various s to es to the Vofume 11 Point-to-Point Transmission Tariff.
Non-rm or short-term rm transmi on serv CC Open Access SS
328.2 Line No.:15 Column: b
328.2 Line No.: 15 Column: c
328.2 Line No;15 Column: d
betweren various ies and ints
Tran.SS resale -o
and cli tch service. Reactive s
Var c)us to es to
nt-to-nt trans SS on
and vol-control service
I system control
Po t.-to-point transm ss on serv
VO ume 11 nt-to-nt
ce under the Open Access Tr
on Tar ff.
ss Ta ff (2nd Revised
328.2 Line No.: 15 Column: m
328.2 Line No.: 16 Column: c
328.2 Line No.: 16 Column: d
Servi ce t 711) which terminated on November 30, 201,8
20L7 Lransmission and ancillary serv ces. 2017 annual transmission services true-up
refur:.ds and or
Var S1 tories to the Volume 11 nt-to-Point Transmission Tarif f
Point -to-po transm ssion service under the Open Access ssion Tar Se ce
328.2 Line No.: 16 Column: m
328.2 Line No.: 17 Column: c
328.2 Line No.: 17 Column: d
328.2 Line No.:17 Column: m
ment 874 termi-nati on December 31 2032
D9, system control and dispatch s ce. React ve s'v vo tage conLroservj-ce. Generation regulation and frequency response service. operating reserve -
l-nn 1 reserve servlce ati reserve - s emental reserve service.
Trans on se ce under the Open Access Transmission Tariff (2nd Revised Se ce
Agreement 847) . Service provided pursuant to rules and regulations of Oregon Direct
Access. Agreement terminates upon notification pursuant to Oregon Direct Access and Open
Access Transmission Tarif f .
Schedul ng, system con spatc ce. React ve supply and voltage controlservice. Regulat.ion and frequency response service. Operating reserve - spinning reserve
serv]-ce 'at reserve - s emental reserve service.
Tran SS on se ce the Open Access on Tar Se ce
Agreement 847). Service provided pursuant to rul-es and regulations of oregon Direct
Access. Agreement terminates upon notification pursuant to Oregon Direct Access and Open
Access Transmission Tarif f .
2017 transmission and anc 11ary serv ces. 2017 annual transm SS on ces true-up
FERC FORM NO. 1 (ED. 12.871 Page 450.14
328.2 Line No.: 18 Column: d
328.2 Line No.: 18 Column: m
328.2 Line No.: 19 Column: d
328.2 Line No.:19 Column: m
refunds and/or surcharge. Refunds for transmission services pursuant to FERC Docket No
and
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
20181Q4
FOOTNOTE DATA
328.2 Line No.: 20 Column: b
328.2 Line No.:20 Column: c
328.2 Line No.:20 Column: d
ER17-219-002.
Va es to the Volume 11 Po -to-Po SS Tar ff
S es to the Volume 11 Point-to-Point Transmission Tariff
Non-f rm or short-term firm transmission service r Open Access Tran on Tar
between various ies and ints.
Scheduling, system control and dispatch se ce. React ve supp -I VO tage controservice. Generation regulation and freguency response service. Operating reserve -spinning reserve service. Operating reserve - supplemental reserve service. Unauthorizeduse of transmission service.
ous s t es to the Volume 11 Po -to-Po t Transmission rariff.
ous s tories to the Volume 11 Point-to-Point Transmiss on Tarif
Non-firm or short-term firm t SS SE ce rt Open Access Transm Tar
between various es and ts.
2017 transmission and anc ary se ces. Re ort SS on se ces pursuant to
FERC Docket No. ERLT-2]-9-002
Various si-tories to t ume 11 Po - to- Po t ss on f
Various si-tories to the Volume 11 Po -to-t SS on
Non-firm or s -term rmt SS SE ce under the Open Access SS Tar ff
between various es and ts.
This footnote applies to occurrences ver ect c Cooperat vetr on
328-330 ete name is FaI1 River Rural Electric tive Inc.
Legacy contract (Rate 6 aaa execute tween Pac Corp I ver RuralElectric Cooperative for transmission service over agreed-upon facilities and/or subjectto a sole-use or facilities c Terminat on .fuf 31 2027
Charge for ssion service over aglreed-upon facili ES or ect to a so -useor facilities charge based on a capacity factor and/or proportional use as defined in thecontract.
Legacy contract Rat.e Schedule 322) executed between PacifiCorp and Fa11 River RuralElectric Cooperative for transmission service over agreed-upon facilities and/or subjectto a sole-use or facilities Terminat On Jul 31 2027
2017 transmiss on serv ces
Serv Agreement 751 executed between Pac f Corp and Foote Creek III, LLC (
Terra-Gen Operating, LLC) for transmission service over agreed-upon facilities and/or
S ect to a sol-e-use or facilities c Terminati on March 1 2024
Charge for transm SS serv over -upon fac 1Distribution volt
FERC FORM 1 ED. I 450.15
328.2 Line No.:20 Column: m
328.2 Line No.:21 Column: b
328.2 Line No.:21 Column: c
328.2 Line No.:21 Column: d
328.2 Line No.:21 Column: m
328.2 Line No.:22 Column: b
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328.2 Line No.:23 Column: d
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328.2 Line No.:24 Column: d
328.2 Line No.:24 Column: m
328.2 Line No;25 Column: d
328.2 Line No.:25 Column: m
328.2 Line No.:26 Column: d
or facilities servlce es ors ect to a sole-use
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
2UAA4
FOOTNOTE DATA
328.2 Line No.:26 Column: m
328.2 Line No.:27 Column: d
Servlce Agreement 751 executed between PacifiCorp and Foote Creek III, LLC (d/b/a
Terrtr-Gen Operating, LLC) for transmission service over agreed-upon facilities and/oroct Lo a sole-use or facilities cha . Terminat on March 1 2024.
201,7 I on anci-1 servlces.
Pointr - t.
Servi.ce
Etr ss se ce r Open Access
201,9 .
SS on Tar 6 Rev sed
21,2 terminat on Ma 3t_
Sc system contro spa se . React ve y and voltage control
servl.ce.
t-t Ltr ss SC ce t Open Access
201_9 .
SS on Tar ff (8th Rev sed
Service ement 2L2) terminat on 31
201,'7 t ssion and anc 11ary se s. 2017 annual t on serv ces true-up
refu::Lds and/or su
re.t on, maintenance or fac 1 lease serv ces th no rece or de1 of
ra.tion ntenance or facilit lease services with no recei t or de1
Non-firm or s -term firm transmission serv r Open Access SS on
betwe,en various ies and ints
S system conLro spa serv React ve supp v tage cont
serv].ce.
328.2 Line No.: 30 Column: b
ra.t ntenance or t serv no rece tor
rat maintenance or fac 1 lease serw ces th no rece t or de1 ve of ene
Non-firm or s -term firm transmiss service under the Open Access Transmj-ssion Tariffrties and ints
201-7 Lransmiss on and ancillary services. 2017 annual transmission services true-up
refunds or sur
ration ntenance or facilit lease services with no recei tor 1Ve ene
rat tenance or ac t lease serv no rece tor ve
Non-rm or short-term rm tran on serv ce under the Open Access on ff
between various rties and ints
20].7 L SS on anc ry services. 2017 annua tr ss se ces Lrue-uprefundsor sur e
Varicus s tor es to Volume 11 Point-to-Po t Tran SS
,cus s tor sto Vo ume 11 Po -to-Po Tr SS
Non- f rm or short-term f rmt SS
between various ies and ints.
FERC FORM NO. 1 (ED. 12-871 Page 450.16
328.2 Line No.:27 Column: m
328.2 Line No.: 28 Column: d
328.2 Line No.:28 Column: m
328.2 Line No.:29 Column: b
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328.2 Line No.:32 Column: b
328.2 Line No.:32 Column: c
328.2 Line No.: 32 Column: d
328.2 Line No.:32 Column: m
serv under the Open Access ss on Tar ff
between various
Name of Respondent
PacifiCorp
This Report is:
(1)XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.2 Line No;33 Column: b
328.2 Line No; 33 Column: c
328.2 Line No.: 33 Column: d
201-7 transmission and ancillary servj-ces. 2017 annual transmission services true-up
refunds or
ous s es to ume 11 Po -to-Po t SS Tar ff
Var ous s t es to the Volume 11 Po t-to-Po t on Tar ff
Non- f rm or short-term firm transmission service under the Open Access Transmission Tariff
between various ies and ts.
Schedul
service
system control and dispatch service. Reactive y and voltage control
Var ous sr tories to the Volume l-1 Point-to-Point Transmiss on
Various si tories to t ume 11 t-to-nt SS on
Non-rmors -term rmt SS on se ce under the Open Access SS 1d ff
between various ies and
ng, system control and spatch s ce. Reac ve supply and voltage control
serv]-ce.
Var ous s tor estot ume 11 t-to-nt ss on ff.
Var ous s tor es to the Volume 11 t-to-nt SS on f f .
Non-rmors -term f rm ss on serv ce under the Open Access Ta ff
between various ies and nts
ng, system control and spatch serv ce. Reactive supply and voltage controlservlce.
Various s tor es to ume 11 nt-to-nt SS on ff.
Var tor es to the Volume 11 nt-to-Point Transmission Tarif f .
Non-or short-term f rm trans SS on service under the Open Access Transmission Tariff
between various es and nts
D9, system control and spatch service. Reactive supply and voltage conErol
serv]-ce
Var SS tor es to the Volume 11 Point-to-Point Transmission Tariff.
Va ss tor to the Volume 11 Point-to-nt on
Non- f rm or short-term firm transmission serv ce Open Access ss onbetween various ies and ints
Schedul
service system control and dispatch service. Reactive supp v voltage cont
Legacy contract (3rd Revised Rate Schedule 302 execu ween Pac Corp Moon
FERC FORM NO.1 (ED. 12-871 Pase 450.17
328.2 Line No.:33 Column: m
328.2 Line No.:34 Column: b
328.2 Line No.:34 Column: c
328.2 Line No.:34 Column: d
328.2 Line No.:34 Column: m
328.3 Line No.: 1 Column: b
328.3 Line No.: 1 Column: c
328.3 Line No.: 1 Column: d
328.3 Line No.: 1 Column: m
328.3 Line No.: 2 Column: b
328.3 Line No.: 2 Column: c
328.3 Line No.: 2 Column: d
328.3 Line No.:2 Column: m
328.3 Line No.:3 Column: b
328.3 Line No.: 3 Column: c
328.3 Line No.: 3 Column: d
328.3 Line No.:3 Column: m
328.3 Line No.:4 Column: d
Electric Association for transmissj-on and interconnection service over agreed-upon
Namel of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.3 Line No.:4 Column: m
facj.--ities and,/or subject to a sole-use or facilities charge. Either party may terminate
the reement at time after october 14, 20l.6 two rs written notice
r transm serv ce over -upon c t or ecttoas e-useor facilities charge based on a capacj-ty fact.or and/or proportional use as defined in the
contr:act.
Legacy contract 3 Rev Rate 302 exe tween Pac Corp MoonElecLric Association for transmission and interconnection service over agreed-uponfacil-ities and/or subject to a sole-use or facil-ities charge. Either party may terminate
the at time after October 14, 20]-5,two written noti-ce
20Li' Lransmission and ancill serv ces
OUS S tor es to Vo ume 11 Point-to-Po ss Ta
C)r-rS S tor es to the Vo ume 11 Po -to-Po SS Ta ff.
Non-f: irm or short-term f rm tr on serv ce under the Open Access Transmission ff
betweren various ies and ints
ScheiLul-ing, system control and d spatch serv Reactive supply and voltage control
servr.ce.
Various s tor es to the Volume 11 Point-to-Point Transmission Tariff.
ous s tor es to Vo ume 11 Po t-to-Po ss Tar
Non- f rm or short-term f rm tr on serv under the Open Access Tr ss on ff
betv,;'een various ies and ints
201-7 transmission and 11ary serv ces. 201-7 annual t SS SC ces true-up
refur:Lds and/or s
crus s tories to the Volume 1-l- Po .t-to-Po Tr SS Tar ff.
Varic,us s tories to the Volume 1l- Po -to-Po Transmission Tariff.
Non-rm or -term irm transmission service under the Open Access Transmission Tariff
between various ies and ints
e , system contro dispatch service. React ve supp VO tage control
servlce.
Varicus si-tor es to the Volume 1l- Po -to-Point Transmission Tarif f .
Varicus s tor es to the Volume 11 Point-to-Point Transmission Tariff.
Non-rm or short-term transmission service under open Access Transmission Tariff
between various ties and ints
Sc system contro dispatch service. React ve supp vservlce.
FERC FORM NO. T (ED. 12.871 Page 450.18
328.3 Line No.: 5 Column: d
328.3 Line No.:5 Column: m
328.3 Line No.:6 Column: b
328.3 Line No.:6 Column: c
328.3 Line No.:6 Column: d
328.3 Line No.:6 Column: m
328.3 Line No.:7 Column: b
328.3 Line No.:7 Column: c
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328.3 Line No.:7 Column: m
328.3 Line No.:8 Column: b
328.3 Line No.:8 Column: c
328.3 Line No.: I Column: d
328.3 Line No.: 8 Column: m
328.3 Line No.:9 Column: b
328.3 Line No.:9 Column: c
328.3 Line No.:9 Column: d
328.3 Line No.:9 Column: m
328.3 Line No.: 10 Column: b
Var cus s gnator sto Volume 11 Point-to-Point Transmiss on Tariff.
tage control
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.3 Line No.:10 Column: c
328.3 Line No;10 Column: d
ous s tories to the Volume 11 Point-to-Point SS Tariff.
Non-firm or short-term rmt on se ce r Open Access SS Id
between various arties and ts
201-7 transmi-ssion anc ary serv ces. 2017 t ss SE ces true-up
refunds or
ous s t estot ume 11 nt - to-t ss on f
Var ous s t es to the Volume 11 nt-to-nt on ff.
Non- f rm or short-term firm transmission service under the Open Access Transmission Tariff
between various ies and nts
Schedul
service
system control and dispatch service. Reactive supply and voltage control
Network t ssion service under the Open Access Transmission Tariff (Service Agreement
894 terminati on December 31, 2057
Schedul ng, system control and d spatch service. Reactive supply and voltage controlservice. Regulation and frequency response service. Operating reserve - spinning reserve
serv]-ce ri reserve - s lemental reserve service
Var ous s tor es to VO ume 11 Po nt-to-nt Tr SS on Tar ff
Var tor es to the Volume 11 Po t-to-nt Tr on Tar ff
Non- f rm or short-term f Eransm SS service under the Open Access Transmission Tariff
between various ies and ints
Dg, system control and d spatch serv ce. Reactive supply and voltage control
serv]-ce
Var ss tor es to the Volume 11 Po -to-Po Tr ssion Tar ff
Var SS tor es to the Vol-ume 11 Po t-to-Point Transmission Tarif f
Non- f or short-term firm transmission service under the Open Access Transmission Tariff
between vari-ous ies and ints .
2017 transm
refunds and
S and ancillary services. 2017 annual transmission services true-upor
tor s to the Volume l-l- Po -to-Point Transmission Tarif f
ous s tories to the Volume l-l- Point-t.o-Po Transm SS Tar
Non-firm or short-term firm transmission se ce r Open Access Tran
between various ies and ints .
FERC FORM NO.1 (ED. 12-871 Paqe 450.19
328.3 Line No.:10 Column: m
328.3 Line No.:11 Column: b
328.3 Line No.:11 Column: c
328.3 Line No.: 11 Column: d
328.3 Line No.: 11 Column: m
328.3 Line No.:12 Column: d
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328.3 Line No.:13 Column: b
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328.3 Line No.: 14 Column: b
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328.3 Line No.: 14 Column: m
328.3 Line No.:15 Column: d
328.3 Line No.: 15 Column: b
328.3 Line No.: 15 Column: c
328.3 Line No.: 15 Column: mScheduling, system control and
service.spat se ce. React ve supp v vo Lage contro
Tar
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.3 Line No.:16 Column: d
328.3 Line No.: 16 Column: m
PoinL-to-po t transmiss on ce under the Open Access SS on Tar ff 3 sed
Serv:Lce L 733) terminat on Novernlcer 30 , 2023.
s , system control and dispatch service. Reactive supply and voltage control
serv:Lce. Generation regulation and frequency response service. Operating reserve -
reserve servace 'at reserve -emental reserve service
-to-po t transmission se ce under the Open Access on Tar ff (3rd sed
Ser\r:-ce reement 733) terminat on Novemlcer 30 , 2023.
20]-7 t SS on ancillary se ces. 2017 annual t on serv ces true-up
ref urrds or surcha
ous s tor es to Volume l-l- PoinE-to-PoinE Transmission Tariff
ous s tories to the Vo ume l-1 t-to-nt ss on Tar
Non-firm or s -term f rmt GC on se ce under the Open Access Transm T
between various rties and ints.
Scheiluling,
servi.ce.
system control and spatch se ce. React ve supply and voltage contro
Varic>us s tor s to the Volume 11 t-to-nt SS on Tar ff
Var OUS S Eor sto Volume l-l- Point-to-Point Transmission tariff
Non- f:rm or short-term f rmt ss ons ce open Access Transmission Tariff
betwe:en various ies and ts.
2017 transmission and anc SE ces
tion maintenance or fac I lease serv th no or ve ene
on .Lenance or facil lease serv ces th no or del ve of ene
Legacy cont.ract (Rate Sc e 507) executed between PacifiCorp and Pacific Gas & Electr
Compa.ny for transmission service over ag'reed-upon faciliEies (Ma1in Eo Round MounLain)
and/or subject to a sole-use or facilities charge. Terminated on December 31, 2017. For
furth.er information refer to FERC Docket No. ER07-882-000, et aI, Settlement Agreement,x 2 (filed November 21 2007
Ma1 to Ind nes t
Ma1 to Indian 1 ne t
Charge for transmission serv ce over -upon fac I t or ecttoas e-use
or faciliLies charge based on a capacity factor and/or proportional use as defined in the
contracE.
Var s tories to the vo ume 11 Po -to-Po SS Tariff.
Various s tories to the Volume l-1 Po -to-Po
328.3 Line No.:17 Column: d
328.3 Line No.:17 Column: m
328.3 Line No.: 18 Column: b
328.3 Line No.: 18 Column: c
328.3 Line No.: 18 Column: d
328.3 Line No.: 18 Column: m
328.3 Line No.:19 Column: b
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328.3 Line No.: 19 Column: m
328.3 Line No.:20 Column: b
328.3 Line No.: 20 Column: c
328.3 Line No.: 20 Column: d
328.3 Line No.:20 Column:
328.3 Line No.:20 Column: f
328.3 Line No.:20 Column: m
328.3 Line No.:21 Column: b
328.3 Line No.:21 Column: c
Schedule Pase:328.3 Line No.:21 Column: d
FERC FORM NO.1 (ED. 12.871 Page 450.20
SS Ta
q
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
20181Q4
FOOTNOTE DATA
328.3 Line No;21 Column: m
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various ies and ts.
s , system cont spat SE ce. React ve v tage contservice. Generation re ation and f re onse servlce.
VA estot ume 11 -to-t SS on
VA t es to the Volume 11 -to-t SS on ff
Non- f rm or short-term f rm transmiss on service under the Open Access Transmission Tariff
between various ies and ts
201,7 L SS on and anc llary services. 2077 annual transmission services true-up
refunds or surc
rat o[,tenance or facilit lease services with no recei-or deli of
ration maintenance or facilit lease se ces w L no rec or ve e
Legacy contract (lst Rev Rate Sc e 137 execut Pac Corp PortGeneral Electric Company for transmission service over ag'reed-upon facilities and/orsubject to a sole-use or facilities charge for the Dalreed Substation, which terminated in
December 201-3.
Charge for transmission service over agreed-upon facilities or subject to a sole-useor facilities c
OUS S tor es to the Volume 11 l-l^nt SS on Tar ff
ous s tor es to the Volume 1l-t-to-Point Transmission Tarif f
Non- f rm or short-term fj-rm transmission service under the Open Access Transmissj-on ff
between various es and nts
2017 annuaf on serv ces true-refunds ors
s footnote applies to all occurrences of "Sher -,J on R'ect. " on pages
328-330 ete name is Sheridan-,Johnson Rural Electric Association
Agreement prov ng for transmission service from Western Area Power strat ontsCasper Substation in Wyoming and Yellowtail Substation in Montana to Sheridan-,JohnsonRural Electric Association's load at Pacifi 's Buf falo Substati-on in
for transm EG serv over agreed-upon facilities or subject to a sole-useor facilities
Agreement prov d for transm serv ce from Western Area Power Administration's
Casper Substation in wyoming and Yellowtail Substation in Montana to Sheridan-,fohnsonRural Electric Association's load at Pacifi 's Buffalo Substation in
2017 transm anc serv
s ootnote app s to all occurrences of "CAISO||on pages 328-330. Complet.e name is
FERC FORM NO.1 (ED. 12471 Page 450.21
328.3 Line No.:22 Column: b
328.3 Line No.:22 Column: c
328.3 Line No.:22 Column: d
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328.3 Line No.:23 Column: b
328.3 Line No.:23 Column: c
328.3 Line No;23 Column: d
328.3 Line No;23 Column: m
328.3 Line No.:24 Column: b
328.3 Line No.:24 Column: c
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328.3 Line No.:24 Column: m
328.3 Line No.:25 Column: c
328.3 Line No.:25 Column: d
328.3 Line No;25 Column: m
328.3 Line No.:26 Column: d
328.3 Line No.:26 Column: m
328.3 Line No.:27 Column: c
California Independent System Operator Corporation
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2UAA4
FOOTNOTE DATA
328.3 Line No.: 27 Column: d
Po -to-po tran GC serv Open Access Tran SS on ff (8th Rev sed
Serrr:Lce
Schedul
serrrice
t 1_69 terminat on October 3l-, 2020
system control and spatch serv ce. React ve supply and voltage control328.3 Line No.:27 Column: m
328.3 Line No.:28 Column: d
PO -to-point tran ss under the Open Access Transmission Tariff (8th Revised
on Oct.ober 31, 2020.Serv:Lce t 169) terminat
2017 transmission and anc 11ary serv 2017 annual- transmission services true-up328.3 Line No.:28 Column: m
refunds or
Point-to-po transmission service under the Open Access Transmission ff (3rd Revised
Servi-ce 'reement 700 ) terminat on March 31, 2022
s tem control and di tch serv ce.
Po -to-po tran SS Open Access Tr ss ff 3rd sed
328.3 Line No.:29 Column: d
328.3 Line No.:29 Column: m
328.3 Line No.: 30 Column: d
Servi-ce
201,7 Lr SS on
t 700 terminat on March 3L 2022
anc serv 2017 annual tran ss se ces Lrue-up
328.3 Line No.:30 Column: m
refunds and or
Po -to-po
Serl'i,ce
Scherclul
Po t--to-point t
tr SS serv the Open Access Tran ff (3rd sedSt 701 terminat on March 3l-2022
tem control
serv
tch serv
under the Open Access Transmission Tariff (3rd Revised
on March 3]-, 2022.
328.3 Line No.: 31 Column: d
328.3 Line No.: 31 Column: m
328.3 Line No.:32 Column: d
328.3 Line No.: 32 Column: m
Servi.ce t 701) terminat
201-7 transmission and ancillary serv 2017 annual transmission services true-up
refunds or
Point.-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Serv'i,ce t 702) terminat on March 31, 2022
Sche,ilul tem control and d tch service.
Po t. - t o-po SS servr_ce Open Access Tran SSt 3
328.3 Line No.:33 Column: d
328.3 Line No.:33 Column: m
328.3 Line No.: 34 Column: d
Serv'i.ce
201,7
t 702) terminat on March 31 2022
ancillary services. 201-7 annual transmission services true-upon
328.3 Line No.:34 Column: m
SS
orrefurrds
Point.-to-po transmission serv ce under the Open Access Transmission Tariff (l-st Revised
Serv i.ce t 748) which terminated on December 3L, 20]-8
ScheiLul tem control and tch service
Point-to-po tran SS service under the Open Access Transmission Tariff (1st Revised
328.4 Line No.: 1 Column: d
328.4 Line No.: 1 Column: m
328.4 Line No.:2 Column: d
Servi ce reement 748) which terminated on Decefidcer 31, 2018.
328.4 Line No.:2 Column: m
201-7 tran SS on and ancillary services. 201-7 annual transmission services true-up
FERO FORM NO. 1 (ED. 12-871 Page 450.22
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.4 Line No.: 3 Column: d
refunds or
Po -to-po t SS the Open Access T SS Tar ff (1st Rev sed
Service reement 749 which terminated on December 31 , 20L8.
S tem control and Lch
Po -Eo-po t on se ce under the Open Access Transmission Tariff (1st Revised
Service reement 749 which terminated on Decemlcer 31 , 20]-8.
20]-7 t SS on and anc Ilary services. 20L7 annual transmission services true-uprefundsor
ous s t es to the Volume 11 Point-to-Point Transmission Tariff.
ous s tories to the Volume 11 Point.-to-Point SS on Ta
Non-firm or short-term rmt ss SE ce rt Open Access Transm Tar ff
between various ies and ints.
Scheduling, system contservice.spat SE ce. React ve y and voltage control
Various si tories to t VO ume 11 Po -to-Po t ss on
ous s tor estot ume 11 Po -to-Po t SS on ff.
Non-firm or s -term rmt ss SE ce under the Open Access ss Tar ff
beLween various ies and ts.
201-7 transmission anc ary se ces. 2017 annual t ss on se ces true-uprefundsors
Various si tories to t ume 11 Po t-to-Po t ss on ff.
Various si tor estot ume 11 t-to-t on ff.
Non-rmors -term f rmt ss on se ce under the Open Access Transmission Tariff
between various es and TS
Sc [9, system control and spatch se ce. Reac ve supply and vo1tage control
servt-ce.
Various s for es to ume 11 t-to-nt ss on ff.
Var ous tor es to the Volume 11 t-to-nt Transmiss on Tariff.
Non- f or short-term f rm transmission service Open Access
between various ies and nts
2017 annua transm SETV ces true refunds and ors
Var SS tor s to the Volume 11 Point-to-Point Transm on Tar
Var SS tories to the Volume 11 nt-to-
328.4 Line No.: 3 Column: m
328.4 Line No.:4 Column: d
328.4 Line No.:4 Column: m
328.4 Line No.: 5 Column: b
328.4 Line No.: 5 Column: c
328.4 Line No.:5 Column: d
328.4 Line No.:5 Column: m
328.4 Line No.:6 Column: b
328.4 Line No; 6 Column: c
328.4 Line No.:6 Column: d
328.4 Line No.:6 Column: m
328.4 Line No.:7 Column: b
328.4 Line No.:7 Column: c
328.4 Line No;7 Column: d
328.4 Line No.:7 Column: m
328.4 Line No.: 8 Column: b
328.4 Line No.: I Column: c
328.4 Line No.: 8 Column: d
328.4 Line No.: 8 Column: m
328.4 Line No.:9 Column: b
328.4 Line No.:9 Column: c
FERC FORM NO.1 ED.1 450.23
nt Transm Tar f
SS
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
201Ao,4
FOOTNOTE DATA
328.4 Line No.:9 Column: d
328.4 Line No.: 10 Column: c
Schedule Page:328.4 Line No.:9 Column: m
328.4 Line No.: 10 Column: b
or surc
328.4 Line No.:10 Column: d
Non-1-rm or short-term rmt ss se ce
re
t Open Access
on Tar ff
on Tar
between various arties and ts.
2017 annual SS on se ces true
Vari.ous s es to the Volume l-l- Po t-to-Po t
Var ous s es to Volume 11 Point-to-Point ssion Tarif
Non- l:rm or short-term f rmt ss on se ce Open Access Transm Tar
betwe:en various es and ts.
2017 annual ss ons ces true re
This footnote es to afl occurrences of "PUD No. 1 of Cowl tz Countyrr on pages
328-:r30 lete name is Public Utili District No. 1 of Cowlitz
Legacy contract Rate Schedule 234) providing for transmission and operation of ft
Hydroelect.ric planE No. 2 and for transmission service over agreed-upon facilities and/orsubject to a sole-use or facilities charge. Agreement may be terminated subseguent to thetermination of the Power contract as defined in the agreement by the customer providing at
leasL six-months written notice and specifying the date on which the customer will assume
res'bilir of tions and maintenance of Swift ectric lant No. 2
or tr on serv ce over agreed-upon ties and,/or s ect to a sole-useor facilities charge based on a capacity factor and/or proportional use as defined in the
cont.ract.
Legacy contract Rate Schedule 234) providing for t.ransmission and operat.ion of swift
Hydroelectric plant No. 2 and for transmission service over agreed-upon facilities and,/or
subjerct to a sole-use or facilities charge. Agreement may be terminated subsequent to the
termj.nation of the Power conEract as defined in the agreement by the customer providing at
1east. six-months wriLten noEice and specifying the date on which the customer will assume
res ibilir of tions and maintenance of Swift lectric lant No. 2
2017 transm on and ces
Var s tories to the Volume 11 t-to-nt Transm Tar ff.
Var S to es to the Volume 1l-nt-to-nt Transm Tar ff.
Non-or short-term rm ss ons ce Open Access Transmission Tariff
328.4 Line No.:10 Column: m ors
328.4 Line No.: 11 Column: a
328.4 Line No.: 11 Column: d
328.4 Line No; 11 Column: m
328.4 Line No.:12 Column: d
328.4 Line No;12 Column: m
328.4 Line No.: 13 Column: b
328.4 Line No.: 13 Column: c
328.4 Line No.: 13 Column: d
328.4 Line No.:13 Column: m
between various ies and nts
S , system conLrol and dispatch service. Reactive supply and volt.age control
servl ce
Varic,us s es to t.he Volume 11 nt-to-nt Tr SS ld f f .
VA tor es to the Volume 11 nt - to- Po Tran fd ff.
Non-rm or short-term firm transmission service under the Open Access Transmission
328.4 Line No.: 14 Column: b
328.4 Line No.: 14 Column: c
328.4 Line No.: 14 Column: d ff
betwe,en various ies and ints
328.4 Line No.:14 Column: m
FERC FORM NO.1 (ED. 12-871 Page 450.24
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Scheduling, system control and dispatch service. Reactive supply and voltage control
servi-ce.
ootnote es to all occurrences of "Sacramento pal Ut I tyD st" on pages
328.4 Line No.:15 Column: b
328-330.
nt-to
ete name is Sacramento Munic urilir District
tt ss on se ce under the Open Access SS on Ta ff (se ce
328.4 Line No.: 15 Column: d
t 853 terminat on ,June 30 zu zz
system control and spatch serv ce. Reac .ve supply and voltage control
serv]-ce
328.4 Line No.:15 Column: m
328.4 Line No.:16 Column: dnt-to ntt SS on serv ce under the Open Access on ff (Se cet 853 terminati on .Tune 30, 2022
2017 ss on and anc 1lary serv ces. 2017 annual transmission services true-up
328.4 Line No.: 16 Column: m
refunds or surc
PO nt - to-nt SS on serv ce under the Open Access on ff (se CC
328.4 Line No.: 17 Column: d
r 809 t.erminati on October 31-, 2020
D9, syst.em contro1 and spatch serv Reactive supply and voltage control
serv]-ce
328.4 Line No.: 17 Column: m
328.4 Line No.:18 Column: d
Po .t-to-nt tr SS on serv ce under the Open Access Transmission Tariff (Service
t 809 terminati on October 31 2020
2017 transm on anc ary serv ces. 2017 annuaf tr ons ces true-uprefundsors
Various s tor es to Vo ume 11 nt - to-nt Tr ss on Tar ff
Var SS tor es to VO ume 11 nt-to-nt Tr on Tar ff
Non-or short-term f transm on serv under the Open Access Transmission Tariff
328.4 Line No.:18 Column: m
328.4 Line No.:19 Column: b
328.4 Line No.:19 Column: c
328.4 Line No.:19 Column: d
328.4 Line No; 19 Column: m
S
between various ies and ints
, system control and d patch serv React ve supply and voltage control
serv]-ce
Var tor to the Volume 11 Po t-to-Po Transm Tar ff
Va s Lor s to the Volume l-1 Point-to-Point Transmission Tariff
Non- f rm or short-t.erm firm transmission service r the Open Access SS on Tar
between various ies and ints
201-7 annual t services true-refunds
t-to-Point Transmission Service under Open Access Tran ss Tar 9 RevServicereement 289) which terminat.ed on October l-l-201,4 .
2017 annual transmission services true-or sur
tt r
328.4 Line No.: 20 Column: b
328.4 Line No; 20 Column: c
328.4 Line No.:20 Column: d
328.4 Line No.:20 Column: m
or
328.4 Line No.:21 Column: d
328.4 Line No.:21 Column: m
328.4 Line No.:22 Column: dPoint-t SS se ce
re
Open Access SS Tar ff (9th Rev
FERC FORM NO.1 (ED. 12471 Page 450.25
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.4 Line No.:23 Column: d
Serv:Lce L 797) terminati written notification
Po -to-po t ss on serv ce Open Access Trans on Tar ff (9rh sed
Serv:Lce t 79L terminat written notification
Va ee to estot ume 11 nt-to-nL Transm SS on Tar ff
VA SS tories to the Volume 11 nt-to-Point Transmission Tarif f .
Non-firm or rt-term firm transmission servi-ce under Open Access ss td
betwoen various es and ts
Sche<lu1ing,
serv:-ce.system control and dispatch service.ves I vo tage contro
Various s to es to the Volume Ll- Point-to-nt on Tar
Var SS to esEot ume 11 nt-to-nt Tr on Tar ff
Non-l:or short-term f rmt ss ons ce under the Open Access Transmission Tariff
between various es and ts.
2017 transmission and anc 11ary se ces. 2017 annual transmission services true-up
ref urrds or surc
Var s1 .tories to the Volume 11 t-to-Point Transmission Tarif f
Various s to es to the Volume 11 Point-to-Point SS on Tar
Non-or short-term rmL ss ons ce Open Access ss Tar ff
betwe:en various ies and ts.
Transm on resale -t-to t ss on. Schedul Dg, system controland dispatch service. Reactive supply and voltage control service. ceneration regulation
and re e servlce.
Var c)us es to ume 11 t-to-nt SS on
Var ous es to the ume 11 t-to-nt SS on ff
Non- f rm or short-term f rmt SS se ce under the Open Access Transmission Tariff
betwe:en various arties and
20]-7 ss and anc SE ces
Th footnote applies to all occurrences of "S erra f c Power Companyrr on pages
328-330. Sierra Pacific Power Company is a who11y owned subsidiary of rW Energy, fnc
which. is an indirect who11y owned subsidiary of Berkshire Hathaway Energy Company,
Pacatr-'s indirect
t on ma tenance or ac l_lease s ces w no rec or o
a.t ma tenance or ac ease s ces no rec or
FERC FORM NO.1 (ED. 12.871 Page 450.26
328.4 Line No.:24 Column: d
328.4 Line No.:24 Column: b
328.4 Line No.:24 Column: c
328.4 Line No.:24 Column: m
328.4 Line No.: 25 Column: b
328.4 Line No.: 25 Column: c
328.4 Line No.: 25 Column: d
328.4 Line No.:25 Column: m
328.4 Line No.: 26 Column: b
328.4 Line No.:26 Column: c
328.4 Line No;26 Column: d
328.4 Line No.:26 Column: m
328.4 Line No.:27 Column: b
328.4 Line No.:27 Column: c
328.4 Line No.: 27 Column: d
328.4 Line No.:27 Column: m
328.4 Line No.:28 Column: a
328.4 Line No.:28 Column: b
328.4 Line No.:28 Column: c
328.4 Line No.: 28 Column: d
Legacy contract (Rate Schedule 674 executed between f Corp and erra Pac
o
f c Power
Name of Respondent
PacifiCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)n
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.4 Line No.:28 Column: m
Company for transmission service over agreed-upon facilit.ies and,/or subject to a sole-useor facili-ties . Terminat ans ember 2022.
Charge for transmission service over agreed-upon ac ties and/or subject to a sole-useor facilities
tion maintenance or facil t lease s ces no rece or delive of ene
t on tenance or E ease serv ces w t no rece or ve o ene
Legacy contract Rate Schedule 574 executed between Pac f Corp and S erra Pac f c Power
Company for transmission service over agreed-upon facilities and/or subject to a sole-useor facilit.ies c Terminati 1n 2022
201,7 ss on anc serv
Var ous s tor es to the Volume 11 Po nt - to-nt ss on ff
Var ous s tor es to the Volume 11 Point-to-Point Transmission Tariff
Non-firm or short-term firm transmission serv Open Access Transmission Tariff
between various ies and ints
2017 annual transmission servi-ces true-u ref
Anc serv ces AcceSS SS on Tar
Generat on t re serv
Anc serv r Access Transm SS Tar
Generat t re se serv
rat ma ce or fac 1 t lease ces th no rece or del-of
erat ma or fac 1 Iease se ces with no recei or deI of
Use of fac 1 t es agireement (Rate Schedule 298) for transmission service over agreed-uponfacilities and/or subject to a sole-use or facilities charge (phase shifting transformersat Sigurd-Glen Canyon 23OkV transmission line and Pinto-Four Corners 34SkV transmissionline)terminat Feb 1,2 2020.
rt SS se ce over agreed-upon fac 1 t S or ect to a sole-useor facilities
ous s es to ume 11 Po t-to-Po Tr SS Tar ff
OUS S es to the Volume 11 t-to-Po ssion Tar ff.
Non- f rm or short-term f rmt SS on service under the Open Access Transmission Tariff
between various ies and nts
Unaut zed use of t SS ons ce. Scheduling, system control and dispatch service.Reactive supply and voltage control service. Generation regulation and frequency responseservice. Operating reserve - spinning reserve service. Operatingi reserve - supplemental
FERC FORM NO. I D.1 450.27
328.4 Line No.:29 Column: b
328.4 Line No;29 Column: c
328.4 Line No.:29 Column: d
328.4 Line No.:29 Column: m
328.4 Line No.:30 Column: b
328.4 Line No.: 30 Column: c
328.4 Line No.: 30 Column: d
328.4 Line No.:30 Column: m ors
328.4 Line No.:31 Column: d
328.4 Line No.:31 Column: m
328.4 Line No.:32 Column: d
328.4 Line No.:32 Column: m
328.4 Line No.:33 Column: b
328.4 Line No.: 33 Column: c
328.4 Line No.:33 Column: d
328.4 Line No.:33 Column: m
328.4 Line No.:34 Column: b
328.4 Line No.: 34 Column: c
328.4 Line No.: 34 Column: d
328.4 Line No.:34 Column: m
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
resel:ve servlce.
Var
Var S
.Eo estot ume 11 Point-to-nt
tories to the ume 11 Po t-to-nt
Non-firm or rt-term f rm on serv
on Tariff.
on Tar
ce under the Open Access Tr ss ff
328.5 Line No.: 1 Column: b
328.5 Line No.: 1 Column: c
328.5 Line No.: 1 Column: d
beEween various
2047
es and nts
and ancillary serv ces. 201-7 annual on ces true-up328.5 Line No.: 1 Column: m
328.5 Line No.: 2 Column: c
SSorref r.Lrrds
ootnote es to all occurrences of 'rsouthern California Pubfic Power" on pages
328-330.lete name is Southern California Public Power Authorit
Sma Generat.or Interconnection Agreement (Service Agreement 629) executed between
PacifiCorp and Southern California Public Power euthority terminating on November 30, 20L9or such other longer period as the Interconnection Customer may request and shal1 be
automatically renewed for each successive one-year period thereafter, unless terminatedearlier based on terms Ii-sted in the contract.
Unauthori-zed use of tr ss on serv , system contro spat se
Reactive supply and voltage control service. Generation regulaEion and frequency response
servj"ce. operat.ing reserve - spinning reserve service. operating reserve - supplemental
reserve service.
l- Generator fnLerconnect Agreement Serv Agreement 529 execut tween
PacifiCorp and Southern California Public Power Authority terminating on November 30, 20L9or snch other longer period as Ehe Interconnection Customer may request and shaLl beautomatically renewed for each successive one-year period thereafter, unless terminatedearlier based on terms listed in the contract.
Unauthori use o transm serv
328.5 Line No.:2 Column: d
328.5 Line No.:2 Column: m
328.5 Line No.: 3 Column: d
328.5 Line No.: 3 Column: m
328.5 Line No.:4 Column: dt-to-po t tran ion service under the Open Access Transm 10n ff (s CC
ement 779 terminat on
system conLro
31 , 201,9
spatch service. React ve supp y and voltage controlSc
servl.ce.
328.5 Line No.:4 Column: m
328.5 Line No; 5 Column: dt-to-po t tran cc serv r Open Access Tran SS Tariff (Service
328.5 Line No.: 5 Column: m
ement 779 terminat on 31 20]-9
20]-7 L SS on anc 11ary services. 2017 annual transmissi-on services true-up
refunds or surcha
c)us s tor s to the Volume 11 Po -to-Point Tariff
Var OUS S tor sto Volume 11 Point-to-Point Transmission Tariff
Non-rm or short-term rmt ss se
betweren various ies and ints.
Eran SS SE ces true-
328.5 Line No.: 6 Column: b
328.5 Line No.: 6 Column: c
328.5 Line No.: 6 Column: d
328.5 Line No.: 6 Column: m
328.5 Line No.:7 b
201,7 re
ce Open Access Transmission Tariff
FERC;FORM NO.1 (ED. 12.871 Page 450.28
Name of Respondent
PacifiCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.5 Line No.:7 Column: c
328.5 Line No.:7 Column: d
Various si tories to the Volume 11 Point-to-Point Transmission Tariff
ous s]-tories to the Volume 1l- Point-to-Point Transmission ff.
Non-firm or short-term rm SS ons L Open Access SS on
between various es and nts.
Scheduling,
service.system contro spatc serv ce. React ves v tage cont
Various tor es to ume 11 t-to-nt ss on ff
Var OUS S tor es to the Volume 11 nt-to-nt SS on Tar ff
Non- f rm or short-term f transm on service under the Open Access Transmission Tariff
between various ies and ints
2017 annual transm ss services true-refunds ors
Var ous tories to t.he Volume 11 Point-to-nt on Tar
Various s tor sto Vo ume 11 nt.-to-nt Trans cc on Tar
Non-or -term rm transm on serv ce under the Open Access Trans cc on ff
between various ies and ints
Scheduling,service.system contro spa serv ce. React ve supp v vo tage cont
Var SS tories to the Vo ume l-1 nt-to-nt Transm SS Tar
Various s tor es to Vo ume 11 Po nt-to-Po nt Transm Tar
Non-or rt - term rm tran SS serv ce under the Open Access Tr ss on Tar ff
between various rties and ints
S , system contro spatch serv ce. React ve supply and voltage controlservlce.
Var to es to Vo ume 11 Po -to-Po Transm QA Tar ff
Va SS to es to the Volume 11 Po -to-Po t Tran ssion Tar ff
Non-rm or short.-term f rmt service under the Open Access Transmission Tariff
between various arties and ints.
201,7 L SS
or
and anc 11ary se ces 2017 annual transmission services true-uprefunds
ous s I es to the Volume 11 Po -to-Po Tar ff.
t-t tt ssion service under the Open Access Transmission tariff (3rd Rev
Service ement 558 ) Lermj-nat on ri1 30 , 2029.
S tem control and tch service. Reactive supply and voltage cont.rol
328.5 Line No.:7 Column: m
328.5 Line No.: 8 Column: b
328.5 Line No.: I Column: c
328.5 Line No.: I Column: d
328.5 Line No.:8 Column: m
328.5 Line No;9 Column: b
328.5 Line No.:9 Column: c
328.5 Line No;9 Column: d
328.5 Line No.:9 Column: m
328.5 Line No.: 10 Column: b
328.5 Line No.: 10 Column: c
328.5 Line No; 10 Column: d
328.5 Line No.:10 Column: m
328.5 Line No.: 11 Column: b
328.5 Line No.: 11 Column: c
328.5 Line No.: 11 Column: d
328.5 Line No.: 11 Column: m
328.5 Line No.: 12 Column: c
328.5 Line No.:12 Column: d
328.5 Line No.:12 Column: m
FERC FORM NO.1 D.1 450.29
Name of Respondent
Pacif Corp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
201AA4
FOOTNOTE DATA
service. Generation regulation and freguency response service. Operating reserve -reserve servlce r.i reserve -emental reserve service.
Var ous s to es Eo Volume 11 Point-to-nt on Tar
nt-to t on serv ce under the Open Access Tr SS TA ff (3rd sed
328.5 Line No; 13 Column: c
328.5 Line No.:13 Column: d
328.5 Line No.: 13 Column: m
Service 558) terminati on i] 30 2029
2017 transmission and 11ary serv ces. 2017 annual Eransmrefunds and/or
Var ous sr_tories to the Volume 11 nt-to-nt ss on Tar ff.
Various si to es to the Vofume 11 Point-to-Point Transmission Tariff.
Non-rm or short,-term rm trans ss ons Open Access
on ces true-up
SS
328.5 Line No.: 14 Column: b
328.5 Line No.: 14 Column: c
328.5 Line No.: 14 Column: d
between various es and nts
Dg, system con spatc ce .ve supp v vo tage contro
servt ce
Var ous to es to ume 11 nt-to-nt
to es to the Volume 1l-nt-to-
Non-firm or rt-Lerm firm
nt on Tar ff.
on service under the Open Access Transmission Tariff
on Tar
Var ous
328.5 Line No.:14 Column: m
328.5 Line No.: 15 Column: b
328.5 Line No.:15 Column: c
328.5 Line No.:15 Column: d
between various
201,7
ref urrds
es and nts
and ancillary services. 201-7 annual t.ransmission services t.rue-upor surc
Var ous s to es to the Volume 11 Point-to-Point Trans SS on Tar f
Var oUS S to es to ume l-l-nt-to-nt Trans on Tar
Non- l:rm or short-term f rm trans ss ons ce under the Open Access Tr SS ff
328.5 Line No.: 15 Column: m
328.5 Line No.:16 Column: b
328.5 Line No.: 16 Column: c
328.5 Line No.: 16 Column: d
between vari-ous
Scheclul
servi-ce
es and nts
D9, system control- and spatch s ce. Reac ve supply and voltage control328.5 Line No.:16 Column: m
328.5 Line No.:17 Column: as footnote applies to all occurrences of -State Genera on and T rr on
Inc.328-330 ete name is Tri-State ceneration and Transmission Association
Var ous s to es to ume 11 nt-to-nt SS on Tar
s footnote appl es to all occurrences of rl -State Gen and Transrr on pages 328-330.
328.5 Line No.:17 Column: b
328.5 Line No.:17 Column: c
l-ete name is Tri-state Generation and Transmission Association Inc.
Network
Service
on serv ce ss Tar ff 7rh sed
L 628 terminati on ilune 30 202L
Sche<1ul-fl7, system control spa serv ce ve supp VO tage contservice. Regulation and frequency response service. Operating reserve - spinning reserveservj-ce. operat,ing reserve - supplemental reserve service.
FERC FORM NO.1 (ED. 12-871 Page 450.30
the Open Access
328.5 Line No.: 17 Column: d
328.5 Line No.: 17 Column: m
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.5 Line No.: 18 Column: h
328.5 Line No.: 18 Column: d
ous s t es to VO ume 1l- Po -to-Po t ss on
Network t ec on se ce under the Open Access SS on ff (7rh sed
Service ement 528) terminat on ,June 30 2021,
201,7 t-SS on and anc 11ary se ces. 2017 annual on se ces true-uprefundsor surc
Var ous s tor es to the Volume 11 Po t-to-Point Transmission Tarif f .
Various si tories to the Volume 11 Point-to-Point Transmission Tariff.
Non-rmors -term rmt SS on serv ce Open Access
between various es and nts.
ng, system con spatc serv ce. React ve s'v tage cont
serv]-ce
Var ous s tor to ume 11 nt-to-nt Transm SS on Tar
Var ous s tor sto ume 11 nt-to-nt Transm Tar ff
Non- f or short-term f on serv ce under the Open Access on ff
between various ies and nts
2017 annua tran SS serv ces true-re or
Var SS tor s to the Volume 11 nt-to-Po nt Tran ss Tar ff
Var ss tor es to the Volume l-1 Po nt-to-Po nt Transmiss Tari f f
Non-f rm or short-term firm transmission service under the Open Access Transmission Tariff
between various ies and ints
2017 annual t serv s true-u refunds or surcha
Network t ssion service and distribution delivery service under the Open AccessTransmission Tariff (2nd Revised Service agreement 506) terminating upon writtennotification.
D st on voltage service charge. Primary delivery servj-ce. Scheduling, system control
and dispatch servj-ce. Reactive supply and voltage control service. Regulation and
frequency response service. Operating reserve - spinning reserve service. Operatingreserve -emental reserve servi-ce
Ne t ss on se ce str very se ce r Open Access
Transmission Tariff (2nd Revised Service Agreement 506) terminating upon writtennotif icati-on.
2017 transmission and ancillary services. 201_7 SS on se ces true-uprefunds and/or s
This footnote applies to all occurrences of "r Bas
FERC FORM NO.1 (ED. 12-871 Page 450.31
328.5 Line No; 18 Column: m
328.5 Line No.: 19 Column: b
328.5 Line No.: 19 Column: c
328.5 Line No.: 19 Column: d
328.5 Line No.: 19 Column: m
328.5 Line No.:20 Column: b
328.5 Line No.:20 Column: c
328.5 Line No.:20 Column: d
328.5 Line No.:20 Column: m
328.5 Line No.: 21 Column: b
328.5 Line No.: 21 Column: c
328.5 Line No.:21 Column: d
328.5 Line No.:21 Column: m
328.5 Line No.:22 Column: d
328.5 Line No.:22 Column: m
328.5 Line No.:23 Column: d
328.5 Line No.: 23 Column: m
328.5 Line No.:24 Column: c
Complete name is Weber Basin Water Conservancy District n Water Conserv.rr on pages 328-330.
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.5 Line No.:24 Column: m
328.5 Line No.:25 Column: d
Schedule Page: 328.5 Line No.:24 Column: d
Leg€rcy contracL (3rd Rate 286 exe tween Pac CorpStates Department of the Interior, Bureau of Reclamation Weber Basin Water ConservancyDist:rict. for transmission service over agreed-upon facilities and/or subject to a sole-useor facilities charge for energy deliveries at and below 138kv. Agreement terminates any
time after 11 2040, with four s written notification.
Ene on for deliveries at and below 138kV
Legacy contract (3rd Rate 286 execute fween Corp Un
StaLes Depart.ment of the Interior, Bureau of Reclamation Weber Basin Water ConservancyDist::ict for transmission service over agreed-upon facilities and/or subject to a sole-useor facilities charge for energy deliveries at and below 138kv. Agreement terminates any
time after iI L 2040, wit.h four rs written notification
20L'l Lransmission and anc 1Ia se ces.
Legacy contract 3 Amended Rate Schedule 67) executed between PacifiCorp and Un ted
States Department of the fnterior, Bureau of Reclamation Crooked River Irrigation Districtfor Lransmission service over agreed-upon facilities and/or subject to a sole-use orfaci.-Lities c ement terminates wit.h one ar written notice
This; footnote app es to alf occurrences of "Utah Associated lutunicipal Power" on pages
328-330.ete name is Utah Associated Munic af Power tems
Legacy contract executed between Pac f Corp and Utah Assoc ated 1 Power Systemsfor transmission service over ag'reed-upon facilities (4th Amended and Restated
Transimission Service and Operating Agreement, 4th Revised Rate Schedule 297) . Agreementect to termination mutual reement and acement ts are in effecE.
st tion voftage se ce charge. S , system con serv
Reactive supply and voltage control service. Generation regulation and frequency responseservice. Operating reserve - spinning reserve service. Operating reserve - supplementaf
reserve service.
Legacy contract execute etween Pac Corp Ut Ass a pa Power Systemsfor transmission service over agreed-upon facilities (ath Amended and Restated
Transmission Service and operating Agreement, 4th Revised Rat.e Schedule 297). Agreementect to termination mutual ement and acement s are in effect
201,7 t-SSor ancillary services. 2017 annual transmission services true-up
ref uLrrds surc
ous g tor es to the Volume l-1 t-to-nt on Tar ff
Var ous s es to Volume 11 Point-to-Point Transmission Tariff .
Non-rm or short-term rm transmission service under the open Access Transmission Tariff
betwelen various arties and TS
tr9, system con and dispatch service. Reactive supply and voltage controlservice. Generation ation and f serv]-ce
.to es to Volume 1l- Point-to-Point Transmission Tariff .
FERG FORM NO.1 (ED. 12471 Page 450.32
328.5 Line No;25 Column: m
328.5 Line No.: 26 Column: d
328.5 Line No,:27 Column: b
328.5 Line No.:27 Column: d
328.5 Line No.:27 Column: m
328.5 Line No.: 28 Column: d
328.5 Line No.:28 Column: m
328.5 Line No.:29 Column: b
328.5 Line No.:29 Column: c
328.5 Line No.:29 Column: d
328.5 Line No.:29 Column: m
328.5 Line No.:30 Column: b
328.5 Line No.: 30 Column: c
Var C)US
Name of Respondent
PacifiCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.5 Line No.:30 Column: d
Various s tories to the Volume lL Point-to-Point Transmission Tariff
Non-rm or rt - term rm transmissi-on service under the Open Access Transmiss Tar ff
between various arties and ints.
201,7 t SS anc servlces.
ous s es to ume 11 t-to-nt SS on
ous s to es to the Volume 11 t-to-nt SS on f
Non-firm or short-term firm transmission service under the Open Access on ff
between various ies and TS
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.
Legacy contract (5th Revised Rate Schedule 637) executed between Pac f Corp and UtahMunicipal Power Agency for transmission service over agreed-upon facilities (Amended and
Restated Transmission Service and Operating Agreement) . Subject to termination upon mutualt and acement ts are in effect.
Schedul [9, system control and spatch serv ce. React ve supply tage contservice. Regulation and frequency response service. Operating reserve spinning reserve
servlce ri reserve - s lemental reserve service.
Legacy contract (5th Revised Rate Schedule 537) executed between Pacj-fiCorp and UtahMunicipal Power Agency for transmission service over agreed-upon facilities (Amended and
Restated Transmission Service and Operating Agreement) . Subject Lo termination upon mutualt and lacement ts are in effect.
201-7 transm GE and anc 11ary s. 201-7 annual tran SS serv ces true-uprefunds and or
s footnote appl s to all occurrences of xPGEtr on pages 328-330. Comp name
Portland General Electric
Legacy contract Rate S 591 execut etween Pac Corp Warm Spr s Power
Enterprises for transmission service over agreed-upon facilities and/or subject to
sole-use or facilities cha . Terminat On ,f 31 2032.
Charge r transmission service over agreed-upon ac1 ties and/or subject to a sole-useor facilities charge based on a capacity factor andfor proportional use as defined in the
contract.
Schedule Pase: 328.6 Line No.: 1 Column: d
Legacy contract (Rate Schedule 591) executed between PacifiCorp and Warm Springs Power
Enterprises for transmission servj-ce over agreed-upon facilities and/or subject tosole-use or facilities Terminat on 31, 2032
20L7 L on and anc 11 SE ces
Vari-ous si tories to the Volume 11 Point-to-Point Transmission tariff.
tories to the Volume 1l- Point-to-
FERC FORM NO.1 1 450.33
328.5 Line No.:30 Column: m
328.5 Line No.: 31 Column: b
328.5 Line No.: 31 Column: c
328.5 Line No.: 31 Column: d
328.5 Line No.:31 Column: m
328.5 Line No.:32 Column: d
328.5 Line No.:32 Column: m
328.5 Line No.: 33 Column: d
328.5 Line No.: 33 Column: m
328.5 Line No.:34 Column: c
328.5 Line No.:34 Column: d
328.5 Line No.:34 Column: m
328.6 Line No.:1 Column: m
328.6 Line No.:2 Column: b
328.6 Line No.:2 Column: c
328.6 Line No.: 2 Column: d
Various s nt ss on f
r7)
Nanre of Respondent
PacifiCorp
This Report is:
(1)XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.6 Line No.: 2 Column: m
Non-.Eirm or short-term firm transmission service under the Open Access Transmission Tariff
between various rties and ints
Scheduling, system control and d spatch se ce. React ve supply and voltage control
ser\/.Lce .
Var:Lr>us Western Area Power strat customers Pac f Co 's control area
Legar:y contract Rate Schedule 262) executed between PacifiCorp and western Area Power
Admi:ristratj-on for transmission and interconnection service over agreed-upon facilities
andT/or subject to a sole-use or faciliti-es charge for load service to preferenti-aI
customers for deliveries of Coforado River Storage Project power and energy. Agreement
terrn:lnates three rs after written notice and mutual consent
F xe<1 termination fee assoc ted th a contract. cancellat on appl ed for the durat othist
Vari-r>us Western Area Power strat on customers n Pac f 's controf area
Leg.rcy contracL Rate Schedul-e 262) executed between PacifiCorp and western Area Power
Admir:.istration for transmission and interconnection service over agreed-upon facilities
andT'or subject to a sole-use or facilities charge for load service to preferential
customers for delj-veries of Colorado River Storage Project power and energy. Agreement
term:Lnates three rs after written notice and mutual consent
201:r transmission and anc 1 SE ces.
Vari.ous Western Area Power strat on customers n Pac f 's controf area
LegErcy contract Rate Schedule 263) executed between PacifiCorp and Western Area Power
Administration for transmission and interconnection service over agreed-upon facilities
andT'or subject to a sole-use or facilities charge for load service to 1ow voltage
customers for deliveries of power and energy from Salt Lake City Area Integrated Projects,
incl.uding the Colorado River Storage Projects, to certain municipalities at service below
1 3 8 lr:\/t termination three after written notice and mutual consent
for Iow-volt L SS on
Various WesLern Area Power strat on customers n 's control areaf
Legelcy contract Rate Schedule 253) executed between PacifiCorp and Western Area Power
Admj.rristration for transmission and interconnection service over agreed-upon facilitiesandlor subject to a sole-use or facilities charge for load service to 1ow voltage
cust.omers for deliveries of power and energy from Salt Lake City Area Integrated Projects,
incl.uding the Colorado River Storage Projects, to certain municipalities at service below
13 8k\r termination three after written notice and mutual consent.
201,7 ss and ancil1 se ces
Va SS es to the Volume 11 Point-to-Point Transmission tariff
Leger(:y contract (Rate e 584) executed between PacifiCorp and Western Area Power
Admj.rristration concerning the exchange of transmission servj-ces over agreed-uponfaci.l-ities. The contract terminates 50 years from execut.ion. See also page 332,
Transimission of electricity by others, in this Form No. 1.
328.6 Line No.:3 Column: c
328.6 Line No.:3 Column: d
328.6 Line No.:3 Column: m
328.6 Line No.:4 Column: c
328.6 Line No.:4 Column: d
328.6 Line No.:4 Column: m
328.6 Line No.: 5 Column: c
328.6 Line No; 5 Column: d
328.6 Line No.: 5 Column: m
328.6 Line No.: 6 Column: c
328.6 Line No.: 6 Column: d
328.6 Line No.:6 Column: m
328.6 Line No.:7 Column: c
328.6 Line No.:7 Column: d
FERC FORM NO.1 (ED. 12-871 Page 450.34
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
2018tQ4
FOOTNOTE DATA
328.6 Line No.:8 Column: d
328.6 Line No.:8 Column: m
Evergreen network t on service under the Open Access Transmission Tari 4
Revised Service reement 175).
D str voltage service charge. Prj-mary ivery se S 1ing, system contro
and di tch service. Reactive 1 and vol control service.
s footnote applies to all occurrences of "western Area Power an verrr on pages
328-330. Complete name is Western Area Power Administration Colorado River Storage
Pro ect.
Evergreen network t ssion service under the Open Access Transmission Tariff (4th
Revised Service ement 175)
20L7 t SS on and ancillary services. 201,7 annual transmission services true-uprefunds and/or
OUS S es to the Volume 11 Point-to-Point Transmission fariff.
Non-firm or short-term firm transmiss on se r Open Access SS Ta
between various arties and ts
Scheduling, system contservice.and spatc se ce. React ve supp v vo tage contro
Various si tories to the volume 11 t-to-Po t ss 1d
Non-firm or short-term firm transmiss on se ce r Open Access .J- <1
between various ies and TS
201-7 annual transmission services true-re
ete name is Western Area Power strat SS
Various si t estot ume 11 nt-to-P t ss on f f .
Non-rmors -term rm SS ons ce under the Open Access on ff
between various ies and nts
, system con spatch s ce. React ve supply and voltage control
serv]-ce
Represents t erence between actual wheel revenues for the period as reflected onthe individual line items within this schedule and the accruals credited to Account456.1-, Revenues from transmission of electricity for others, during the period.
FERC FORM NO.1 (ED. 12-871 Page 450.35
328.6 Line No.:9 Column: b
328.6 Line No.:9 Column: d
328.6 Line No.:9 Column: m
Schedule Page: 328.6 Line No.: 10 Column: c
onal-nr'
Schedule Page: 328.6 Line No.: 10 Column: d
328.6 Line No.:10 Column: m
328.6 Line No.:11 Column: c
328.6 Line No.:11 Column: d
or
Column: m
Column: a
328.6 Line No.: 11
328.6 Line No.: 12
328.6 Line No.:12 Column: c
328.6 Line No.: 12 Column: d
328.6 Line No.: 12 Column: m
328.6 Line No.: 13 Column: m
Date
PacifiCorp (1)
(2)
Original (Mo, Da,
Resubmission
Year/Period of Report
End of 20'l8lQ4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)(lncluding transactions refered to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, clualifying 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 conditions of the service as follows:
FNS - Firm lletwork Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term F:irm 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 statistical classifications.
4. Report in ,:olumn (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in i:olumn (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 (0 energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shovvn in column (g). Report 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-monetary settlement, including the amount and
type of energly or service rendered.
6. Enter "TOIAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line
No.Name of Company or Public
Authori\, (Footnote Affiliations)
(a)
Statistical
Classification
(b)
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Maoawatt-
h-oursReceived
(c)
Magawarr-
hOUTS
Delivered
(d)
uemanoCharoes($I
(e)
EnerovCharots($r
(0
charpes
(s)
Total Cost of
''.,nJfli"'on
1 Adams Siolar Center LLC -33,682 -33,682
2 Adams [iolar Center LLC -8,950
3 Adams liolar Center LLC -31,897
4 Arizona Public Service 17,667
E Arizona Public Service 225,569 225,569 1,069,94'l 1,069,941
6 Arizona Public Service NF 32,872 32,872 227,082 227,082
7 Arizona Public Service 1,638 1,639 700,703
8 Arizona Public Service SFP 68,003 68,003 850,309 850,309
o Ashland, C;ity of FNS 13,090 13,090 23,476 23,476
10 Avista Cr:rcoration FNS 274 848 219,077 219,077
11 Avista Corporation NF 3,846 3,846 36,534 36,534
12 Avista Corcoration SFP 21,726 21,726 1,1 10,295 1,1 10,295
'13 NF 1 58,518 1 58,51 8 1,725 1,725
14 Big Horn Fural Eleclric 164,875
15 Big Horn Fural Electric 1,1 16
16 Black Hilis Power, lnc.SFP 33,574 33,574 194,534 194,534
TOTAI..21,138,401 21,354,478 120,661,469 247,558 14,112,570 1 35,02 1,597
FERC FORM N(). 1/3-Q (REV. 02-04)Page 332
LFP
OS $,950
AD -31,897
AD 17,667
LFP
OS 700,703
Basin Ekrt. Poler Coop
OLF 164,875
AD 1,1 16
Name of
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(lncluding transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying 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 conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General 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), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. ln column (e) report the demand
charges and in column (0 energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. lf no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line
No.Name of Company or Public
Authority (Footnote Affi liations)
(a)
Statistical
Classification
(b)
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICIry BY OTHERS
Maoawatt-h'oursReceived
(c)
Magawall-
noursDelivered
(d)
Enerov
Charoi6s($I
(D
UINETCharoes($r
(q)
Total Cost of
Transmission($)
ft)
I Black Hills Power, lnc.NF 16,668 '16,668 16,668 16,668
2 Black Hills Power, lnc.OS 51,044 51,044
?Bonneville Power Admin AD 75,242 75,242
Bonneville Power Admin FNS 2,802 2,853 5,625,58'l 5,625,581
5 Bonneville Porer Admin LFP 5,1 15,731 5,209,59't 52,940,308 52,940,308
6 Bonneville Porer Admin NF 35,936 36,595 128,88'r 1 28,881
7 Bonneville Power Admin OLF 5,580,565 5,682,953 1 9,9 1 9,767 19,919,767
Bonneville Power Admin AC '17,1s6,699 17,156,699
9 Bonneville Power Admin SFP 270,270 275,229 1,270,795 1,270,795
10 CA lnd Sys Operator AD 35,593 35,593 -329,909 -329,909
11 CA lnd Sys Operator OS 2,169,654 2,169,654
12 CA lnd Sys Operator SFP 222,576 222,576
't3 Deseret Gen and Trans OS 1,676,000 1,676,000
14 Deseret Gen and Trans LFP 616,684 616,684 3,919,090 3,91 9,090
15 Deseret Gen and Trans NF 281,424 281,424 55,903 55,903
16 Elbe Solar Center, LLC LFP -168,771 168,771
TOTAL 21,138,401 21,3s4,478 1 20,661,469 247,558 14,112,570 1 35,021,597
FERC FORM NO. 1/3-Q (REV.02-04)Page 332.1
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5l1Rn original(2) [A Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(lncluding transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying 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 conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General lnstructions for definitions of statistical classifications.
4. Report in r:olumn (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in ,;olumn (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 (0 energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. lf no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line
No.Name of Company or Public
Authori$r (Footnote Affi liations)(a)
Statistical
Classification(b)
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Magawatt-hoursReceived
(c)
Magawa[-
noursDelivered
(d)
Enerov
Charo''ds($r
(f)
Total Cost of
Transffission
1 Elbe Solar Center, LLC 44,749
2 Elbe Solar Center, LLC -159,484
I SFP 27,160 27,160 17,690 17,690
4 EOG Resources, lnc.-1,676,000
A 98,108
6 Flahead Elecl Coop lnc 4,368
7 201,050
I ldaho Porrl'er Company FNS 1 1,941 11,941
9 ldaho Pouer Company 3,341,010 3,349,612 1 7,333,523 17,333,523
10 ldaho Povrer Company NF 1,064,144 1,064,144 235,458 235,4s8
11 ldaho Porer Company SFP 9,964 9,964 1,1 94,791 1,1 94,791
12 ldaho Poller Company 231,061 231,061 -3,347,325
'13 NF 1 1 4 4
14 LA Dept ofWater & Pwr SFP 50 50 424 424
15 LA Dept. of Water & Rrvr 43
16 FNS 16 '16 I 275,777
TOTAt.21,1 38,401 21,354,478 1 20,661,46S 247,558 14,112,570 135,021,597
FERC FORrrr NO.1/3-Q (REV.02-04)Page 332.2
os -M,749
AD -159,484
El Paso Co.
os -1,676,000
Flatheac Eilect Coop lnc OS 98,'108
AD 4,368
Hermiskrn Gen Co L.P.OS 201,050
LFP
os -3,347,325
LA Dept. cfWater & Pwr
OS 43
Moon Lake Elect. Assoc.275,777
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]nn originat(2\ ;lA Resubmission
Date of ReDort(Mo, Da, Yi)
tt
Year/Period of Report
End of 20181Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(lncluding transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying 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 conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General 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 (0 energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. lf no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line
No.Name of Company or Public
Authori$ (Footnote Affi liations)(a)
Statistical
Classification
(b)
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Magawatt-
hoursReceived
(c)
Magawa[-hours
Delivered
(d)
uemanoCharoes($I
(e)
Enerov
Charoi'ds($I
(D
9lnerCharoes($I
(s)
Total Cost of
Transffission
1 Morgan City Corporation AD 1,446 1,446
I Morgan City Corporation LFP 1,506 1,506
3 Nevada Porver Company AD -5,135 -5,135
4 Nevada Power Company NF 15,463 15,463 267,204 267,204
5 Nevada Power Company OS 46,481 46,481 178,452 178,452
6 Nevada Power Company SFP 260,640 260,640 1,236,250 1,236,250
7 NorthWestern Corp.NF 18,346 18,803 62,551 62,551
NorthWestem Corp.SFP 4,053 4,137 6,442 6,442
I NorthWestem Corp.0s 3,620 3,620
10 River Pwr Auth LFP 1 63,775 163,775 849,350 849,350
11 Platte River Pwr Auth NF 55,227 55,227 10 10
12 Platte River Pwr Auth SFP 25,481 25,481
13 Plate River Pwr Auth OS 20,619 20,619
14 Portand Gen. Electric LFP 1 03,954 103,954 75,360 75,360
15 Portland Gen. Electric 1,001 1,001
16 Portland Gen. Electric 4,442 7,331 7,331
TOTAL 21,138,401 21,354,478 120,661,469 247,558 14,112,570 '135,021,597
Page 332.3
OLF
OS
FERC FOR[',I NO. 1/3-Q (REV. 02-04)
PacifiCorp (1
(2)A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 2018/Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(lncluding transactions refened to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity prcivided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying 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 rf 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 conditions of the service as follows:
FNS - Firm lletwork Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term F:irm Transmission Service, SFP - Sho(-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General lnstructions for definitions of statistical classifications.
4. Report inr r:olumn (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in r:olumn (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 (0 energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shovvn in column (g). Report 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-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line
No.Name of Company or Public
Authori\r (Footnote Affi liations)
(a)
Statistical
Classification
(b)
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Maoawatt-
h-oursReceived
(c)
Maoawan-
h-ours
Delivered
(d)
EnerovCharoi6s($I
(f)
L'INETCharoes($I
(s)
fotal Gost of
rran?grjssion
(h)
1 Powerex 0orporation SFP -63,850
2 219,600 219,600 1,079,31 1 1,079,31 1
3 Public Service Co of CO NF 1 10,558 1 10,558 864 864
4 Public Service Co of CO 70
(Puget Sr:r nd Energy, lnc SFP 14,400 '14,400 29,600 29,600
b Salt River Project NF 1,550 1,550 2,865 2,865
7 Salt River Project 337
8 SFP 93,000 93,000 331,250 331,250
9 Siena Parific Power Co NF 1,530 1,530 9,088 9,088
10 Siena Paoilic Power Co 26,738
11 608
12 Surprise lhlley Electr.7,302
13 The Energy Authority SFP -127]04
14 SFP -63,132
15 219,600 219,600 1,084,031 1,084,031
16 Tri-State Gen and Trans NF 114,792 114,792 27,893 27,893
TOTAL 21,138,401 21.354,478 1 20,661,469 247,558 14,112,570 135,021,597
FERC FORM NO. r/3-Q (REV.02-04)Page 332.4
-63,850
co LFP
OS 70
os 337
Siena Pit(ific Powe, Co
OS 26,738
Electr.AD 608
OLF 7,302
-127,704
TransAlla Energy -63,132
and Trans LFP
PacifiCorp (1)
(2)
Original
Date of Report(Mo, Da, Yr)ttResubmission
Year/Period of Report
End of 20181Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(lncluding transactions referred to as "wheeling")
1. Repo( all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying 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 conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General 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), (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 transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. lf no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line
No.Name of Company or Public
Authority (Footnote Afliliations)
(a)
Statistical
Classification(b)
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Magawatt-hoursReceived
(c)
Magawa[-
hours
Delivered
(d)
uemanqCharoes($I
(e)
EnetovCharots($r
(D
\JINETCharoes($r
(s)
Iotal cost of
Transmission($)
(h)
1 Tri-State Gen and Trans SFP 1,068 1,068 3,608 3,608
2 Tri-State Gen and Trans 4,064
2 NF 100 100 8,639 8,639
4 Tucson Electric Pwr Co.SFP 6,059 6,059 4,939 4,939
5 Tucson Elec'tric Pwr Co.1,212
6 Western Area Power Admn FNS 684,692 684,692 5,957,39'l 5,957,39'l
7 Western Area Porver Admn 963,384 963,384 2,260,417 2,260,417
8 Western Area Porver Admn NF 698,004 698,004 852,507 852,507
I Western Area Polver Admn 79,859 79,859 804,276
10 Western Area Polver Admn -25,296
11 Western Area Power Admn SFP 74,077 74,077 308,550 308,5s0
12 WesQort Field Srv Llc -3,147,'109
13 Accrual -506,31 2
14
15
to
TOTAL 21,138,401 21,354,478 1 20,661,46!247,558 14,112,570 1 35,021,597
FERG FORM NO. 1/3-Q (REV. 02-04)Page 332.5
OS 4,064
Tucson Electric Pwr Co.
0s 1,212
LFP
os 804,216
AD -25,296
LFP -3,147,109
-506,31 2
Name of Respondent
PacifiCom
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
332 Line No.:1 b
Adams Solar Center LLC - contract e: October 30 2036.
332 Line No.:2 Column: b
Ancil1 servlces
Aric i- 11 serv
Sett ement ustmenE.
Sett-Lement ad ustment.
Sett-Lement ustment.
Set ement ustment.
Ar zona Publ cSe ce Company - contract te t on tes: ,January 11 , 204]-tethat all generating plants comprising PacifiCorp resources associated with this agreement
have been retired from service or interests transferred.
Ar zona cSe ce Company - Legacy contract execute tween Pac Corp Arizona
Public Service Company concerning the exchange of transmission services over agreed-uponfaci.Lities (Restated Transmission Service Agreement between PacifiCorp and Arizona Public
Serv:lce Company, Rate Schedule 436). The contract terminat.es October 31, 2020. See aLso
328-330 Transmission of electrici for others, in this Form No. 1
Ancil1 serv ces .
ete name S Bas E ctric Power rative Inc.
I{orn Rural Elect rr_c - contract. te t on te: March 10 2024
Use of facilities.
Sett-.Lement ustment.
Sett-ement ustment.
Anc :11 servlces.
Anc 11 servlces.
SetL.lement ,j ustments .
332 Line No.:2 Column:
332 Line No.:3 Column: b
332 Line No.:3 Column:
332 Line No.:4 Column: b
332 Line No.:4 Column:
332 Line No.:5 Column: b
332 Line No.:7 Column: b
332 Line No.:7 Column:
332 Line No.: 13 Column: a
332 Line No.: 14 Column: b
332 Line No.: 14 Column:
332.1 Line No.: 3 Column: b
332 Line No.: 15 Column: b
332 Line No.: 15 Column:
332.1 Line No.: 2 Column: b
332.1 Line No.: 2 Column:
Scheltile page: SgZ.t tiie No.: g Cotumn: g
Settlement ustment.
Bonnevill-e Povrer Administration - contract termi.na on dates: April 1, 20L8; ,Ju1y 1, 20:.8;
OctoJrer 1, 20L8; December 1, 201-8; January 1, 201-9; ,Iu1y 1, 20]-9; September 1, 201-9;
October 1, 2Ol9; Novedber 1, 201-9; November 1, 2020; iranuary 1, 202l. ; rfuly 1, 2O2A;
November L, 2021-; Decemlcer 1, 202L; ilanuary 1, 2022; March 1, 2022; April 1, 2022;,Ju1y 1,
2022; November 1, 2022; March 1, 2023;,Ju]y 1,2023; December 1, 2023; November 1, 2027;
November 1 2033 and eve en
Bonn13v e Power nistration - contract termination dates: December 31, 20L8; September
l
332.1 Line No.: 5 Column: b
332.1 Line No.:7 Column: b
30, :2027 ar:d evergreen
FERC FORM NO.1 (ED. 12-871 Page 450.1
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
20't8lQ4
FOOTNOTE DATA
332.1 Line No.:8 Column: be Power stra on - Legacy contract executed between Pac f Corp andBonneville Power Administration concerning the exchange of transmission services over
agreed-upon facilities (r'Midpoint-Meridian Transmission Agreement", Rate Schedule 359).This agreement runs concurrently with the AC Intertie Agreement (Rate Schedule 368), whichterminates when the facilities subject to that agreement are taken out of service. See
also 328-330 Transmission of electricit for others, in this Form No. 1
11 serv ces. Use of f 1 ties
s footnote applies to all occurrences of "CA I Sys Operator" on page 332. Complete
332.1 Line No.:8 Column:
332.1 Line No.: 10 Column: a
name is California I .t stem tor tion
332.1 Line No.:10 Column: b
332.1 Line No;10 Column:
Settlement ad ustment
Settlement ad ustment
serv ces
serv ces
footnote applies to all occurrences o rrDeseret Gen
AnC
Anc 1
lete name is Deseret Generation and Transmission Co-
ti-on and settlement of firm int-to-int transm on
on and settlement of firm int-to-i-nt transm
Deseret Generation and Transmj-ssion Co-operat ve - contract term t
2022
Elbe Solar Center, LLC - contract termination te:30 2036.
Trans" on page 332.tive.
t
te 1,
332.1 Line No.: 13 Column: a
332.1 Line No.: 11 Column: b
332.1 Line No.:11 Column:
332.1 Line No.: 13 Column: b
332.1 Line No.:13 Column:
332.1 Line No.:14 Column: b
332.1 Line No.: 16 Column: b
332.2 Line No.: 1 Column: b
332.2 Line No.: 1 Column:
Sett
Sett
Ancil servl-ces.
Ancil servlces.
ustment.
ustment.
lete name s Ef Paso Electric
Te and settlement of firm
Te ion and settlement rm
ete name c a ect
Use t es
-to-t
-to t GG st
332.2 Line No.: 5 Column: b
332.2 Line No.:2 Column: b
332.2 Line No.:2 Column:
332.2 Line No.: 3 Column: a
332.2 Line No.:4 Column: b
332.2 Line No.:4 Column:
332.2 Line No.: 5 Column: a
Settlement ustment
rat ve, Inc.
332.2 Line No.: 5 Column:
Use ac t CS
332.2 Line No.: 6 Column: b
FERG FORM NO. r (ED. 12-871 Page 450.2
Name of Respondent
Pacif Corp
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Schedule Page:332.2 Line No.: 6 Column: g
Sett-Lement ustment
ete name s Hermiston Generat L.P
ston Generat Company, L.P. operates Herm ton Generat ngP
332.2 Line No.:7 Column: a
332.2 Line No.:7 Column: b
oirit:L owned. Pacifi
Use <>f fac 1 t
Idahc> Power - contract
owns 50t of the ant
na on dates:1 1, 2025 and Ju1 1 ,notr
Anci.-t1 serv es. Credit for unreserved use
Anc t for unres use
s footnote appl es to occurrences of ttLA Dept. of Water & Pwr" on page 332.ete name is Los 1es t of Water and Power
:-1 servr_ces
:_1 servlces.
ete name Moon Lake El-ectri-c Association Inc.
Use ac t
Sett-.:-ement ad ustment
Settl-ement ad ustment
rat on - contract termination te
ootnote app es to occurrences ilN Power Company" on page 332.
Power: Company is a who11y owned subsidiary of Nv Energy, Inc., which is an indirect whoI1y
ownecl subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
Settl-ement ustment.
Sett.ement ustment.
Anc serv ces.
Anc serv ces.
Anc l-1 serv ces.
Anc 1,1 servlces.
This footnote app ies to all occurrences of "Platte River Pwr Auth" on page 332. Complete
332.2 Line No.:7 Column:
332.2 Line No.: 12 Column: b
332.2 Line No; 9 Column: b
332.2 Line No.: 12 Column:
332.2 Line No.: 13 Column: a
332.2 Line No.:15 Column: b
332.2 Line No.: 15 Column:
332.2 Line No.: 16 Column: a
332.2 Line No.: 16 Column:
332.3 Line No.: 1 Column: b
332.3 Line No.: 1 Column:
332.3 Line No.:2 Column: b
332.3 Line No.: 3 Column: a
332.3 Line No.:3 Column: b
332.3 Line No.:3 Column:
332.3 Line No.: 5 Column: b
332.3 Line No.:5 Column:
332.3 Line No.:9 Column: b
332.3 Line No.:9 Column:
332.3 Line No.: 10 Column: a
nam€r is Platte River Power Authori
332.3 Line No; 10 Column: bPlat.te River Power Autho ty - contract tion date: October 31, 2022.
FERC FORM NO.1 (ED. 12.871 Page 450.3
Name of Respondent
PacifiCorp
This Report is:
(1) XAn OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
FOOTNOTE DATA
332.3 Line No.:13 Column: b
332.3 Line No.: 13 Column:
11 serv s
Ancil serv]-ces
ootnote app stoa occurrences of "Portland Gen. Electric" on page 332. Complete
name is Portland ceneral Electric
Port Genera E ect contract tion date:ri1 t 2022
Port Genera Elect c Company - contract te t on e: Upon two years written
notice.
Use of fac 1 t
Anc 1 ces
Anci11 serv]-ces
Revenues rom s es on sec transmission market.
ootnote es to occurrences c Serv ce Co CO" on page 332.ete name is Public Service of Colorado.
cS ce Company o - contract t na on te:te tgenerating plants comprisi-ng PacifiCorp resources associated with this agreement have beenretired from service or interests transferred.
Schedule Pase:332.4 Line No.:4 Column: b
Anci1l serv]-ces
Anci11 serv].ces .
serv ces
Aric serv
Th footnote app s to all occurrences of "S ra Pac Power Co" on page 332. SPacific Power Company is a wholIy owned subsidiary of NV Energy, Inc., which is anindirect. whoI1y owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp'sindirectt
Anci servr_ces.
Anc SC
tnote es to occurrences o rrSurp eyE ectr." on page 332.lete name is se vaII Electrification
Sett ement ustment
ement ustment
Electr f ca on
FERC FORM NO. 1 (ED. 12-871 Page 450.4
332.3 Line No.: 14 Column: a
332.3 Line No.:14 Column: b
332.3 Line No.:15 Column: b
332.3 Line No.: 15 Column:
332.3 Line No.: 16 Column: b
332.3 Line No.:16 Column:
332.4 Line No.:1 Column:
332.4 Line No.: 2 Column: a
332.4 Line No.:2 Column: b
332.4 Line No.:4 Column:
332.4 Line No.:7 Column: b
332.4 Line No.:7 Column:
332.4 Line No.: I Column: a
332.4 Line No.:10 Column: b
332.4 Line No.: 10 Column:
332.4 Line No.: 11 Column: a
332.4 Line No.:11 Column: b
332.4 Line No.:11 Column:
332.4 Line No.: 12 Column: b
332.4 Line No.: 12 Column:
Sett
se VaI1 - conLract t nat on date
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
332.4 Line No.: 13 Column:
332.4 Line No.: 14 Column: a
332.4 Line No.:14 Column:
332.4 Line No.:15 Column: a
Use of facilities.
Revenues rom sa s on the sec tr market.
ete name s ta Ene Market (U.S.) Inc.
Revenues from sales on the sec t ss t
This footnote applies to all occurrences of I'-State Gen and Transr on page 332
C eLe name is Tri-State Generation and Transmission Association fnc
Tri-Sitate Generation and SS on Assoc o[, Inc. - contract term t te
date that all generating plants comprising PacifiCorp resources associated with thist have been retired from service or inEeresEs transferred
Ancil.l servlces
ces
s footnote appl es to occurrences of ttTucson Electric Pwr Co.tr on page 332. Theete name is Tucson Electric Power
ces
1.1 serv]-ces
Western Area Power Adm stra on - contract. t ermlna on date 31,2022.
West€:rn Area Power Administration - Legacy contract (Rate Schedul-e 584) executed beEween
Pacif:iCorp and Western Area Power Administration concerning the exchange of transmission
servj.ces over agreed-upon facilities. The contract terminates 50 years from execution. See
also 328-330, Transmission of electricit for others in this Form No. 1.
ancil.ces. Use of Fac I ES
Sett.t ustment
Sett.l,ement ad ustment
West.Field Serv ces, LLC - contract nat te 3 Eve
Reimbursement or third serv CES
Represents the difference between actua expenses r pe as re ect onthe individual line items within this schedule and the accruals charged to Account 555,
Transmission of electricity by others, during this period.
FERC FORM NO.1 (ED. 12-871 Page 450.5
332.4 Line No.: 15 Column: b
332.5 Line No.:2 Column: b
332.5 Line No.: 2 Column:
332.5 Line No.: 3 Column: a
332.5 Line No.: 5 Column: b
332.5 Line No.: 5 Column:
332.5 Line No.:7 Column: b
332.5 Line No.:9 Column: b
332.5 Line No.:9 Column:
332.5 Line No.: 10 Column: b
332.5 Line No.: 10 Column:
332.5 Line No.: 12 Column: b
332.5 Line No.: 12 Column:
332.5 Line No.: 13 Column:
Name of Respondent
PacifiCorp
This Benort ls:
(1) lx_.j An original
(2) n A Resubmission
Date of ReDort(Mo, Da, Yi)lt
Year/Period of Report
End of 20181Q4
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line
No.
Description
(a)
Amount
(b)
1 lndustry Association Dues 1 ,338,912
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist lnfo to Stkhldrs...expn servicing outstanding Securities
5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000
6
7 Business & Economic Development and
8 Corporate Memberships & Subscriptions
I Alliance for Transportation Electrifi cation 10,000
10 American Leadership Forum of Oregon 10,000
11 American \Mnd Wildlife lnstitute 25,000
12 Clatsop Economic Development Resources 6,000
13 Economic Development for Central Oregon 7,500
14 Greater Yakima Chamber of Commerce 5,000
't5 Klamath County Economic Development Association 6,000
16 Laramie Chamber of Business Alliance s,000
17 Ogden-Weber Chamber of Commerce 6,000
18 Oregon Business Council 33,777
19 Oregon Economic Development Association 13,500
20 Redmond Economic Development, lnc.7,000
21 Salt Lake Chamber 28,000
22 Sandy Area Chamber of Commerce 5,000
23 South Coast Development Council, lnc.5,000
24 Southern Oregon Regional Economic Development, lnc 5,700
25 Utah Clean Air Partnership UCAIR lnc.5,000
26 Utah Manufacturers Association 5,544
27 Utah Taxpayers Association 18,700
28 Utah Technology Council 8,400
29 Walla Walla Valley Chamber of Commerce 15,000
30 \Af oming Business Alliance 5,000
31 Yakima County Development Association 7,980
32 Other (lndividually < $5,000)156,506
33
34 Rating Agency and Trustee Fees:
35 The Bank of New York Mellon 129,475
36 Computershare Shareowner Services, LLC 17.733
37 Moody's lnveslors Service, lnc.112,990
38 Standard and Poor's Financial Services, LLC 20s,259
39 U.S. Bank National Association 16,085
40 Other (lndividually < $5,000)2,468
41
42 General:
43 Other 2,160
44
45
46 TOTAL 2,225,689
FERC FORM NO. I (ED. 12-94)Page 335
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]An orisinat(2) aA Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of 20181Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
(Except amortization of aquisition adjustments)
1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. ldentify 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 balances are obtained. lf average balances, state the
method of arreraging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). lf plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortalig curve
selected as rnost appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. lf
composite d,apreciation 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 year in addition to depreciation provided by application of reported rates, state at the
bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Line
No.Functional Classifi cation
(a)
DeDreciationExpense
(Account 403)
(b)
Deoreciation
Experise for Asset
Retirement Costs
(Accounl 403.'l)
(c)
Amortization of
Limited Term
Electric Plant
(Account 404)(d)
Amortization ofOther Electric
Plant (Acc 405)(e)
Total
(f)
1 lntangiblr: Plant 45,506,528
2 Steam Production Plant 439,095,633 439,095,633
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 36,103,407 309,776 36,413,183
5 Hydrau ir: Production PlanlPumped Storage
6 Other Pnlduction Plant 127,480,652 't27,480,652
7 Transmis,sion Plant 109,403,638 109,403,638
8 Distributi,cn Plant 154,815,630 154,815,630
I Regional Transmission and Market Operation
10 General Plant 41 ,562,941 1,067,4',14 42,630,355
11
12
Common Plant-Electric
TOTAL 46,883,7'18 955,345,619
B. Basis for Amortization Charges
The Amortization of Limited-Term Electric Plant is based on straighlline amortization over the life of the asset.
FERC FORM NO.1 (REV. 12-03)Page 336
45,506,528
L I
908,46't,90'lI
Name of Respondent
PacifiCorp (1)
(2\Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No.Account No.
(a)
uepreclaDte
Plant Base(ln Thousands)(b)
trsIrmaleo
Avg. Service
Life(c)
Salvage
€e,5;nt)
Appleo
Depr. rates(Percent)
(e)
MOnailry
Curve
'ffi"
AVerage
Remainino
Life(q)
12 HYDRAULIC PROD.
13
14 330.20 CA/OR 41 -5.16 1.00
15 330.40 CA/OR I -7.90 1.00
16 331.00 CA/OR 16,161 13.89 1.00
't7 332.00 CA/OR 39,464 12.99 1.00
18 333.00 CA/OR 18,17C 6.23 1.00
19 334.00 CA/OR 16,57C 7.',16 1.00
20 335.00 CA/OR 't82 3.40 1.00
21 336.00 CA/OR 2,753 8.94 1.00
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03)Page $7
Klamath River
Name of Respondent
PaciliCorp
This Report is:
(1)XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Line No.:1 Column: dustment to Pac Corp's formula rate under FERC Docket No. ER11-3643-000, AttachmentH-1, is as follows:
Functional Classif ication
(a)
Ref.Line No.
(Column)
Intangible PlantLess: Intangible mining plant(1)
Revised Intangible Plant
(1) :ro adjust PacifiCorp's formula rate, p€r FERC Docket No.of mining assets related to production p1ant.
1(d) $ 45 ,506,528
705
$ 45, 503, 823
FA15-4-000 for amortization
Depr:eciation expense assoc ted th transportat on pment.s generally charged tooperations and maintenance expense and construct.ion work in progress. During the year
endecl Decernlcer 31, 20a8, depreciation expense associated with transportation equipment. was
$L5 ,829 ,895 .
Y, Pac Corp reco the depreciation expense asset ret rement obligations aseither a regulatory asset or liability.
at rate s are for the Klamath hydroe ect c system's four mainstem
dams (.TC Boy1e, fron Gate, Copco No. l- and Copco No. 2) . For further discussion, refer to
Note 13 of Notes to Financial Statements, in this Form No. L.
FERC FORM NO.1 (ED. 12-871 Page 450.1
f
336 Line No.: 12 Column: b
336 Line No.: 12 Column: e
336 Line No.:13 Column: a
Amort. of Ltd.
Term Elec. PIt.(Acct 404 )(d)
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5l1Rn originat(2) f]A Resubmission
Date of Report(Mo, Da, Yr)lt
Year/Period of Report
End of 20181Q4
REGULATORY COMMISSION EXPENSES
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being
amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Line
No.
Descriplion
(Furnish name of regulatory commission or body the
docket or case number and a description of the case)
(a)
Assessed by
Reoulalorv
Corimissi5n
(b)
Expenses
of
Utility
(c)
Total
Exoense forCuirenl Year(b) + (c)
(d)
uelerredin Account
'182.3 alBeginning of Year
(e)
1 Utah Public Service Commission:
2 Annual Fee 6,284,858 6,284,858
3 Rate Cases and Proceedings 290,838 290,838
4
E Oregon Public Utility Commission:
6 Annual Fee 3,029,969 3,029,969
7 Rale Cases and Proceedings 659,081 659,081
8 Deferred lntervenor Funding Grants 535,508
I
10 \A!oming Public Service Commission:
11 Annual Fee 1,758,157 1,758,157
12 Rate Cases and Proceedings 178,591 178,591
13
14 Washington Utilities and Transportation
15 Commission
16 Annual Fee 659,957 659,957
17 Rate Cases and Proceedings 38,413 38,413
18
19 ldaho Public Utilities Commission:
20 Annual Fee 655,184 655,1 84
21 Rate Cases and Proceedings 13,964 '13,964
22 Deferred lntervenor Funding Grants 26,865
23
24 California Public Utilities Commission
25 Annual Fee 912 912
26 Rate Cases and Proceedings 765,542 765,542
27 Deferred lntervenor Funding Grants 41 ,0'19
28
29 California Environmental Protection Agency:
30 lndustry Compliance Fee 12',t,363 7,980 129,343
3'1
32 Multi-State:
33 Rate Cases and Proceedings 418,733 418,733
34 Other Regulatory 1,40',t,281 1,401 ,281
35
36 Federal Energy Regulatory Commission
37 Annual Fee 2,288,389 2,288,389
38 Annual Fee - Hydroelectric Plants 2,926,671 2,926,671
39 Transmission Rate Cases 325,635 325,635
40 Other Regulatory 658,843 658,843
41
42
43
44
45
46 TOTAL 17,725,464 4,758,901 22,484,36'.1 603,392
FERC FORM NO. r (ED. 12-96)Page 3S0
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]nn original(2) f]A Resubmission
Date of Report
(Mo, Da, Yr)lt
Year/Period of Report
End of 20181Q4
REGULATORY COMMISSION EXPENSES
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to
Account 182.3
(i)
Contra
Account
fi)
Amount
(k)
Defened inAccount 182.3
End of Yearo
Line
No.Department
(0
ACCOUNINo.(s)
AmounI
(h)
1
Electric 928 6,284,858 2
Electric 928 290,838 3
4
5
Electric 928 3,029,969 6
Electric 928 659,081 7
391,443 926,951 8
I
10
Electric 928 1,758,157 11
Electric 928 178,591 12
13
14
15
Electric 928 659,957 16
Electric 928 38,413 17
18
19
Electric 928 655,1 84 20
Electric 928 13,964 21
40,000 66,865 22
23
24
Electric 928 912 25
Electric 928 765,542 26
976 4'l ,995 27
28
29
Electric 928 129,U3 30
31
32
Electric 928 418,733 33
Electric 928 1,401 ,281 34
35
36
Electric 928 2,288,389 37
Electric 928 2,926,671 38
Electric 928 325,635 39
Electric 928 658,843 40
41
42
43
44
45
22AU,361 432,419 1,035,811 46
FERC FORM NO. r (ED. 12.96)Page 351
PacifiCorp (1)
(2)
Original Date of ReDorl(Mo, Da, Yi)
Resubmission
Year/Period of Report
End of 20181Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
1 . Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D & D)
project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(ldentify
recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, developmenl, and demonstration in Uniform System of Accounts).
2. lndicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, D & D Performed lnternally:
(1) Generation
a. hydroelectric
i. Recreation fish and wildlife
ii Other hydroelectric
b. Fossil-fuel steam
c. lnternal combustion or gas turbine
d. Nuclear
e. Unconventional generation
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 include items in excess of $50,000.)
(7) Total Cost lncuned
B. Electric, R, D & D Performed Extemally:
(1) Research Support to the electrical Research Council or the Electric
Power Research lnstitute
Line
No.
Classification
(a)
Description
(b)
1 A. Electric R, D & D Performed lnternally:
2 (3) Distribution
3
4 (6) Other
5
6 B. Electric R, D & D Performed Externally:
7 (1) Research Support Electric Power Research lnstitute
8 - Advancing Smart lnverter lntegration in Utah
I
10 (2) Research Support Edison Electric lnstitute
't1 - Avian Power Line lnteraction Committee
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
37
38
FERC FORM NO. r (ED.12-87)Page 352
WestSmarl Electric Vehicle Pro.iect
Utah Sustainable Transportation and Energy Plan
Name of Resp,ondent
PacifiCorp
This ReDort ls:(1) 5]Rn original(2\ fiA Resubmission
Date of ReDort(Mo, Da, Yi)Year/Period of Report
End of 20181Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
(2) Research Support to Edison Electric lnstitute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classify)
(5) Total Cost lncurred
3. lnclude in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $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 classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classiry 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,
listing Accounl '107, Conslruction Work in Progress, first. Show in column (0 the amounts related to the accounl charged in column (e)
5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research,
Development, and Demonstration Expenditures, Outstanding al the end of the year.
6. lf costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (fl with such amounts identified by "Est."
7. Report sep;arately research and related testing facilities operated by the respondenl.
Costs lncurrerd lnternally
Currenl \/ear
(c)
Costs lncurred Externally
Current Year
(d)
AMOUNTS CHARGED IN CURRENT YEAR Unamortized
Accumulation
(s)
Line
No.Account
(e)Amount
(D
1
5,663 908 5,663 2
3
322,676 1,417,466 107,908 1,740,142 4
5
6
7
250,000 908 250,00c I
I
10
13,613 4,420 18,033 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
FERC FORM NO.1 (ED. 12-87)Page 353
Name of Respondent
PacifiCorp
This Report is:
(1) XAn OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
201AA4
FOOTNOTE DATA
352 Line No.:2 Column: b
352 Line No.:4 Column: b
fn Dec r 20L6, Pac Corp was se ra 4 on grant rom U.S. Departmentof Energy to insta11, operate and collect data on plug-in electric vehicle chargingstations located on 1,500 miles of interstate across Utah, Idaho and Wyoming. A componentof this program related to research, development and demonstration activities is to manage
and design an electric grid to handle widespread electric vehicle charging reguirements incollaboration with the Universit of Utah.
The Ut Sust e Transportat and Energy Plan was s gned to ,w 201,6.
Utah legislation established a five-year pilot program to provide up to $10 million
annually of mandated funding for electric vehicle infrastructure and clean coal research,
and authorized funding at the Utah Public Service Commission's discretion for solar
development, utility-sca1e battery storage and other innovative technology, economic
devel t and air 1 initiatives.
Account 920,strat ve and general sa1 ES
Account 921", Office supplies and expensesAccount 930.2, Miscellaneous General Expenses
FERC FORM NO.1 (ED. 12.871 Page 450.1
352 Line No.: 11 Column: e
Name
PacifiCorp (1)
(2)Resubmission
Date of Reoort(Mo, Da, Yi)tt
Year/Period of Report
End of 20'l8lQ4
DISTRIBUTION OF SALARIES AND WAGES
Report belovv the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. ln determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Line
No.
Classification
(a)
Direct PavrollDistribution
(b)
Total
(d)
1 Electric
2 Operation
3 Produr:tion 95,054,780
4 Transm ssion 14,783,731
5 Regional Market
6 Distribution 34,091,180
7 Customer Accounts 38,573,572
I Customer Service and lnformalional 6,548,333
I Sales
10 Administrative and General 42,123,486
11 TOTAI- Operation (Enter Total of lines 3 thru 10)231,175,082
12 Maintenance
13 Produr:t on 46,706,822
14 Transmission 1 1 ,907,1 30
15 Regionerl Market
'16 Distribulion 59,591,171
17 Administrative and General 't,740,227
18 TOTAI- Maintenance (Total of lines 1 3 thru 17)119,945,350
'19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)141,761,602
21 Transmission (Enter Total of lines 4 and 14)26,690,861
22 Regione I Market (Enter Total of Lines 5 and 1 5)
23 Distribulion (Enter Total of lines 6 and 16)93,682,351
24 Custornr:r Accounts (Transcribe from line 7)38,573,572
25 Cuslomr:r Service and lnformational (Transcribe from line 8)6,548,333
26 Sales r.f ranscribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 1 7)43,863,713
28 TOTAI.- r3per. and Maint. (Total of lines 20 thru 27)351,120,432 351,120,432
29 Gas
30 Operalion
3'l Production-Manufactured Gas
32 Production-Nat. Gas (lncluding Expl. and Dev.)
33 Other G,as Supply
34 Storage LNG Terminaling and Processing
35 Transnrission
36 Distribulion
37 Custorner Accounts
38 Custorner Service and lnformational
39 Sales
40 Administrative and General
41 TOTAL t)peration (Enter Total of lines 31 thru 40)
42 Mainten;rnce
43 Production-Manufactured Gas
44 Production-Natural Gas (lncluding Exploration and Development)
45 Other Gas Supply
46 Slorage, LNG Terminaling and Processing
47 Transnlission
FERC FORM NO. r (ED. 12-88)Page 354
Name of Respondent
PacifiCorp
This
(1)
(2)
Reoort ls:
5]Rn originat
[--lA Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Line
No.
Classification
(a)
Direct PavrollDistribution
(b)
Total
(d)
48 Distribution
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (lncluding Expl. and Dev.) (Total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru 47)
56 Transmission (Lines 35 and 47)
57 Distribution (Lines 36 and 48)
58 Customer Accounts (Line 37)
59 Customer Service and lnformational (Line 38)
60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)
63 Other Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64)351,120,432 351,120,432
66 Utility Plant
67 Construction (By Utility Departments)
68 Electric Plant 162,409,945 162,409,945
69 Gas Planl
70 Other (provide details in footnote):
7',!TOTAL Construction (Total of lines 68 thru 70)162,409,945 162,409,945
72 Plant Removal (By Utility Departments)
73 Electric Plant 10,547,821 10,547,821
74 Gas Plant
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)10,547,821 10,547,821
77 Other Accounts (Specifo, provide details in footnote)
78 Fuel Stock 5,316,261 5,316,261
79 Miscellaneous Other lncome Deductions 485,975 485,975
80 Miscellaneous Non-Operating and Non-Utility 546,524 546,524
81 Charges to Affiliates 1,034,490 1,034,490
82
83
84
85
86
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts 7,383,250 7,383,250
96 TOTAL SALARIES AND WAGES 531,461,448 531 ,461,448
FERC FORM NO. 1 (ED. 12-88)Page 355
Name of Resp,6nds61
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for
Resale, for ilems shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for
purposes of dr:termining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining
\,vhether a net purchase or sale has occurred. ln each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and
separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line
No.
Description of ltem(s)
(a)
Balance at End of
Quarter 1
(b)
Balance at End of
Quarter 2
(c)
Balance at End of
Quarler 3
(d)
Balance at End of
Year
(e)
1 Energy
2 Net F'urchases (Account 555)( 61,870)( 60,555)'1,629,580 1,943,271
3 Net Sales (Account,{47)( 205,629)( 237.729\( 583,231)( 643,620)
4 Transmission Riqhts
5 Ancillary Services
6 Other ltems (list separately)
7 Energl, ;666;"nce Market (Account 555)( 6.425.782\12,383,299 ( 25.885,713)( 44.915,544)
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
44
45
46 TOTAL,( 6,693,281)12,085,015 ( 24,839,3M)( 63,615,893)
FERC FORM NO. 1/3.Q (NEW. 12-0s)Page 397
PacifiCorp (1)
(2)Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
ln columns for usage, report usage-related billing determinant and the unit of measure
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year,
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (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 gpes ancillary services 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 the Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant
Line
No
Type of Ancillary Service
(a)
Number of Units
(b)
Unit of
Measure
(c)
Dollars
(d)
Number of Units
(e)
Unit of
Measure
(D
Dollars
(s)
1 Scheduling, System Control and Dispatch 133,397,813 M\ /h 12,146,144
2 Reaclive Supply and Voltage 111,261.712 t\.4wh 7,325,300 125,946,125 MVVt'8,292,230
3 Regulation and Frequency Response 52,'136,625 MWh 35,145,321 68,297,939 M\/tr 35,852,98 1
4 Energy lmbalance 189,478 MVVh 46,495,236
5 Operating Reserve - Spinning 120,788,112 M\ /h 1 8,239,005 1 32,008,379 M\/tr 19,617,901
6 Operating Reserve - Supplement 120,788,112 M\h I 8,239,005 132,120,404 M\/t'19,029,503
7 Other
8 Total (Lines 1 thru 7)404,974,561 78,948,631 s9 1,960,1 38 136,691,026
FERC FORM NO. 1 (New 2.04)Page 398
I -4,742,96(
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
398 Line No.:7 Column:
Refr.urd for transmission
ERll--3643-000.
ces pursuant to FERC Docket No. BR1-7-21-9-002 and
FERC; FORM NO.1 (ED. 12471 Page 450.1
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
(1) Report the monthly peak load on the respondent's transmission system. lf the respondent has two or more power systems wtich are not physically
integrated, furnish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c ) and (d) the specified informalion for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through O by month the system' monthly maximum megawatt load by statistical classifications. See General lnstruction for the
definition of each stalistical classification.
NAME OF SYSTEM:
Line
No.Month
(a)
Monthly Peak
MW- Total
(b)
Day of
Monhly
Peak
(c)
Hour of
Monthly
Peak
(d)
Firm Network
Service for Self
(e)
Firm Network
Service for
Others
(f)
Long-Term Firm
Point-to-point
Reservations
(s)
Other Long-
Term Firm
Service
(h)
Short-Term Firm
Point-to-point
Reservation
(D
0her
Service
o
,|January 15,29a I 8,414 509 3,624 1,546 1,202
z February 14,944 2i 8,657 54'l 3,624 859 1,263
I March 1s,1 1€€8,121 475 3,674 1,625 1,223
4 Total for Quarter 1 25,152 1,525 10,922 4,030 3,688
q April 14,37t 7,694 442 3,674 1,399 1,167
€May 14,882 2t 7,929 303 3,674 1,605 1,371
7 June 18,094 2i 9,810 374 3,832 2,313 1,765
8 Total lor Ouarter 2 25,433 1,'t 19 1 1,180 5,317 4,303
9 July 18,61t 1e 10,708 434 3,832 1,736 1,905
10 August 18,12t (10,483 435 3,832 1,547 '1,831
11 September 16,72i 9,090 345 3,832 1,803 1,652
't2 Total for Quarter 3 30,281 1,214 11,496 5,086 5,388
13 October 14,524 7,314 3,793 1,672 1,323
14 November 15,12i 2A 8,101 457 3,635 1,698 1,231
15 December 15,771 6 I 8,558 520 3,635 1,729 1,333
16 Total for Qua(er 4 24,081 1,291 11,063 5,099 3,887
17 Total Year to
Date/Year
I5.149 44,661
-
tl
-
FERC FORM NO. l/s-Q (NEW.07-04)Page 400
180(
80(
80c
80(
1 700
1700
1 700
1600
1700
1300
800
1 800
t
Name of Respondent
PaciliCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
2018tQ4
FOOTNOTE DATA
400 Line No.:2 Column: d
Sehedule Pase:400 Line No.: 1 Column: d
Paci:Eic Standard Time
Pac cS T me
Pac :E c Standard me
Pac I :E 1i t me
Pacific 1 .t Time
Paci c t me
c I hr me
i:1i ht me
Paci:: i c .t. Time
Pac me400 Line No.: 14 Column: d
Pac c Standard me
Pac l:c Standard me
Year-to-dat.e 201-8 Net System Load rmat was comp Ied us meter ng or
sche<luling data. Reflects actual peak net system load for self at time of Transmission
S tem Peak. Peak load includes behind-the-meter ration
Year-to-date 201-8 Net system Load rmaE was comp 1ed us meter ng or
scheduling data. Reffects actuaL peak of customers' load at time of Transmission System
Peak.
Year:-to-date 2018 Net System Lo rmat was comp l-e US ng reserva ons n OASIS at
time of Transmission System Peak. Long-term firm point-to-point reservations have been
adjusted so that the monthly megawatt reservations represent an amount at system input as
measrrred by the transmission system loss factor. This adjustment has been made to ensurethat transmission rates are designed fairly and in a non-discriminatory manner and is
consj.stent wit.h the system input measurement utilized for other long-term firm users of
PAC], I1 's transmission tem incl network service
Year-to-date 2018 Net System Load rmat was c e us ng' reservat ons n OASIS attime of Transmission S'tem Peak.
Year-to-date 2018 NeE System ormat was c e us ng metering, scheduling
and/or contracEual data. Reflects actual peak and/or contractual demands of customers'load at time of Transmission System Peak.
FERG FORM NO.1 (ED. 12-871 Page 450.1
400 Line No.:3 Column: d
400 Line No.:5 Column: d
400 Line No.:6 Column: d
400 Line No.: 11 Column: d
400 Line No.:13 Column: d
400 Line No.: 10 Column: d
400 Line No.:7 Column: d
400 Line No.:9 Column: d
400 Line No.: 15 Column: d
400 Line No.: 17 Column: e
400 Line No.: 17 Column: f
400 Line No.:17 Column:
400 Line No.: 17 Column: i
400 Line No.: 17 Column:
PacifiCorp (1)
(2\
Original (Mo, Da,tlA Resubmission
Year/Period of Report
End of 20181Q4
ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year
Line
No.
Item
(a)
MegaWatl Hours
(b)
Line
No.
Item
(a)
MegaWatt Hours
(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to Ultimate Consumers (lncluding
lnterdeparlmental Sales)
55,1 15,456
3 Steam 39,967,861
4 Nuclear 23 Requirements Sales for Resale (See
instruction 4, page 31 1.)
308,313
5 Hydro-Conventional 3,26't,654
6 Hydro-Pumped Storage 24 Non-Requirements Sales for Resale (See
instruction 4, page 31 1.)
8,001,159
7 Other 10,276,271
8 Less Energy for Pumping 4,251 25 Energy Furnished Wthout Charge
I Net Generation (Enter Total of lines 3
through 8)
53,501,535 26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
10 Purchases 13,668,425 27 Total Energy Losses 3,484,684
11 Power Exchanges:28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
67,038,832
12 Received 7,967,992
'13 Delivered 7,994,88€
14 Net Exchanges (Line 12 minus line 1 3)-26,89i
15 Transmission For Other (Wheeling)
16 Received 16,159,593
17 Delivered 16,047,747
18 Net Transmission for Other (Line 16 minus
line 17)
111,846
19 Transmission By Others Losses -216,O77
20 TOTAL (Enter Total of lines 9, 1 0, 14, 1 8
and '19)
67,038,832
FERC FORM NO.1 (ED. 12-90)Page 40la
129,22(
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tl
Year/Period of Report
End of 20'l8lQ4
MONTHLY PEAKS AND OUTPUT
1. Report the monthly peak load and energy output. lf the respondent has two or more power which are not physically integrated, furnish the required
information lbr each non- integrated system.
2. Report in crllumn (b) by month the system's output in Megawatt hours for each month.
3. Report in crllumn (c) by month the non-requirements sales for resale. lnclude in the monthly amounts any energy losses associated with the sales.
4. Report in column (d) by month the system's monthly maximum megawatl load (60 minute integration) associated with the system.
5. Report in crllumn (e) and (f) the specified information for each monthly peak load reported in column (d).
NAME OF SYSTEM:
Line
No.Month
(a)
Total Monthly Energy
(b)
Monthly Non-Requirments
Sales for Resale &
Associated Losses
(c)
MONTHLY PEAK
Megawatts (Seelnstr.4)
(d)
Day of Month
(e)
Hour
(0
29 January 6,115,335 1,026,961 8,164 2 18OO PST
30 Februarl,5,232,606 690.452 8,436 23 OSOO PST
31 March 5,390,036 618,316 7,872 6 OSOO PDT
32 April 4,950,593 570,863 7,446 3 OSOO PDT
33 May 5,076,782 526,093 7,727 24 18OO PDT
34 June 5,548,195 555,267 9,584 27 17OO PDT
.E July 6,370,540 458,7*10,551 16 17OO PDT
36 August 6,05s,886 534,799 10,263 9 1600 PDT
37 Septernh,er 5,488,846 7't8,263 8,866 7 17OO PDT
38 October 5,450,455 901,565 7,250 1 2OOO PDT
?o Novembr:r 5,433,689 754,139 7,852 20 OSOO PST
4A Decembr:r 5,925,869 645,687 8,318 7 OSOO PST
41 TOTI\L 67,038,832 8,001 ,159
FERC FORrtr NO. I (ED.12-90)Page 401b
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
lt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
401 Line No.:26 Column: b
For t on
FERC FORM NO.1 (ED. 12-871 Pase 450.1
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn originat(2) 1A Resubmission
Date of Reoort(Mo, Da, Yi)
tt
Year/Period of Report
End of 20181Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1 . Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas.,turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. lndicate by a footnote any plant leased or operated
as a joint fac;ility. 4. lf net peak demand for 60 minutes is not available, give data which is available, specirying period. 5. lf any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. lf gas is used and purchased on a
therm basis report the Btu content orthe gas and the quantity offuel burned converted to Mct. 7. Quantities offuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and il7 (Line 42) as show on Line 20. 8. lf more than one
fuel is burned in a plant fumish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name:
Plant
Name
1 Kind of Plant (lnternal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Full Outdoor Conventional
3 Year Originally Constructed 198't 'r 984
4 Year Last Unit was lnstalled 1 981 1 986
5 Total lnstalled Cap (Max Gen Name Plate Ratings-MW)414.00 155.61
6 Net Peak Demand on Plant - MW (60 minutes)380 157
7 Plant Hours Connected to Load 6073 8297
8 Net Continuous Plant Capability (Megawatts)0 0
I \Men llot Limited by Condenser Water 395 148
10 \Men L.imited by Condenser Water 0 0
11 Average, Number of Employees
12 Net Ger,eration, Exclusive of Plant Use - K\Mt 1916020000 947341 000
'13 Cost of Plant: Land and Land Rights 26353',t7 1788644
14 Structures and lmprovements 65476965 62658945
15 Equipment Costs 483537232 1 7071 9668
16 Asset [letirement Costs 't2698745 8509670
17 Total C:ost 564348259 243676927
18 Cost per KW of lnstalled Capacity (line 17l5) lncluding 1 363.1 600 I 565.9464
'19 Produrlion Expenses: Oper, Supv, & Engr 2327801 46436
20 Fuel 51 1 38962 14844191
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 8't42986 1147621
23 Steam From Other Sources 0 0
24 Sleam'fransferred (Cr)0 0
25 Electric Expenses 281070 61 869
26 Misc St,-.am (or Nuclear) Power Expenses 2374542 1799195
27 Rents 0 23058
28 Allowarces 0 0
29 Mainterrance Supervision and Engineering 2820176 239276
30 Maintenance of Structures 3861 343 318886
31 Maintenance of Boiler (or reactor) Plant 8099267 2633725
32 Mainterrance of Electric Plant 1958604 324986
33 Mainterrance of Misc Steam (or Nuclear) Plant 1544014 425069
34 Total Production Expenses 82548765 21864312
35 Expenses per Net K\/vh 0.0431 o.023'l
36 Fuel: K.ind (Coal, Gas, Oil, or Nuclear)Coal Composite Coal Composite
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)Tons Barrels Tons Barrels
38 Quantitv (Units) of Fuel Burned 1122843 2913 0 605618 1734 0
39 Avg He;at Cont - Fuel Burned (btu/indicate if nuclear)91 91 129293 0 848'1 140000 0
40 Avg Co:it of Fuel/unit, as Delvd f.o.b. during year 44.253 93.360 0.000 21.674 96.596 0.000
4',!Average Cost of Fuel per Unit Burned 45.302 93.360 0.000 24.2U 96.596 0.000
42 Average Cost of Fuel Bumed per Million BTU 2.464 17.193 2.476 1.429 16.428 1.444
43 Average Cost of Fuel Burned per K\M Net Gen 0.027 0.000 0.027 0.015 0.000 0.015
44 Average BTU per KWh Net Generation 10772.367 8.256 1 0780.623 10843.242 10.762 1 0854.004
FERC FORi' NO.1 (REV. 12-03)Page 402
(c
Name of Respondent
PacifiCorp
This
(1)
(2)
Reoort ls:
5]Rn originat
f]A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. ltems under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Olher 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 for peak load service. Designate automatically operated plants. 1 1. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional sleam unit, include the gas-turbine with the steam plant. 12. lf a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name: Cratg
Plant
Name Dave Johnston
(e)
Plant
Name: Hayden
(0
Line
No.
Steam Steam Steam 1
Outdoor Boiler Semi-Outdoor Outdoor Boiler 2
'1979 1 959 1 965 3
1 980 1972 't976 4
172.13 816.77 81.37 5
163 754 78 6
8760 8760 8760 7
0 0 0 8
161 751 77 I
0 0 0 10
0 189 0 11
I 201 526000 4800371000 474063000 12
137086 10449793 683069 13
38586351 159752557 't7795743 14
1 84905599 875125839 96364150 15
35149 1 5492309 51 1486 't6
223664',t85 1060820498 115354448 17
1299.391 1 1298.7995 1417.6533 18
391 931 21188 335266 19
23904488 5451 901 I 11428283 20
n 0 0 21
1 899748 3083282 974138 22
0 0 0 23
0 0 24
0 464607 25
I 5866745 412169 26
99555 0 27
0 0 28
0 1 19291 29
508901 2295638 487284 30
1 '1068547 1417576 31
660655 10790684 1 1 06808 32
775764 703556 349021 33
33606054 98448213 17094443 u
0.0280
Coal Composite
0.0205
Coal oit Composite
0.0361
Coal oit Composite
35
36
Tons Barrels Tons Barrels Tons Barrels 37
642447 59 0 331 01 65 1 3075 0 222992 301 0 38
9880 133434 0 8244 1 38000 0 11277 't37269 0 39
31.109 103.260 0.000 16.188 106.926 0.000 44.801 94.1 86 0.000 40
37.065 103.260 0.000 16.048 106.926 0.000 51.043 94.186 0.000 4',!
1.876 18.443 1.883 0.973 18.448 0.997 2.263 16.339 2.272 42
0.020 0.000 0.020 0.01 1 0.000 0.01'1 0.024 0.000 0.024 43
10565.168 0.276 10565.444 1 1369.954 15.787 11385.741 10608.634 3.656 10612.290 44
FERC FORM NO.1 (REv. 12-03)Pag6 403
0
739568
1071430
I 000
0
728272
2924297
Name of Resp,ondent
PaciflCorp
This
(1)
(2)
Reoort ls:
5]Rn orisinal
aA Resubmission
Date of Reoorl(Mo, Da, Yi)tt
Year/Period of Report
End of 2018/Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Reporl in
this page ga$.turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. lndicate by a footnote any plant leased or operated
as a joint facilily. 4. lf net peak demand for 60 minutes is not available, give data which is available, speciffing period. 5. lf any employees attend
more than one plant, report on line 1 1 the approximate average number of employees assignable to each plant. 6. lf gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistenl with charges to expense accounts 501 and *7 (Line 42, as show on Line 20. 8. lf more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name:
Plant
Name:
1 Kind ol ['lant (lnternal Comb, Gas Turb, Nuclear Steam Steam
2 Type of rSonstr (Conventional, Outdoor, Boiler, etc)Outdoor Boiler Outdoor Boiler
3 Year Originally Constructed 1978 1 980
4 Year Last Unit was lnstalled 1978 1 980
5 Total lnstalled Cap (Max Gen Name Plate Ratings-Mvv)457.73 294.46
6 Net Peak Demand on Plant - MW (60 minutes)421 271
7 Plant Hours Connected to Load 7138 8214
8 Net Continuous Plant Capability (Megawatts)0 0
I When Not Limited by Condenser Water 418 269
10 When Limited by Condenser Water 0 0
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - KWh 2356979000 1810269000
13 Cost of Plant: Land and Land Rights 9688261 9688261
14 Structures and lmprovements 64971404 54346329
15 Equipmr:nt Costs 388748500 246956656
16 Asset Fletirement Costs 4278309 4278309
17 Total 3ost 467686474 31 5269555
18 Cost per KW of lnstalled Capacity (line 17l5) lncluding 102',t.7518 1070.6702
19 Productirrn Expenses: Oper, Supv, & Engr -1221 -786
20 Fuel 46389882 34186040
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam E:xpenses 6514688 51 80561
23 Steam F:rom Other Sources 0 0
24 Steam l'ransferred (Cr)0 0
25 Electrir: fxpgnss5 44182 76607
26 Misc Steam (or Nuclear) Power Expenses 1047416 -3374347
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 1814729 987501
31 Maintenance of Boiler (or reactor) Plant 9672902 395571 5
32 Maintenance of Eleclric Plant 4482499 1 0321 59
33 Maintenance of Misc Steam (or Nuclear) Plant 386953 279662
34 Total Production Expenses 70263666 42323',t12
35 Expenses per Net K\Mr 0.0298 0.0234
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Composite Coal Composite
37 Unit (Ooal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)Tons Barrels Tons Barrels
38 Quantity (Units) of Fuel Burned 1 076602 2705 0 799867 2144 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)1',t321 1 38000 0 11518 138000 0
40 Avg Cos,t of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000
41 Average Cost of Fuel per Unit Burned 42.838 0.000 0.000 42.470 0.000 0.000
42 Averag€ Cost of Fuel Burned per Million BTU 1.892 17.2',t9 1.902 1.U4 17.347 1.854
43 Averag€ Cost of Fuel Burned per K\Mt Net Gen 0.020 0.000 0.020 0.019 0.000 0.019
44 Average BTU per KVvh Net Generation 10342.504 6.651 1 0349.1 55 10178.802 6.865 10185.667
FERC FORM NO.1 (REV. 12-03)Page 402.1
1 Hunter Unit No.2
(c)
(c
Name of Respondenl
PacifiCorp
This Reoort ls:(1) 5]Rn original(2) f]A Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. ltems under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 1 0. For lC and GT plants, report Operating Expenses, Account Nos.
t47 and ilg on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 5t4 on Line 32, "Maintenance of Electric Plant." lndicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. lf a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data conceming plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name: Hunler Unit No. 3
(d)
Plant
Name:
Plant
Namei Huntington
(0
Line
No.
Steam Steam Steam 1
Outdoor Boiler Outdoor Boiler Outdoor Boiler 2
1 983 't978 1974 3
I 983 I 983 1977 4
495.59 1247.78 996.00 5
480 1 366 907 6
8426 8760 8618 7
0 0 0 8
47',!1 158 909 I
0 0 0 '10
214 158 11
2954132000 71 21 380000 5087824000 't2
10274569 29651 091 2377564 13
93037673 212355406 125725785 14
447605400 1 08331 0556 749858203 15
4278309 12834927 10't62682 16
555195951 13381 51 980 888',t24234 17
1120.2727 't072.4262 891.6910 18
-1 376 -3383 7601 19
57000166 1 37576088 1 257601 56 20
0 0 0 21
7537492 1923274',1 10745267 22
0 0 0 23
0 0 0 24
47170 -14745 0 25
2659661 332730 7992603 26
0 0 1574 27
0 0 0 28
0 0 1724730 29
1422247 4224477 23628',t8 30
5106595 18735212 14177302 31
665760 61 8041 I 4665426 32
5751 91 124',t806 752946 33
74918566 1 87505344 1 681 90423 34
0.0214 0.0263 0.0331 35
Coal Composite Coal Composite Coal Composite 36
Tons Barrels Tons Barrels Tons Barrels 37
1307413 12340 0 3183882 17189 0 231799',1 7888 0 38
11241 1 38000 0 1 1338 138000 0 1 1499 1 38000 0 39
0.000 0.000 0.000 42.296 102.297 0.000 s2.728 101 .694 0.000 40
42.624 0.000 0.000 42.658 102.297 0.000 53.908 101 .694 0.000 41
1.896 17.796 1.935 't.881 17.649 1.903 2.344 17.546 2.357 42
0.019 0.000 0.019 0.019 0.000 0.019 0.025 0.000 0.025 43
9949.490 24.211 9973.701 1 01 37.859 13.990 1 0151 .849 10478.037 8.986 10487.023 44
FERC FORM NO. 1 (REV. 12-03)Page 403.1
Total Plant
0
oit
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn Originat(2\ TrA ResubmissionLI
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and inlemal combustion plants of 10,000 Kw or more, and nuclear plants. 3. lndicate by a footnote any plant leased or operated
as a joint facility. 4. lf net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. lf any employees attend
more than oner plant, report on line 1'l the approximale average number of employees assignable to each plant. 6. lf gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. lf more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name:
Plant
Name:
,|Kind of Plant (lnternal Comb, Gas Turb, Nuclear Steam Steam
2 Type of Sonstr (Conventional, Outdoor, Boiler, etc)Outdoor Boiler Outdoor Boiler
3 Year O riginally Constructed 1974 1 963
4 Year La:it Unit was lnstalled 1 979 197 1
5 Total lnstalled Cap (Max Gen Name Plate Ratings-MW)1550.65 707.20
b Net Peal< Demand on Plant - MW (60 minutes)1422 650
7 Plant l-lcurs Connected to Load 8760 8760
I Net Continuous Plant Capability (Megawatts)0 0
I \Men Not Limited by Condenser Water 't415 637
10 \Men Limited by Condenser Water 0 0
11 Average Number of Employees 334 't27
12 Net Generation, Exclusive of Plant Use - K\Mr 84547S9000 4740078000
13 Cost ol Plant: Land and Land Rights 1 1 93761 't321031
14 Structures and lmprovements 147793420 126677607
15 Eguipmrent Costs 1 261 996800 676575672
16 Asset Ftetirement Costs I 81 73604 49036301
17 Total Cost 1429',t57585 85361061 1
18 Cost per KW of lnstalled Capacity (line 17l5) lncluding 921.6507 1207.0286
19 Producti,)n Expenses: Oper, Supv, & Engr 14244410 432464
20 Fuel 115283027
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam E:xpenses 19732163 11709432
23 Steam F:rom Other Sources 0 0
24 Steam'l-ransferred (Cr)0 0
25 Electri,l Expenses 0 601 5
26 Misc Steam (or Nuclear) Power Expenses -22794898 8357145
27 Rents 327809 14350
28 Allowances 0 0
29 Maintenance Supervision and Engineering 882154 1473533
30 Maintenance of Structures 11129738 1 '179901
31 Maintenance of Boiler (or reactor) Plant 24298890 6003999
32 Maintenance of Electric Plant 1 0735807 1530777
33 Maintenance of Misc Steam (or Nuclear) Plant 2159453 887053
34 Total Production Expenses 31 3504948 146877696
35 Expenses per Net K\M 0.0371 0.0310
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Composite Coal Composite
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)Tons Barrels Tons MCF
38 Quantity (Units) of Fuel Burned 4780005 11405 0 2595814 88860 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nucleafl 9275 1 38000 0 9961 1048 0
40 Avg Cos,t of Fuel/unit, as Delvd f.o.b. during year 47.987 92.338 0.000 44.550 5.968 0.000
41 Average Cost of Fuel per Unit Burned 52.664 92.338 0.000 44.207 5.968 0.000
42 Average Cost of Fuel Burned per Million BTU 2.839 15.931 2.849 2.219 5.694 2.225
43 Average Cost of Fuel Burned per l(Wh Net Gen 0.030 0.000 0.030 0.024 0.000 0.024
44 Average BTU per K\Mr Net Generation 10487.380 7.819 I 0495.1 99 10909.721 19.649 1 0929.370
FERC FORM NO. I (REV.12-03)Page 402.2
252789421
Name of Respondent
PacifiCorp
This ReDort ls:(1) 5]nn orisinat(2) f]A Resubmission
Date of ReDort(Mo, Da, Yi)Year/Period of Report
End of 20181Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. ltems under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For lC and GT planls, 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 for peak load service. Designate automatically operaled planls. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, intemal combustion or gas-turbine equipmenl, report each as a separate plant. However, if a gas-lurbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine with the steam planl. 12. lf a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development (b) types of cost units
used for the various components of fuel cost; and (c) any other informalive data conceming plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name:
Plant
Name: GadsbySleam
(e)
Plant
Name:
Line
No.
Steam Steam Combined Cycle 1
Conventional Outdoor Outdoor 2
1 978 1 951 1 996 J
1 978 1 955 1 996 4
140.29 251.64 279.56 5
270 167 248 6
8218 926 7839 7
0 0 0 I
266 238 231 I
0 0 0 10
62 33 11
1741620000 51636000 1472457000 12
210526 1252090 796929 13
52275645 1 5331 406 12843088 14
41 01 85493 6896991 1 1 651 98033 15
279518 1 1 32809 407646 16
462951182 86686216 '179245696 17
3299.9585 344.4850 641.1708 18
17194 't8134 0 19
27048098 3248365 288878r'.0 20
0 0 0 21
3663968 96246 0 22
0 0 0 23
0 0 0 24
0 0 7211303 25
3474225 3360741 0 26
13719 0 0 27
0 0 0 28
0 0 0 29
247015 95587 0 30
3666252 1098593 0 31
1't42523 1097467 0 32
160172 1 37581 0 33
39433166 9152714 36099143 34
0.0226 0.1773 0.0245 35
Coal Composite Gas Gas 36
Tons Barrels MCF MCF 37
1393744 3395 0 894072 0 1 0984079 0 0 38
8032 1 38000 0 '1040 0 't022 0 0 39
19.016 88.443 0.000 3.633 0.000 0.000 2.630 0.000 0.000 40
19.19't 88.443 0.000 3.633 0.000 0.000 2.630 0.000 0.000 41
1.195 '15.2s9 1.207 3.495 0.000 0.000 2.573 0.000 0.000 42
0.015 0.000 0.015 0.063 0.000 0.000 0.020 0.000 0.000 43
12855.726 1 1.300 12867.026 1 7998.896 0.000 0.000 7624.810 0.000 0.000 44
FERC FORM NO.1 (REV. {2-03)Page 403.2
Wyodak
0
oit
0
0
Name of Re:spondent
PacifiCorp
This Report ls:(1) [An Original(2) [A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
'l . Report data for plant in Service only. 2. Larye plants are steam plants 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 operated
as a joint facility. 4. lf net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. lf any employees attend
more than oner plant, report on line 11 the approximate average number of employees assignable to each plant. 6. lf gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit offuel burned (Line 4'l) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. lf more than one
fuel is burnerl in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name:
Plant
Name: Chehalis
(c)
,|Kind of Plant (lnternal Comb, Gas Turb, Nuclear Steam - Geothermal Combined Cycle
2 Type of Constr (Conventional, Outdoor, Boiler, etc)lndoor Outdoor
3 Year Originally Constructed 1 984 2003
4 Year Last Unit was lnstalled 2007 2003
5 Total lns.talled Cap (Max cen Name Plate Ratings-Mw)38.1 0 593.30
6 Net Pea( Demand on Plant - MW (60 minutes)35 506
7 Plant Hc,urs Connected to Load 8544 5575
I Net Continuous Plant Capability (Megawatts)0 0
I When lrlot Limited by Condenser Water 32 477
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 21 19
12 Net Generation, Exclusive of Plant Use - K\ /h 223051 000 1 741 969000
13 Cost of Plant: Land and Land Rights 41 195596 3730527
14 Structures and lmprovements 8338030 24474663
'15 Equipm,ent Costs 102923431 328950227
16 Asset Fletirement Costs 239't759 1030777
17 Total Cost '154848816 3581 861 94
'18 Cost prx KW of lnstalled Capacity (line 17l5) lncluding 4064.2734 603.7185
19 Producti,)n Expenses: Oper, Supv, & Engr 8081 126746
20 Fuel 0 26546969
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam E:xpenses 225718 0
23 Steam From Other Sources 4714446 0
24 Steam l'ransferred (Cr)0 0
25 Electrirc Expenses 0 1948752
26 Misc Steam (or Nuclear) Power Expenses 2126361 641474
27 Rents 7560 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Shuctures 237793 37024
31 Maintenance of Boiler (or reactor) Plant 120536 0
32 Maintenance of Electric Plant 283273 2266933
33 Maintenance of Misc Steam (or Nuclear) Plant 1 0091 4 0
34 Total Production Expenses 7824682 3'ts67898
35 Expenses per Net KVwr 0.035't 0.0181
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)MCF
38 Quantity (Units) of Fuel Burned 0 0 0 1 1 805959 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicale if nuclear)0 0 0 1099 0 0
40 Avg Cos,t of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 2.249 0.000 0.000
41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 2.249 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 2.046 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.015 0.000 0.000
44 Average BTU per KVvh Net Generation 0.000 0.000 0.000 7446.740 0.000 0.000
FERC FORM NO.1 (REV. t2-03)Page 402.3
-iEI-
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn orisinat(2) 1A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. ltems under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 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 for peak load service. Designale automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-lurbine with the steam plant. 12. lf a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Plant
Name: Gadsby Peakers
(d)
Plant
Name: Cunant Creek
(e)
Plant
Name: Lake Slde
(f)
Line
No.
Gas Turbine Combined Cycle Combined Cycle 1
Outdoor Outdoor Outdoor 2
2002 2005 2007 J
2002 2006 2007 4
181 .05 566.90 s91.30 5
124 540 520 b
492 7358 6166 7
0 0 0 I
119 524 546 I
0 0 0 '10
18 32 11
8046000 24',t8275000 1 839453000 't2
0 3403277 14532275 't3
426391 3 44250508 3550971 2 14
81 389845 307242254 339338282 '15
0 1UUg 0 16
85653758 355030887 389380269 17
473.0945 626.2672 658.5"156 18
0 62684 44613 19
1435967 59493080 4U93424 20
0 0 0 21
0 0 0 22
0 0 0 23
0 0 0 24
768281 1 82591 1 2107000 25
0 677960 516622 26
0 0 0 27
0 0 0 28
0 0 0 29
95220 688422 1344667 30
0 0 0 31
37t490 1140634 529726 32
142655 54855 30000 33
2817613 63943546 53066052 34
0.3502 0.0264 0.0288 35
Gas Gas Gas 36
MCF MCF MCF 37
1 33908 0 0 17337641 0 0 13326731 0 0 38
1 039 0 0 '1040 0 0 1039 0 0 39
10.724 0.000 0.000 3.431 0.000 0.000 3.639 0.000 0.000 40
'10.724 0.000 0.000 3.431 0.000 0.000 3.639 0.000 0.000 41
10.324 0.000 0.000 3.300 0.000 0.000 3.503 0.000 0.000 42
0.178 0.000 0.000 0.025 0,000 0.000 0.026 0.000 0.000 43
17286.726 0.000 0.000 7455.298 0.000 0.000 7525.434 0.000 0.000 44
FERC FORM NO. { (REV. 12-03)Page 403.3
0
Name of Respondent
PacifiCorp
This
(1)
(2)
Reoort ls:
5]Rn orisinal
flA Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report datia for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. lndicate by a footnote any plant leased or operated
as a joint facility. 4. lf net peak demand for 60 minutes is not available, give data wtrich is available, specirying period. 5. lf any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. lf gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity offuel burned converted to Mct. 7. Quantities offuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and il7 (Line 42) as show on Line 20. 8. lf more than one
fuel is burnerJ in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name: Lake Srde 2
(b)
Plant
Name:
(c)
,|Kind of Plant (lntemal Comb, Gas Turb, Nuclear Combined Cycle
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Ouldoor
J Year C,riginally Constructed 2014
4 Year Last Unit was lnstalled 2014
5 Total lns,talled Cap (Max Gen Name Plate Ratings-MW)655.20 0.00
6 Net Peak Demand on Plant - MW (60 minutes)639 0
7 Plant Hc,urs Connected to Load 7472 0
I Net Continuous Plant Capability (Megawatts)0 0
I When Nlot Limited by Condenser Water 631 0
'10 \Men Limited by Condenser Water 0 0
11 Average Number of Employees 0
12 Net Generation, Exclusive of Plant Use - K\Mt 3021716000 0
13 Cost of Plant: Land and Land Rights 16794626 0
14 Structures and lmprovemenls 53124296 0
15 Equiprn,ant Costs 569854794 0
16 Asset Retirement Costs 0 0
17 Total Cost 639773716 0
18 Cost per KW of lnstalled Capacity (line 17l5) lncluding 976.4556 0
19 Production Expenses: Oper, Supv, & Engr 51 559 0
20 Fuel 74274535 0
21 Coolant,s and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam F:rom Other Sources 0 0
24 Steam l'ransferred (Cr)0 0
25 Electrlc Expenses 3542172 0
26 Misc Steram (or Nuclear) Power Expenses 603508 0
27 Rents 0 0
28 Allowan,ces 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 2231623 0
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 2865016 0
33 Maintenance of Misc Steam (or Nuclear) Plant 33&41 0
34 Total Production Expenses 83602054 0
35 Expenses per Net K\Mr 0.0277 0.0000
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas
37 U nit (C oal-tons/Oil-barrel/Gas-mcf/N uclear-ind icate)MCF
38 Quantity (Units) of Fuel Burned 21258527 0 0 0 0 0
39 Avg Heert Cont - Fuel Burned (btu/indicate if nucleao 1039 0 0 0 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 3.494 0.000 0.000 0.000 0.000 0.000
41 Average Cost of Fuel per Unil Burned 3.494 0.000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000
43 Average Cost of Fuel Burned per KVwl Net Gen 0.025 0.000 0.000 0.000 0.000 0.000
44 Average BTU per K\M Net Generation 7306.212 0.000 0.000 0.000 0.000 0.000
FERC FORM l,l0. 1 (REV. 12-03)Page 402.4
(
3.364
Name of Respondent
PacifiCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
402 :-1
402 Line No.: -1 Column: c
P s operate zona Pub cSe ce Company and 1y ovrnedPacifiCorp owns l-00? of Unit No. 4 and 49.53? of common facilities. Data reportedresents PacifiCo 's share.
The Colstrip Plant s operate en Monfana, LLC o r . Pac rp ownsa 10.0? share of Colstrip Plant Unit Nos. 3 and 4. Data reported represents PacifiCorpts
share.
The Craig Plant is operated by Tri-State cenerat SS Assoc , Incis jointly owned. PacifiCorp owns a 19.28% share of Craig Plant Unit Nos. 1 and 2 and
L2.86r" of common facili-ties. Data rted resents Pacifi-Co 's share.
The Hayden Plant is operated by Public Service Company o Col 1S oint vPacifiCorp owns a 24.52 (45 Mw) share of Hayden Unit No. t-, a 1-2.62 (33 IUW) share of
Hayden Unit No. 2 and 1,7.52 of common facilities. Data reported represents PacifiCorpts
share.
Pac not have at the Cholla P1ant.
Pac f does not have at the Colstri Plant.
Paci f i does not have at the P ant.
Pacifi does not P ant
Amount includes interc fc
Hunter Unit No. 1 s opera Corp and t1y owned by Pac f Corp and Ut.ahMunicipal Power Agency with an undivided interest of 93.75? and 6.259<, respectively. Datareported represents PacifiCorp's share. Costs that were bi1led to minority owners for theoperation and maintenance (excluding fuel) of this unit for calendar year 2018 were $2.0million and were imaril credited to Account 506, Miscellaneous steam r es.
Hunter t. No. 2 s operated by f Corp and t1y ovrned by Pacif Corp, Deseret
Power Electric Cooperative and Utah Associated Municipal Power Systems, each with anundivided interest of 50.31?, 25.108? and 14.5822, respectively. Data reported representsPacifiCorp's share. Costs that. were billed to minority owners for the operation andmaintenance (excluding fuel) of this unit for calendar year 2018 were $7.5 million and
were imaril credited to Account 505, Miscellaneous steam ES
Refer to Hunter t Nos. 1, 2 and 3 for each unit's ant statistics.
Refer to Hunter - Total Plant for the
Refer to Hunter - Total P .t or
Refer to Hunter - Tota P or a'of
The .Tim Bridger P s opera Pac f Corp and ntly owned by f Corp andIdaho Po$rer Company with an undivided interest of 66.67? and 33.33?, respectively. Dat.areported represents Pacj-fiCorpts share. Costs that were bi11ed to minority owners for theoperation and maintenance (excluding fuel) of this plant for calendar year 2018 were $33.7million and were primarily credited to Account 506, Miscellaneous steam power expenses.
FERC FORM NO.1 ED.1 450.1
403 Line No.: -1 Column: d
403 Line No.: -1 Column: f
403 Line No.: 11 Column: fatt
403 Line No.:20 Column: d
402.1 Line No.: -1 Column: b
402 Line No.: 11 Column: c
402 Line No.: 11 Column: b
403 Line No.: 11 Column: d
402.1 Line No.: -1 Column: c
402.2 Line No.: -1 Column: b
403.1 Line No; -1 Column: e
402.1 Line No.: 11 Column: b
402.1 Line No.: 11 Column: c
403.1 Line No.:11 Column: d
2-871
Name of Respondent
PaciliCorp
This Report is:
(1) XAn Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
402.2 Line No.: -1 Column: c
403.2 Line No.: -1 Column: d
On January 30, 201,9, Naughton Unit No. 3 (280 Mw) a coal-fueled generat p , was
removed from service due to state permits. Currently, PacifiCorp is evaluating the
economic benefits of converting the Naughton Unit No. 3 to a naturaL gas-fueled generation
resource.
The Wyodak PLant is operated by Pac f Corp and ointly owned by Pacificorp and BlackHi1ls Corporation with an undivided interest of 80? and 20?, respectively. Data reportedrepresents PacifiCorp's share. Costs that were bi11ed to minority owners for the operationand maintenance (excluding fuel) of this plant for calendar year 2018 were $4.0 million
and rvere imaril credited to Account 506 Miscellaneous steam ses.
The tston P t s operated by ston Genera ng Company, L.P o
owned. PacifiCorp owns a 50.0? share of the Hermiston Plant. Data reported representsPacil:i ts share
s not att He ston ant
Amount ncludes terc TS
A11 or some of the renewable energy att tes associated t.h generation from the
Blun<1e11 generat.ing facility may be: (a) used in future years to comply with renewableporLfolio standards or other regulatory requirements or (b) sold to third parties in the
form of renewabl-e credits or other environmental commodities
er to the Steam ant or ave of
Referr: to the Lake S de Plant for the ave number of 1 es
Choll.a - Fuel oi1 is used for start ses.
Colst:- Fue o s used for start ses .
- Fuel o sus or start1
t No. 1 -
t No. 3 -
Dave Johnston - Fuel 1 s used for start
Ha'- Fuel oiI is used for start-
es.
SES .
Hunter
Hunt€:r
Hunt€)r tNo.2-Fue
s used start
S USE or start
sus start
s used for start
I
es.
Hunter - Total Plant - Fuel
Hunt on - Fuel oi1 s used for start
u r_m IJr].- Fuel oi1 is used for start
ton - Nat s used for start-
es
ES
403.2 Line No.: -1 Column: f
403.2 Line No.: 11 Column: f
402.2 Line No.:20 Column: b
402.3 Line No.: -1 Column: b
403.3 Line No.: 11 Column: d
402.4 Line No.: 11 Column: b
402 Line No.: 36 Column: b2
402 Line No.: 36 Column: c2
Scheclule Page:402 Line No.: 36 Column: d2
402 Line No.: 36 Column: e2
402 Line No.: 36 Column: f12
402.1 Line No.: 36 Column: b2
402.1 Line No.:36 Column: c2
402.1 Line No.: 36 Column: d2
402.1 Line No.: 36 Column: e2
402.1 Line No.: 36 Column: fi2
Schedule Pase:402.2 Line No.: 36 Column: b2
402.2 Line No.:36 Column: c2
402.2 Line No.:36 Column: d2
Na
- Fuel o 1 sus or start-up purposes
FERC FORM NO. I (ED. 12.871 Page 450.2
s
Name of Respondent
PacifiCorp
ThiS
(1)
(2)
Reoort ls:
5]Rn orisinat
f]A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (LaTge Plants)
1 . Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. ll any planl is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a
footnote. lf licensed project, give project number.
3. lf net peak demand for 60 minutes is not available, give that which is available specirying period.
4. lf a group of employees attends more than one generating plant, report on line 1'1 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
Licensed Project No.
Name:
FERC Licensed ProjectNo. I
Plant Name: Copco No.2
(c)
1 Kind of Plant (Run-of-River or Storage)Run-of-River
2 Plant Construction type (Conventional or Outdoor)Conventional Conventional
3 Year Originally Constructed 1918 1925
4 Year Last Unit was lnstalled 1922 1925
5 Total installed cap (Gen name plate Rating in MW1 20.00 27.00
b Net Peak Demand on Plant-Megawatts (60 minutes)26 33
7 Plant Hours Connect to Load 4,946 4,895
I Net Plant Capability (in megawatts)
I (a) Under Mosl Favorable Oper Condilions 28 34
10 (b) Under the Most Adverse Oper Conditions 28 34
11 Average Number of Employees 1 2
12 Net Generation, Exclusive of Plant Use - Kwh 73,916,000 92,720,000
13 Cost of Plant
14 Land and Land Rights 107,019 20,914
15 Structures and lmprovements 1,774,794 2,457,315
16 Reservoirs, Dams, and Waterways 3,357,158 2,965,439
17 Equipment Costs 5,679,214 10,488,152
18 Roads, Railroads, and Bridges 133,348 551 ,687
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 1 9)'11,051,533 16,483,s07
21 Cost per KW of lnstalled Capacity (line 20 / 5)552.5767 61 0.5003
22 Production Expenses
23 Operation Supervision and Engineering 10,712 15,900
24 Water for Power 0 0
25 Hydraulic Expenses 1,534 2,071
26 Electric Expenses 0 0
27 Misc Hydraulic Power Generation Expenses 1,062,803 1,269,691
28 Rents 55,925 75,499
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 6.612 2,835
31 Maintenance of Reservoirs, Dams, and Waterways 36,523 1,604
32 Maintenance of Electric Plant 27,523 93,146
33 Maintenance of Misc Hydraulic Plant 20,285 27,385
34 Total Production Expenses (total 23 thru 33)1,221,9',t7 1 ,488,1 31
35 Expenses per net l(VVh 0.0165 0.0160
FERC FORM NO. I (REV. 12-03)Page 406
Storaqe
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5l1Rn orisinat(2) [A Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1927
Plant Name: Clearwater No. 1
(d)
FERC Licensed Project No. 1g2Z
Plant Name: Clearwater No. 2
(e)
FERC Licensed Project No. 2420
Plant Name: Cutler
(f)
Line
No.
Storage 1
Outdoor Outdoor Conventional 2
1953 1 953 1927 3
1953 1 953 1927 4
15.00 26.00 30.00 5
I 12 30 6
8,757 8,355 5,772 7
8
18 31 29 I
18 31 29 10
1 1 3 11
40,494,000 36,927,000 69,760,000 12
13
0 0 3,511,105 14
1,504,709 2,449,890 4,042,960 15
5,184,972 14,819,998 10,073,946 16
1,407,668 2,197,U8 15,037,762 17
50,817 250,151 569,655 18
0 0 0 19
8,148,166 't9,717,887 33,23s,428 20
543.2',111 758.3803 1 ,107.8476 21
22
10,630 19,439 114,749 23
812 1,407 0 24
41 ,891 72,611 'l 18,394 25
0 0 0 26
283,766 459,560 1,318,206 27
48,426 83,938 -11,112 28
0 0 0 29
25,412 43,622 0 30
7,482 't0,589 26,358 31
9,990 132,829 5,835 32
33,914 58,784 446,423 33
462,323 882,779 2,018,853 34
o.o114 0.0239 0.0289 35
FERC FORTU NO. 1 (REV. 12-03)Page 407
Run-of-River Run-of-River
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]en originat
(2) f]A Resubmission
Date of Report(Mo, Da, Yr)
tl
Year/Period of Report
End of 20181Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. 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 a
footnote. lf licensed project, give project number.
3. lf net peak demand for 60 minutes is not available, give that which is available speciffing period.
4. lf a group of employees attends more than one generating plant, reporl on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 1927
Plant Name: Fish Creek
(b)
FERC Licensed Project No.
Plant Name: Grace
(c)
20
1 Kind of Plant (Run-of-River or Storage)Storage
2 Plant Construction type (Conventional or Outdoor)Outdoor Conventional
3 Year Originally Constructed 1952 1908
4 Year Last Unit was lnstalled 1952 1923
5 Total installed cap (Gen name plate Rating in MW)11.00 33.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)'10 29
7 Plant Hours Connect to Load 2,714 8,336
a Net Plant Capability (in megawatts)
I (a) Under Most Favorable Oper Conditions 10 33
10 (b) Under the Most Adverse Oper Conditions 10 33
11 Average Number of Employees 1 4
12 Net Generation, Exclusive of Plant Use - Kwh 14,758,000 123,892,000
't3 Cost of Plant
14 Land and Land Rights 0 62,169
15 Structures and lmprovements 't,7u,792 2,9U,991
't6 Reservoirs, Dams, and Wateruays 12,459,236 11,561,657
17 Equipment Costs 2,993,343 5,343,471
18 Roads, Railroads, and Bridges 533,015 499,327
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 1 9)17,750,386 20,401 ,615
21 Cost per KW of lnstalled Capacity (line 20 / 5)1 ,613.6715 618.2308
22 Production Expenses
23 Operation Supervision and Engineering 6,719 132,149
24 Water for Power 595 0
25 Hydraulic Expenses 30,720 42,856
26 Electric Expenses 0 0
27 Misc Hydraulic Power Generation Expenses 254,569 1,317 ,793
28 Rents 35,512 -3,439
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 19,678 11,335
31 Maintenance of Reservoirs, Dams, and WateMays 10,651 72,456
32 Mainlenance of Electric Plant 54,001 32,524
33 Maintenance of Misc Hydraulic Plant 24,870 53,616
34 Total Production Expenses (total 23 thru 33)437.315 1,659,290
35 Expenses per net KWh 0.0296 0.0134
FERC FORM NO. I (REV. 12-03)Page 406.1
Run-of-River
Name of Respondent
PacifiCorp
This
(1)
(2)
Reoort ls:
5]Rn Original
flA Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinalions of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Projec't No. I
Plant Name: lron Gate
(d)
FERC Licensed Project No. IPlant Name: JC Boy'e
(e)
FERC Licensed Project No. 1927
Plant Name: Lemolo No. 1
(f)
Line
No.
I
Outdoor Outdoor Outdoor 2
't962 1 958 1 955 3
1962 1 958 1 955 4
18.00 97.98 31.99 5
19 85 32 6
8,655 5,276 8,710 7
8
19 83 32 I
19 83 32 10
1 2 1 11
88,987,000 194,050,000 124,864,000 12
13
341,617 25,U5 0 14
8,175,609 3,731,330 2,940,403 15
17,240,4U 15,899,073 15,807,219 16
3,150,391 15,603,261 6,726,791 17
1,095,742 972,360 4U,094 18
0 0 0 19
30,003,843 36,231,869 25,958,507 20
1,666.8802 369.7884 81 1.4569 21
22
1,584,515 162,361 18,954 23
0 0 1,731 24
1,381 7,417 89,340 25
0 0 0 26
989,730 810,557 674,580 27
50,333 1,873 103,276 28
0 0 0 29
1,888 17,209 80,309 30
23,067 93,244 13,262 31
8,027 5't,291 28,315 32
18,256 36,954 72,327 33
2,677,197 1 ,1 80,906 1,082,094 34
0.0301 0.0061 0.0087 35
FERC FORM NO. I (REV. 12-03)Page 407.1
Storage Storage
Name of Respondent
PacifiCorp
This Reoorl ls:(1) 5l1Rn original(2) [A Resubmission
Dale of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1 . Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. lf any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facls in a
footnote. lf licensed project, give project number.
3. lf net peak demand for 60 minutes is not available, give that which is available specirying period.
4. lf a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 't927
Plant Name: Lemolo No. 2
(b)
FERC Licensed Project No. 93S
Plant Name: Merwin
(c)
1 Kind of Plant (Run-of-River or Storage)Storage (Re-Reg)
2 Plant Construction type (Conventional or Outdoor)Outdoor Conventional
3 Year Originally Constructed 1 956 1 931
4 Year Last Unit was lnstalled 1 956 1958
5 Total installed cap (Gen name plate Rating in MW)38.50 136.00
b Net Peak Demand on Plant-Megawatts (60 minutes)31 149
7 Plant Hours Connect to Load 7,982 8,759
I Net Plant Capability (in megawatts)
I (a) Under Most Favorable Oper Conditions 39 '151
10 (b) Under the Most Adverse Oper Conditions 39 151
11 Average Number of Employees 1 1
12 Net Generation, Exclusive of Plant Use - Kwh 133,034,000 450,459,000
13 Cost of Plant
14 Land and Land Rights 0 1,735,054
'15 Structures and lmprovements 6,295,797 110,619,342
16 Reservoirs, Dams, and Wateruays 32,875,543 30,506,980
17 Equipment Costs '11,847,637 18,925,1 1 1
18 Roads, Railroads, and Bridges 1,820,580 4,140,268
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)52,839,557 165,926,755
21 Cost per KW of lnstalled Capacity (line 20 / 5)1,372.4560 1,220.0497
22 Production Expenses
23 Operation Supervision and Engineering 22,812 1,458,874
24 Water for Power 2,083 2,420
25 Hydraulic Expenses 107,520 878,055
26 Electric Expenses 0 0
27 Misc Hydraulic Power Generation Expenses 596,292 541 ,499
28 Rents 124,293 107,560
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 64,310 43,894
31 Maintenance of Reservoirs, Dams, and Wateruays 1't9,649 47,405
32 Maintenance of Electric Plant 202,5',t9 138,578
33 Maintenance of Misc Hydraulic Plant 87,045 581,301
34 Total Production Expenses (total 23 thru 33)1,326,523 3,799,586
35 Expenses per net KWh 0.0100 0.0084
FERC FORM NO. r (REV. 12-03)Page 406.2
Run-of-River
Name of Respondent
PacifiCorp
This
(1)
(2)
ReDort ls:
E:]An orisinat
EA Resubmission
Date of Reoort
(Mo, Da, Yi)tt
Year/Period of Report
End of 2018/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as €r separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1927
Plant Name: Toketee
(d)
FERC Licensed Project No.
Plant Name: oneida
(e)
20 FERC Licensed Project No. 2630
Plant Name: Prospect No.2(fl
Line
No.
Storage ,|
Conventional Conventional Conventional 2
1 949 1915 1928 3
1 950 1920 1928 4
42.50 30.00 32.00 5
39 20 36 6
8,758 8,679 8,701 7
I
45 28 36 I
45 28 36 10
1 2 1 11
195,057,000 61,899,000 1S9,202,000 12
13
0 283,870 105,168 14
4,379,946 2,330,393 4,074,730 15
12,847,979 8,532,515 35,357,614 16
5,661,905 12,747,634 7,362,752 17
502,952 661 ,547 324,746 18
0 0 0 19
23,392,782 24,555,959 47,225,010 20
550.4184 818.5320 1,475.7816 21
22
30,456 111,944 259,677 23
2,300 0 11,058 24
118,694 38,960 2,422 25
0 0 0 26
750,704 643,336 628,714 27
't37,210 -3,581 8,054 28
0 0 321 29
84,144 628 65,757 30
10,547 'r,358 125,189 31
107,407 46,1 03 88,518 32
96,091 61 ,993 262,964 33
1,337,553 900,741 1,452,674 34
0.0069 0.0146 0.0073 35
FERC FORi' r{O.1 (REV. 12-03)Page 407.2
Storage
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]nn originat(2) [A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 2O18lQ4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. lf any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a
footnote. lf licensed project, give project number.
3. lf net peak demand for 60 minutes is not available, give that which is available speciffing period.
4. lf a group of employees attends more than one generating plant, report on line 't 1 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 1927
Plant Name: Slide Creek
(b)
FERC Licensed Project No.
Plant Name: Soda
(c)
20
1 Kind of Plant (Run-of-River or Storage)Run-of-River Storage
2 Plant Construction type (Conventional or Outdoor)Outdoor Conventional
3 Year Originally Constructed 1 951 't924
4 Year Last Unit was lnstalled 1 951 1924
5 Total installed cap (Gen name plate Rating in M\A/)18.00 14.45
b Net Peak Demand on Planl-Megawatts (60 minutes)14 I
7 Plant Hours Connect to Load 8,734 6,583
8 Net Plant Capability (in megawatts)
I (a) Under Most Favorable Oper Conditions 18 14
10 (b) Under the Most Adverse Oper Conditions 18 14
11 Average Number of Employees 1 2
12 Net Generation, Exclusive of Plant Use - Kwh 56,868,000 29,789,000
13 Cost of Plant
14 Land and Land Rights 0 511,083
15 Structures and lmprovements 2,213,290 782,666
'16 Reservoirs, Dams, and WateMays 14,884,883 1 1 ,'1 08,268
17 Equipment Costs 8,978,529 5,420,920
18 Roads, Railroads, and Bridges 599,269 0
19 Assel Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru '19)26,675,971 17,822,937
21 Cost per KW of lnstalled Capacity (line 20 / 5)1,481.9984 1,233.4212
22 Production Expenses
23 Operation Supervision and Engineering 12,274 52,240
24 Water for Power 3,618 0
25 Hydraulic Expenses 50,269 '18,181
26 Electric Expenses 0 0
27 Misc Hydraulic Power Generation Expenses 31 3,1 39 326,605
28 Rents s8,111 -1,590
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 47,101 64
31 Maintenance of Reservoirs, Dams, and Waterways 23,853 1,335
32 Maintenance of Electric Plant 32,313 17,372
33 Maintenance of Misc Hydraulic Plant 40,697 22,608
34 Total Production Expenses (total 23 thru 33)581,375 436,815
35 Expenses per net KWh 0.01 0.0147
FERC FORM NO. I (REV. 12-03)Page 406.3
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5l1An orisinat(2) [A Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1927
Plant Name: Soda Springs
(d)
FERC Licensed Project No. 2111
Plant Name: Swift No. 1
(e)
FERC Licensed Project No. 2071
Plant Name: Yale (fl
Line
No.
Storage (Re-Reg)Storage Storage 1
Outdoor Conventional Conventional 2
1952 I 958 1 953 3
1 952 1 958 1 953 4
11.00 240.00 134.00 5
12 241 167 6
8,757 5,352 6,1 57 7
8
12 264 164 o
12 264 164 10
2 1 1 11
44,108,000 545,383,000 519,637,000 12
13
0 't7,912,070 8,363,0't 3 14
4,307,766 71,629,227 17,792,675 15
90,253,682 47,515,885 33,765,145 16
2,635,457 24,895,858 16,988,507 17
2,089,012 1,319,865 2,045,631 '18
0 0 0 '19
99,285,917 163,272,905 78,954,971 20
9,025.9925 680.3038 589.2162 21
22
6,819 2,398,400 1,374,491 23
595 4,271 2,385 24
175,155 1,762,545 862,592 25
0 0 0 26
411,117 406,456 488,969 27
35,512 189,584 105,851 28
0 0 0 29
18,350 52,108 38,976 30
93,544 75,010 66,064 3'l
6,482 176,265 111,478 32
24,870 986,325 559,586 33
772,444 6,050,964 3,610,392 34
0.0175 0.011't 0.0069 35
FERC FORM NO.1 (REV. 1z-Os)Page '107.3
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Y0tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
406 Line No.: -2 Column: b
406 Line No.: -2 Column: c
In FERC Order No. P-14803-000 (ssued March 15, 2018), art cles ng tohydroelectric plant were transferred from the Klamath (FERC License) Project No. 2082 to a
new license for the Lower Klamath Project No. l-4803. For further discussion, refer to Note
l-3 of Notes to Financial Statements in this Form No. 1
In FERC O No. P-14803-000 SS 15, 2018 , arL ngtothydroelectric plant were transferred from the Klamath (FERC License) Project No. 2082 Lo a
new license for the Lower Klamath Project No. 14803. For further discussion, refer to Note13 of Notes to Financial Statements, in this Form No. 1.
Schedule Page:406 Line No; -1 Column: bThis footnote applies to all hydroelectric generating facilities with currenL generation.Al1 or some of the renewable energy attributes associated with generation from thesegenerating facilities may be: (a) used in future years to comply with renewable portfolio
standards or other regulatory requirements or (b) sold to third parties in the form of
renewable ene credits or other environmental commodities.
coNo.1-stor r Klamath Lake
Clearwater No. 1 for
Cl-earwaterNo.2-Fo for
In FERC Order No. P-14803-000 Mar 15, 2018 , art es perta to shydroelectric plant were transferred from the Klamath
new license for the Lower Ktamath Project No. 14803. .
(FERC License) Project No. 2082 Lo aFor further discussion, refer to Note
1.13 of Notes to Financial Statements in this Form No.
rn FERC No. P-14803-000 MA 15, 2018 art cles perta tohydroelectric plant were transferred from the Klamath (FERC License) Project No. 2082 to a
new license for the Lower Klamath Project No. 14803. For further discussion, refer to Note
13 of Notes to Financi-a1 Statements, in this Form No. l-.
sh Creek -for
Iron Gate - S for ation
,JC Le-or -st r amat
o No. 1 -o
o No. 2 - S Lemolo Lake
for -st Lemolo Lake
Prospect No. 2 - Forebay for peaking
FERC FORM NO.1 (ED. 12-871 Page 450.1
406 Line No.: 1 Column: bfor406 Line No.: 1 Column: d
406 Line No.:1 Column: e
406.1 Line No.: -2 Column: d
406.1 Line No.: -2 Column: e
406.1 Line No.: 1 Column: b
406.1 Line No.: 1 Column: d
406.2 Line No.: 1 Column: b
406.1 Line No.: 1 Column: e
406.1 Line No.: I Column: f
406.2 Line No.: 1 Column: d
406.2 Line No; 1 Column: f
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from olhers, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. lf licensed project, give
project number in footnote.
Line
No.
Name of Plant
(a)
Year
Orio.ConEt.
(b)
lnstalled uapacttyName Plate Ratinc
(ln MW)
(c)
NEt PCAKDemand
MW(60,6in.)
Net Generation
ExcludinoPlant UsE
(e)
Cost of Plant
(0
1
2 Ashton 2381 1917 6.70 7.4 38,064,000 34,009,021
3 Bend 1913 1.11 1.0 1,448,000 2,326,593
4 Big Forlr 2652 1910 4.15 4.6 26,131 ,000 9,684,965
5 Eagle Point 1 957 2.81 2.8 16,411,000 2,011 ,829
6 1924 3.20 1,991,695
7 Fall Creek 2082 1 903 2.20 2.C 3,931,000 2,112,218
8 Granite 1 896 2.00 1.3 5,359,000 5,261,282
I Gunlock 1917 0.75 0.4 663,000 683,045
'10 Last Chirnce 1 983 1.73 1.3 4,553,000 3,132,443
11 Paris 703 1 910 0.72 0.7 2,455,000 459,985
12 Pioneer 2722 1897 5.00 2.7 9,235,000 11 ,548,276
13 Prospect No. 1 2630 19',t2 3.76 4.6 12,114,000 5,U4,452
14 Prospect No. 3 2337 1932 7.20 7.7 22,263,004 9,134,363
15 Prosperct No. 4 2630 1944 1.00 0.9 2,541,000 2,409,752
16 Sand Cove '1926 0.80 0.4 471,000 939,281
17 Stairs 597 1 895 1.00 1.2 3,766,000 1,953,373
18 1 920 0.50 899,1 80
19 Viva Naughton I 986 0.74 0.2 509,000 't,232,115
20 Wallowa Falls 308 192',1 1.10 1.0 4,664,000 3,282,375
2',!Weber 1744 191 1 3.85 2.0 11,273,004 3,877,478
22 1 908 0.60 -1,000 489,350
23 7,684,061
24 3,847,587
25 16,931,391
26
27 Pumping Plant:
28 1917 -2.80 -2.0 -4,251,000 't9,532,260
29
30
31 Dunlap Ranch 1 2010 111.00 111.0 391,874,000 242,003,550
32 1 999 32.15 31.4 104,801 ,000 38,185,620
33 Glenrock 2008 99.00 99.0 303,865,000 202,915,370
34 Glenrock lll 2009 39.00 39.0 117,589,000 88,354,617
35 Rolling llills 2009 99.00 99.0 277,843,00A 204,806,286
36 Goodnor: Hills 2008 94.00 93.0 230,513,000 185,587,277
37 Leaning Juniper 1 2006 100.00 100.0 201,665,000 179,254,420
38 Marengcr 2007 140.40 132.0 336,426,00C 242,815,922
39 Marengo ll 2008 70.20 68.0 164,436,00C 130,336,135
40 Seven lvlile Hill 2008 99.00 99.0 348,285,00C 201,875,938
41 Seven Nlile Hill ll 2008 19.50 19.5 73,738,00C 42,718,778
42 High Plains 2009 99.00 99.0 327,035,000 220,691,336
43 McFaddr:n Ridge I 2009 28.50 28.5 100,324,000 57 ,381,213
44
45 Solar:
46 2012 2.00 2.0 4,1 1 3,000 74,986
FERC FORM NO.1 (REV. 1243)Page 410
Licensed Proj. No.
East 2082
Veyo
West Sii{le 2082
Keno Regulating Dam 2082
Upper Klamath Lake 2082
North tJrnpqua 1927
Lifton
\Mnd:
Foote Oreek
Black Cap
Name
PacifiCorp (1)
(2)
Original
Resubmission
Date of Reoort
(Mo, Da, Yi)tl
Year/Period of Report
End of 20181Q4
3. List plants appropriately under subheadings for steam, hydro, nuclear, intemal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. lf net peak demand for 60 minutes is not available, give the which is available, specifing period. 5. lf any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (lncl Asset
Retire. Costs) Per MW
(s)
Operation
Exc'l. Fuel
(h)
Production Expenses
Kind of Fuel
(k)
Fuel Costs (in cents
(per Million Btu)
(t)
Line
No.Fuel
(D
Maintenance
o
1
5,075,973 444,252 134,798 Water 2
2,096,030 95,041 42,971 Water 3
2,333,727 315,476 65,349 Water 4
715,9s3 264,668 't 1'1 ,666 Water 5
622,405 47.027 5,437 Water 6
960,099 137,333 17,370 Water 7
2,630,641 1 87,994 -5,143 Water 8
910,727 49,770 70,'t78 Water I
1 ,810,661 182,633 14,058 Water 10
638,868 69,060 9,616 Water 11
2,309,655 493,215 75,013 Waler 12
1,421,397 117,563 70,656 Water 13
1,268,662 242,552 261 ,016 Water 14
2,409,792 40,7U 29,181 Water 15
1,174,',t01 59.774 60,629 Water 16
1,953,373 203,706 9,883 Water 17
1,798,360 74,495 212,980 Water 18
1,665,020 88,273 21,577 Water 19
2,983,977 261,492 13,880 Water 20
1,007,137 351,561 1 9,1 64 Water 21
815,583 9,860 322 Water 22
2'.t.652 8,184 23
267,236 48,559 24
25
26
27
-6,975,807 255,670 25,083 Water 28
29
30
2,180,212 237,653 1,173,502 Wind 31
1,187,733 429,264 1,316,345 Wind 32
2,049,650 226,080 1,557,499 Wind 33
2,265,503 92,455 249,637 Wind 34
2,068,750 212,518 633,695 Wind 35
1,974,333 577,377 1 ,I 30,320 Wnd 36
1,792,544 '1,004,517 946,663 Wind 37
'l ,729,458 1,254,830 1 ,1 95,256 Wnd 38
1,856,640 636,941 597,628 Wnd 39
2,039,151 478,611 1,102,825 Wnd 40
2,190,707 89,232 217,223 Wind 41
2,229,205 1,023,684 1,231,800 \Mnd 42
2,013,376 289,2U 339,358 \Mnd 43
44
45
37,493 416,670 Solar 46
FERC FORM NO. I (REV. 12-03)Page 411
Name of Respondent
PaciliCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
410 No.:1 Column: a
Comrnon ver system costs for the operation of these facilities are allocated to eachplan-- based upon the unit's name plate rating.
This footnote applies to all hydroelectric generating facilities with current generation.
All or some of the renewabl-e energy attributes associated with generation from Lhese
gene:rating facilities may be: (a) used in future years to comply with renewabl-e portfolio
standards or other regulatory reguirements or (b) sold to third parties in the form of
rener,vable credits or other environmental commodities.
llast S de plant was s 1 icantly curtailed pursuant to Section 6.2 of the Klamathlectric Settlement in FERC Docket No. P-2082-000.
ant rat was curtailed in 2018 due to a water resources.
The l^Iest Si-de plant generat suppl s stat use and was s f cantly curtpur$uant to Section 6.2 of the Klamath Hydroelectric Settlement Agreement in FERC Docket
No. ll-2082-000.
Use<1 regulat the re seo water rom t t ng proper water
surface 1eve1 in the Klamath River between Klamath Fal-l-s and Keno
Sto::age reservoir for s P ts on ver Copco No. 1,, Copco No. 2, East
Side, West Side, ,JC and Iron Gate
Reprr:sents facilities that support No Umpqua ver system ects common
roacls,houses, control etc. are i-n this account
Usecl in regulating the release of water from Bear Lake and t ng proper water
surface 1eve1 in the Bear River near st. Charles Idaho
Common costs for the operat of these fac 1 t es are allocated to each plant upon
the rrnit's name plate rating.
This footnote applies to all wind-powered generating facilities with current generation.
A11 or some of the renewable energy attributes associated with generation from these
gene::ating facilities may be: (a) used in future years to comply with renewable portfolio
stan<lards or ot.her regulatory requirements or (b) sold to third parties in the form of
rener^rab1e credits or other environmental commodities
The Iloote Creek wind-powered generat fac 1 ty s operated by Pac f Corp and S o t
owne<1 by PacifiCorp and Eugene water and Electric Board with an undivided interest of
78.792 a::d 21-.21-Z ctivel . Data ed ts Pacifi 's share
Pac Corp has an agreement t Citizens Asset Fj-nance, Inc. to lease the Black Cap Solar
gene::ating facility. The lease has a 15-year term from October 2012 Lo october 2028 and is
accorrnted for as an operating 1ease.
FERC FORM NO. r (ED. 12-871 Page 450.1
410 Line No.:6 Column: a
410 Line No.: 18 Column: a
410 Line No.:22 Column: a
410 Line No.:23 Column: a
410 Line No.:24 Column: a
410 Line No.:25 Column: a
410 Line No.: 28 Column: a
410 Line No.: 30 Column: a
410 Line No.:32 Column: a
410 Line No.:46 Column: a
PacifiCorp (1)
(2)
Original (Mo, Da,
Resubmission tt
Year/Period of Report
End of 20181Q4
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 include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which planl costs are included in Account 't 21 , 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) tower; or
(4) underground construction lf a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (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 which is
reporled for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). ln a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION VULIAGE (KV)(lndicate wtierdbther than
60 cvcle. 3 Dhase)
Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the dase.ofunderoround lrnesreport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
un ulruclureof LineDesionated
to
un Slruquresof AnolherLine
(s)
1
2 DIXONVILLE sOOKV, OR 500.00 500.00 Steel Tower 58.00 1
3 CAPTAIN JACK, OR MALIN, OR 500.00 500.00 Steel Tower 7.00 1
4 MERIDIAN, OR 500.00 500.00 Steel Tower 74.00 1
E KLAMATH CO-GEN, OR CAPTAIN JACK, OR 500.00 500.00 Steel Tower 26.00 1
6 MALIN, OR PG&E ROUND MTN, CA 500.00 500.00 Steel Tower 47.00 1
7 MERIDIAN, OR KLAMATH CO-GEN, OR 500.00 500.00 Steel Torver 58.00 I
I MALIN, OR 500.00 500.00 Steel Torver 447.00 1
9 SWTCHYARD, MT 500 00 500.00 Steel Totrvet 2.00 1
10 BROADVIEWA, MT 500.00 500.00 Steel Tower I 12.00 1
11 BROADVIEW B, MT 500.00 500.00 Steel Tower 1 16.00 1
12 TO!\NSEND A, MT 500.0c 500.00 Steel Tower 133.00 1
13 TO!\NSEND B, MT 500.0c 500.00 Steel Tower 133.00 1
14 500kV costs and expenses
15 Subtotal 500kV 1,213.00 12
16
17 gOTH SOUTH, UT CAMP WILLIAMS #3, UT 345.0C 345.00 Steel - SP 1 1.00 1
'18 gOTH SOUTH, UT CAMP WILLIAMS #4, UT 345.0C 345.00 I 1.00 I
'19 gOTH SOUTH, UT CAMPWLLIAMS#1, UT 345.0C 345.00 Steel - SP 1 1.00 I
20 gOTH SOUTH, UT TERMINAL, UT 345.0C 34s.00 16.00 1
21 BEN LOMOND, UT POPULUS#1,ID 345.0C 345.00 82.00 1
22 BEN LOMOND, UT POPULUS #2, ID 345.0C 345.00 Steel - SP 86 00 1
23 BEN LOMOND, UT CAMP WLLIAMS, UT 345.0C 345.00 Steel - SP 69 00 1
24 BEN LOMOND, UT TERMINAL #2, UT 345.0C 345.00 47.00 1
25 BEN LOMOND, UT TERMINAL#1, UT 345.0C 345.00 Steel - SP 47.00 1
26 MIDPOINT#1,ID 345.0C 345.00 Wood - H 83.00 1
27 MIDPOINT #2, ID 345.0(345.00 Wood - H 78.00 1
28 CAMP WLLIAMS, UT MONA#3, UT 345.0(345.00 Wood - H 47.00 1
29 CAMP WLLIAMS, UT MONA#1, UT 345.0(345.00 Wood - H 47.00 1
30 CAMP WLLIAMS, UT MONA #2, UT 345.0(345.00 Steel Tower 47.00 1
3'l CAMP WLLIAMS, UT MONA #4 UT 345.0(345.00 5.00 42.00 1
32 CLOVER, UT OQUIRRH, UT 345.0(345.00 Steel Tower 100.00 1
JJ CURRANT CREEK, UT MONA, UT 345.0(345.00 Steel - SP 1.00 1
34 EMERY, UT CAMP WLLIAMS, UT 345.0(345.00 Steel Tower 121.00 1
35 EMERY, UT HUNTINGTON, UT 345.0(345.00 Wood - H 20.00 1
36 TOTAL 1 6,928.0C 6s1.00 285
FERC FORM NO. I (ED. 12-87)Page 422
ALVEY, OR
DIXONVILLE, OR
MIDPOINT, ID
COLSTRIP 4, MT
COLSTRIP, MT
COLSTRIP. MT
BROADVIEW MT
BROADVIEW MT
BORAH, ID
BORAH, ID
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
TRANSMISSION LINE STATISTICS
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles ol tlle primary structure in column (0 and the pole miles of the other line(s) in column (g)
8. Designate ,any transmission line or portion thereof for which lhe respondent is not the sole owner. lf such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondert is not the sole owler but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangemenl and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affecled. Speci! whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Sipeciry whether lessee is an associated company.
10. Base the ;clant cost figures called for in columns [) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(D
cosT oF LINE (lndude rn L;olumn u) Lano,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
(i)
Construction and
Other Costs(k)
Total Cost
(D
Operation
Expenses
(m)
Maintenance
Expenses(n)
Rents
(o)
Total
Exne;ses
1
l-2250 AAC /91 2
l-1272 ACSR 36/r 3
3-1272 ACSR 36/t 4
3-1272 ACSR 54/t9 6
l-1852 ACSR 51/:17 6
l-1272 ACSR 54fl9 7
l-1272 ACSR 36/l 8
/95 KCM ACSR 9
/95 ACSR 26r/10
795 ACSR 26n 11
/95 ACSR 26/7 12
/95 ACSR 26/7 13
13,339,69(237,124,882 250,464,581 449 1,463,566 330,667 1,794,682 14
13,339,69(237,124,882 250,464,581 449 1,463,566 330,667 1,794,682 15
16
17
18
1272 ACSR 45/7 19
t272 ACSR 45/7 20
1272 ACSR 45/7 21
1272 ACSR 45/7 22
t272 ACSR 45r',23
t272 ACSR 45/7 24
t272 ACSR 45/i 25
t272 ACSR 45/7 26
1272 ACSR 45/7 27
154 ACSR 45/7 28
1272 ACSR 45/7 29
154 ACSR 45i7 30
t54 ACSR 45/7 31
1949 ACSR 45/7 32
154 ACSR 54r/aa
1272 ACSR 45/7 34
,54 ACSR 45/7 35
245,939,765 3,522,864,268 3,768,804,033 864,557 16,229,553 2,138,34a 19,232,45!36
FERC FORM NO.1 (ED.12-87)Page 423
Name of Respondent
PacifiCorp
This
(1)
(2)
ls:
Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
tt
Year/Period of Report
End of 20181Q4
TRANSMISSION LINE STATISTICS
1 . Report information concerning transmission lines, cost of lines, and expenses for year. Lisl each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. 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) tower; or
(4) underground construction lf a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (D and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on struclures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). ln a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reporled forthe line designated.
Line
No.
IJESIGNAIION Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the dase.ofunderoround ltnes
report 6ircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
UN iJIofDesii
i
JClUreinelated
on Sructuresof AnotherLine
(s)
1 EMERY, UT SIGURD #1, UT 345.00 345.00 Steel - H 74.00 1
2 EMERY, UT SIGURD #2, UT 345.00 345.00 Steel - H 75.00 1
3 FOUR CORNERS, NM PINTO, UT 345.00 345.00 Wood - H 101.00 I
4 KINPORT, ID 345.00 345.00 Wood - H 41.00 1
5 HUNTINGTON, UT HUNT PLANT 1. UT 345.00 345.00 Steel Tower 1.00 1
6 HUNTINGTON, UT HUNT PLANT 2, UT 345.00 345.00 Steel Tower 1.00 1
7 HUNTINGTON, UT PINTO, UT 345.00 345.00 Steel - SP 158.00 1
I HUNTINGTON, UT SPANISH FORK, UT 345.00 345.00 Steel Tower 78.00 1
I GOSHEN, ID 345.0C 345.00 Steel Tolver 220.00 1
10 BORAH, ID 345.0C 345.00 Steel Tower 240.00 1
11 KINPORT, ID 345.0C 345.00 Steel - SP 234.00 1
12 MIDPOINT. ID 345.0C 345.00 Steel - SP 113.00 1
13 MONA, UT SIGURD #1, UT 345.0C 345.00 Wood - H 69.00 1
14 MONA, UT SIGURD #2, UT 345.0C 34s.00 Steel - SP 69.00 1
'15 MONA, UT HUNTINGTON, UT 34s.0c 345.00 Steel - SP 60.00 1
16 RED BUTTE, UT SIGURD, UT 345.0t 345.00 Steel - H 170.00 1
17 SIGURD, UT UT/NV STATE LINE 345.0C 345.00 Steel Tower 190.00 1
18 SPANISH FORK, UT CAMP WILLIAMS, UT 345.0C 345.00 35.00 1
19 TERMINAL, UT BORAH, ID 345.0C 345.00 Wood - H 138.00 1
20 TERMINAL, UT BORAH,ID 345.0C 345.00 Steel - SP 47.00 1
21 TERMINAL, UT CAMP WILLIAMS #2, UT 345.0C 345.00 Steel - SP 16.00 10.00 1
22 TERMINAL, UT CAMP WLLIAMS, UT 345.0(345.00 23.00 1
23 345kV costs and expenses
24 Subtotal 345kV 2,752.04 382.00 41
25
26 ALVEY, OR DIXONVILLE, OR 230.0(230.00 Wood - H 59.00 1
27 ANTELOPE, ID ANACONDA, MT 230.0(230.00 Wood - H 76.00 1
28 ANTELOPE, ID LOST RIVER, ID 230.0(230.00 Wood - H 20.00 1
29 ARROWHEAD, \AAT FIREHOLE, \AAT 230.0(230.00 Wood - H 9.00 I
30 ATLANTIC CITY, \AAT COLUMBIA GENEVA, \AA/230.0(230.00 Wood - H 1.0c 1
31 BEN LOMOND, UT NAUGHTON #1, WY 230,0(230 00 Wood - H 88.0C 1
32 BEN LOMOND, UT NAUGHTON #2, WY 230.0(230.00 Wood - H 88,0C 1
33 BIRCH CREEK, UT RAILROAD, \AAT 230.0(230.00 Wood - H 19.00 1
34 BITTER CREEK, WY MONELL, \AAT 230.0(230.00 Wood - H 3.00 I
35 BRIDGER PUMP, WY MANS FACE, WY 230.00 230.00 Wood - H 1.00 1
36 TOTAL 16,928.00 651.00 285
FERC FORM NO. 1 (ED. 12-87)Page 422.1
GOSHEN, ID
JIM BRIDGER, \AAT
JIM BRIDGER, \M1
JIM BRIDGER, \ATY
KINPORT, ID
PacifiCorp t2)Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20'l8lQ4
7. Do nol report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles ol the primary structure in column (f1 and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. lf such property is leased fiom another company,
give name ol'lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondert is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangemenl and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owrer, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Speciff whether lessor, co-owler, or other party is
an associated company.
9. Designate iany transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Sipecify whether lessee is an associated company.
1 0. Base the plant cost figures called for in columns O to (l) on the book cost at end of year.
Size of
Conductor
and Material
(D
U(.)S I ()l- LINE (rncruoe rn uorumn u) Land,
Land rights, and clearing rightof-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
0)
Construction and
Other Costs(k)
Total Cost
o
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses
(p)
154 ACSR 45/7 1
354 ACSR 54/7 2
/95 ACSR 45i7
795 ACSR 26/7 4
2156 ACSR 841 I
2156 ACSR 8419 6
795 ACSR 45/7 7
1272 ACSR 45'8
1272 ACSR 36/1 o
1272 ACSR 36/1 10
1272 ACSR 36/1 11
1272 ACSR 45/7 12
/95 ACSR 45r/13
154 ACSR 45tl 14
154 ACSR 54r 15
2-954 ACSR 45//16
154 ACSR 54/7 17
1272 ACSR 45''18
2-954 ACSR 45/7 19
2-1272 ACSR 45,r',20
1272 ACSR 45n 21
1272 ACSR 45n 22
1 52,61s,16S 1,659,942,00C '1,812,557,169 339,884 2,022,182 521,772 2,883,83t 23
152,6't5,169 1,659,942,00C 1,81 2,557,169 339,884 2,022,182 521,772 2,883,83t 24
25
r272 ACSR 36/1 26
1272 ACSR 45/7 27
/95 ACSR 45/7 28
/95 ACSR 26/7 29
1272 ACSR 36/1 30
/95 ACSR 26/7 31
/95 ACSR 26/7 32
154 ACSR 54/7 33
I95 ACSR 26/7 34
1272 ACSR 36/'l J5
245,939,765 3,522,864,268 3,768,804,03:864,55i 1 6,229,553 2,1 38,345 19,232,45!36
FERC FORM NO. I (ED. 12-87)Page 423.1
TRANSMISSION LINE STATISTICS
PacifiCorp (1)
(2)
Original (Mo, Da,
Resubmission tt
Year/Period of Report
End of 20181Q4
TRANSMISSION LINE STATISTICS
I . Report information concerning 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 include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. 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) tower; or
(4) underground construction lf a transmission line has more lhan one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (0 and (g) the total pole miles of each transmission line. Show in column (D the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on slructures the cosl of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). ln a footnote, explain the basis of such occupancy and state whether expenses with
respect to such slructures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION VOLTAGE (KV)
(lndicate wtierdbther than
60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENGTH (POIE MiIES)(ln the tase.ofunderoroun0 lrnesreport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
UN UITUqUTEof LineDesionated(o
un Slrucluresof AnotherLine
(s)
1 BUFFALO, WY CASPER, v1l/230.0(230.00 Wood - H 107.00 1
2 DAVE JOHNSTON, \AI/230.0(230.00 Wood - H 36 00 1
3 CASPER, WY RIVERTON, \A/Y 230.0(230.00 Wood - H 110.00 1
4 CHAPPEL CREEK, \AI/CRAVEN CREEK, \A/Y 230.0(230.00 Steel - SP 30.0c 1
5 CHAPPEL CREEK, \A/Y JONAH GAS, WY 230.0(230.00 Wood - H 32,0C 1
6 CHAPPEL CREEK, \^'Y RILEY RIDGE, WY 230.0(230.00 Wood - H 29.0C 6.00 1
7 CRAVEN CREEK, \A/Y PIONEER, \MT 230.0(230.00 Wood - H 2.00 1
8 DAVE JOHNSTON, \AI/SPENCE, \MT 230.0(230.00 Wood - H 31.00 1
9 DAVE JOHNSTON, \MT WYODAK, WY 230 0(230.00 Wood - H 69.0C 1
10 DIXONVILLE sOOKV, OR DIXONVILLE 23OKV, OR 230.0t 230.00 Wood - H 1.00 1
11 DIXONVILLE, OR RESTON (BPA), OR 230.0(230.00 Wood - H 17.00 1
12 FAIRVIEW (BPA), OR ISTHMUS, OR 230.0(230.00 Wood - H 12.00 I
13 FIREHOLE, \AAT MONUMENT, WY 230.0(230.00 Wood - H 49.00 1
14 FRY, OR BETHEL, OR 230.0(230.00 Wood - H 26.00 1
'15 FRY, OR ALVEY, OR 230.0(230.00 Wood - H 45.00 1
'16 GLEN CANYON, AZ SIGURD, UT 230.0(230.00 Wood - H 1s9.00 1
17 PAVANT, UT 230 0(230.00 Wood - H 98.00 1
18 DIXONVILLE, OR GRANTS PASS, OR 230 0(230.00 Wood - H 62.00 1
19 HIGH PLAINS, \AI/STANDPIPE, WY 230,00 230 00 Wood - H 38.00 1
20 WALLAWALLA, WA 230.00 230.00 Wood - H 78.00 1
21 JIM BRIDGER, \AA/ROCK SPRINGS, \A/Y 230.00 230.00 Wood - H 35.00 1
22 JIM BRIDGER, \ffT SPENCE, WY 230.00 230.00 Wood - H 149 00 1
23 KLAMATH FALLS, OR MALIN, OR 230.00 230.00 Wood - H 36.00 1
24 LIMA, \A/Y ROBERSON, WY 230.00 230.00 Wood - H 200 1
25 LONE PINE, OR KLAMATH FALLS, OR 230.00 230.00 Wood - H 76.00 1
26 LONE PINE, OR MERIDIAN #1, OR 230.00 230.00 Steel - SP 5.00 1
27 LONE PINE, OR MERIDIAN #2, OR 230.00 230.00 Steel - SP 5.00 1
28 MCNARY (BPA), WA WALLAWALLA, WA 230.00 230.00 Wood - H 56.00 1
29 MERIDIAN, OR GRANTS PASS, OR 230.00 230.00 Wood - H 35.00 I
30 MONUMENT, \AAT EXXON, WY 230.00 230.00 Wood - H 13.00 1
31 MONUMENT, WY CRAVEN CREEK, \A/Y 230.0c 230.00 Wood - H 20.00 1
32 NAUGHTON, \MT TREASURETON, ID 230.0c 230.00 Wood - H 80.00 1
33 NAUGHTON, \AAT MONUMENT, \AAT 230.0c 230.00 Wood - H 30.00 1
34 NAUGHTON, WY CRAVEN CREEK, WY 230.0c 230.00 Wood - H 16.00 I
35 PALISADES SS, WY BLUE RIM, WY 230.0c 230.00 Wood - H 4.00 1
36 TOTAL 1 6,928.00 651.00 285
FERC FORM NO. 1 (ED. 12-87)Page 422.2
CASPER, \A/Y
GONDER, UT-NVSTATE
HURRICANE, OR
Name of Respondent
PacifiCorp
(1)
(2')
Original (Mo,
ltResubmission
Year/Period of Report
End of 2018/Q4
TRANSMISSION LINE STATISTICS
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles ol the primary structure in column (0 and the pole miles of the other line(s) in column (g)
8. Designate ,any lransmission line or portion thereof for which the respondent is not the sole owner. lf such property is leased ftom another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation ol furnish a succinct statement explaining the
anangemenl and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts afiected. Speciry whether lessor, co-owner, or other party is
an associated company.
9. Designate ;any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Sipeciry lvhether lessee is an associated company.
10. Base the plant cost figures called for in columns (D to (l) on the book cost at end ofyear.
Size of
Conductor
and Material
(i)
COST OF LINE (lnclude in Column U) Land,
Land rights, and clearing rightof-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
No.
Land
0)
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses(m)
Maintenance
Expenses(n)
Rents
(o)
Total
Expenses
r272 ACSR 36/1 1
2
1272 ACSR 36/1 2
154 ACSR 54/7 4
1272 ACSR 45/7 5
1272 ACSR 45/7 b
1272 ACSR 45/7 7
1272 ACSR 45/7 I
t272 ACSR 36/1 9
1272 ACSR 36/1 10
/95 ACSR 26/7 11
1272 ACSR 36/1 12
t272 ACSR 45n 13
t272 ACSR 36/1 14
t272 ACSR 36/1 15
154 ACSR 45Il 't6
I95 ACSR 45/7 17
t272 ACSR 36/1 18
t272 ACSR 45n '19
1272 ACSR 36/1 20
1272 ACSR 45/7 21
1272 ACSR 36/1 22
t272 ACSR 36/1 23
1272 ACSR 45i7 24
795 ACSR 26r 25
1272 ACSR 54/1 I 26
1272 ACSR 36/1 27
1272 ACSR 36/1 28
1272 ACSR 36/1 29
1272 ACSR 36/1 30
1272 ACSR 45/7 31
1272 ACSR 45r/32
1272 ACSR 36/1 JJ
]54 ACSR 54/7 34
1272 ACSR 36/1 35
245,939,765 3,522,864,268 3,768,804,033 864,557 16,229,553 2,138,345 19,232,45t 36
FERC FORM NO. I (ED. 12-87)Page 423.2
PacifiCorp (1)
(2)
Original (Mo, Da,
Resubmission tt
Year/Period of Report
End of 20181Q4
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. lndicate whether the type of supporting struclure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground conslruction lf a lransmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (0 and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of vvhich is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). ln a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
DESIGNATION VOLTAGE (KV)
(lndicate wtierdbther than
60 cvcle. 3 Dhase)
Type of
Supporting
Slructure
(e)
LENGTH (Pole miles)(ln the tase.ofunderoroun0 ltnes
report Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
UN DIofDesit
uclure
.inenated
)
UN DITUCIUTESof AnotherLine(s)
1 PAROWAN VALLEY, UT SIGURD, UT 230.0(230 00 Wood - H 94.00 I
2 PAROWAN VALLEY, UT WEST CEDAR, UT 230,0(230.00 Wood - H 26.00 1
3 PAVANT, UT SIGURD, UT 230.0(230.00 Wood - H 43.0C 1
4 POINT OF ROCKS, \AAT DAVE JOHNSTON, WY 230.0(230.00 Wood - H 209,0c 1
5 POMONA, WA UNION GAP, WA 230.00 230.00 Wood - H 7.00 I
6 RIVERTON, \ffY ROCK SPRINGS, \M/230.00 230.00 Wood - H 118.0C 1
7 RIVERTON, \Ary THERMOPOLIS, \AI/230.00 230.00 Wood - H 51.0C 1
8 ROCK SPRINGS, \A/Y FLAMING GORGE, UT 230.00 230.00 Wood - H 55.00 1
9 ROCK SPRINGS, WY JIM BRIDGER, WY 230.00 230.00 Wood - H 35.00 1
10 ROCK SPRINGS, WY MONUMENT, \^l/230.00 230.00 Wood - H 41.00 1
11 SHERIDAN (MDU), WY BUFFALO, WY 230.00 230.00 Wood - H 40.00 1
12 SHERIDAN (MDU), WY YELLOWTAIL, MT 230,0c 230.00 Wood - H 62.00 1
13 SHIRLEY BASIN, WY DUNLAP RANCH, \MY 230.0c 230.00 Wood - H 12.00 I
14 SWFTNO. 1,WA SWFT NO.2, WA 230.0c 230.00 Wood - H 2.00 1
15 SWFT NO.2, WA WOODLAND (BPA) SS, WA 230.0c 230.00 Wood - H 23,00 1
16 TALBOT, WA MARENGO II, WA 230.0c 230.00 Wood - H 7.00 I
17 TAP TO HANNA, OR NICKEL MOUNTAIN, OR 230 0c 230.00 Wood - H 9.00 1
18 THERMOPOLIS, W/YELLOWTAIL, MT 230.0c 230.00 Wood - H 176.00 1
19 TREASURETON, ID BRADY, ID 230.0c 230.00 Wood - H 66.00 I
20 TROUTDALE (BPA), OR GRESHAM (PGE), OR 230.0c 230.00 Steel Tower 6.00 1
21 TROUTDALE (BPA), OR LINNEMAN (PGE), OR 230.0(230.00 7.00 1
22 UNION GAP, WA MIDWAY (BPA), WA 230.0(230.00 Wood - H 39.00 1
t5 WALLAWALLA, WA LEWISTON (AVISTA), ID 230.0(230.00 Wood - H 45.00 I
24 WALLAWALLA, WA WANAPUM (GPUD), WA 230.0(230.00 Wood - H 33 00 1
25 WANAPUM (GPUD), WA POMONA, WA 230.0(230.00 Wood - H 37.00 1
26 WNDSTAR, WY GLENROCK, WY 230.0(230.00 Wood - H 13.00 1
27 WYODAK, WY BUFFALO, \MT 230.0(230.00 Wood - H 69.00 1
28 YAMSAY (BPA), OR KLAMATH FALLS, OR 230.0(230.00 Wood - H 63.00 1
29 230kV costs and expenses
30 Subtotal 230kV 3,338.00 13.00 aa
31
32 GOSHEN, ID 161.0(161.00 Wood - H 45.00 1
33 JEFFERSON, ID 161.0(161.00 Wood - H 21.00 1
34 BONNEVILLE, ID EAGLEROCK, ID 161.0(161.00 Wood - SP 9.00 I
35 EAGLEROCK, ID GOSHEN, ID 161 00 161.00 Wood - H 15.00 1
36 TOTAL 1 6,928.00 65'1.00 285
FERC FORM NO. r (ED. r2-87)Page 422.3
ANTELOPE, ID
BIG GRASSY, ID
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn orisinal(2) ;-1A Resubmission
Date of ReDort(Mo, Da, Yi)tt
Year/Period of Report
End of 20181Q4
7. Do not rep,)rt the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles ol the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. lf such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any lransmission line other than a leased line, or portion thereof, for which
the responderrt is nol the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matlers as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, ernd how the expenses borne by the respondent are accounted for, and accounts affected. Speciff whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Sipecify whether lessee is an associated company.
10. Base the clanl cost figures called for in columns O to (l) on the book cost at end ofyear.
Size of
Conduclor
and Material
(D
COST OF LINE (lnclude in Column U) Land,
Land rights, and clearing rightof-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
0)
Construction and
Other Costs
(k)
Total Cost
o
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses(p)
795 ACSR 45fl 1
795 ACSR 45/7 2
795 ACSR 45/7 2
1272 ACSR 36/1 4
1272 ACSR 36/1 q
1272 ACSR 36/1 b
1272 ACSR 36/1 7
1272 ACSR 36/'l
1272 ACSR 36/1 o
'1272 ACSR 36/1 10
795 ACSR 26/7 11
795 ACSR 26r 12
795 ACSR 26'13
954 ACSR 4sl7 14
954 ACSR 45/7 15
795 ACSR 26/7 16
795 ACSR 26/7 17
1272 ACSR 36/1 18
795 ACSR 26r 19
354 ACSR 45'20
300 AcsR 54/7 21
354 ACSR 45/7 22
1272 ACSR 36/1 23
1272 ACSR 36/1 24
1272 ACSR 36/1 25
1272 ACSR4Sn 26
1272 ACSR 36/1 27
/95 ACSR 26/7 28
19,999,28(399,993,714 41 9,992,994 82,576 2,482,173 389,978 2,9t4,727 29
19,999,280 399,993,714 419,992,99{82,576 2,482,173 389,978 2,954,727 30
31
397.5 ACSR 26/i 32
250HH CU /7 11
]54 ACSR 45/7 34
1272 ACSR 45/7 35
245,939,765 3,522,864,268 3,768,804,033 864,55i 16,229,553 2,1 38,345 19,232,45a 36
FERC FORM NO. 1 (EO. 12-87)Page 423.3
IRANSMISSION
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn orlsinat(2) [lA Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
TRANSMISSION LINE STATISTICS
1 . Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for wtrich 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) tower; or
(4) underground construction lf a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and exlra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (0 and (g) the total pole miles of each transmission line. Show in column (0 the pole miles of line on structures lhe cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). ln a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
UESIGNAIIUN VULIAGE (KV)(lndicate wtierebther than
60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the Lase.ofunderoroun0 ltnes
report Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
UN UIofDesi,
un brrucruresof AnotherLine(s)
1 GOSHEN,ID GRACE, ID 161.0(161.00 Wood - H 57.00 1
2 JEFFERSON,ID 16 1 .0(161.00 Wood - H 30.00 1
3 GOSHEN, ID RIGBY, ID 161.0(161.00 Wood - H 31.00 1
4 GOSHEN, ID SUGAR MILL, ID 161.0(161.00 Wood - SP 17.00 I
5 RIGBY,ID JEFFERSON, ID 161.0(161.00 Wood - SP 18.00 1
b SUGARMILL,ID RIGBY, ID 161.0(161.00 Wood - SP 17.00 1
7 YELLOWTAIL, MT RIMROCK, MT 161.0(16'1.00 Wood - H 46.0C 1
8 'l61kV costs and expenses
I Subtotal 161kV 255.00 51.00 11
10
11 gOTH SOUTH, UT DUMAS #1. UT 138.00 138.00 Wood - H 12,00 1
12 gOTH SOUTH, UT DUMAS #2, UT 138.00 138.00 Wood - H 6,00 1
'13 gOTH SOUTH, UT OQUIRRH, UT 138.00 138.00 Wood - SP 10.00 1
14 gOTH SOUTH, UT SANDY, UT 138.00 138.00 Steel - SP 1.00 1
15 ABAJO, UT PINTO, UT 138.0C 138.00 Wood - H 44.00 1
'16 ABAJO, UT RESOLUTE, UT 138.0C 138.00 Wood - SP 10.00 1
17 AGRIUM, UT THREEMILE KNOLL, ID 138.0C 138.00 Wood - H 4.00 1
18 ANSCHTZ CO-GEN, \A/Y EVANSTON, \MT 138.0C 138.00 Wood - H 22.00 1
19 SCOVILLE #1, ID 138.0C 138.00 Wood - H 1 .00 1
20 SCOVILLE #2, ID 138.0C 138.00 Wood - H 1.00 1
21 ASHGROVE, UT CLOVER, UT 138 0C 138.00 Wood - H 26 00 1
22 ASHLEY, UT CARBON, UT 138.0(138.00 Wood - H 102.00 1
23 ASHLEY, UT VERNAL, UT 138.0(138.00 Wood - H 12.00 1
24 BANGERTER, UT OQUIRRH, UT 138.0(138.00 Wood - H 6.00 1
25 BARNEYS, UT GRINDING, UT 138.0t 138.00 Wood - SP 1.00 I
26 BDO, UT BDO TAP, UT 138.0(138.00 Wood - SP 1.00 1
27 BEN LOMOND, UT ANGEL, UT 138.0(138.00 Steel - SP 27.04 1
28 BEN LOMOND, UT BRIGHAM CITY, UT 138.0(138.00 Wood - H 14.00 1
29 BEN LOMOND #1, UT EL MONTE, UT 138.0(138.00 Steel - SP 14.00 1
30 BEN LOMOND #2, UT EL MONTE, UT 138.0(138.00 13.00 I
31 BEN LOMOND, UT HONEWILLE, UT 138.0(138.00 Steel Tower 22.04 1
32 BEN LOMOND, UT SYRACUSE #1, UT 138.0(230.00 Steel Tower 7.0c 13.00 1
33 BEN LOMOND, UT SYRACUSE, UT 138 0(138.00 Steel Tower 58.0C 1
34 BEN LOMOND, UT WZIRCONIUM, UT 138.00 138.00 Wood - SP 14.00 1
35 BEN LOMOND, UT WHEELON, UT 138.00 138.00 Steel Tower 42.00 I
36 TOTAL 16,928,00 651.00 285
FERC FORM NO. r (ED. 12-87)Page 422.4
t(;tule
nelaled
GOSHEN, ID
ANTELOPE, ID
ANTELOPE, ID
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20'l8lQ4
7. Do not repr)rt the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f; and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. lf such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation ol furnish a succinct statemenl explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Speciry whether lessor, co-owner, or other party is
an associaled company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. $peciry whether lessee is an associated company.
1 0. Base the olant cost figures called for in columns O to (l) on the book cost at end of year.
Size of
Conductor
and Material
0
COST OF LINE (lnclude rn column 0) Land,
Land rights, and clearing rightof-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
No.
Land
(i)
Construction and
Other Costs(k)
Total Cost
o
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses(p)
250HH CU /7 I
250HH CU /7 2
t97.5 ACSR 26/7 I
/95 AAC /37 4
197.5 ACSR 26r/E
397.5 ACSR 26r/b
t56.5 ACSR 26r/7
661,22i 32,580,164 33,241,387 14,168 14',t,907 26,433 182,50t 8
661,22i 32,580,1 64 33,241,387 14,168 141,907 26,433 182,50t I
10
/95 AAC /37 11
/95 AAC i37 12
/95 ACSR 26/7 13
/95 AAC /37 14
197.5 ACSR 26'15
/95 ACSR 26/7 16
197.5 ACSR 26rl 17
/95 ACSR 26/7 18
397.5 ACSR 26Il 19
197.5 ACSR 26'20
197.5 ACSR 26[21
t97.5 ACSR 2617 22
t97.5 ACSR 26/,/23
24
1272 tAC t61 25
197.5 ACSR 26tr 26
397.5 ACSR 26/7 27
1272 ACSR4Sn 28
/95 ACSR 45r/29
/95 ACSR 45tl 30
250 CUHD /12 31
/95 AAC /37 32
1272 ACSR 45/7 33
/95 AAC /37 34
250 CUHD /12 35
245,939,765 3,522,864,268 3,768,804,033 864,55i 16,229,553 2,1 38,345 19,232,451 36
FERC FORM NO. 1 (ED.12.87)Page 423.4
PacifiCorp (2)Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
TRANSMISSION LINE STATISTICS
1 . Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 1 32
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which planl 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) tower; or
(4) underground construction lf a transmission line has more than one type of supporting structure, indicale the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (0 the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). ln a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
IJESIGNAIION Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the tase.ofunderoroun0 ltnesreport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
un slrucluresof AnotherLine
(s)
1 BONANZA, UT CHAPITA, UT 138.0(138.00 Wood - H 9.00 1
2 BRIDGERLAND, UT GREEN CANYON, UT 138.0(138.00 Wood - SP 16.00 1
3 BRIGHAM CITY, UT WHEELON, UT 138.0(138.00 Wood - H 24.00 1
4 BUTLERVILLE, UT gOTH SOUTH, UT 138.0(138.00 Steel - SP 9.00 1
5 CAMERON, UT MILFORD, UT 138.0(138.00 Wood - SP 25.00 1
6 CAMERON, UT PAROWAN, UT 138.0(138.00 Wood - H 35.00 1
7 CAMERON, UT SIGURD, UT 138.0(138.00 Wood - H 65.00 I
I CANYON COMP, \AAT STR 204, WY 138.0(138.00 Wood - H 12.00 1
9 CARBON, UT HELPER#2, UT 138.00 138.00 Wood - H 2.00 1
10 CARBON, UT MOAB, UT 138.00 138.00 Wood - H 120.00 1
11 CARBON, UT SPANISH FORK#1, UT 138.00 138.00 Steel Tower 54.00 1
12 CARBON, UT SPANISH FORK #2, UT 138.00 138.00 Steel Tower 52.00 1
13 SAINT GEORGE, UT 138.00 138.00 Steel - SP 20.00 I
14 SAINT GEORGE, UT 138.00 138.00 Steel - SP 20.00 1
15 CLEAR CREEK, WY PAINTER, UT 138.00 138.00 Wood - SP 5.00 1
'16 CLOVER, UT 138.0C 138.00 Wood - SP 2.00 1
17 CLOVER, UT NEBO, UT 138.0C 138.00 Wood - SP 8.00 I
18 COLUMBIA, UT SUNNYSIDE, UT 138.0C 138.00 Wood - H 2.00 1
19 COTTONWOOD, UT HAMMER, UT 138.0C 138.00 Wood - SP 5.00 1
20 COTTONWOOD, UT MCCLELLAND, UT 138.0C 138.00 Steel - SP 6.00 I
2',!COTTONWOOD, UT SILVER CREEK, UT 138.0C 138.00 Wood - SP 30.00 I
22 CUTLER, UT \A/TIEELON, UT 138.0C 138.00 Wood - SP 1
23 DRY CREEK, UT SPANISH FORK, UT 138.0t 138.00 Steel - SP 5.00 1
24 DUMAS, UT WESTFIELD, UT 138.0(138.00 Wood - SP 19.00 1
25 DYNAMO, UT TR|-CtTY#1, UT 138.0(138.00 Steel - SP 2.00 1
26 DYNAMO, UT TRI-CITY #2, UT 138.0(138.00 3.00 1
27 EAGLE MOUNTAIN, UT PONY EXPRESS, UT 138.0(138.00 Wood - SP 10.00 1
28 EAST LAYTON, UT 105 TAP, UT 138.0(138 00 Steel - SP 15.00 1
29 EBAY TAP, UT OQUIRRH, UT 138.0(138.00 Wood - SP 1.00 1
30 EL MONTE, UT PIONEER, UT 138.0(138.00 Steel - SP 1.00 1
3'1 EL MONTE, UT EAST BANK, UT '138.0(138.00 Steel - SP 4.00 1
32 EVANSTON, WY RAILROAD, UT 138.0(138.00 Wood - SP 3.0c 1
33 FORT DOUGLAS, UT MCCLELLAND, UT 138.0(138.00 Wood - SP 3.00 1
34 FRANKLIN, ID GREEN CANYON, UT 138.0(138.00 Wood - SP 25.00 1
35 FRANKLIN,ID TREASURETON, ID 138.00 138.00 Wood - SP 10.00 1
36 TOTAL 1 6,928.00 651.00 285
FERC FORM NO. 1 (ED. 12-87)Page 422.5
o1Des
JUtUrtinerated
)
CENTRAL (UAMPS) #2, UT
CENTRAL (UAMPS) #3. UT
BURRASTON PONDS
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn orisinal(2) [-1A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
IRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles ol the primary structure in column (D and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. lf such property is leased fom another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any lransmission line other than a leased line, or portion thereof, for which
the respondert is not the sole owner but lvhich the respondent operales or shares in the operation of, furnish a succinct statement explaining the
arrangemenl and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate ,any transmission line leased lo another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Speciff Mrether lessee is an associated company.
10. Base the plant cost figures called for in columns O to (l) on the book cost at end ofyear.
Size of
Conductor
and Material
(i)
cosT oF LINE (lnclude in L;orumn 0) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
o
Construction and
Other Costs(k)
Total Cost
o
Operation
Expenses(m)
Maintenance
Expenses(n)
Rents
(o)
Total
Exo,e;ses
795 ACSR 26/7 I
1272 ACSR 45/7 2
795 ACSR 26/7
795 AAC /37 4
397.5 ACSR 26/7 E
397.5 ACSR 26/7 b
397.5 ACSR 26/7 7
795 ACSR 26/7 8
s56.5 ACSR 26i7 I
954 ACSR s4n 10
/95 ACSR 26/7 11
1272 ACSR 45r',12
1272 ACSR 45i7 13
1272 ACSR 45/7 14
/95 ACSR 26r/15
397.5 ACSR 26n 16
1272 ACSR 45i7 17
397.5 ACSR 26n 18
295 AAC /37 19
795 AAC /37 20
397.5 ACSR 2617 21
250 CUHD /'t2 22
1272 ACSR 45/i 23
/95 ACSR 26/7 24
I95 ACSR 26i7 25
/95 ACSR 26n 26
/95 ACSR 26i7 27
/95 ACSR 26/7 28
/9s ACSR 26i7 29
t272 ACSR 45r/30
t272 ACSR 45r/31
/9s ACSR 26/7 32
33
397.5 ACSR 26fl 34
/95 ACSR 26/7 35
245,939,765 3,s22,864,268 3,768,804,033 864,55i 16,229,553 2,138,341 19,232,45t 36
FERC FORtUt tio. I (ED. 12-87)Page 423.5
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5l1Rn orisinat(2) 1-1A Resubmission
Date of ReDort(Mo, Da, Yi)tt
Year/Period of Report
End of 20'l8lQ4
TRANSMISSION LINE STATISTICS
'l . Report information concerning 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 include all lines covered by the definition of transmission system planl as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. 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 construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished fom the remainder
of the line.
6. Report in columns (D and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). ln a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
UESI(jNAIIUN Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the base.ofunderoround linesreport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
un utrucrureof LineDesignated(0
un Slrucluresof AnotherLine
(s)
1 GADSBY, UT JORDAN, UT 138.0(138 00 Wood - SP 1
2 GADSBY, UT TERMINAL, UT 138.0(138.00 Wood - SP 6.00 I
3 GADSBY, UT THIRD WEST, UT 138.0(138.00 Wood - SP 1.00 1
4 GRAPHITE, UT MOUNTAIN VIEW, UT 138.0(138.00 Wood - SP 1.00 1
5 GREEN CANYON, UT NIBLEY, UT 138.0(138.00 Wood - SP 7.00 1
6 GREEN CANYON, UT WHEELON, UT 138.0(138.00 Wood - SP 19.00 1
7 GRINDING, UT OQUIRRH, UT 138.0('138.00 Wood - SP 3.00 1
8 GRINDING, UT TOOELE, UT 138.0(138.00 Wood - SP 14.00 1
I HALE, UT MIDWAY, UT 138.0(138.00 Wood - H 19.0C I
'10 HALE, UT SPANISH FORK, UT 't38.0(138.00 Wood - H 18.0C 1
11 HALE, UT TANNER, UT 138 0(138.00 Wood - H 7.0c 1
12 HAMMER, UT BUTLERVILLE, UT 138.00 138.00 2.00 1
13 HIGHLAND, UT BULL RIVER (LEHI #5), UT 138.00 138.00 Wood - SP 5.00 1
14 HONEWILLE, UT LAMPO, UT 138.00 138 00 Wood - H 25.00 1
15 HONEWILLE, UT WHEELON, UT 138.00 138.00 14.00 1
16 HUNTINGTON, UT MCFADDEN, UT 138.00 138.00 Wood - H 7.00 1
17 JERUSALEM, UT NEBO, UT 138.00 138.00 Wood - H 26.00 I
18 JORDAN, UT MCCLELLAND, UT 138.00 138.00 Wood - SP 5.00 1
19 JORDAN, UT TERMINAL, UT 138.0C 138.00 Wood - SP 6.00 I
20 JORDAN, UT THIRD WEST, UT 138.0C 138.00 Wood - SP 1.00 1
21 KEARNS, UT TAYLORSVILLE, UT 138.0C 138.00 Wood - SP 300 1
22 KEARNS, UT WEST VALLEY, UT 138.0C 138.00 Wood - SP 2.00 1
23 LONE PEAK, UT CAMP WLLIAMS, UT 138.0C '138.00 8.00 1
24 MCCLELLAND, UT MIDVALLEY, UT 138.0C '138.00 Wood - SP 6.00 I
25 MCFADDEN, UT BLACKHAWK, UT 138.0C 138.00 Wood - H 1 1.00 1
26 MID VALLEY, UT gOTH SOUTH, UT 138.0C 138.00 Wood - H 9.00 1
27 MID VALLEY #2, UT COTTONWOOD, UT 138.0C 138.00 Wood - SP 3.00 1
28 MIDVALLEY#1, UT COTTONWOOD, UT 138.0C 138.00 Wood - SP 5.00 1
29 MID VALLEY, UT TAYLORSVILLE, UT 138.0(138.00 Wood - SP 4.00 2.00 1
30 MIDDLETON, UT ST GEORGE, UT 138.0(138.00 Wood - H 1
31 MOAB, UT PINTO, UT 138.0(138.00 Wood - H 68.00 1
32 NAUGHTON, \AA/CANYON COMP, \AAT 138.0(138.00 Wood - H 35.00 1
33 NAUGHTON, WY PAINTER, \MT 138.0(138.00 Wood - H 44.00 1
34 NEBO, UT DRY CREEK, UT 138.0(138.00 Wood - H 33.00 1
35 NUCOR STEEL, UT WHEELON, UT 138.0(138.00 Wood - H 10.00 1
36 TOTAL 16,928.0C 651.00 285
FERC FORM NO. I (ED. 12-87)Page 422.6
(1)
(2)Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
TRANSMISSION LINE STATISTICS I
7. Do not report the same transmission line slructure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, reporl the
pole miles of the primary structure in column (0 and the pole miles of the other line(s) in column (g)
8. Designate ,any transmission line or portion thereof for which the respondent is not the sole owner. lf such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but wtich the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Speciry whether lessor, co-owner, or other party is
an associated company.L Designate iany transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Sipeci! whether lessee is an associated company.
1 0. Base the plant cost figures called for in columns O to (l) on the book cost al end of year.
Size of
Conductor
and Material
(i)
uos I oF LINE (lnduoe rn uolumn u) Lano,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
(j)
Construction and
Other Costs
(k)
Total Cost
o
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses(p)
I 272 ACSR 45r',I
1272 ACSR 45/7 2
1272 AAC t61 3
397.5 ACSR 26/7 4
t272 ACSR 45r',5
397.5 ACSR 26r 6
795 ACSR 45/7 7
795 ACSR 45/7 6
397.5 ACSR 26/7 9
1272 ACSR 45i7 10
1272 ACSR 45/i 11
/9s ACSR 26/7 12
1272 ACSR 45r',13
397.5 ACSR 26/7 14
250 CUHD /1 2 15
397.5 ACSR 26r/16
397.5 ACSR 26tr 17
/95 AAC /37 18
1272 AAC|q1 19
1272 A C 161 20
795 ACSR 26/7 21
22
1272 ACSR 45/7 23
795 P,AC26n 24
795 AAC 26/7 25
1272 ACSR 45'26
27
28
1272 ACSR /61 29
397.5 ACSR 26'30
397.5 ACSR 26Il 31
795 AAC 26/7 32
795 AAC 26/7 22
795 AAC 26/7 34
397.5 ACSR 26rl 35
245,939,765 3,522,864,268 3,768,804,033 864,557 16,229,553 2,138,345 15,232,451 36
FERC FORM NO. { (ED. t2-87)Page 423.6
Name of Respondent
PacifiCorp
Name of Respondent
PacifiCorp (2)A Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20181Q4
TRANSMISSION LINE STATISTICS
1 . Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 12 t, 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) tower; or
(4) underground construction lf a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (0 the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). ln a footnote, explain the basis of such occupancy and state whether expenses with
respect to such struclures are included in the expenses reported for the line designated.
Line
No.
IJESIGNAIION Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the tase.ofunderoroun0 lrnes
report Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
UN OIofDesil
I
tcIUreinelated
UN DUUCIUTESof AnotherLine(s)
1 ONEIDA, ID OVID, UT 138.0C 138.00 Wood - H 23.00 1
2 ONIEDA, ID GRACE, ID 138.0C 138.00 Wood - H 19.00 1
3 OQUIRRH, UT BARNEY, UT 138.0C 138.00 Wood - H 5.00 1
4 OQUIRRH, UT 138.0C 138.00 Wood - H 8.00 1
5 OQUIRRH, UT TOOELE, UT 138.0C 138.00 Steel - SP 23.00 1
6 PAINTER, UT RAILROAD, UT 138.0C '138.00 Wood - H 7.00 I
7 PARRISH #105, UT TERMINAL, UT 138.0(138.00 Steel - SP 14.00 1
8 PAROWAN, UT WEST CEDAR, UT 138.0(138.00 Wood - H 21.00 1
I PARRISH, UT TAP TO N. SALT LAKE, UT 138.0(138.00 Steel - SP 8.00 1
'10 PARRISH, UT TERMINAL #1 , UT 138.0(138.00 Steel - SP 16.00 1
11 PARRISH, UT TERMINAL #2, UT 138.0(138.00 14.00 1
12 RAILROAD, UT CANYON COMP, WY 138.0(138.00 Wood - H 17.00 I
13 RED BUTTE, UT PURGATORY FLAT, UT 138.0(138.00 Wood - SP 11.00 1
14 RED BUTTE, UT WEST CEDAR, UT '138.0(138.00 Wood - H 49.00 1
15 RIVERDALE, UT EAST LAYTON, UT 138.0t 138.00 Steel - SP 7.00 1
16 SHICK, UT PARRISH, UT 138.0(138.00 Wood - H 10.00 1
17 SILVER CREEK, UT JORDANELLE, UT 138.0(138.00 Wood - SP 10.00 1
18 SILVER CREEK, UT RAILROAD, UT 138.0(138.00 Wood - SP 72.00 1
19 SPANISH FORK, UT TANNER, UT 138,0(138.00 Wood - H 10.00 1
20 SUNRISE, UT OQUIRRH, UT 138.0(138.00 Wood - SP 2.00 1
21 SYRACUSE, UT ANGEL#1, UT 138.0(138.00 7.00 1
22 SYRACUSE, UT CLEARFIELD SOUTH, UT 138.0(138.00 Steel - SP 5.00 1
23 SYRACUSE, UT PARRISH, UT 138.0(138.00 Steel Tower 15.00 I
24 TAP TO ANGEL NORTH, UT TAP TO PARRISH, UT 138.0(138.00 Wood - H 4.00 1
25 TAYLORSVILLE, UT gOTH SOUTH, UT 138.0(138.00 Wood - SP 6.00 2.00 1
26 TERMINAL, UT KENNECOTT, UT 138.0(138.00 Steel - SP 9.00 1
27 TERMINAL, UT MIDVALLEY#1, UT 138.0(138.00 Wood - H 7.00 1
28 TERMINAL, UT MIDVALLEY #2, UT 138.0(138.00 Wood - H 7.00 1
29 TERMINAL, UT ROWLEY, UT 138.0(138.00 Wood - H 53.00 I
30 TERMINAL, UT TOOELE, UT 138.0(138.00 Wood - H 24.00 6.00 1
3'1 TERMINAL, UT WEST VALLEY, UT 138.0(138.00 Wood - SP 7.00 1
32 THREEMILE KNOLL, ID GRACE#1 .ID 138.00 138.00 Wood - H '17.00 1
33 THREEMILE KNOLL, ID GRACE#2, ID 138.00 138.00 Wood - H 17.0C 1
34 THREEMILE KNOLL, ID MONSANTO #1 , ID 138.00 138.00 Wood - H 2.0c 1
35 THREEMILE KNOLL, ID MONSANTO #2, ID 138.00 '138.00 Steel - SP 2.00 1
36 TOTAL 16,928.00 651.00 285
FERC FORM NO. 1 (ED. 12-87)Page 422.7
BINGHAM CANYON, UT
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn original
(21 [-lA Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles ol the primary structure in column (0 and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. lf such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of renl for year. For any transmission line other than a leased line, or porlion lhereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation ol furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Speciry whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Sipeci! whether lessee is an associated company.
10. Base the olant cosl figures called for in columns O to (l) on the book cost at end ofyear.
Size of
Conductor
and Material
(D
COST OF LINE (lnclude in Column (,) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
0)
Construction and
Other Costs(k)
Total Cost
(D
Operation
Expenses(m)
Maintenance
Expenses(n)
Rents
(o)
Total
Expenses(p)
336.4 ACSR 26/7 1
250 CUHD /12 2
/95 AAC 26fl 2
4
1272 ACSR 45/7 I
1272 ACSR4sn 6
795 AAC 45r/7
397.5 ACSR 26/7 8
795 AAC26t7 o
795 AAC 45/7 10
755 AAC26n 11
795 ACSR 26t7 12
1272 ACSR 45r','t3
397.s ACSR 26/7 14
795 AAC 26/7 15
250 CUHD /12 16
795 AAC 26/7 17
1272 ACSR4sn 18
1272 ACSR 45/7 19
20
250 CUHD /12 21
1272 ACSR 45/7 22
1272 ACSR 45/7 23
795 AAC /37 24
795 AAC /37 25
/95 AAC 26n 26
1272 ACSR 45/7 27
1272 AAC t61 28
795 AAC /37 2S
397.5 ACSR 26tl 30
31
250 CUHD /1 2 32
1272 ACSR 45/7 22
1272A Ct61 34
1272 ACSR 45n 35
245,939,765 3,522,864,268 3,768,804,033 864,557 16,229,553 2,138,345 19,232,455 36
FERC FORM rlro. 1 (ED. 12-87)Page 423.7
lr
Name of Respondent
PacifiCorp
This Reoort ls:(1) 5]Rn orisinat(2) [lA Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
TRANSMISSION LINE STATIST]CS
1 . Report information concerning 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 include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Proper$.
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) tower; or
(4) underground construction lf a transmission line has more than one lype of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (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 which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). ln a footnote, explain the basis of such occupancy and state \,vhether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
No.
UESIGNAIIUN VULIAGE (KV)(lndicate wfierebther than
60 cvcle. 3 ohase)
Type of
Supporting
Struclure
(e)
LENGTH {POIE MiIES)(ln the tase.ofunderorouno ltnesreport Eircuit miles)
Number
of
Circuils
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
un ulruqureof LineDesignated(0
un Slrucluresof AnotherLine
(s)
1 TIMP#1, UT DYNAMO, UT 138.0(138.00 Steel - SP 2.00 1
2 TIMP #2, UT DYNAMO, UT 138.0(138.00 2.00 1
3 TIMP, UT HALE, UT 138.0(138.00 Steel - SP 40c 1
4 TIMP, UT SPANISH FORK, UT 138.0(138.00 Wood - H 20 00 1
5 TIMP, UT VINEYARD, UT 138.0(138.00 Wood - SP 2.00 1
6 TREASURETON, ID GRACE, ID 138.0(138.00 Steel Tower 25.00 1
7 TREASURETON, ID GRACE #2, ID 138.0(138.00 25.00 1
I TREASURETON, ID ONEIDA, ID 138.0(138.00 Wood - H 6.00 1
I TRI-CITY, UT BANGERTER, UT 138 0t 138 00 Wood - SP 6.00 12.00 1
10 TRI-CITY, UT SUNRISE, ID 138.0(138.00 Wood - SP 22.00 1
11 TRI-CITY, UT \A/ESTFIELD, UT 138,0(138.00 Wood - H 15.00 1
12 WEST CEDAR, UT THREE PEAKS, UT 138.0(138.00 Wood - SP 20.00 1
13 WEST VALLEY, UT OQUIRRH, UT 138.0(138.00 Wood - H 9.00 I
14 WESTFIELD, UT HALE, UT 138.0(138.00 Wood - H 13.00 1
15 AMERICAN FALLS, ID 138.0(138.00 Wood - H 87.00 I
16 WHEELON #1, UT TREASURETON, ID 138.00 138.00 Steel Tower 29.00 1
17 WHEELON #2, UT TREASURETON, ID 138.00 138.00 29.00 1
18 \A/I-IEELON #3, UT TREASURETON, ID 138.00 138.00 Wood - H 29.00 1
19 1 38kV costs and expenses
20 Subtotal 138kV 2,222.00 205.00 '148
21
22 All 1'15kV Lines 1,655.00
23
24 All 69kV Lines 2,913.00
25
26 All 57kV Lines 107,00
27
28 All 46kV Lines 2,473.04
29
30
31
32
33
34
35
36 TOTAL 16,928.00 651.00 285
FERC FORM NO.1 (ED. r2-87)Page 422.8
WHEELON, UT
Name of Res;rondent
PacifiCorp
This Reoort ls:(1) 5]An originat(2) fiA Resubmission
Date of Report(Mo, Da, Yr)
tt
Year/Period of Report
End of 20'l8lQ4
TRANSM ISSION Ll NE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate iany transmission line or portion thereof for which the respondent is not the sole owner. lf such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but wtrich the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangemenl and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Speciff whether lessor, co-owner, or other party is
an associated company.
9. Designate iany transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. S;peciry whether lessee is an associated company.
1 0. Base the planl cost figures called for in columns (i) to (l) on the book cost at end of year.
Size of
Conductor
and Material
0
coST OF LINE (lnclude in column U) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
0)
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses
(m)
Mainlenance
Expenses
(n)
Rents
(o)
Total
Exo,e;ses
1
2
J
4
1272 ACSR 45/7 5
250 CUHD /12 6
250 CUHD /12 7
250 CUHD /12 I
9
10
1272 ACSR 45n 11
795 AAC 26r/12
13
795 A C26n 14
250 CUHD /12 15
250 CUHD /12 16
250 CUHD /12 17
250 CUHD /12 '18
33,900,03(408,031,032 441,931,068 242,614 1,784,831 165,019 2,192,464 19
33,900,03(408,031,032 441,931,068 242,614 1,784,83',1 165,019 2,192,464 20
21
5,427,951 203,209,263 208,637,213 35,385 2,560,171 460,910 3,056,46€22
23
8,352,s8r 291,850,1 58 300,202,742 43,358 3,490,634 170,890 3,704,882 24
25
52,65{12,435,120 12,487,775 1,516 30,951 6,034 38,501 26
27
1 1,591,16(277 ,697,935 289,289,104 104,607 2,253,138 66,642 2,424,387 28
29
30
31
32
33
34
35
245,939,765 3,522,864,268 3,768,804,03:864,557 1 6,229,5s3 2,'138,345 19,232,45a 36
FERC FORM NrO. r (ED. 12-87)Page 423.8
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
FOOTNOTE DATA
422 No.:1 Column: a
422 Line No.:2 Column: a
Cert t ss on report on pages 422-423 are part agreemenLs withvarious Ehird parties. For further discussion, see also page 328-330, Transmission of
elect rici for others in this Form No. L.
The Alvey - Dixon e 500kV line is jointly owned PacifiCorp and Bonneville PowerAdministration ('BPA,), each with an undivided interest of 50.0?. Plant cost reported forthis line represenLs PacifiCorpts 50.0? share. operation and maintenance costs are shared
between the two parties and responsibiliEy is as follows: PacifiCorp 58.0? and the BPA
42 .02 .
xonv 1Ie - Mer an 500kV 1 ne ntly owned by Pac f Corp BPA, E anundivided interest. of 50.0?. Plant cost reported for this line represents PacifiCorp's
50.0? share. Operation and maintenance costs are shared between the two parties andbiliris as follows: Pacifi 58.0? and the BPA 42.02
The Midpoint - Ma 500 ne s n v PacifiCorp and rdaho Power Company
ownership of the line designation is as follows:
Designation PacifiCorp Idaho Power Company
Hemingway - Summer Lake 78.02Midpoint - Hemingway 63.02
22.O237.0t
o 1y ovrned by Pac
Plant cost and operation and maintenance costs reported for this line represents
Paci f 's share
ternCorporation, Puget. Sound Energy, Avista Corporation and Portland General Electric Company,in which PacifiCorp owns 6.8? of the 1ine. Plant cost and operation and maintenance costsrted for this line resents Pacifi 's share
The Colstrip - Broadview A 500kV line is jointly owned by Pacificorp, Northwestern
Corporation, Puget Sound Energy, Avista Corporation and Portland ceneral Electric Company,in which PacifiCorp owns 6.8? of t.he 1ine. Plant cost and operation and maintenance costsrted for this line sents PacifiCo 's share.
The st ew B 500kV 1 1y owned by Pac f Corp, No sternCorporation, Puget Sound Energy, Avista Corporation and Portland ceneral Electric Company,in which PacifiCorp owns 6.8? of the line. Plant cost and operation and maintenance costs
ed for this line sents PacifiCo 's share.
The Broadview - Townsend A 500kV line is jointly owned by Pacificorp, NorthwesternCorporation, Puget Sound Energy, Avista Corporation and Portland ceneral Elect.ric Company,in which PacifiCorp owns 8.1? of the line. Plant cost and operation and maintenance costsed for this line ents Pacifi 's share
The ew - Townsend B 500kV 1 t1y ovrned by Pac f Corp, Northwestern
Corporation, Puget Sound Energy, Avista Corporation and Portland ceneral Electric Company,in which PacifiCorp owns 8.1-? of the 1ine. Plant cost and operation and maintenance costsfor this line ts Pacifi-
The Colstr
1,557 .4
tchyard 500kV 14-f
7
422 Line No.:4 Column: a
422 Line No.: 8 Column: a
422 Line No.:9 Column: a
422 Line No.: 10 Column: a
422 Line No.:11 Column: a
422 Line No.: 12 Column: a
422 Line No.:13 Column: a
Schedule Page:422 Line No.: 17 Column: i
)SR/TW 367
Schedule Page:422 Line No.: 18 Column: i
L557 - 4 ACSR TW 35 7
's share.
FERC FORM NO.1 (ED. 12.871 Paqe 450.1
Name of Respondent
PacifiCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
422 Line No.:26 Column: a
The Ilorah - M nt 345 t Y Pac Corp Power Company.
owne::ship of the line designation Borah - Adelaide - Midpoint #1 is as follows: Pacj-fiCorp
35.6tb, Idaho Power Company 64.4vo. Pfant cost and operation and maintenance costs reportedfor Lhis Line ts Pacifi 's share.
nt 345kv line is jointly owned by Pacificorp and Idaho Power Company.
Owne::ship of the line designation Borah - Adelaide - Midpoint #2 is as follows: PacifiCorp
35.6ei, Idaho Power Company 64.42. Plant cost and operation and maintenance costs reportedfor Lhis 1i-ne ts Pacifi 's share.
The Goshen - Kinport 345kV 1 ne ntly owned by f Corp and Idaho Power Companywith an undivided interest of 81.7? and l-8.3%', respectively. Plant cost and operation and
maintenance costs for this line ents Pacifi 's share
The ilim Bridger - Goshen 345kv 1 ne S t1y owned by Corp and Idaho Power Companywittr an undivided interest of 70.8? and 29.22, respectively. Plant cost and operation and
mairLtenance cosLs for this line ents Pacifi 's share
f
The atim Bridger - Borah 345kv 1 ne
owne::ship of the line designation is as follows
Desi.clnat.ion PacifiCorp
Jim Ilridger - Populus #1 70.82
PopuJ-us - Borah #1 70.82
ntly owned by Corp and Idaho Power Company.
Idaho Power Company
29.22
29.22
f
Plant- cost and operation and maintenance costs reported for t.his line represents
422 Line No.: 27 Column: a
422.1 Line No;4 Column: a
422.1 Line No.:9 Column: a
422.1 Line No.: 10 Column: a
422.1 Line No.: 11 Column: a
PAC ],I: 1 's share
The ir mBr ne
Comp€rny. Ownership of the line designation is as follows
Desi 5lnation Paci fiCorp
,Jim llridger - Populus #2 70.8?
Popul.us - Kinport 70.82
Corp
Idaho Power Company29.2*
29.22
er-K 345 nt v Power
P1ant. cost and operation and maintenance costs reported for this line represents
Paci I:'s share.
l:dpo 34 ne n v Pac Corp Power Company
withi an undivided j-nterest of 26.8? and 73.2%, respectively. Plant cost and operation and
mair:.t.enance costs for this line ents Pacifi 's share.
A 1.5 mi segment of the Casper - Dave .Tohnston 230kV 1 o tIy owned by Pac f Corp
and Black Hi1Is Power with an undivided int.erest of 43.75? and 55.252, respectively. Plant
cost and operation and maintenance costs reported for this line represents PacifiCorp's
share.
1557 ACSS 45 7
l.ete name is Gonder (NV ) , tIT - NV State
The Eturricane - Wa11a Walla 230kV 1 S o t1y owned by Pac rp and Idaho Power
Comp€my with an undivided j-nterest of 59.22 arrd 40.82, respectively. Plant cost and
opereLtion and maintenance costs reported for this line represents PacifiCorp's share.
FERC|FORM NO.1 (ED. 12471 Page 450.2
f
422.1 Line No.:12 Column: a
422.2 Line No.:2 Column: a
422.2 Line No.: 2 Column: i
422.2 Line No.: 17 Column: a
422.2 Line No.:20 Column: a
Name of Respondent
PacifiCorp
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
422.3 Line No.: 32 Column: a
422.3 Line No.: 33 Column: a
An ope - Gos l_ 51 o t v Corp Power Companywith an undivided interest of 78.1% and 21,.92, respectively. Plant cost and operation and
mainLenance costs ed for this line ents Pacifi 's share.
The Big Grassy - ,f erson 151 t v Pac Corp Power
company with an undivided interest of 52.22 and 37.8?, respectively. Plant costs andtion and maintenance costs ed for this line ents Pacifi 's share.
The Goshen - ,fefferson 151kV line is jointly Corp I Power Companywith an undivided interest of 52.2% and 37.8t, respectively. Plant cost and operation and
maintenance costs for this line ents Pacifi 's share
The Antelope - Scoville #1 138kV line is jointly owned by Pacificorp and Idaho Power
Company with an undivided interest of 33.32 and 66.72, respectively. Plant cost andation and maintenance costs ed for this line ts Pacifi 's share
The Antel-ope - Scov 1Ie #2 138kV line ntly owned by PacifiCorp and Idaho Power
Company with an undivided interest of 33.3? and 65.72, respectively. Plant cost and'ation and maintenance costs for this line ts Pacifi 's share
1557.4 ACSR 35 7
Schedule Page:422.5 Line No.: 13 Column: aThe Central - St. George 13BkV line is jointly owned by Pacificorp and Utah AssociatedMunicipal Power Systems with an undivided i-nterest of 43 .25% arrd 56.742, respectively.Plant cost and operation and maintenance costs reported for this line representsPacifrs share
The Central - St. ceorge 138 ne o nt I Pac Assoc aMunicipal Power Systems with an undivided interest of 43 .25* and 56.742, respectivelyPlant cost and operation and maintenance costs reported for this line represents
Paci f iCo 's share.
ete name s Burraston Ponds Meter UT
t_557 .4 AC 35 7
L557.4 36 7
1,557.4 l
1,557.4 36 7
(KCC UT
1557 .4 ACS TW 35 7
1557 .4 ACS TW 36 7
1557 .4 ACS 7
1"557.4 TW 36 7
]-557.4 7
FERC FORM NO.1 (ED. 12-871 Page 450.3
422.4 Line No.: 2 Column: a
422.4 Line No.:19 Column: a
422.4 Line No.: 20 Column: a
422.4 Line No;24 Column: i
422.5 Line No.:14 Column: a
422.5 Line No.:16 Column: b
422.5 Line No.:33 Column: i
422.6 Line No.:22 Column: i
422.6 Line No.: 27 Column: i
35
422.6 Line No.:28 Column: i
422.7 Line No.:4 Column: b
)mplete name is Bingham Canyc
422.7 Line No.:4 Column: i
422.7 Line No.: 20 Column: i
422.7 Line No;31 Column: ilTW 36/
422.8 Line No.: 1 Column: i
422.8 Line No.: 2 Column: i
lsR/TW 35/
Schedule Page:422.8 Line No.:3 Column: i
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
422.8 Line No.:4 Column: i
422.8 Line No.;9 Column: i
422.8 Line No.:10 Column: i
1557.4 ACSR 35
1557.4 ACSR 36 7
]-557.4 7
L55',t .4 36 7
1,557 .4 7
The - Amer Fa1ls 138kV 1 ne is jointly owned by Pacificorp and Idaho Power
Comp.rny. Ownership of the line designation American Fa11s - Malad is as follows:PacifiCorp 95.42, Idaho Power Company 3.5?. Plant cost and operation and maintenance costsreported for this line represents PacifiCorp's share.
FERC FORM NO.1 (ED. 12-871 Page 450.4
422.8 Line No.:13 Column: i
422.8 Line No.: 15 Column: a
PacifiCorp
(1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
TRANSMISSION LINES ADDED DURING YEAR
1. Report below the information called for concerning Transmission lines added or altered during the year. lt is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. lf actual
costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the
Line
No.
LINE DESIGNATION Ltne
Length
tn
Miles
(c)
SUPPORTING STRUCTURE CIRCUIIS PER S IRUC IUR
From
(a)
To
(b)
Type
(d)
AVeraqeNumbeiper
Miles
(e)
Present
(0
Ultimate
(s)
1 PURGATORY FLAT, UT 10.00 Wood - SP 8.00 2 2
2
4
5
6
7
I
I
't0
11
12
13
14
't5
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 10.00 8.00 2 z
FERC FORM NO. I (REV. 12-03)Page 424
ST GEORGE, UT
Name of Rest,ondent
PacifiCorp
This
(1)
(2)
Reoort ls:
5]nn original
[-1A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
costs. Designate, however, if estimated amounts are reported. lnclude costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in colLlmn (l) with appropriate footnote, and costs of Underground Conduit in column (m).
3. lf design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate
such other characteristic.
UUNUUU I ORS Voltage
KV
(Operating)
LINE COST Line
No.Size
(h)
lSpecification
(D
Confiouration
and Spacing
0)
Land and
Land(Rights
Poles, Towers
and Fixtures
(m)
Conductors
and Devices(n)
Asset
Retire. Cosls(o)
Total
(p)
1272 ACSR Vertical 10'138 676,370 574,87t 423,866 -158,81 'r 1,516,301 ,|
2
3
4
5
6
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
33
34
35
36
37
38
39
40
41
42
43
676,370 574,876 423,866 -158,81 1 1,516,301 44
FERC FORM Nr). 1 (REV. 12-03)Page 425
Name of Respondent
PacifiCorp
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
tt
Year/Period of Report
2o1AA4
FOOTNOTE DATA
424 Line No.:7 Column: aLines added to the designation Butte, Ut to Purgatory at, Ut
FERC FORM NO. r (ED. 12-871 Page 450.1
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SUBSTATIONS
L Report br:low the information called for concerning substations of the respondent as of the end of the year.
2. Substaticrns which serve only one industrial or street railway customer should not be listed below.
3. Substatic'ns with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional clraracter, 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 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 Subslation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 CALIFORNIA
2 BELMONT SUB DISTRIBUTION.UNATTEN 69.00 12.47
3 BIG SPRINGS SUB DISTRIBUTION-UNATTEN 69.00 12.47
4 CASTEI-LA SUB DISTRIBUTION.UNATTEN 69.00 2.40
5 CLEAR I.AKE SUB DISTRIBUTION.UNATTEN 69.00 12.47
6 DOG CITEEK SUB DISTRIBUTION-UNATTEN 69.00 2.40
7 DORRIS SUB DISTRIBUTION-UNATTEN 69.00 12.47
8 FORT JONES SUB DISTRIBUTION-UNATTEN 69.00 12.47
I GASOUET SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
10 GREENHORN SUB DISTRIBUTION.UNATTEN 69.00 12.47
11 HAMBURG SUB DISTRIBUTION-UNATTEN 69.00 2.40
12 HAPPY CAMP SUB DISTRIBUTION-UNATTEN 69.00 12.47
13 HORNBROOK SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 INTERNATIONAL PAPER SUB DISTRIBUTION-UNATTEN 69.00 2.40
15 LAKE EqRL SUB DISTRIBUTION-UNATTEN 69.00 12.47
16 LITTLE SHASTA SUB DISTRIBUTION-UNATTEN 69.00 7.20
17 LUCERNE SUB DISTRIBUTION.UNATTEN 1 15.00 't2.47
18 MACDOEL SUB DISTRIBUTION-UNATTEN 69.00 20.80
19 MCCLOUD SUB DISTRIBUTION-UNATTEN 69.00 12.47
20 MILLER REDWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
21 MONTAGUE SUB DISTRIBUTION.UNATTEN 69.00 12.47
22 MORRISON CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.50
23 MOUNT SHASTA SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 NEWELI- SUB DISTRIBUTION.UNATTEN 69.00 12.47
25 NORTH DUNSMUIR SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 NORTHI]REST SUB DISTRIBUTION-UNATTEN 69.00 12.47
27 NUTGU\DE SUB DISTRIBUTION-UNATTEN 69.00 2.40
28 PATRICKS CREEK SUB DISTRIBUTION-UNATTEN 1 15.00 7.20
29 PEREZ ISUB DISTRIBUTION-UNATTEN 69.00 12.47
30 REDWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
31 SCOTT BAR SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 SEIAD SiUB DISTRIBUTION-UNATTEN 69.00 12.47
33 SHASTII\.IA SUB DISTRIBUTION-UNATTEN 69.00 20.80
34 SHOTGIJN CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
35 SMITH FIIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 SNOW BRUSH SUB DISTRIBUTION-UNATTEN 69.00 7.20
37 SOUTH DUNSMUIR SUB DISTRIBUTION-UNATTEN 69.00 4.16
38 TULELAKE SUB DISTRIBUTION-UNATTEN 69.00 12.47
39 TUNNEI.. SUB DISTRIBUTION-UNATTEN 69.00 12.47
40 WALKER BRYAN SUB DISTRIBUTION-UNATTEN 69.00 12.47
FERC FORL NO.1 (ED. t2-96)Page 426
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
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 substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
0)
Total Capacity
(ln MVa)
(k)
1
25 1 2
6 1 3
1 3 4
4 3 5
1 6
7 3 7
6 1 8
I 1 q
12 1 10
1 1 11
7 3 12
4 3 13
I J 14
12 1 15
2 J 16
4 1 17
30 2 '18
6 1 19
4 3 20
6 1 21
14 1 22
'16 4 23
12 1 24
6 6 25
20 4 26
I J 27
1 1 28
1 3 29
o 3 30
2 3 31
2 3 32
6 3 33
1 1 u
6 3 35
1 3 36
2 3 37
20 1 38
6 6 39
3 40
FERC FORM NO. I (ED. 12-96)Page 427
(
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report txllow the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. lndicate ir 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 (f1.
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
,|WEED SUB DISTRIBUTION-UNATTEN '1 '15.00 12.47
2 YUBA SUB DISTRIBUTION-UNATTEN 69.00 12.47
3 YUROK SUB DISTRIBUTION-UNATTEN 69.00 12.47
4 TOTAL i(Number of Substations-42)3082.00 465.96
5
6 ALTURI\S SUB T/D.UNATTENDED 1 15.00 69.00
7 YREKA SUB T/D-UNATTENDED 1 15.00 12.47 69.00
8 TOTAL riNumber of Substations-2)230.00 81.47 69.00
I
10 coPco #2 230 suB TRANSMISSION-ATTENDE 230.00 1 15.00
1',!COPCO #2 SUB TRANSMISSION-ATTENDE 1 15.00 69.00 12.47
12 AGER SUB TRANSMISSION-UNATTEN '1 '15.00 69.00
13 CRAG \lEW SUB TRANSMISSION-UNATTEN 1 15.00 69.00
14 DEL N,CRTE SUB TRANSMISSION-UNATTEN 1 15.00 69.00
15 TOTAI. rNumber of Substations-5)690.00 391.00 12.47
16
17 IDAHO
18 ALEXANIDER DISTRIBUTION-UNATTEN 46.00 12.47
19 AMMON DISTRIBUTION-UNATTEN 69.00 12.47
20 ANDERI}ON DISTRIBUTION-UNATTEN 69.00 12.47
21 ARCO DISTRIBUTION-UNATTEN 69.00 12.47
22 ARIMC'DISTRIBUTION-UNATTEN 46.00 12.47
23 BANCROFT SUB DISTRIBUTION-UNATTEN 46.00 12.47
24 BELSOT.I SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 BERENICE SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 CAMAS SUB DISTRIBUTION-UNATTEN 69.00 12.47
27 CANYOI{ CREEK SUB DISTRIBUTION.UNATTEN 69.00 24.90
28 CHESI-ETRFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47
29 CLEME:NTS SUB DISTRIBUTION-UNATTEN 69.00 12.47
30 CLIFTOhI SUB DISTRIBUTION-UNATTEN 46.00 12.47
31 COVE SUB DISTRIBUTION.UNATTEN 46.00 12.47
32 DO!ryNEY SUB DISTRIBUTION-UNATTEN 46.00 12.47
33 DUBOIS SUB DISTRIBUTION-UNATTEN 69.00 12.47
34 EASTIIIONT SUB DISTRIBUTION-UNATTEN 69.00 12.47
35 EGIN SL'B OISTRIBUTION.UNATTEN 69.00 12.47
36 EIGHT NIILE SUB DISTRIBUTION.UNATTEN 46.00 12.47
37 GEORGIETOWN SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 GRACE CITY SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 HAMER SUB DISTRIBUTION-UNATTEN 69.00 12.47
40 HAYESi ISUB DISTRIBUTION-UNATTEN 69.00 12.47
FERC FORM 1{O.1 (ED. 12-96}Page 426.1
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
5. Show in columns (l), (t), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other pafi is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(D
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
fi)
Total Capacity
(ln MVa)
(k)
25 I 1
4 3 2
4 J 3
323 99 4
5
35 4 b
95 2 7
130 6 8
I
500 2 10
51 4 11
5 J 't2
19 3 13
150 2 14
72s 14 15
16
17
4 1 18
14 1 19
20 1 20
6 ,|21
7 1 22
4 1 23
12 I 24
10 1 25
14 1 26
20 1 27
5 1 28
5 1 29
4 1 30
6 1 31
5 1 32
12 I 33
14 1 u
14 1 35
4 1 36
6 1 37
5 1 38
14 1 39
I 1 40
FERC FORM NO. 1 (ED. 12.96)Page 427.1
Name of Respondent
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. lndicate ir 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 Subslation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 HENRY SUB DISTRIBUTION-UNATTEN 46.00 7.20
2 HOLBR,COK SUB DISTRIBUTION-UNATTEN 69.00 12.47
3 HOOPES SUB DISTRIBUTION-UNATTEN 69.00 12.47
4 HORSL=Y SUB DISTRIBUTION-UNATTEN 46.00 12.47
5 IDAHC} =ALLS SUB DISTRIBUTION-UNATTEN 46.00 12.47
6 INDIAN CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
7 JEFFCO SUB DISTRIBUTION-UNATTEN 69.00 24.90
8 KETTI..E: SUB DISTRIBUTION-UNATTEN 69.00 24.90
I LAVA SUB DISTRIBUTION-UNATTEN 46.00 12.47
10 LUND SUB DISTRIBUTION-UNATTEN 46.00 12.47
11 MCCAIVIMON SUB DISTRIBUTION-UNATTEN 46.00 12.47
12 MENAN SUB DISTRIBUTION-UNATTEN 69.00 12.47
13 MERRII..L SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 MILLER SUB DISTRIBUTION-UNATTEN 69.00 12.47
15 MONTPELIER SUB DISTRIBUTION-UNATTEN 69.00 12.47
16 MOODY SUB DISTRIBUTION-UNATTEN 69.00 12.47
17 NEWDA.LE SUB DISTRIBUTION-UNATTEN 69.00 12.47
18 OSGOCID SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 PRESTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
20 RAYMOND SUB DISTRIBUTION-UNATTEN 69.00 12.47
21 RENO SUB DISTRIBUTION-UNATTEN 69.00 12.47
22 REXBIJIiG SUB DISTRIBUTION.UNATTEN 69.00 12.47
23 RIRIE SUB DISTRIBUTION-UNATTEN 69.00 12.47
24 ROBERTS SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 RUBY SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 SAND C|REEK SUB DISTRIBUTION.UNATTEN 69.00 12.47
27 SANDIJNE SUB DISTRIBUTION-UNATTEN 67.00 24.90
28 SHELI..E:Y SUB DISTRIBUTION.UNATTEN 46.00 12.47
29 SMITF] I]UB DISTRIBUTION-UNATTEN 69.00 12.47
30 SOUTH FORK SUB DISTRIBUTION-UNATTEN 69.00 12.47
31 SPUD SUB DISTRIBUTION-UNATTEN 46.00 12.47
32 ST. CI{I\RLES SUB DISTRIBUTION-UNATTEN 69.00 12.47
33 SUGAR CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47
34 SUNN'YDELL SUB DISTRIBUTION-UNATTEN 69.00 12.47
35 TANNEIi SUB DISTRIBUTION-UNATTEN 46.00 't2.47
36 TARGI.{EE SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 THORNTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 UCON SUB DISTRIBUTION-UNATTEN 69.00 12.47
39 WATKIIIS SUB DISTRIBUTION-UNATTEN 69.00 12.47
40 WEBSTER SUB DISTRIBUTION-UNATTEN 69.00 12.47
FERC FORM NO. I (ED. 12-96)Page 426.2
Name of Respondent
PacifiCorp Original
Resubmission
(1)
(2)
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
5. Show in columns (l), O, 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 otheruise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
0)
Capacity
MVa)
(k)
Total
(ln
1 1 1
6 1 2
o 1 3
4 1 4
20 1 5
3 1 6
22 ,|7
14 1 8
6 I I
5 1 10
3 1 11
10 1 12
20 1 '13
5 1 14
8 1 15
14 1 16
20 1 17
20 1 18
12 1 19
2 1 20
20 ,|21
32 2 22
I 1 23
8 1 24
7 1 25
40 2 26
30 1 27
20 1 28
20 1 29
14 ,|30
I 1 3'l
5 1 32
't2 ,|33
13 1 34
4 1 2E
4 1 36
7 1 37
7 1 38
14 1 39
20 1 40
Page 427.2FERC FORM NO. r (ED. r2-96)
Name of Respondent
PacifiCorp
(1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 WESTO,N SUB DISTRIBUTION-UNATTEN 46.00 12.47
2 WNDSPER SUB DISTRIBUTION-UNATTEN 69.00 24.90
J TOTAL (Number of Substations-65)4000.00 867.43
4
5 CINDEFI BUTTE SUB T/D-UNATTENDED 16't.00 12.47
6 MALAD SUB T/D-UNATTENDED 1 38.0C 69.00 12.47
7 MUD UKE SUB T/D-UNATTENDED 69.0C 12.47
I RIGBY ISUB T/D-UNATTENDED 161.00 12.47 69.00
I SAINT I\NTHONY SUB T/D-UNATTENDED 69.00 46.00 12.47
10 TOTAL (Number of Substations-s)598.00 152.41 93.94
11
12 AMPS SUB TRANSMISSION-UNATTEN 230.00 69.00 12.47
13 TRANSMISSION-UNATTEN 230.00 161.00 13.80
14 ASHTONI PLANT TRANSMISSION-UNATTEN 46.00 12.47 2.40
15 TRANSMISSION-UNATTEN 161.00 69.00
16 BONNEVILLE SUB TRANSMISSION-UNATTEN 161.00 69.00
17 CONDA SUB TRANSMISSION.UNATTEN 138.00 46.00
18 FISH CTIEEK SUB TRANSMISSION-UNATTEN 161.00 46.00
19 FRANKI-IN SUB TRANSMISSION-UNATTEN 138.00 46.00
20 TRANSMISSION.UNATTEN 345.00 161.00 69.00
21 GRACE SUB TRANSMISSION-UNATTEN 161.00 138.00 12.50
22 TRANSMISSION.UNATTEN 161.00 69.00
23 TRANSMISSION.UNATTEN 500.00 345.00
24 OVID SIJB TRANSMISSION-UNATTEN 138.00 69.00
25 SCOVILLE SUB TRANSMISSION-UNATTEN 138.00 69.00
26 SUGARMILL SUB TRANSMISSION-UNATTEN 161.00 46.00 69.00
27 TRANSMISSION-UNATTEN 345.00 138.00 46.00
28 TREASIJRETON SUB TRANSMISSION-UNATTEN 230.00 138.00
29 WEST\^/OOD SUB TRANSMISSION.UNATTEN 161.00 13.20
30 TOTAL (Number of Substations-'t8)3605.00 1704.67 225.17
31
32 MONTANA
33 TRANSMISSION.UNATTEN 500.00 230.00
34 TRANSMISSION-UNATTEN 500.00 230.00
35 YELLO\VTAIL SUB TRANSMISSION-UNATTEN 230.00 161.00
36 TOTAL (Number of Substations-3)1230.00 621.00
37
38 OREGON
39 26TH S'TREET DISTRIBUTION-UNATTEN 20.80 4.16
40 35TH STREET DISTRIBUTION-UNATTEN 20.80 2.40
FERC FORM r{O. I (ED. 12-96)Page 426.3
SUB
BIG SUB
GOSHEN SUB
JEFFE,FISON SUB
MIDPOINT SUB
KNOLL SUB
SUB
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
5. Show in columns (l), O, and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(f)
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
fi)
Total Capacity
(ln MVa)
(k)
4 1 1
20 1 2
736 67 3
4
30 1 5
39 4 ,|6
14 1 7
189 4 8
40 2 I
312 12 1 10
11
75 1 12
250 1 13
15 1 14
67 1 15
67 1 '16
67 1 17
25 3 18
75 ,|19
908 4 1 20
2',t7 2 21
233 3 22
1 500 1 23
30 1 24
76 2 25
168 3 26
775 2 27
533 2 28
30 1 29
5111 31 2 30
31
32
32 2 JJ
68 2 34
100 1 35
200 5 36
37
38
5 1 39
30 40
FERC FORM NO. r (ED. r2.96)Page 427.3
(.
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)lt
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substaticns which serve only one industrial or street railway customer should not be listed below.
3. Substaticns 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 rrnattended. 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)
,|AGNESS AVE DISTRIBUTION-UNATTEN 1 15.00 12.47
2 ALDER\A/OOD SUB DISTRIBUTION.UNATTEN 69.00 12.47
3 ARLINCiTON DISTRIBUTION-UNATTEN 69.00 12.47
4 ATHENA DISTRIBUTION-UNATTEN 69.00 12.47
5 BANDON TIE SUB DISTRIBUTION.UNATTEN 20.80 12.47
6 BEACON SUB DISTRIBUTION-UNATTEN 69.00 12.47
7 BEALL LANE SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
I BEATT\/ SUB DISTRIBUTION-UNATTEN 69.00 12.47
I BELKNAP SUB DISTRIBUTION-UNATTEN 115.00 12.47
10 BLALOCK SUB DISTRIBUTION-UNATTEN 69.00 12.47
11 BLOSS SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
12 BLY S{.JB DISTRIBUTION-UNATTEN 69.00 12.47
13 BOISE CASCADE SUB DISTRIBUTION-UNATTEN 69.00 11.00
14 BONAN,ZA SUB DISTRIBUTION-UNATTEN 69.00 12.47
15 BOND STREET SUB DISTRIBUTION.UNATTEN 69.00 12.50
16 BROOKHURST SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
17 BRO!\NSVILLE SUB DISTRIBUTION-UNATTEN 69.00 20.80
18 BRYANT SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 BUCHANAN SUB DISTRIBUTION-UNATTEN 1 15.00 20.80
20 BUCKAITOO SUB DISTRIBUTION-UNATTEN 69.00 12.47
21 CAMPBELL SUB DISTRIBUTION-UNATTEN I 15.00 12.47
22 CANNON BEACH SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
23 CANYONVILLE SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
24 CARNEIS SUB DISTRIBUTION-UNATTEN 69.00 't2.47
25 CASEBEER SUB DISTRIBUTION-UNATTEN 69.00 20.80
26 CAVEM,CN SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
27 CHERR'Y LANE SUB DISTRIBUTION-UNATTEN 69.00 12.47
28 CHILOOUIN MARKET SUB DISTRIBUTION.UNATTEN 69.00 12.47
29 CHINA }1AT SUB DISTRIBUTION-UNATTEN 69.00 12.47
30 CIRCLE BLVD SUB DISTRIBUTION-UNATTEN 1 15.00 20.80
3'1 CLEVELAND AVE SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 CLOAKE SUB DISTRIBUTION-UNATTEN 69.00 20.80
33 COBURG SUB DISTRIBUTION-UNATTEN 69.00 20.80
34 COLISEUM SUB DISTRIBUTION-UNATTEN 20.80 4.16
35 COLU]iIBIA SUB DISTRIBUTION-UNATTEN 1 15.00 69.00 12.47
36 COOS FIIVER SUB DISTRIBUTION-UNATTEN I 15.00 20.80
37 COQUILLE SUB DISTRIBUTION-UNATTEN 1 15.00 20.80
38 CREEK SUB DISTRIBUTION-UNATTEN 69.00 34.50
39 CROOKED RIVER RANCH SUB DISTRIBUTION.UNATTEN 69.00 20.80
40 CROWFOOT SUB DISTRIBUTION-UNATTEN 115.00 12.47
FERC FORM NO.1 (ED. 12-95)Page 426.4
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
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 substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondents books of account. Specify in each €se whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(D
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
U)
Total Capacity
(ln MVa)
(k)
25 1 1
45 2 2
5 1 3
I 1 4
8 3 1 5
11 3 o
25 1 7
6 I 8
40 2 I
2 3 10
32 2 11
8 3 12
3 I 13
8 J 14
25 1 15
50 2 16
13 1 17
40 2 18
45 2 19
34 2 20
20 2 21
13 1 22
25 1 23
I 3 24
20 1 25
45 2 26
25 ,|27
I 3 2E
25 ,|29
80 2 30
45 2 31
20 1 32
10 3 33
I 2 34
't28 4 1 35
20 1 36
40 2 37
5 1 38
25 2 39
20 ,|40
FERC FORM NO. r (EO.12-96)Page 427.4
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of
(Mo, Datl
Report
r, Yr)
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report br:low the information called for concerning substations of the respondent as of the end of the year.
2. Substatic,ns which serve only one industrial or street railway customer should not be listed below.
3. Substatrcns 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 rlnattended. 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 CULLY SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
2 CULVEI1 SUB DISTRIBUTION.UNATTEN 69.00 't2.47
3 DAIRY I;UB DISTRIBUTION-UNATTEN 69.00 12.47
4 DALLAS| SUB DISTRIBUTION-UNATTEN 1 15.00 20.80
5 DALREED SUB DISTRIBUTION-UNATTEN 230.00 34.40
6 DEVILS LAKE SUB DISTRIBUTION-UNATTEN 1 15.00 20.80
7 DIXON SUB DISTRIBUTION.UNATTEN 1 15.00 4.16
I DODGE BRIDGE SUB DISTRIBUTION.UNATTEN 70.60 20.80
I DOVI/ELL SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
10 EASY VALLEY SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
11 EMPIRE SUB DISTRIBUTION-UNATTEN 1 15.00 20.80
12 ENTE[I]'RISE SUB DISTRIBUTION-UNATTEN 69.00 12.47
13 FERN HILL SUB DISTRIBUTION-UNATTEN 1 15.00 't2.47
14 FIELDER CREEK SUB DISTRIBUTION-UNATTEN I 15.00 20.80
15 FOOTHILLS SUB DISTRIBUTION.UNATTEN 69.00 12.47
16 FRALE:\'SUB DISTRIBUTION-UNATTEN 69.00 12.47
17 GARDEI\ VALLEY SUB DISTRIBUTION-UNATTEN 69.00 20.80
18 GLENDI\LE SUB DISTRIBUTION-UNATTEN 230.00 12.47
19 GLENEDEN SUB DISTRIBUTION.UNATTEN 20.80 4.16
20 GLIDE SUB DISTRIBUTION.UNATTEN 1 15.00 12.47
21 GOLD HILL SUB DISTRIBUTION.UNATTEN 69.00 't2.47
22 GORDON HOLLOW SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 GOSHET{ SUB DISTRIBUTION-UNATTEN 1 15.00 20.80
24 GRANT STREET SUB DISTRIBUTION-UNATTEN 1 15.00 20.80
25 GREEN SUB DISTRIBUTION-UNATTEN 69.00 12.47
26 GRIFFIN CREEK SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
27 HAMAKER SUB DISTRIBUTION-UNATTEN 69.00 12.47
28 HARRISBURG SUB DISTRIBUTION.UNATTEN 69.00 20.80
29 HENLEY SUB DISTRIBUTION.UNATTEN 69.00 12.47
30 HERMISTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
31 HILLVIE'W SUB DISTRIBUTION-UNATTEN 115.00 20.80
32 HINKLE SUB DISTRIBUTION-UNATTEN 69.00 't2.47
33 HOLLAEIAY SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
34 HOLLYWOOD SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
35 HOOD FIIVER SUB DISTRIBUTION-UNATTEN 69.00 12.47
36 HORNE'T SUB DISTRIBUTION-UNATTEN 69.00 12.47
37 HUMBIJG CREEK SUB DISTRIBUTION-UNATTEN 67.00 12.50
38 HUNTERS CIRCLE TEMP SUB DISTRIBUTION-UNATTEN 69.00 12.47
39 ILLAHEE FLATS SUB DISTRIBUTION.UNATTEN '1 15.00 12.47
40 INDEPENDENCE SUB DISTRIBUTION-UNATTEN 69.00 20.80
FERC FORM NO. r (ED.12-96)Page 426'5
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
5. Show in columns (l), O, and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(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
fi)
Total Capacity
(ln MVa)
(k)
25 1 1
13 1 2
25 1 3
50 2 4
95 4 5
50 2 6
7 ,|7
25 2 8
20 1 I
45 2 10
20 1 11
19 2 12
12 I 13
25 1 14
21 4 15
5 J 16
20 1 17
25 2 18
6 1 19
12 1 20
11 3 21
6 I 22
20 1 23
45 2 24
25 1 25
20 1 26
I J 27
13 1 28
6 3 29
40 1 30
45 2 31
20 1 32
75 3 33
50 2 34
40 2 35
20 1 36
I 1 37
12 1 38
2 1 39
,|40
FERC FORM NO.1 (ED. 12-96)Page 427'5
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. lndicate irr 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
,|JACKSONVILLE SUB DISTRIBUTION-UNATTEN 115.00 12.47 69.00
2 JEFFER,SON SUB DISTRIBUTION-UNATTEN 69.00 20.80
3 JEROMI= PRAIRIE SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
4 JORDA]{ POINT SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
5 JOSEPH SUB DISTRIBUTION-UNATTEN 20.80 12.47
6 JUNC'I-I,3N CIry SUB DISTRIBUTION-UNATTEN 69.00 20.80
7 KENWOOD SUB DISTRIBUTION-UNATTEN 69.00 12.47
I KILLINGiWORTH SUB DISTRIBUTION.UNATTEN 69.00 12.47
I KNAPPI\ SVENSEN SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
10 LAKEPORT SUB DISTRIBUTION-UNATTEN 69.00 12.47
11 LANCASTER SUB DISTRIBUTION-UNATTEN 69.00 20.80
12 LEBANON SUB DISTRIBUTION-UNATTEN 1 15.00 20.80
13 LINCOL]N SUB DISTRIBUTION.UNATTEN 115.00 12.47
14 LOCKHI\RT SUB DISTRIBUTION-UNATTEN 115.00 20.80
15 LYONS SUB DISTRIBUTION-UNATTEN 69.00 20.80
16 MADRAS SUB DISTRIBUTION-UNATTEN 69.00 12.47
17 MALLORY SUB DISTRIBUTION.UNATTEN 115.00 12.47
18 MARYS RIVER SUB DISTRIBUTION-UNATTEN 1 15.0C 20.80
19 MEDCO SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
20 MEDFOIlD DISTRIBUTION-UNATTEN 1 15.00 12.47
21 MERLIN SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
22 MERRILL SUB DISTRIBUTION.UNATTEN 69.00 12.47
23 MINAM ISUB DISTRIBUTION-UNATTEN 69.00 12.47
24 MODOC SUB DISTRIBUTION-UNATTEN 69.00 12.47
25 MURDER CREEK SUB DISTRIBUTION-UNATTEN 115.00 20.80
26 MYRTLE: CREEK SUB DISTRIBUTION.UNATTEN 69.00 12.47
27 MYRTLE POINT SUB DISTRIBUTION.UNATTEN 1 15.00 20.80
28 NELSCOTT SUB DISTRIBUTION-UNATTEN 20.80 4.16
29 NEW DESCHUTES SUB DISTRIBUTION-UNATTEN 70.44 13.09
30 NEWO'I]RIEN SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
31 OAK KN,CLL SUB DISTRIBUTION.UNATTEN 1 15.00 12.47
32 OAKLAND SUB DISTRIBUTION-UNATTEN I 15.00 't2.47
33 OREMET SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
34 OVERPI\SS SUB DISTRIBUTION-UNATTEN 69.00 12.47
35 PALLETTE SUB DISTRIBUTION.UNATTEN 69.00 20.80
36 PARK S'IREET SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
37 PARKROSE SUB DISTRIBUTION-UNATTEN 120.00 't3.20
38 PENDLETON SUB DISTRIBUTION-UNATTEN 69.00 12.47
39 PILOT ROCK SUB DISTRIBUTION-UNATTEN 69.00 12.47
40 POWELI.- BUTTE SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
FERC FORM NO.1 (ED.12-96)Page 426'6
(1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
5. Show in columns (l), O, and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(f)
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(D
Number of Units
fi)
Total Capacity
(ln MVa)
(k)
75 2 1
12 1 2
20 1 3
20 1 4
6 1 1 5
22 2 6
3 3 7
40 2 8
6 1 I
50 2 10
12 3 11
40 2 12
105 3 13
40 2 14
25 2 15
25 2 16
25 1 17
20 1 18
20 1 19
67 8 20
45 2 21
17 6 22
1 23
6 3 24
100 4 25
14 1 26
I 1 27
4 1 28
25 1 29
I 1 30
45 2 31
I 1 32
75 2 33
45 2 34
1 1 1 35
40 2 36
37 2 37
46 7 1 38
22 2 39
12 I 40
FERC FORM NO. 1 (ED. 12-95)Page 427.6
Name of Respondent
PacifiCorp
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 2018/Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 PRINEVILLE SUB DISTRIBUTION-UNATTEN 115.00 12.47
2 PROVOLT SUB DISTRIBUTION-UNATTEN 69.00 12.47
3 QUEEN AVE SUB DISTRIBUTION-UNATTEN 69.00 20.80
4 RED BLANKET SUB DISTRIBUTION-UNATTEN 69.00 4.',l6
5 REDMOND SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
6 RIDDLE VENEER SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
7 ROGUE RIVER SUB DISTRIBUTION.UNATTEN 69.00 12.47
I ROSEBIJRG SUB DISTRIBUTION-UNATTEN 1 15.00 20.80
I ROSS AVE SUB DISTRIBUTION-UNATTEN 69.00 't2.47
10 ROXY ANN SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
11 RUCH SUB DISTRIBUTION-UNATTEN 69.00 12.47
12 RUNNING Y SUB DISTRIBUTION.UNATTEN 69.00 20.80
13 RUSSEI'LVILLE SUB DISTRIBUTION-UNATTEN 115.00 12.47
14 SCENIS SUB DISTRIBUTION-UNATTEN 115.00 12.47 69.00
15 SCIO SL'B DISTRIBUTION.UNATTEN 69.00 12.47
16 SEASIDI= SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
17 SELMA ISUB DISTRIBUTION-UNATTEN 1 15.00 12.47
18 SHASTP. WAY SUB DISTRIBUTION.UNATTEN 12.47 4.16
19 SHEVLIII PARK SUB DISTRIBUTION-UNATTEN 69.00 12.50
20 SIMTAG BOOSTER PUMP DISTRIBUTION-UNATTEN 34.50 4.16
21 SOUTH DUNES SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
22 SOUTHGATE SUB DISTRIBUTION-UNATTEN 69.00 20.80
23 SPRAGL'E RIVER SUB DISTRIBUTION.UNATTEN 69.00 12.47
24 STATE SiTREET SUB DISTRIBUTION-UNATTEN 1 15.00 20.80
25 STAYTON SUB DISTRIBUTION.UNATTEN 69.00 20.80
26 STEAMBOAT SUB DISTRIBUTION-UNATTEN 1 't s.00 7.20
27 STEVENS ROAD SUB DISTRIBUTION.UNATTEN 115.00 20.80
28 SUTHEF:LIN SUB DISTRIBUTION-UNATTEN 115.00 12.00
29 SWEET IOME SUB DISTRIBUTION-UNATTEN 115.00 20.80
30 TAKELMA SUB DISTRIBUTION.UNATTEN 115.00 20.80
31 TALENT SUB DISTRIBUTION.UNATTEN 1 15.00 12.47
32 TEXUM IJUB DISTRIBUTION-UNATTEN 69.00 12.47
33 TILLER {}UB DISTRIBUTION-UNATTEN 1 15.00 12.47
34 TOLO S}IJB DISTRIBUTION-UNATTEN 69.00 12.47
35 TURKEY HILL SUB DISTRIBUTION.UNATTEN 69.00 12.47
36 UMAPINI= SUB DISTRIBUTION-UNATTEN 69.00 12.47
37 UMATIT-I.A SUB DISTRIBUTION-UNATTEN 69.00 12.47
38 VERNCIN SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
39 VILAS SIJB DISTRIBUTION-UNATTEN 1 15.00 12.47
40 VILLAGE GREEN SUB DISTRIBUTION-UNATTEN 1 15.00 20.80
FERC FORI',| NO. 1 (ED. 12-96)Page 426.7
Name
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
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 substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)
(k)
50 2 1
11 3 2
50 2 3
2 J 4
50 2 5
25 ,|6
25 2 7
50 2 8
I 3 I
25 1 10
I 1 11
I 1 12
45 2 '13
70 J 14
I 1 15
40 2 16
I 1 17
2 3 18
25 ,|19
19 2 20
I I 21
20 1 22
7 J 23
40 2 24
55 2 25
1 26
50 2 27
25 1 28
42 2 29
12 1 30
50 2 3'1
25 1 32
1 1 33
11 1 34
'13 3 35
20 I 36
25 2 37
50 2 38
25 1 39
40 2 40
FERC FORM NO. I (ED. 12-95)Page 427.7
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of 2018/Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional c;haracter, but the number of such substations must be shown.
4. lndicate irr 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
,|VINE STREET SUB DISTRIBUTION-UNATTEN 67.00 21.80
2 WALLO\A/A SUB DISTRIBUTION-UNATTEN 69.00 12.47
3 WARM IJPRINGS SUB DISTRIBUTION-UNATTEN 69.00 20.80
4 WARRENTON SUB DISTRIBUTION-UNATTEN 115.00 12.47
5 WASCO SUB DISTRIBUTION-UNATTEN 20.80 4.16
6 \A/ECONIA BEACH SUB DISTRIBUTION-UNATTEN 20.80 4.16
7 WESTtf,N SUg DISTRIBUTION-UNATTEN 70.60 13.09
8 \A/ESTSIDE HYDRO/SUB DISTRIBUTION-UNATTEN 69.00 12.47
I \A/EYERHAUSER SUB DISTRIBUTION.UNATTEN 69.00 12.47
't0 \A/TIITE CITY SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
11 WLLO\I/ COVE SUB DISTRIBUTION.UNATTEN 34.50 4.',!6
12 WINSTC)N SUB DISTRIBUTION-UNATTEN 69.00 12.47
'13 YEWAV'ENUE SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
14 YOUNG.S BAY SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
15 TOTAL (Number of Substations-176)15500.31 2539.44 150.47
16
17 ALBINA SUB T/D-UNATTENDED 116.00
18 APPLEC|ATE SUB T/D-UNATTENDED 1 15.00 69.00 12.47
19 ASHLA.ND SUB T/D-UNATTENDED 1 15.00 12.47 7.20
20 BEND P-ANT SUB T/D.UNATTENDED 69.00 13.09 12.47
21 CAVE.JI,JNCTION SUB T/D-UNATTENDED 1 15.00 12.47 69.00
22 HAZELU/OOD SUB T/D-UNATTENDED 115.00 69.00 't2.47
23 KNOTI'ISUB T/D-UNATTENDED 115.00 12.47 57.00
24 MILE HI SUB T/D-UNATTENDED 1 15.00 69.00 12.47
25 PILOT BUTTE SUB T/D.UNATTENDED 230.00 69.00 't2.47
26 RIDDLE SUB T/D-UNATTENDED 1 15.00 69.00
27 SAGE RI3AD SUB T/D-UNATTENDED I 15.00 12.47
28 WNCHESTER SUB T/D-UNATTENDED '1 't 5.00 12.47 69.00
29 TOTAL (Number of Substations-12)1450.00 420.44 2U.55
30
31 LEMOL,C) #1 HYDRO TRANSMISSION-ATTENDE 11.50 't2.50
32 CALAPCOYA SUB TRANSMISSION-UNATTEN 230.00 69.00
33 CHILOQJIN SUB TRANSMISSION-UNATTEN 230.00 '1 15.00 69.00
34 COLD IJI'RINGS SUB TRANSMISSION-UNATTEN 230.00 69.00 2.40
35 COVE IJIJB TRANSMISSION-UNATTEN 230.00 69.00
36 DIAMOND HILL SUB TRANSMISSION-UNATTEN 230.00 69.00
37 DIXONVILLE 115/230 SUB TRANSMISSION-UNATTEN 230.0c 1 15.00 69.00
38 TRANSMISSION-UNATTEN 500.00 230.00
39 FISH HOLE SUB TRANSMISSION.UNATTEN 1 15.00 69.00
40 FRY SLJT}TRANSMISSION-UNATTEN 230.00 1 15.00
FERC FORM NO. 1 (ED. {2-96)Page 426.8
DXON'ilLLE 5OO SUB
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
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 substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(f)
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
0)
Total Capacity
(ln MVa)
(k)
30 1 1
7 1 2
12 J 3
25 2 4
2 3 5
3 1 6
25 1 7
22 9 E
40 2 I
60 3 10
28 3 11
22 3 12
25 1 13
37 2 14
4653 335 5 15
16
60 1 1 17
65 2 18
20 1 19
31 3 20
70 2 21
106 3 22
162 5 23
39 4 24
400 4 25
75 2 26
40 2 27
75 E 28
1143 34 1 29
30
2 3 31
87 2 32
119 4 33
66 2 34
67 3 35
75 1 36
344 6 37
650 3 1 38
7 3 39
500 2 40
FERC FORM NO. r (ED. 12-96)Page 427.8
SUBS
Name of ResF)ondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20'l8lQ4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
,|GRANTS PASS SUB TRANSMISSION-UNATTEN 230.00 1 15.00 69.00
2 TRANSMISSION-UNATTEN 230.00 69.00 2.40
3 ISTHMLIS SUB TRANSMISSION-UNATTEN 230.00 1 15.00
4 KLAM/\.TH FALLS SUB TRANSMISSION-UNATTEN 230.00 69.00
5 LONE PINE SUB TRANSMISSION-UNATTEN 230.00 1 15.00 69.00
6 TRANSMISSION-UNATTEN 500.00 230.00 69.00
TRANSMISSION-UNATTEN 500.00 230.00
I MONPAC SUB TRANSMISSION-UNATTEN 115.00 69.00
I NICKEL MOUNTAIN SUB TRANSMISSION.UNATTEN 230.00 1 15.00
10 PARRISH GAP SUB TRANSMISSION-UNATTEN 230.00 69.00 12.47
11 PONDEROSA SUB TRANSMISSION-UNATTEN 230.00 1 15.00
12 PROSPI=CT CENTRAL SUB TRANSMISSION-UNATTEN 1 15.00 69.00
13 ROBERTS CREEK SUB TRANSMISSION-UNATTEN 1 15.00 69.00
14 TRANSMISSION-UNATTEN 230.00 69.00
15 TRANSMISSION-UNATTEN 230.00 69.00
16 SNOW GOOSE SUB TRANSMISSION-UNATTEN 525.00 230.00 34.50
17 TROUTDALE SUB TRANSMISSION-UNATTEN 230.00 't't 5.00 69.00
18 TUCKER SUB TRANSMISSION-UNATTEN 1 15.00 69.00
19 WHETSTONE SUB TRANSMISSION-UNATTEN 230.00 115.00 12.47
20 TOTAI. r,Number of Substations-29)6981.50 3048.50 478.24
21
22 UTAH
23 1O6TH SiOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.47
24 118TH SiOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.47
25 23RD S'T SUB DISTRIBUTION-UNATTEN 46.00 12.47
26 TOTH SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.47
27 ALTAVIEWSUB DISTRIBUTION.UNATTEN 46.00 12.47
28 AMALGI\ SUB DISTRIBUTION-UNATTEN 46.00 12.47
29 AMERIC;AN FORK SUB DISTRIBUTION-UNATTEN 138.00 12.47
30 ARAGO\ITE DISTRIBUTION-UNATTEN 46.00 7.20
31 AUROR,C SUB DISTRIBUTION-UNATTEN 46.00 12.47
32 BANGEITTER SUB DISTRIBUTION-UNATTEN 138.00 12.47
33 BEAR RIVER SUB DISTRIBUTION-UNATTEN 46.00 12.47
34 BENJANIIN SUB DISTRIBUTION-UNATTEN 46.20 12.47
35 BINGHA.M SUB DISTRIBUTION-UNATTEN 46.00 7.62
36 BLUE (] REEK DISTRIBUTION.UNATTEN 46.00 12.47
37 BLUFF {iUB DISTRIBUTION-UNATTEN 69.00 12.47
38 BLUFFDALE SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 BOTHWELL SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 BRIAN I.IEAD SUB DISTRIBUTION.UNATTEN 34.50 12.47
FERC FORM NO.1 (ED. 12-96)Page 426.9
SUB
MALIN IiUB
7 MERII)I,qN SUB
ROUNDUP SUB - BPA
TIE. BPA
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
5. Show in columns (l), [), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondents books of account. Specifu 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)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
o
Total Capacity
(ln MVa)
(k)
583 4 3 1
29 2 2
250 1 3
251 6 1 4
733 10 5
775 4 1 6
1 300 6 1 7
50 1 8
114 1 9
150 I 10
500 2 11
30 3 12
50 1 13
67 2 14
75 1 15
650 1 1 16
500 3 17
100 2 18
250 1 19
8374 81 8 20
21
22
30 1 23
30 1 24
12 1 25
30 1 26
45 2 27
11 1 28
30 1 29
1 1 30
3 1 31
50 2 32
17 2 33
4 1 34
25 1 35
2 3 36
,|3 37
o 1 38
4 1 39
14 1 40
FERC FORM NO.1 (ED.12.96)Page 427.9
PacifiCorp (1)
(2\
Original
Resubmission
Date of
(Mo, Datt
Report
r, Yr)
Year/Period of Report
End of 20181Q4
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substatic,ns 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 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 BRIGHTON SUB DISTRIBUTION-UNATTEN 46.0C 24.90
2 BROOKLA\^JN SUB DISTRIBUTION-UNATTEN 46.00 12.47
3 BRUNSWCK SUB DISTRIBUTION-UNATTEN 46.00 12.47
4 BURTON SUB DISTRIBUTION-UNATTEN 34.5C 12.47
5 BUSH SiUB DISTRIBUTION-UNATTEN 46.00 12.47
6 CANNON SUB DISTRIBUTION-UNATTEN 46.00 12.47
7 CANYONLANDS SUB DISTRIBUTION-UNATTEN 69.00 12.47
8 CAPITCIL SUB DISTRIBUTION-UNATTEN 46.00 12.47
I CARBIEIE SUB DISTRIBUTION.UNATTEN 69.00 7.20
10 CARBONVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
11 CARLISLE SUB DISTRIBUTION-UNATTEN 138.00 12.47
12 CASTO SUB DISTRIBUTION-UNATTEN 46.00 12.47
'13 CENTEITVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 CENTR,qL SUB DISTRIBUTION-UNATTEN 43.80 12.47
15 CHAPEL HILL SUB DISTRIBUTION-UNATTEN 138.00 12.47
16 CHERRYWOOD SUB DISTRIBUTION-UNATTEN 138.00 12.47
17 CIRCLEVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47
18 CLEAR CREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47
19 CLEAR LAKE SUB DISTRIBUTION-UNATTEN 69.00 12.47
20 CLEARFIELD SOUTH SUB DISTRIBUTION-UNATTEN 138.00 12.47
21 CLINTON SUB DISTRIBUTION-UNATTEN 138.00 12.47
22 CLIVE SUB DISTRIBUTION-UNATTEN 46.00 12.47
23 COAL\/ILLE SUB DISTRIBUTION-UNATTEN 138.00 12.47
24 COLD VI/ATER CANYON SUB DISTRIBUTION-UNATTEN 138.00 12.47
25 COLEIVIAN SUB DISTRIBUTION-UNATTEN 138.00 69.00 12.47
26 COLTOI! WELL SUB DISTRIBUTION-UNATTEN 46.00 2.40
27 COMME:RCE SUB DISTRIBUTION-UNATTEN 138.00 12.47
28 COPPER HILLS SUB DISTRIBUTION-UNATTEN 't 38.00 12.47
29 CORINT.IE SUB DISTRIBUTION-UNATTEN 46.00 't2.47
30 COVE FORT SUB DISTRIBUTION-UNATTEN 46.00 12.47
31 COZYD,CLE SUB DISTRIBUTION-UNATTEN 1 38.00 12.47
32 CROSS HOLLOW SUB DISTRIBUTION-UNATTEN 138.00 12.47
33 CUDAHY SUB DISTRIBUTION-UNATTEN 138.00 12.47
34 DAMMERON VALLEY SUB DISTRIBUTION-UNATTEN 34.50 12.47
35 DECKEIT LAKE SUB DISTRIBUTION-UNATTEN 138.00 12.47
36 DELLEI IJUB DISTRIBUTION-UNATTEN 46.00 12.47
37 DELTA TSUB DISTRIBUTION-UNATTEN 46.00 69.00
38 DEWEYVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 DIMPLE DELL SUB DISTRIBUTION-UNATTEN 138.00 12.47
40 DRAPEIT SUB DISTRIBUTION-UNATTEN 46.00 12.47
FERC FORM NO.1 (ED. 12-95)Page 426.10
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
5. Show in columns (l), O, 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 otheruise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondents books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(D
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(D
Number of Units
0)
Total
(ln
Capacity
r MVa)
(k)
29 2 1
6 1 2
60 3 3
11 J 4
I 1 5
12 1 o
I 1 7
20 1 I
3 I I
6 1 10
30 ,|11
25 1 12
22 1 13
I 1 14
30 1 15
50 2 16
3 1 17
4 ,|18
3 19
60 2 20
50 2 21
4 1 22
22 1 23
30 1 24
'106 4 25
1 3 26
30 1 27
30 1 28
3 1 29
2 3 30
30 1 31
22 1 32
30 1 33
42 1 34
55 2 35
6 1 36
48 3 JI
4 1 38
60 2 39
23 40
FERC FORrul NO. 1 (ED.12-96)Page 427.10
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report br:low 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. Substaticrns with capacities of Less than '10 MVa except those serving customers with energy for resale, may be grouped according to
functional ctraracter, 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 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)
(c)
Secondary
(d)
Tertiary
(e)
1 EAST BENCH SUB DISTRIBUTION-UNATTEN 138.00 12.47
2 EAST HYRUM SUB DISTRIBUTION-UNATTEN 46.00 12.47
3 EAST LAYTON SUB DISTRIBUTION-UNATTEN 138.00 12.47
4 EAST MILLCREEK SUB DISTRIBUTION.UNATTEN 46.00 12.47
5 EDEN SiUB DISTRIBUTION-UNATTEN 46.0C 12.47
6 ELBERTA SUB DISTRIBUTION-UNATTEN 46.0C 12.47
7 ELK MEADOWS SUB DISTRIBUTION-UNATTEN 46.00 12.47
8 ELSINORE SUB DISTRIBUTION-UNATTEN 46.00 't2.47
I EMERY CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47
10 EMIGR/\TION SUB DISTRIBUTION-UNATTEN 46.0C 12.47
11 ENOCH SUB DISTRIBUTION-UNATTEN 138.0C 12.47
12 ENTERPRISE VALLEY SUB DISTRIBUTION-UNATTEN 138.00 12.47
13 EUREKA SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 FARMINIGTON SUB DISTRIBUTION-UNATTEN 138.0C 12.47
15 FAYEN'E SUB DISTRIBUTION-UNATTEN 46.0C 12.47
16 FERRON SUB DISTRIBUTION-UNATTEN 69.00 12.47
17 FIELDINIG SUB DISTRIBUTION-UNATTEN 46.0C 12.00
18 FIFTH WEST SUB DISTRIBUTION.UNATTEN 138.00 12.47
19 FLUX SUB DISTRIBUTION-UNATTEN 46.0C 12.47
20 FOOL CREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47
21 FORT DOUGLAS DISTRIBUTION-UNATTEN 138.00 13.20
22 FOUNTAIN GREEN SUB DISTRIBUTION-UNATTEN 46.0C 12.47
23 FREEDOM SUB DISTRIBUTION.UNATTEN 46.0C 7.20
24 FRUIT IIEIGHTS SUB DISTRIBUTION-UNATTEN 46.0C 12.47
25 GARDEN CITY SUB DISTRIBUTION-UNATTEN 69.0C 12.47
26 GATEWAY SUB DISTRIBUTION.UNATTEN 69.00 12.47
27 GOLD RUSH SUB DISTRIBUTION-UNATTEN 138.00 12.47
28 GORDON AVENUE SUB DISTRIBUTION-UNATTEN 138.0C 12.47
29 GOSHEN SUB DISTRIBUTION-UNATTEN 46.0C 12.47
30 GRANGER SUB DISTRIBUTION-UNATTEN 46.0C 12.47
31 GRANTSVILLE SUB DISTRIBUTION.UNATTEN 46.00 12.47
32 GUNNISiON SUB DISTRIBUTION.UNATTEN 46.00 12.47
33 HAMMER SUB DISTRIBUTION-UNATTEN 138.00 12.47
34 HAVASIJ SUB DISTRIBUTION-UNATTEN 69.00 12.47
35 HELPEFI CIry SUB DISTRIBUTION.UNATTEN 46.00 4.16
36 HERRIMAN SUB DISTRIBUTION-UNATTEN 138.00 13.20
37 HIGHLAND DIST SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 HOGGARD SUB DISTRIBUTION-UNATTEN 138.00 12.47
39 HOLDEII SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 HOLLADAY SUB DISTRIBUTION-UNATTEN 46.00 12.47
FERC FORM NO. { (ED.12-96)Page 426.'|.1
Primary
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)ll
Year/Period of Report
End of 20181Q4
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 substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other pafi is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(f)
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
0)
Total Capacity
(ln MVa)
(k)
30 1 1
6 I 2
60 2 3
20 1 4
19 2 5
5 1 6
3 1 7
2 1 8
3 3 I
25 1 '10
14 1 11
10 1 12
3 1 13
30 1 14
1 2 15
5 I '16
6 1 17
50 2 18
4 1 19
2 1 20
40 1 21
7 1 22
1 23
22 1 24
12 ,|25
14 1 2 26
30 1 27
30 ,|28
2 ,|29
50 2 30
23 1 31
11 2 32
60 2 33
3 1 34
3 3 35
60 2 36
25 1 37
50 2 38
4 1 39
32 2 40
FERC FORM NO.1 (ED. 12.96)Page 427.11
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. lndicate irr 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 HUNTER SUB DISTRIBUTION-UNATTEN 46.00 12.47
2 HUNTINIGTON CITY SUB DISTRIBUTION-UNATTEN 69.00 12.47
3 IRON MOUNTAIN SUB DISTRIBUTION-UNATTEN 34.50 7.20
4 IRONTON SUB DISTRIBUTION-UNATTEN 46.00 12.47
5 IVINS SUB DISTRIBUTION-UNATTEN 67.00 12.47
6 JORDr\lrl NARROWS SUB DISTRIBUTION-UNATTEN 46.00 2.40
7 JORDAhI PARK SUB DISTRIBUTION-UNATTEN 138.00 12.47
8 JORDr\lrlELLE SUB DISTRIBUTION-UNATTEN 138.00 12.47
I JUAB SIJB DISTRIBUTION-UNATTEN 46.00 12.47
10 JUNCI-ICN SUB DISTRIBUTION-UNATTEN 69.00 't2.47
11 KAIBAB SUB DISTRIBUTION.UNATTEN 69.00 't2.47
12 KAMAS SUB DISTRIBUTION-UNATTEN 46.00 12.47
'13 KEARNIS SUB DISTRIBUTION-UNATTEN 138.00 12.47
14 KENSINGTON SUB DISTRIBUTION-UNATTEN 46.00 4.16
15 KYUNE SUB DISTRIBUTION-UNATTEN 46.00 7.20
16 LAKE P,\RK SUB DISTRIBUTION-UNATTEN 138.00 't2.47
17 LAYTOII SUB DISTRIBUTION-UNATTEN 46.00 't2.47
18 LEGRANDE SUB DISTRIBUTION.UNATTEN 46.00 12.47
19 LEWISTON SUB DISTRIBUTION-UNATTEN 46.00 7.20
20 LINCOLN SUB DISTRIBUTION.UNATTEN 46.00 't2.47
21 LINDON SUB DISTRIBUTION-UNATTEN 46.00 12.47
22 LISBON SUB DISTRIBUTION-UNATTEN 70.60 12.47
23 LOAFEFI SUB DISTRIBUTION-UNATTEN 46.00 't2.47
24 LOGAN CANYON SUB DISTRIBUTION.UNATTEN 46.00 7.20
25 LONE TREE SUB DISTRIBUTION-UNATTEN 34.50 12.47
26 LOWER BEAVER SUB DISTRIBUTION.UNATTEN 46.00 6.60
27 LYNND.\TL SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 MAESEIT SUB DISTRIBUTION-UNATTEN 69.00 12.47
29 MAGNA SUB DISTRIBUTION-UNATTEN 138.00 't2.47
30 MANILA SUB DISTRIBUTION-UNATTEN 138.00 12.47
31 MANTUA SUB DISTRIBUTION.UNATTEN 44.O0 12.47
32 MAPLE:]'ON SUB DISTRIBUTION-UNATTEN 46.00 12.47
33 MARRIOTT SUB DISTRIBUTION-UNATTEN 46.00 12.47
34 MARYS\/ALE SUB DISTRIBUTION.UNATTEN 46.00 12.47
3s MATHIS SUB DISTRIBUTION-UNATTEN 46.00 12.47
36 MCCORNICK SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 MCKAY SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 MEADO'A/BROOK SUB DISTRIBUTION-UNATTEN 138.00 12.47 46.00
39 MEDICT,L SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 MIDLAND SUB DISTRIBUTION-UNATTEN 138.00 12.47
FERC FORM NO. 1 (ED. 12-96)Page 426.12
Name of Respondent
PacifiCorp (1)
(2\
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
5. Show in columns (l), [), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other pafi is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(D
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
U)
Total
(ln
Capacity
MVa)
(k)
22 1 1
12 2 2
,|1 3
2 1 4
30 1 5
13 2 6
30 1 7
30 1 I
4 1 I
3 1 10
5 ,|11
7 1 12
60 2 13
7 ,|14
I 15
53 2 't6
40 2 17
2 1 18
22 1 19
20 1 20
20 1 21
3 1 22
1 23
1 1 24
20 1 25
1 1 26
4 I 27
12 1 28
30 1 29
22 1 30
2 1 3'1
14 1 32
20 1 33
3 1 34
I 1 35
6 1 36
20 1 JI
42 2 38
57 4 39
30 1 40
FERC FORM NO. I (ED. 12-96)Page 427.12
Name of Respondent
PacifiCorp
(1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report berlow the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 MIDVALE SUB DISTRIBUTION-UNATTEN 46.00 12.47
2 MILFORD SUB DISTRIBUTION-UNATTEN 138.00 46.00
3 MILFORD TV SUB DISTRIBUTION-UNATTEN 46.00 13.20
4 MINERSVILLE SUB DISTRIBUTION-UNATTEN 46.00 12.47
5 MOAB CiITY SUB DISTRIBUTION-UNATTEN 69.00 12.47
6 MOORE SUB DISTRIBUTION-UNATTEN 69.00 12.47
7 MORGAN SUB DISTRIBUTION-UNATTEN 46.00 4.16
I MORONI SUB DISTRIBUTION-UNATTEN 46.00 12.47
I MOUNT,clN DELL SUB DISTRIBUTION-UNATTEN 46.00 12.47
10 MOUNT,CIN GREEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
11 MYTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
't2 NEW HP,RMONY SUB DISTRIBUTION.UNATTEN 69.00 12.47
13 NEWG.ATE SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 NEWTOI\ SUB DISTRIBUTION-UNATTEN 46.00 12.47
15 NIBLE\/ SUB DISTRIBUTION-UNATTEN 138.00 24.90
16 NORTI-I BENCH SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 NORTI-I FIELDS SUB DISTRIBUTION-UNATTEN 46.00 12.47
18 NORTI-I LOGAN SUB DISTRIBUTION-UNATTEN 46.00 12.47
19 NORTII OGDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
20 NORTI-{ SALT LAKE SUB DISTRIBUTION-UNATTEN 46.00 13.20
2',1 NORTHEtrAST SUB DISTRIBUTION-UNATTEN 46.00 12.50
22 NORTHRIDGE SUB DISTRIBUTION.UNATTEN 46.00 12.47
23 OAKLAND AVE SUB DISTRIBUTION-UNATTEN 46.00 12.47
24 OAKLEY SUB DISTRIBUTION.UNATTEN 46.00 12.47
25 OLYMF,L'S SUB DISTRIBUTION-UNATTEN 46.00 12.47
26 OPHIR S|UB DISTRIBUTION-UNATTEN 46.00 12.47
27 ORANGE SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 ORANGEVILLE SUB DISTRIBUTION-UNATTEN 69.00 12.47
29 OREM SUB DISTRIBUTION-UNATTEN 46.00 12.47
30 PACK CttEEK RESERVOIR DISTRIBUTION-UNATTEN 46.00 't2.47
31 PANGUICH SUB DISTRIBUTION-UNATTEN 69.00 12.47
32 PARIET]'E SUB DISTRIBUTION.UNATTEN 69.00 24.94
33 PARK CITY SUB DISTRIBUTION.UNATTEN 46.00 12.47
34 PARKSIDE SUB DISTRIBUTION.UNATTEN 138.00 12.47
35 PARK\^/I\Y SUB DISTRIBUTION.UNATTEN 138.00 12.47
36 PARLEYS SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 PELICAN POINT SUB DISTRIBUTION.UNATTEN 46.00 12.47
38 PINE CANYON SUB DISTRIBUTION-UNATTEN 138.00 12.47
39 PINE CREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 PINNACl-E SUB DISTRIBUTION.UNATTEN 46.00 12.47
FERC FORM NO. 1 (ED. 12-96)Page 426.13
Name
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)ll
Year/Period of Report
End of 2018/Q4
5. Show in columns (l), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otheruise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(f)
Number of
Transformers
ln Service
(q)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(D
Number of Units
(i)
Total Capacity
(ln MVa)
(k)
25 1 I
89 2 2
,|3
2 1 4
19 2 5
3 1 6
7 2 7
6 1 8
5 1 I
6 1 10
6 1 11
7 1 12
20 1 13
5 1 14
14 1 15
25 1 16
2 1 17
25 1 18
22 ,|19
25 1 20
45 2 21
14 1 22
24 2 23
6 1 24
22 1 25
J 1 26
20 1 27
14 1 28
48 2 29
4 1 30
5 1 31
't4 1 32
42 2 33
60 2 u
50 2 35
16 2 36
6 1 37
55 2 38
2 1 39
14 ,|40
FERC FORM NO. 1 (ED.12-96)Page 427.13
Name of Respondent
PacifiCorp (1)
(2\
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 2018/Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substati,crls 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 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 PLAIN CITY SUB DISTRIBUTION-UNATTEN 138.00 12.47
2 PLEASANT GROVE SUB DISTRIBUTION-UNATTEN 138.00 12.47
3 PLEASANT VIEW SUB DISTRIBUTION-UNATTEN 46.00 12.47
4 PONY EXPRESS SUB DISTRIBUTION-UNATTEN 138.00 12.47
5 PORTE:R ROCKWELL SUB DISTRIBUTION-UNATTEN 138.00 13.20
6 PROMONTORY SUB DISTRIBUTION-UNATTEN 46.00 12.47
7 QUAIL C;REEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
I OUARIi'/ SUB DISTRIBUTION-UNATTEN 138.00 12.47
I QUICHAPA SUB DISTRIBUTION-UNATTEN 34.50 12.47
10 RAINS SiUB DISTRIBUTION-UNATTEN 46.00 7.20
't'l RANDOI.PH SUB DISTRIBUTION-UNATTEN 46.00 12.47
12 RASMIJ{SON SUB DISTRIBUTION-UNATTEN 46.00 12.47
13 RATTLESNAKE SUB DISTRIBUTION-UNATTEN 69.00 24.90
14 RED MCIUNTAIN SUB DISTRIBUTION.UNATTEN 69.00 34.50
15 REDWOOD SUB DISTRIBUTION-UNATTEN 46.00 12.47
16 RESEAFICH PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 RICH S|LIB DISTRIBUTION-UNATTEN 69.00 12.47
18 RICHFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47
19 RICHMOND SUB DISTRIBUTION.UNATTEN 46.00 12.47
20 RIDGEL\ND SUB DISTRIBUTION-UNATTEN 138.00 12.47
21 RITER SUB DISTRIBUTION-UNATTEN 46.00 12.47
22 ROCK CANYON SUB DISTRIBUTION-UNATTEN 69.00 12.47
23 ROCKVILLE SUB DISTRIBUTION-UNATTEN 34.50 12.47
24 ROCKY POINT DISTRIBUTION-UNATTEN 138.00 13.20
25 ROSE P,qRK SUB DISTRIBUTION-UNATTEN 46.00 12.47
26 ROYAL. IJUB DISTRIBUTION-UNATTEN 46.00 4.16
27 SALINI\ SUB DISTRIBUTION-UNATTEN 46.00 12.47
28 SANDY'ISUB DISTRIBUTION-UNATTEN 138.00 12.47
29 SARATOGA SUB DISTRIBUTION-UNATTEN 1 38.00 12.47
30 SCIPIC, IJUB DISTRIBUTION-UNATTEN 46.00 12.47
31 SCOFII]I-D RESERVOIR SUB DISTRIBUTION-UNATTEN 46.00 7.20
32 SCOFIELD SUB DISTRIBUTION-UNATTEN 46.00 12.47
33 SEGO 3ANYON SUB DISTRIBUTION.UNATTEN 69.00 12.47
34 SEVEN IilILE SUB DISTRIBUTION-UNATTEN 68.68 7.20
35 SHARO]{ SUB DISTRIBUTION-UNATTEN 46.00 12.47
36 SHORE:L.|NE SUB DISTRIBUTION-UNATTEN 138.00 13.20
37 SIXTH SOUTH SUB DISTRIBUTION-UNATTEN 46.00 12.47
38 SKULL \ALLEY SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 SKYPAR.K SUB DISTRIBUTION-UNATTEN 138.00 12.47 12.47
40 SNARFI ISUB DISTRIBUTION-UNATTEN 46.00 12.47
FERC FORM NO. 1 (ED. 12-96)Page 426.14
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
5. Show in columns (l), O, and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
0
Number of Units
0)
Total Capacity
(ln MVa)
(k)
22 1 1
25 1 2
14 1 3
60 2 4
60 2 5
2 1 6
4 1 7
60 2 I
4 1 9
15 1 10
2 ,|11
1 3 12
14 1 13
12 1 14
45 2 15
45 2 16
5 1 17
22 2 18
11 1 19
40 2 20
20 I 21
5 1 22
4 1 23
30 1 24
24 J 25
J 26
11 1 27
60 2 28
60 2 29
1 3 30
1 1 31
,|3 32
14 1 33
1 34
20 I 35
60 2 36
20 1 37
2 1 38
40 1 39
40 2 40
FERC FORM NO. ,l (EO. 12-96}Page 427.14
Name of
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report trerlow the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than '10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 SNO\AfolLLE SUB DISTRIBUTION-UNATTEN 69.00 12.47
2 SNYDEITVILLE SUB DISTRIBUTION-UNATTEN 138.00 46.00
3 SOLDIER SUMMIT SUB DISTRIBUTION-UNATTEN 46.00 12.47
4 SOUTII JORDAN SUB DISTRIBUTION-UNATTEN 138.00 12.47
5 SOUTII MILFORD SUB DISTRIBUTION-UNATTEN 46.00 12.47
6 SOUTII MOUNTAIN SUB DISTRIBUTION-UNATTEN 138.00 12.47
7 SOUTH OGDEN SUB DISTRIBUTION-UNATTEN 46.00 12.47
I SOUTH PARK SUB DISTRIBUTION-UNATTEN 138.00 12.47
I SOUTH WEBER SUB DISTRIBUTION.UNATTEN 138.00 12.47
10 SOUTII'/UEST SUB DISTRIBUTION-UNATTEN 46.00 12.47
11 SPANISH VALLEY SUB DISTRIBUTION-UNATTEN 67.00 12.47
12 SPRINC;DALE SUB DISTRIBUTION.UNATTEN 34.50 12.47
13 ST. JOI-INS SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 STANSI]URY SUB DISTRIBUTION-UNATTEN 46.00 12.47
15 SUMMI'T CREEK SUB DISTRIBUTION-UNATTEN 138.00 12.47
16 SUMMI-T PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
17 SUNRISE SUB DISTRIBUTION-UNATTEN 138.00 12.47
18 SUTHERLAND SUB DISTRIBUTION-UNATTEN 46.00 12.47
19 TAMARISK SUB DISTRIBUTION-UNATTEN 138.00 12.47
20 TAYLOI1 SUB DISTRIBUTION-UNATTEN 46.00 12.47
21 THIEF CREEK SUB DISTRIBUTION-UNATTEN 138.00 24.90
22 THIRD \A/EST SUB DISTRIBUTION-UNATTEN 138.00 't3.20
23 THIRTEENTH SOUTH SUB DISTRIBUTION.UNATTEN 46.00 12.47
24 TOOELI= DEPOT SUB DISTRIBUTION-UNATTEN 46.00 12.50
25 TOQUERVILLE SUB DISTRIBUTION.UNATTEN 69.00 12.47 34.50
26 UINTA,FI SUB DISTRIBUTION-UNATTEN 46.00 12.47
27 UNION SUB DISTRIBUTION-UNATTEN 46.00 't2.47
28 VALLEY CENTER SUB DISTRIBUTION-UNATTEN 46.00 12.47
29 VERMII..LION SUB DISTRIBUTION-UNATTEN 46.00 12.47
30 VERN,AL SUB DISTRIBUTION-UNATTEN 69.00 12.47
31 VICKE,FIS SUB DISTRIBUTION-UNATTEN 46.00 12.47
32 VINEYT.RD SUB DISTRIBUTION-UNATTEN 138.0C 't3.20
33 WALLISI3URG SUB DISTRIBUTION-UNATTEN 138.00 12.47
34 WALNUT GROVE SUB DISTRIBUTION-UNATTEN 138.00 12.47
35 WARFIE:N SUB DISTRIBUTION.UNATTEN 138.0C 12.47
36 WASATCH STATE PARK SUB DISTRIBUTION-UNATTEN 46.00 12.47
37 WASFIP.KIE SUB DISTRIBUTION-UNATTEN 138.00 4.16
38 WELBY SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 \A/ELFARE SUB DISTRIBUTION-UNATTEN 46.00 12.47
40 WEST COMMERCIAL SUB DISTRIBUTION-UNATTEN 46.00 12.47
FERC FORM hto.1 (ED. 12-96)Page 426.15
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
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 substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other pafi, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(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
fi)
Total Capacity
(ln MVa)
(k)
5 1 1
127 3 2
12 1 3
60 2 4
28 2 5
60 2 6
25 1 7
30 1 8
22 1 I
22 2 10
14 1 1',1
4 1 12
4 1 13
20 1 14
14 1 15
7 1 16
60 2 17
6 1
'18
20 1 19
14 1 20
14 1 21
100 2 22
22 I 23
25 ,|24
34 2 25
39 2 26
50 2 27
22 1 2E
3 I 29
33 2 30
2 1 3t
30 1 32
13 1 JJ
30 ,|34
30 1 35
2 3 36
't4 I 37
42 2 38
10 1 39
22 1 40
FERC FORM NO. 1 (ED. 12-96)Page 427.15
PacifiCorp (1)
(2',)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 WEST JORDAN SUB DISTRIBUTION.UNATTEN 138.00 12.47
2 WEST OGDEN SUB DISTRIBUTION-UNATTEN 138.00 12.47
3 WEST F'OINT SUB DISTRIBUTION-UNATTEN 138.00 13.20
4 WEST FIOY SUB DISTRIBUTION-UNATTEN 46.00 12.47
5 WEST T'EMPLE SUB DISTRIBUTION-UNATTEN 46.00 4.16
6 WESTTA/ATER SUB DISTRIBUTION.UNATTEN 69.00 12.47
7 WHITE: ROCK SUB DISTRIBUTION.UNATTEN 138.00 12.47
8 WILLOVVCREEK SUB DISTRIBUTION-UNATTEN 46.00 12.47
o WLLC,VVRIDGE SUB DISTRIBUTION-UNATTEN 44.90 12.47
10 WNCHESTER HILLS SUB DISTRIBUTION-UNATTEN 34.50 12.47
11 WNKL.EIMAN SUB DISTRIBUTION.UNATTEN 46.00 7.20
12 WOLF C}REEK SUB DISTRIBUTION.UNATTEN 69.00 12.47
13 WOOD,IROSS SUB DISTRIBUTION-UNATTEN 46.00 12.47
14 WOODFIUFF SUB DISTRIBUTION-UNATTEN 46.00 12.47
15 TOTAL,lNumber of Substations-272)20128.68 3524.38 105.44
16
17 gOTH SOUTH SUB T/D-UNATTENDED 345.00 138.00 12.47
18 ANGEI- SUB T/D-UNATTENDED 138.00 12.47 46.00
19 BDO SLIB T/D-UNATTENDED 138.00 12.47
20 BUTLE:FIVILLE SUB T/D-UNATTENDED 138.00 46.00 12.47
21 CENTENNIAL SUB T/D-UNATTENDED 138.00 12.47
22 COTTONWOOD SUB T/D-UNATTENDED 138.00 12.47 46.00
23 DECADI= SUB T/D-UNATTENDED 138.00 12.47
24 DUMAS SUB T/D.UNATTENDED 138.00 12.47
25 EMMA F'ARK SUB T/D-UNATTENDED 138.00 12.47
26 GRO\A/ ISUB T/D-UNATTENDED 138.00 12.47 46.00
27 HALE.SUB T/D-UNATTENDED 138.00 46.00 '12.47
28 HIGHLAND SUB T/D-UNATTENDED 138.00 12.47 46.00
29 JORDAI{ SUB T/D.UNATTENDED 138.00 46.00 12.47
30 JUDGE SUB T/D-UNATTENDED 46.00 12.47
31 MCCLELLAND SUB T/D-UNATTENDED 138.00 46.00 12.47
32 MORTON COURT SUB T/D-UNATTENDED 138.00 12.47
33 OQUIRRH SUB T/D-UNATTENDED 345.00 46.00 '138.00
34 PARRISH SUB T/D-UNATTENDED 138.00 12.47 46.00
35 PIONEER PLANT T/D-UNATTENDED 138.00 12.47
36 RIVERDALE SUB T/D-UNATTENDED 138.00 46.00 12.47
37 SEVIER SUB T/D-UNATTENDED 138.00 46.00 12.47
38 SILVER CREEK SUB T/D-UNATTENDED 138.00 12.47 46.00
39 SOUTIIEAST SUB T/D-UNATTENDED 138.00 12.47 46.00
40 SYRACIJSE SUB T/D.UNATTENDED 345.00 138.00 46.00
FERC FORM NO. I (ED. 12-96)Page 426.16
Name of Respondent
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)ll
Year/Period of Report
End of 20181Q4
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 substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
0
Number of Units
o
Total Capacity
(ln MVa)
(k)
28 1 1
60 2 2
40 1 3
25 1 4
60 3 5
5 1 6
30 1 7
1 1 8
24 1 I
4 ,|10
1 11
6 1 12
20 1 13
2 1 14
5810 374 2 15
16
1572 5 17
135 3 18
30 1 19
205 4 20
40 2 21
289 7 22
60 2 23
60 2 24
8 1 25
72 J 26
114 2 27
97 2 2E
164 2 29
22 1 30
340 3 31
65 2 3Z
835 4 1 33
97 2 34
30 ,|35
180 3 36
34 4 37
100 2 38
50 2 39
1 300 6 40
FERC FORM NO. 1 (ED. 12-96)Page 427.16
Name of Resrrondent
PacifiCorp
(1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report bellow the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. 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)
Characler of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 TAYLORSVILLE SUB T/D-UNATTENDED 138.00 46.00 12.47
2 TERMINAL SUB T/D-UNATTENDED 345.00 46.00 138.00
3 TIMP SUB T/D-UNATTENDED 138.00 46.00 12.47
4 TOOELE SUB T/D-UNATTENDED 138.00 46.00 12.47
5 TRI CITT SUB T/D.UNATTENDED 138.00 12.47
6 WEST \ALLEY SUB T/D-UNATTENDED 138.00 12.47
7 WESTFIELD SUB T/D-UNATTENDED 138.00 12.47
I TOTAL. lNumber of Substations-31)5014.00 1006.46 768.70
I
10 EMERY SUB TRANSMISSION-ATTENDE 345.00 138.00 69.00
't1 GADSB'/ SUB TRANSMISSION-ATTENDE 138.00 46.00
12 ABAJC' ISUB TRANSMISSION-UNATTEN 138.00 69.00
13 ASHLEY SUB TRANSMISSION-UNATTEN 138.00 46.00
14 BARNE\/ SUB TRANSMISSION-UNATTEN 138.00 46.00
15 BEN LOIVOND SUB TRANSMISSION-UNATTEN 345.00 230.00 138.00
16 BLACK ROCK SUB TRANSMISSION-UNATTEN 230.00 69.00
't7 BLACKI-IAWK SUB TRANSMISSION-UNATTEN 138.00 69.00 46.00
18 CAMERI)N SUB TRANSMISSION-UNATTEN 138.00 46.00
19 CAMP V/ILLIAMS SUB TRANSMISSION-UNATTEN 345.00 138.00 12.47
20 CLOVE:R SUB TRANSMISSION.UNATTEN 345.00 138.00 14.40
21 COLUMI3IA SUB TRANSMISSION-UNATTEN 138.00 46.00 12.47
22 CRANEII FLAT SUB TRANSMISSION.UNATTEN 138.00 't2.47
23 CROYDIfN SUB TRANSMISSION-UNATTEN 138.00 46.00 12.47
24 CUTLEFI SUB TRANSMISSION.UNATTEN 138.00 46.00
25 EL MONTE SUB TRANSMISSION-UNATTEN 138.00 46.00
26 GARKANE SUB TRANSMISSION.UNATTEN 69.00 46.00
27 GREEN CANYON SUB TRANSMISSION-UNATTEN 138.00 46.00
28 GRINDING SUB TRANSMISSION-UNATTEN 138.00 13.80
29 HELPER SUB TRANSMISSION-UNATTEN 138.00 46.00
30 HONEY]/ILLE SUB TRANSMISSION-UNATTEN 138.00 46.00
3'l HORSESHOE SUB TRANSMISSION-UNATTEN 138.00 46.00 12.47
32 HUNTINGTON SUB TRANSMISSION-UNATTEN 345.00 138.00 24.90
33 JERUSALEM SUB TRANSMISSION-UNATTEN 138.00 46.00
34 LAMPO SUB TRANSMISSION-UNATTEN 138.00 46.00
35 MATHINGTON SUB TRANSMISSION-UNATTEN 138.00 46.00 13.20
36 MCFADDEN SUB TRANSMISSION.UNATTEN 138.00 46.00
37 MIDDLETON SUB TRANSMISSION-UNATTEN 138.00 69.00 34.50
38 MIDVALLEY SUB TRANSMISSION.UNATTEN 345.00 138.00
39 MIDWAY CIry SUB TRANSMISSION-UNATTEN 138.00 46.00
40 MINERAL PRODUCTS SUB TRANSMISSION-UNATTEN 69.00 46.00
FERC FORM NO. 1 (ED. 12-96)Page 426.17
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
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 substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(f)
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
0)
Total Capacity
(ln MVa)
(k)
358 4 1
1 108 6 2 2
130 2 3
249 3 4
30 1 5
30 1 6
20 1 7
7824 84 3 8
I
783 '13 10
3't 8 2 11
67 1 12
133 2 13
100 1 14
1 813 E 15
75 1 16
100 2 17
25 4 18
169 2 19
448 ,|20
71 2 21
40 2 22
81 2 aa
50 1 24
312 J 25
33 1 26
67 2 27
225 J 28
77 2 29
35 1 30
80 2 3'l
270 4 32
67 1 33
75 1 34
160 E 1 35
45 1 36
137 3 37
900 2 38
67 1 39
1 40
FERC FORM NO. I (ED. r2.96)Page 427.17
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tl
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report trerlow the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 MOAB SiUB TRANSMISSION-UNATTEN 138.00 69.00
2 NEBO SUB TRANSMISSION.UNATTEN 138.00 46.00
J PARO!\AN VALLEY SUB TRANSMISSION-UNATTEN 230.00 138.00 34.50
4 PAVAN- SUB TRANSMISSION-UNATTEN 230.00 46.00
E PINTO SiUB TRANSMISSION.UNATTEN 345.00 138.00 69.00
6 PURGA'TORY FLAT SUBSTATION TRANSMISSION.UNATTEN 138.00 69.00 't2.47
7 RED BUTTE SUB TRANSMISSION-UNATTEN 345.00 138.00
8 SIGURCI SUB TRANSMISSION-UNATTEN 345.00 230.00 138.00
I SMITHFIELD SUB TRANSMISSION-UNATTEN 138.00 46.00 12.47
10 SPANISH FORK SUB TRANSMISSION-UNATTEN 345.00 138.00 46.00
11 ST GEORGE SUB TRANSMISSION-UNATTEN 138.00 16.50
12 THREE: PEAKS SUB TRANSMISSION-UNATTEN 345.00 138.00
13 WEST CEDAR SUB TRANSMISSION.UNATTEN 230.00 138.00 34.50
14 TOTAL. (Number of Substations-44)8579.00 3446.77 736.82
15
16 WASHINIGTON
17 ATTALU\ SUB DISTRIBUTION-UNATTEN 69.00 12.47
18 BOWMP,N SUB DISTRIBUTION-UNATTEN 69.00 12.47
19 CASCADE KRAFT SUB DISTRIBUTION-UNATTEN 69.00 12.47 4.16
20 CLINTON SUB DISTRIBUTION-UNATTEN 11s.00 12.47
21 DAYTON SUB DISTRIBUTION-UNATTEN 69.00 12.47
22 DODD F:OAD SUB DISTRIBUTION-UNATTEN 69.00 20.80
23 GRAND'r'IEW SUB DISTRIBUTION-UNATTEN 1 15.00 12.47 69.00
24 GROMCRE SUB DISTRIBUTION-UNATTEN 116.00 13.20
25 HOPLAIID SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
26 NACHEIJ SUB DISTRIBUTION-UNATTEN 't 15.00 't2.00
27 NOB HII.L SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
28 NORTH PARK SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
29 ORCHAITD SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
30 PACIFIC, SUB DISTRIBUTION.UNATTEN 1 15.00 12.47
31 POMERTf,Y SUB DISTRIBUTION.UNATTEN 69.00 12.47
32 PROSPECT POINT SUB DISTRIBUTION-UNATTEN 69.00 12.47
33 PUNKIN CENTER SUB DISTRIBUTION-UNATTEN 116.00 13.20
34 RIVER FIOAD SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
35 SELAH {JUB DISTRIBUTION-UNATTEN 115.00 12.47
36 SULPFIL'R CREEK SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
37 SUNNY{;IDE SUB DISTRIBUTION-UNATTEN 115.00 12.47
38 TIETON SUB DISTRIBUTION-UNATTEN 1 15.00 12.47 34.50
39 TOPPE:f'llSH SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
40 TOUCHET SUB DISTRIBUTION-UNATTEN 69.00 12.47
FERC FORM NO. 1 (ED. 12-96)Page t125.18
Name of Respondent
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20'l8lQ4
5. Show in columns (l), [), 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 otheruise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondents books of account. Specify 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
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
0)
Total Capacity
(ln MVa)
(k)
67 1 1
67 I 2
138 2 3
133 2 4
258 3 5
300 2 6
414 2 7
1124 6 8
63 2 I
1 100 2 10
100 3 1 11
450 1 't2
262 3 13
11311 104 2 14
15
16
25 1 17
45 2 18
118 b 19
25 1 20
23 2 21
25 4 22
42 2 23
25 I 24
50 2 25
25 1 26
42 2 27
45 2 28
50 2 29
28 3 30
I 1 31
40 2 32
44 3 33
76 5 34
45 2 35
25 1 36
45 2 37
29 2 38
50 2 39
6 1 40
FERC FORM NO.1 (ED. 12.96)Page 427.18
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report b,elow the information called for concerning substations of the respondent as of the end of the year.
2. Substati,cns which serve only one industrial or street railway customer should not be listed below.
3. Substati,ons 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 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 VOELKE:R SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
2 WAITSBURG SUB DISTRIBUTION-UNATTEN 69.00 't2.47
J WAPATI) SUB DISTRIBUTION.UNATTEN 1 15.00 12.47
4 WENAS SUB DISTRIBUTION.UNATTEN 1 15.00 12.47
5 WHITE ISWAN SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
6 WLEY SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
7 TOTAL (Number of Substations-3o)3038.00 383.42 107.66
8
I CENTR/\L SUB T/D-UNATTENDED 69.00 't2.47
10 MILL CFIEEK SUB T/D-UNATTENDED 69.00 12.47
11 UNION GAP SUB T/D-UNATTENDED 230.00 I 15.00 12.47
12 TOTAL. tNumber of Substations-3)368.00 139.94 12.47
13
14 TRANSMISSION-UNATTEN 1 15.00 69.00
15 OUTLOOK SUB TRANSMISSION-UNATTEN 230.00 115.00
16 PASCO SUB TRANSMISSION-UNATTEN 115.00 69.00 7.20
't7 POMONA HEIGHTS SUB TRANSMISSION-UNATTEN 230.00 115.00 13.20
18 TRANSMISSION-UNATTEN 230.00 69.00
19 WALLUTA SUB TRANSMISSION-UNATTEN 230.00 69.00
20 WNE C,CUNTRY SUB TRANSMISSION-UNATTEN 230.00 115.00
21 TOTAI. tNumber of Substations-7)1380.00 621.00 20.40
22
23 WYOMII{G
24 ANTELOPE MINE SUB DISTRIBUTION.UNATTEN 230.00 34.50
25 ARRO\i{|IEAD SUB DISTRIBUTION-UNATTEN 230.00 34.50
26 ASTLE I]TREET DISTRIBUTION-UNATTEN 34.50 13.20
27 BAILEY DOME SUB DISTRIBUTION-UNATTEN 57.00 12.47
28 BAR NUNN DISTRIBUTION-UNATTEN 1 15.00 12.47
29 BAR X SiUB DISTRIBUTION.UNATTEN 230.00 34.50
30 BIG MUI]DY SUB DISTRIBUTION-UNATTEN 69.00 12.47
31 BIG PINEY SUB DISTRIBUTION-UNATTEN 69.00 24.90
32 BLACKS FORK SUB DISTRIBUTION-UNATTEN 230.00 34.50
33 BRIDGE,R PUMP SUB DISTRIBUTION-UNATTEN 230.00 34.50 13.20
34 BRYAN SUB DISTRIBUTION.UNATTEN 1 15.00 12.47
35 BYRON SUB DISTRIBUTION-UNATTEN 34.50 4.16
36 CASSA SUB DISTRIBUTION-UNATTEN 57.00 20.80 12.47
37 CENTEtt STREET SUB DISTRIBUTION-UNATTEN 11s.00 12.47
38 CHAPM,AN SUB DISTRIBUTION-UNATTEN 46.00 12.47
39 CHUKAII SUB DISTRIBUTION-UNATTEN 't2.47 4.16
40 CHURCH AND DWGHT SUB DISTRIBUTION-UNATTEN 34.50 0.48
FERC FORM NO. I (ED. 12-96)Page 426.19
DRY GLILCH SUB - AVISTA
WALU\ WALLA 23OKV SUB I
Name Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
5. Show in columns (l), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other pafi 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 AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
0)
Total Capacity
(ln MVa)
(k)
25 1 1
o 1 2
45 2 3
25 2 4
22 2 5
45 2 6
'I 108 62 7
I
14 1 I
45 2 10
595 5 11
654 8 't2
13
20 1 14
125 1 15
39 9 16
325 3 17
300 2 '18
120 2 19
250 ,|20
1179 't9 21
22
23
25 1 24
150 2 25
't3 1 zo
2 1 27
30 1 28
25 ,|29
7 ,|30
14 1 3'1
150 2 32
73 4 33
25 1 34
2 3 35
2 6 36
12 1 37
4 1 38
1 J 39
1 ,|40
FERC FORM NO. I (ED. 12-96)Page 427.19
PacifiCorp (1)
(2)
Original
Resubmission
Date of(Mo, Da
Report
r, Yr)
Year/Period of Report
End of 2018/Q4
SUBSTATIONS
1. Report trerlow the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 COKE\/ILLE SUB DISTRIBUTION-UNATTEN 46.00 24.90
2 COLU]ilBIA-GENEVA SUB DISTRIBUTION-UNATTEN 230.00 13.80
3 COMMLINITY PARK SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
4 CROOKS GAP SUB DISTRIBUTION-UNATTEN 34.50 12.47
5 DEER CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
6 DJ CO,AL MINE SUB DISTRIBUTION.UNATTEN 69.00 34.50
7 DOUGlJ\S SUB DISTRIBUTION-UNATTEN 57.00 4.16
8 DRY FORK SUB DISTRIBUTION-UNATTEN 69.00 4.16
I ELK BAIJIN SUB DISTRIBUTION-UNATTEN 34.50 7.20
10 EMIGFII'NT SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
11 EVANS SUB DISTRIBUTION-UNATTEN 115.00 12.47
12 EVANSI-ON SUB DISTRIBUTION-UNATTEN 138.00 12.47
13 FORT TOASPER SUB DISTRIBUTION-UNATTEN 69.00 12.47
14 FORT S,ANDERS SUB DISTRIBUTION-UNATTEN 1 15.00 13.20
15 FRANNIE SUB DISTRIBUTION-UNATTEN 230.00 34.50
16 FRON-IER SUB DISTRIBUTION-UNATTEN 69.00 4.16
17 GARLAIID SUB DISTRIBUTION.UNATTEN 230.00 34.50
18 GLENDO SUB DISTRIBUTION-UNATTEN 57.00 4.16
19 GRASS CREEK SUB DISTRIBUTION.UNATTEN 230.00 34.50
20 GREAII DIVIDE SUB DISTRIBUTION-UNATTEN 1 15.00 34.50
21 GREYBIJLL SUB DISTRIBUTION-UNATTEN 34.50 4.16
22 HANNA SUB DISTRIBUTION.UNATTEN 34.50 12.47
23 JACKALOPE SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
24 KEMMEI1ER SUB DISTRIBUTION.UNATTEN 6S.00 24.90
25 KIRBY CiREEK PUMPING STATION DISTRIBUTION-UNATTEN 34.50 2.40
26 KIRBY C;REEK SUB DISTRIBUTION-UNATTEN 34.50 4.16
27 LANDE:FI SUB DISTRIBUTION-UNATTEN 34.50 12.47
28 LARAIVIIE SUB DISTRIBUTION.UNATTEN I 15.00 13.20
29 LATHA]VI SUB DISTRIBUTION-UNATTEN 230.00 34.50
30 LINCH SUB DISTRIBUTION-UNATTEN 69.00 13.80
31 LITTLE I/OUNTAIN SUB DISTRIBUTION-UNATTEN 230.00 34.50
32 LOVELL SUB DISTRIBUTION-UNATTEN 34.50 4.',t6
33 MILL IRON SUB DISTRIBUTION-UNATTEN 34.50 13.80
34 MILLS SUB DISTRIBUTION-UNATTEN 12.47 4.16
35 MURPII'/ DOME SUB DISTRIBUTION-UNATTEN 34.50 13.20
36 NUGGE]-T SUB DISTRIBUTION-UNATTEN 69.00 7.20
37 OPAL SIJB DISTRIBUTION-UNATTEN 69.00 24.90
38 ORIN SI.JB DISTRIBUTION-UNATTEN 57.00 7.20
39 ORPHI\ SUB DISTRIBUTION-UNATTEN 57.00 7.20
40 PARADISE SUB DISTRIBUTION-UNATTEN 69.00 25.00
FERC FORM NO. 1 (ED. 12-96)Page 426.20
Original
Resubmission
(1)
(2\PacifiCorp
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
5. Show in columns (l), O, and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(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
(D
Number of Units
(i)
Capacity
MVa)
(k)
Total
(ln
4 1 1
45 2 2
50 2 3
5 J 4
I 1 5
12 1 6
6 1 7
I 1 I
5 1 I
't2 1 10
9 1 11
40 2 12
28 1 13
20 1 14
50 2 15
6 1 16
45 2 17
1 3 18
25 1 19
20 1 20
3 1 21
6 I 22
25 I 23
14 1 24
J 3 25
2 3 26
25 2 27
50 2 28
25 1 29
12 1 30
20 1 31
4 1 32
12 1 33
1 J 34
5 1 35
1 36
8 1 37
1 1 38
3 3 39
30 1 40
Page 427.20FERC FORM NO. 1 (ED.12-96)
Name of Resrrondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Repo( trerlow the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
,|PARCO SUB DISTRIBUTION-UNATTEN 34.50 12.47
2 PINEDALE SUB DISTRIBUTION-UNATTEN 69.00 24.90
3 PITCHFORK SUB DISTRIBUTION-UNATTEN 69.00 24.90
4 POlScrl.l SPIDER SUB DISTRIBUTION-UNATTEN 69.00 2.40
5 POLEC/\T SUB DISTRIBUTION-UNATTEN 34.50 12.47
6 RAINBCIW SUB DISTRIBUTION-UNATTEN 34.50 13.20
7 RAVEN SUB DISTRIBUTION-UNATTEN 230.00 34.50
8 RED BUTTE SUB DISTRIBUTION-UNATTEN 1 15.00 13.20
I REFINERY SUB DISTRIBUTION-UNATTEN 1 15.00 12.47
10 SAGE HILL SUB DISTRIBUTION-UNATTEN 34.50 13.20
't'l SHOSHIf,NI SUB DISTRIBUTION-UNATTEN 34.50 2.40
12 SLATE CREEK SUB DISTRIBUTION-UNATTEN 69.00 12.47
13 SOUTH CODY SUB DISTRIBUTION-UNATTEN 69.00 24.90
14 SOUTI{ ELK BASIN SUB DISTRIBUTION-UNATTEN 34.50 4.16
15 SOUTH TRONA SUB DISTRIBUTION-UNATTEN 230.00 34.50
16 SPRING CREEK SUB DISTRIBUTION.UNATTEN 115.00 13.20
17 SVILAR SUB DISTRIBUTION-UNATTEN 34.50 4.16
18 TEN MII..E STEP DO!\N SUB DISTRIBUTION-UNATTEN 34.50 12.50
19 TEN MII..E SUB DISTRIBUTION.UNATTEN 69.00 34.50
20 THERMOPOLIS TOI,\N SUB DISTRIBUTION-UNATTEN 34.50 4.16
21 THUNDER CREEK SUB DISTRIBUTION-UNATTEN 57.00 12.47
22 VETERI\NS SUB DISTRIBUTION.UNATTEN 34.50 13.20
23 WAPA THERMOPOLIS DISTRIBUTION-UNATTEN 1 15.00 34.50
24 WERT.Z.SINCLAIR SUB DISTRIBUTION-UNATTEN 57.00 4.16 12.50
25 WEST ADAMS SUB DISTRIBUTION-UNATTEN 34.50 4.16
26 WEST\'\CO SUB DISTRIBUTION-UNATTEN 230.00 34.50
27 WORLAND TO\^N SUB DISTRIBUTION-UNATTEN 34.50 4.16
28 WYOPIC SUB DISTRIBUTION.UNATTEN 230.00 34.50
29 TOTAL (Number of Substations-85)7875.44 1378.71 38.17
30
31 BUFFALO SUB T/D.UNATTENDED 230.00 20.80
32 ELK HOI1N SUB T/D.UNATTENDED 1 15.00 12.47
33 FIREHOLE SUB T/D.UNATTENDED 230.00 34.50
34 HILLTOP SUB T/D-UNATTENDED 1 15.00 34.50 20.80
35 LABARCiE SUB T/D-UNATTENDED 69.00 24.90
36 POINT OF ROCKS SUB T/D-UNATTENDED 230.00 34.50
37 RIVERTON 230 SUB T/D-UNATTENDED 230.00 12.47 34.50
38 YELLOVI/CAKE SUB T/D-UNATTENDED 230.0c 34.50
39 TOTAL (Number of Substations-8)1449.00 208.64 55.30
40
FERC FORM NO. 1 (ED. 12-96)Page 426.21
Name of
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)lt
Year/Period of Report
End of 20181Q4
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 substations or major items of equipment leased from others, jointly owned with others, or operated otheruise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(D
Number of Units
(i)
Total
(ln
Capacity
MVa)
(k)
5 1 1
20 1 2
16 I 2 3
3 1 4
2 J 5
12 1 b
200 2
30 ,|8
45 2 I
6 ,|10
2 3 1',!
1 1 12
14 J ,|13
2 6 14
150 2 15
28 1 16
2 3 17
5 1 18
12 1 19
5 1 20
I 1 21
25 2 22
25 I 23
2 6 24
3 1 25
25 1 26
5 1 27
20 'l 1 28
1 860 148 4 29
30
20 1 I 3't
25 ,|32
50 2 33
45 2 1 u
I b 35
25 1 36
76 4 37
25 1 38
274 18 2 39
40
FERC FORM NO. I (ED. 12-96)Page 427.21
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)lt
Year/Period of Report
End of 20181Q4
SUBSTATIONS
L Report br;low the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. lndicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended orr 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 TRANSMISSION-ATTENDE 230.00 1 15.00 69.00
2 TRANSMISSION-ATTENDE 345.00 230.00 34.50
3 NAUGHTON SUB TRANSMISSION-ATTENDE 230.00 138.00 69.00
4 BAIROIL SUB TRANSMISSION-UNATTEN 1 15.00 34.50 57.00
5 CASPEI? SUB TRANSMISSION-UNATTEN 230.00 115.00 69.00
6 CHAPPEL CREEK SUB TRANSMISSION-UNATTEN 230.00 69.00
7 CHIMNEY BUTTE SUB TRANSMISSION-UNATTEN 230.00 69.00
I FOOTE CREEK WND FARM TRANSMISSION-UNATTEN 230.00 34.50
9 GLENDO AUTO SUB TRANSMISSION-UNATTEN 69.00 57.00
10 MANSF,ACE SUB TRANSMISSION-UNATTEN 230.00 34.50
MIDVVEIST SUB TRANSMISSION-UNATTEN 230.00 69.00 34.50
't2 MINERS SUB TRANSMISSION-UNATTEN 230.00 34.50 9.70
13 MUSTANG SUB TRANSMISSION-UNATTEN 230.00 1 15.00
14 OREGO,N BASIN SUB TRANSMISSION-UNATTEN 230.00 69.00 34.50
15 PLATTEI SUB TRANSMISSION-UNATTEN 230.00 115.00 34.50
16 RAILRCAD SUB TRANSMISSION-UNATTEN 230.00 138.00
17 ROCK SPRINGS 230 SUB TRANSMISSION-UNATTEN 230.00 34.50
18 SAGE SUB TRANSMISSION-UNATTEN 69.00 46.00
19 STANDI'IPE SUB TRANSMISSION-UNATTEN 230.00 12.47
20 THERMCPOLIS SUB TRANSMISSION-UNATTEN 230.00 1 15.00
21 TOTAL riNumber of Substations-20)4278.00 1U4.97 4',t1.70
22
23 CALIFORNIA
24 Distribution - 42
25 TID -2
26 Transmission - 5
27
28 IDAHO
29 Distribution - 65
30 T/D-5
31 Transmission - 18
32
33 MONTANA
34 Transmirision - 3
35
36 OREGON
37 Distribut on - 176
38 r,D-12
39 Transmirision - 29
40
FERC FORm NO.1 (ED. t2-95)Page 426.22
DAVE JOHNSTON PLANT/SUB
JIM BRIDGER 345lry SUB
11
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
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 substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(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
0)
Total Capacity
(ln MVa)
(k)
303 3 I 1
703 7 2
661 4 3
53 3 4
575 4 5
75 1 6
75 1 7
196 2 6
I ,|1 o
20 1 10
157 3 11
20 1 12
100 1 13
100 2 14
140 3 't5
400 1 16
50 2 17
22 1 18
75 1 19
84 1 20
3817 43 2 21
22
23
323 24
130 25
725 26
27
28
736 29
312 30
51'11 31
32
33
200 34
35
36
4653 37
1143 38
8374 39
40
FERC FORM NO. I (ED. 12-96)Page 427.22
PacifiCorp (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)tt
Year/Period of Report
End of 20181Q4
SUBSTATIONS
1. Report lxllow the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional cl"raracter, 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 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)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 UTAH
2 Distribulion - 272
3 T/D - 31
4 Transmission - 44
5
6 WASHINGTON
7 Distribulion - 30
8 T/D-3
I Transmission - 7
10
11 WYOMI\G
12 Distribution - 85
13 T/D-8
14 Transnrission - 20
15
't6 ALL STI\TES
17 Distribution - 670
18 T/D - 61
19 Transmission - 126
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 426.23
Name of Respondent
PacifiCorp (1)
(2)
Original
Resubmission
Date of ReDort
(Mo, Da, Yi)tt
Year/Period of Report
End of 20181Q4
5. Show in columns (l), O, and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(s)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
0
Number of Units
0)
Total Capacity
(ln MVa)
(k)
1
5810 2
7824 3
11311 4
5
6
1 108 7
654 8
1179 I
10
11
1860 12
274 13
3817 14
'15
16
14490 17
1 0337 '18
307'.t7 19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
u
35
36
37
38
39
40
Page 427.23FERC FORm NO. { (ED. {2-96)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2UAA4
FOOTNOTE DATA
426.3 :1
426.3 Line No.: 15 Column: a
i\n ope 23OkV Substa on s n y owned f Corp and tdaho Power Company
Owne::ship and operations and maintenance costs vary by type of asset as defined in the,Joint Ownershi and ri t
The Il g Grassy 161 tation is join v Corp Power Company.
Ownership and operations and maintenance cosLs vary by type of asset as defined in the,foint Ownershi-and ri t
The 34 s ta on s jointly Pac Corp I Power Company
Owne::ship and operations and maintenance costs vary by ty;:e of asset as defined in the
,foirLt- Ownershi and ri t
iIe erson 161 ta on S n v Corp Power Company.
Owner:ship and operations and maintenance costs vary by type of asset as defined in the,foint: Ownershi and ri t
The IIi nt 50 Substation is jointly owned by PacifiCorp I Power Company.
Owner:ship and operations and maintenance costs vary by tytrle of asset as defined in the,Joir:t Ownershi and ri t
ts one 3 bank
e Kno 345 ta on nt v Corp Power
Comperny. Ownership and operations and maintenance costs vary by type of asset as definedin the ,foint Ownershi and L
The ew 500 Substation is jointly owned by Pacificorp,stern Energy, Puget
Soun.cl Energy, Inc., Portland General Electric Company and Avista Corporation. Ownership
and operations and maintenance costs vary by type of asset as defined in the Transmissiont
The Ciol-strip 50OkV Substat on t1y owned by fiCorp, NorthWestern Energy, Puget
Sounil Energy, Inc., Portland General Electric Company and Avista Corporation. Ownership
and operations and maintenance costs vary by type of asset as defined in the Transmi-ssiont
xonv 11e 50OkV Substat on t y owne Pac f Corp and I1e Power
Admir.istration (ilBPA"), each with an undivided interest of 50.02. Operation and
maintenance costs are shared between the two parties and responsibility is as follows:
Paci f i 58.0? and BPA 42.02
The U.urricane 230 Substation is jointly owned by PacifiCorp and fdaho Power Company.
Ownership and operations and maint.enance costs vary by type of asset as defined in the,Joint Ownersh and ri t
The VIal n 500kV Substa on ntly owned by Pac f Corp, BPA and Portland GeneralElectric Company. Ownership and operations and maintenance costs vary by type of asset asdefined in the tion and maintenance t.
IV.er an 500kV ta on nt v Corp BPA, EA an
ies and re biliL is as follows: Pacifi 58.0? and BPA 42.02.
FERC FORM NO.1 (ED. 12-871 Page 450.1
426.3 Line No.: 20 Column: a
426.3 Line No.: 22 Column: a
426.3 Line No.:23 Column: a
426.3
426.3
Line No.:23
Line No.: 27 Column: a
Column:
426.3 Line No.: 33 Column: a
426.3 Line No.:34 Column: a
426.8 Line No.: 38 Column: a
426.9 Line No.:2 Column: a
426.9 Line No.:6 Column: a
426.9 Line No.:7 Column: a
426.9 Line No.: 14 Column: a
The .up 23 tation property is owned by Pacificorp and BPA as defined in the
undivided interest of 50.0?. Operation and maintenance costs are shared between the two
Name of Respondent
PacifiCorp
This Report is:
(1) XAn Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
20,t8tQ4
FOOTNOTE DATA
426.9 Line No.: 15 Column: a
facility sharing agreement where operation and maintenance costs vary by type of asset and
ormance ibili
The San am e 230kV Substation property is owned by Paci Corp BPA aS 1nfacility sharing agreement where operation and maintenance costs vary by type of asset and
formance ibi 1i r
The Dry Gulch 115kV Subst.ation property is owned by PacifiCorp and Avista Corporation asdefined in the interconnection agreement where operation and maintenance costs vary bytof asset and ormance ibili
a a 230 Substat on S t1y owned by Pacificorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the.Ioint Ownershi and ri
The Dave ,f ton 230 S tat on ntly owned by f Corp and Black fls Powerwith an undivi-ded interest of 85.0% and l-5.0?, respectively. Operation and maintenancecosts are shared between the two parties based on a fixed amount derived as a factor of
the owned of the ori inal installed substation.
The ,l Br dger 345kV Substation is jointly Pac Corp I Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the.Ioint Ownership and Operating Agreement.
FERC FORM NO.1 (ED.12-871 Page 450.2
426.19 Line No.:14 Column: a
426.19 Line No.: 18 Column: a
426.22 Line No.: 1 Column: a
426.22 Line No.:2 Column: a
Name of Restpondent
PacifiCorp
This ReDort ls:(1) 5]Rn originat(2) fiA Resubmission
Date of ReDort
(Mo, Da, Yi)tt
Year/Period of Report
End of 20181Q4
ES
1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to
an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not
attempt to include or aggregate amounts in a nonspecific category such as "general".
3. Where amounts billed to or received from the associated (afiiliated) company are based on an allocation process, explain in a footnote.
Line
No.Description of the Non-Power Good or Service
(a)
Name of
Associated/Affiliated
Company
(b)
Account
Charged or
Credited
(c)
Amount
Charged or
Credited
(d)
1 Non-power Goods or Servaces Provided by Affiliated
2 Coal purchases Bridger Coal Company 151 ,501 170,644,431
3 Coal purchases Trapper Mining lnc.15'l ,501 14,501,341
4 services under BHE 5,165,883
5 Administrative services under the IASA MEC 4,465,031
6 Administrative services under the IASA BHE U.S. Transmission, LLC 426.5,923 1 , 199,006
7 Administrative services under the IASA MHC lnc.426.5 499,935
8 Administrative services under the IASA Kern River Gas Transmission Company 923 104
I Gas transportation services Kern River Gas Transmission Company 547 3,072,669
10 Rail serrvices and right-of-way fees BNSF Railway Company 151 ,501 ,567,589 32,526,666
11 EmPloyr3s relocation services HomeServices of America, lnc.1,429,105
12 Travel services Delta Air Lines, lnc 1,152,381
13 Operational support services Marmon Utility, LLC 397,298
14 Banking services Wells Fargo & Company 1,125,775
15 Banking services and rating agency fees U.S. Bancorp 401,092
16 Rating agency fees Moody's lnvestors Service, lnc 181 ,427,930.2 371,157
17 Lubrical.ing oil and grease products Phillips 66 7',t9,',t74
18
19
20 Non-power Goods or Services Provided for Afflllate
21 lnformalion technology and administrative
22 support services Bridger Coal Company 501 ,557,931 1,409,166
23 Administrative services under the IASA MEC 485,465
24 Administrative services under the IASA NV Energy, lnc.116,005
25 Operational support services NV Energy, lnc.416 172,998
26 Financial transactions related lo energy hedging Wells Fargo & Company 1,781 ,225
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORI'rl NrC. 1
FERC FORM NIC. 1
(New)
New)-F
Page 429
59:
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)tt
Year/Period of Report
2018tQ4
FOOTNOTE DATA
429 Line No.:4 Column: a
Thj.s footnote applies to alf occurrences of "Administrat ve se ces under the IASA" on
page 429. TIASAI is the Intercompany Administrative Services Agreement between Berkshire
Hathaway Energy Company (trBHEn) and its subsidiaries. Amounts which are chargeable to or
from another affiliate are assigned first by coding to the specific affiliate. These
charges are based on actual Iabor, benefits and operational costs incurred. Amounts notdirectly assignable Lo an individual affiliate, such as work performed where multipleaffiliates benefit, are assigned on the basis of allocations, as described below:
Labor and Assets: An egual weighting of each company's ]abor and assets expressed as a
percentage of the whole ( (labor ? + assets ?) * 2) determines the portion assigned to each
company. Labor is 1,2 months ended through December of the prior year. Assets are total
assets at December 31 of the prior year. Nine combinations of this allocator are used foralfocating services that benefit different companies within the BHE organization.
Information Technology Infrastruct : Allocates costs related to shared information
technology infrastructure owned by the affiliate to other benefited affiliates based on an
aggregation of various measures of usage of such infrastructure including storage capacityutilized, number of servers utilized, server processi-ng times, etc.
Plant: This allocator distributes costsffisets for each affiliate.of managing the corporaLe insurance function based
Schedule Page:429 Line No.:4 Column: c
Accounts c for BHE: a07, 426.4, 426.5, 92]- arLd 923
This footnote applies to all occurrences of UMECU on page 429. Complete name is429 Line No.:5 Column: b
MidAmerican
429 Line No.: 5 Column: c
429 Line No.:10 Column: d
Accounts for MEC:. 1-07 , 426.4, 426.5 and 923
Non-power goods or services provided by BNSF Railway Company are as follows:
$32,489,1-02 Rail services
37 554 Right-of-way fees
$32 ,525 ,566
Included in the right-of-way fees are amounts related to jointly-owned facilities that areid either directl or indirect to BNSF Railwa
Accounts charged for HomeServices of Ameri-ca, Inc.: 505, 535, 539, 548, 553, 557, 550,56a.2, 551.5, 570,580, 581, 590, 592,593, 901, 903, 908 and 921.
Accounts charged for Delta Lines, Inc . z 426 .4 , 426 .5, 500, 501 , 502, 506 , 51-2, 513,
544 , 535, 539 , 546 , 548 , 549 , 553, 554 , 555 , 557 , 550, 56]- .2 , 557 .5 , 56l. .7, 568 , 569 .3 ,571,580, 581, 585, 588, 590, 592,593, 595,598,901_, 903,908, 909,920,921-,922 arrd
928.
AccounEs
928.
or We s Fargo & Company:.228.3, 4]-9, 426.5, 427, 43!, 501, 903, 921
429 Line No.:11 Column: c
429 Line No.: 12 Column: c
429 Line No.: 14 Column: c
429 Line No.:15 Column: c
AccountsAssociation:4L9 r U.S. Bancorp,
431 537
ts subs ary U. S.
557 s60 903 921 928 and 930.2.
Nat
429 Line No; 17 Column: c
Accounts r s 65,
511 51,2 513 c1A 539
tS
548
ary
562
Company: 154, 500,
592 and 593.501 502 505 544 549 570 582
56
429 Line No.:23 Column: c
FERC FORM NO.1 (ED. 12-871 Page 450.1
Nanrer of Respondent
PacifiCorp
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
tl
Year/Period of Report
2018tQ4
FOOTNOTE DATA
Accounts
Accounts
Non-power goods orrelated to energy hedging activiEy
for MEC: 426.5 557 580 588, 920, 92]-, 923, 931- and 930.2
for NV Inc. : 408.2, 425 .5, 920, 921-922 923 931.
ces by Wells Fargo & Company131, 232 ar]d 547.
r transac ons
429 Line No.:24 Column: c
429 Line No;26 Column: c
FERC FORM NO.1 (ED. 12-871 Page 450.2
INDEX
Schedule
Accrued and prepaid taxes
Paqe No.
Accumulated Deferred Income Taxes
262-263
... 234
272-277
Accumulatsed provisions for depreciation of
common utility planE .
utility plant .
utility plant (summary) .
Advances
from associated companies ..,.
Allowances
Amortization
miscellaneous ....
of nuclear fuel .
Appropriatsions of Retained Earnings
Associated Companies
advances from .
corporations controlled by respondent .......
control over respondent .,
interest on debt to ...
Attestation
Balance sheet
comparaEive
notes to
Bonds .
Capital Stock .
expense
premiums
reacquired
subscribed
Cash flows, statement of ...
changes
important during year .
Construction
work in progress - common utility plants .....
work in progress - electric
work in progress - other utility departments
control
corporations controlled by respondent .......
over respondent ..
corporation
controlled by ...
incorporated
CPA, background informat.ion on
cPA certification, this reports form .
... 356
200 - 20]-
. 256-257
. 228-229
...340
202-203
1l-8- 119
256-257
... 103
...102
256 - 257
..... i
110-113
L22-L23
2s6-257
...251
... 254
aEa
... 25L
aca
L2O-L2L
l-08 - 10 9
..... 356
..... 2L6
. 200-20L
103
L02
103
101
101
a-11
FERC FORir NO. 1 (ED.12-93)Index 1
INDEX (continued)
SchedUe
Deferred
credits, other .
de:tit.s, miscellaneous ...
income taxes accumulated - accelerated
amc,rE.ization property
income taxes accumulated - other property . ..
income taxes accumulated - other .
income taxes accumulated - pollutsion control facilities
Definitions, this report form .
Deprecjation and amortization
of: common utility plant .
of electric p1ants .
Paqe No.
259
233
272-273
274-275
276-277
.... 234
.. .. ltf
Directcrrs
Discour:Lt - premium on long-term debt .
Distri.bution of salaries and wages
DividerLd appropriations ...
Earnirrgs, Retained
Electric energy account
Expens€:s
el-erctric operation and maintenance ..
el-ectric operation and maintenance, summary ..
urr€rmort.ized debt ,
Extraoldinary property losses
Filing requirements, this report form
ceneral. information
Instruc:tions for filing the FERC Form 1
Generating plant statistics
hyatroelectric (1arge)
prrnrped storage (1arge)
small plants
steam-electric (Iarge)
Hydro-electric generating plant statistics
Identification ...
Import-ant changes during year .
Income
statement of, by departments
statement of, for lhe year (see also revenues)
deductsions, miscellaneous amortization .....,.
decluctions, other income deduction
deductions, otsher interest charges
Incorporalion information ....
.. .. 3s6
.... 2L9
336-337
.. .. 105
2s6-257
354-355
118 - Ll-9
l.1,8 - 119
.. .. 401
320-323
... 323
... 256
. .. 230
101
i-iv
406 - 407
408-409
410 - 411
402- 403
406 - 407
. .. 101
108 - 109
tt-4-tL7
LL4.IL7
. .. 340
. .. 340
... 340
. .. 101
FERC FORM NO.1 (ED.12-9s)lndex 2
INDEX (continued)
Schedule Paqe No.
Interest
charges, paid on long-term debt, advances, etc ...
Investments
nonutility property
subsidiary companies
Investment tax credits, accumulated deferred
Law, excerpts applicable to this report form .
List of schedules, tshis report form .
Long-term debt .
Losses - Extraordinary property
Materials and supplies
Miscellaneous general expenses
Notes
to balance sheet .
to statemen! of changes in financial position ,...
to stsatement of income
to statemen! of retained earnings
Nonutility property
Nuclear fuel- materials ....
Nuclear generating plant., statistics
Officers and officers' salaries
operating
erq>enses-electric .
e:.penses-electric (summary) ..
Other
paid-in capiEal
donations received from stockholders .
gains on resale or cancellation of reacguired
capital stock .
miscellaneous paid-in capital
reduction in par or stated value of capital stock
regulatory assets
regulatory liabilities
Peaks, monthly, and output
P1ant, Common utility
accumulated provision for depreciation .
acguisition adjustments
allocated to utility departments
complet.ed construction not classified ...
construction work in progress
expenses
held for future use ..
in service
leased to others
Plant data
256 - 257
..... 22L
. 224-22s
. 266-257
...... iv
.....2-4
. 256-257
.... - 230
..... 227
.....335
L22-723
L22- 123
L22-L23
L22-L23
... 22L
202-203
402-403
... 104
320-323
... 323
,E1
,E1
253
253
253
a1)
278
401
3s6
3s6
3s6
3s6
3s6
356
355
356
3s6
.336-337
40L-429
FERC FORM NO.1 (ED. t2-9s)lndex 3
!NDEX (continued)
Schedule
Plant - electric
accumulated provision for depreciation .
con.struction work in progress
held for future use ..
in service
leased to others
Plant - utilitsy and accumulaEed provisions for depreciation
amcrtization and deplet.ion (summary)
Pollution control facilities, accumulated deferred
income taxes .
Power Exchanges ..
Premiurn and discount on long-term debt .
Premium on capital stock .
Prepaid taxes .
Property - losses, extraordinary ...
Pumped storage generat.ing plant statistics .
Purcha.sed power (including power exchanges)
Reacquired capital stock ,
Reacquired long-lerm debt .
Receivers' certif icates
neconciliation of reported net income with taxable income
from Federal income laxes .
Regulatory commission expenses deferred
Regulatory commission elq)enses for year
Research, development and demonstsration activities .
Retained Earnings
amortization reserve Federal
appropriated
statement of, for tshe year
unappropriated ...
Revenues - electric operating
Salaries and wages
directors fees .
distribution of .. .
officersr ....,
sales of electricity by ratse schedules
Sales - for resale
Salvage - nuclear fuel .
schedules, this report form ..
Securities
exchange registration ....
statement of cash F10ws ,
Statement of income for the year .
Statement of retained earnings for the year .
steam-electric generating plant statistics
Substations
supplies - materials and ..
Paqe No.
... 2L9
... 2L6
... 2L4
204-207
... 2L3
20L
... 234
326 - 327
... 25L
262-263
... 230
408 - 409
326-327
... 250
256-257
256-257
... 261
-.. 233
350-3sL
3s2-353
... Ll-9
11.8 - 119
118 - 119
l-18 - 1l-9
300-301
.. .. 105
354-355
.... l-04
....304
310-311
202-203
....2-4
250-25!
L20-L2r
L]-4- LL1
118-L19
402-403
A)A
.... 227
FERC FORM NO. { (ED. t2-90)lndex 4
INDEX (continued)
Schedule Paqe No.
Taxes
accrued and prepaid
charged during year .
on income, deferred and accumulated
262-263
262-263
... 234
272-277
... 26].
... 429
reconciliation of net income with Eaxable income for
Transformers, line - electric
Transmission
lines added during year .424-425
422-423
328-330
... 332
Iines statistics
of electricity for otshers
of electricity by
Unamortized
debt discount ...
debt expense ....
premium on debt
Unrecovered P1ant and
others ...
;";;i";;;;Study
.. 256-257
. . 256-25'7
. . 256-25',1
..... . 230
FERC FORM NO.1 (ED.12-90)lndex 5