2019 Annual Report.pdf

1 r_ i r i fl r\
r.'.-l t t-J
ROCKY MOUNTAIN
HSS,E#"*1407 W. North Temple, Suite 330
Salt Lake City, Utah 841'16
Re:
May 19,2020
VA OVERNIGHT DELIWRY
Idaho Public Utilities Commission
I l33l W Chinden Blvd.
Building 8 Suite 20lA
Boise,ID 83714
Attention:Diane Hanian
Commission Secretary
Annual Idaho Form 1 Report -2019
Rocky Mountain Power, a division of PacifiCorp, hereby submits for filing an original and seven
(7) copies of the Idaho Public Utilities Commission Annual State Form 1 report for 2019. This is
being provided with PacifiCorp's annual FERC Form 1.
It is respectively requested that all formal correspondence and staffrequests regarding this matter
be addressed to:
By E-mail (preferred):
By Fax:
By regular mail:
datarequest@Pac ifi Corp.com
[phone]
Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR97232
Any informal inquiries may be directed to Ted Weston, Idaho Regulatory Manager at80l-220-
2963.
Vice President, Regulation
PAC-E
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM NO. 1
FOR
MULTI-STATE ELECTRIC COMPANI ES
INDEX
Page
Number
Title
3
1
2
-o
7
I
9
10
-1
13
Statement of Operating lncome for the Year
Electric Operating Revenues
Electric Operation and Maintenance Expenses
Depreciation and Amortization of Electric Plant
Taxes, Other Than lncome Taxes
Non-Utility Property
Summary of Utility Plant and Accumulated Provisions
Electric Plant in Service
Materials and Supplies
I 1 2
provided in this report is consistent with the unadjusted data reflected in the company's Results of
perations in the ldaho general rate case, which will be filed with the ldaho Public Utilities Commission on June
1,2020. For further information regarding ldaho's 2019 financial results, refer to the ldaho general rate case.
This Report ls:(1) X An Original(2) _ Aresubmission
Date of Report
(Mo, Da, Yr)
May 19,2020
Year of Report
Dec. 31,2019
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
STATE OF IDAHO STATEMENT OF OPERATING INCOME FOR THE YEAR
ELECTRIC UTILITY
(Reo
Page
No.
b)
Current Year
b)
Previous Year
(d)
Line
No.
ACCOUNT
(a)
1 UTILITY OPERATING INCOME
31 1 .215.5802Ooeratino Revenues (400)2 298,763,227
3 ODeratino ExDenses
3-6 148.465.404 '155.045.7644Ooeration ExDenses (401 )
3-6 20.256.417 23.414.6175Maintenance Ercenses (402)
6 7 40.903.1 00 41.826.626DeDreciation Expenses (403) (rr
7 2.688.697 2.656.5037Amort. & Deol. of Utilitv Plant (404-405)
282.644 296,4558Amort. of Utilitv Plant Acq. Adi (406)
9
Amort. of Property Losses, unrecovereo
Plant and Resulatory Study Costs (407)
10 Amort. of Conversion Expenses (407)
9.849.43911Taxes other Than lncome Taxes (408.1) (z'8 9,389.124
1 I .'1 25.860 1 3.328.06912lncome Taxes - Federal (409.1)
2.893.1 93 3.704,83513- Other (409.1)
14 Provision for Defened lncome Taxes (410.1)'t4,858,331 11.297,703
1 (16.807.4981'15 Provision for Defened lncome Taxes - Cr. @'11.1\
(3',t2.920\872.891'.16 lnvestment Tax Credit Adi. - Net (41 1.4)
1 (59.227'17 (Gain)/Loss from Disp. of Utility Plant (41 1.6, 41'1.7, 421\
('t 1)fi2',,18 Gains from Disp. Of Allowances (411.8)
244.180.38319
TOTAL Utility Operating Expenses
(Enter Total of Lines 4 thru 1 8)231,826.795
20 66,936,432 67,035,'197
Net utility operating lnc,me (Enter I otal ot
line 2less 19)
IIIIIIIII
(1) Depreciation expense associated with transportation equipment is generally charged to operations and maintenance
expense and construction work in progress.
(2) Payroll taxes are generally charged to operations and maintenance expense and construction work in progress.
IDAHO SUPPLEMENT Page 1
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Page2IDAHO SUPPLEMENT
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report ls:(1) X An Original(2) _ A resubmission
Date of Report
(Mo, Da, Yr)
May 19,2020
Year of Report
Dec.31.2019
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
lf the amount for previous year is not derived from previously reported figures, explain in footnotes.
Ltne
No Account
(a)
Amount for
Current Year
(b)
Amount tor
Previous Year
(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Ooeration
4 (500) Ooeration Suoervision and Enoineerinq 1,053,665 1 ,106,501
5 (50'l) Fuel 47.745.478 51 ,813,402
6 (502) Steam ExDenses 4.743.637 5.000.469
7 (503) Steam ftom Other Sources 315.452 307.616
I (Less) (504) Steam Transfened - Cr.
I (505) Electric ExDenses 90,589 95,379
10 (506) Miscellaneous Steam Power Exoenses 't.598.531 1.511.'t66
11 (507) Rents 29.110 30.295
12 TOTAL Operation (Enter Total of lines 4 thru 11)55.576.462 59.864.828
13 Maintenance
't4 (510) Mainlenance SuoeMsion and Enqineerinq 431.127 495,217
't5 (51 1) Mainlenance of Struc{ures 1.632.341 1,670,850
16 (512) Maintenance of Boiler Plant 5.263.249 5,843,098
17 (513) Maintenance of Electric Plant 2.335.427 2.509.582
18 (514) Maintenance of Miscellaneous Steam Plant 612.214 602.716
19 TOTAL Maintenance (Enter Total of lines 14 thru 18)10,274,358 11.121 .463
20 TOTAL Power Production Expenses - Steam Power (Enter Total of lines 12 & 19)65,850,820 70.986,291
21 B. Nuclear Power Generation
22 Ooeration
23 (51n Operation Supervision and Engineering
24 (518) Fuel
25 (5'19) Coolants and Water
26 (520) Steam Exoenses
27 (521) Steam from Other Sources
28 (Less) (522) Steam Transfened - Cr
29 (523) Elec{ric Expenses
30 (524) Miscellaneous Nuclear Power Expenses
31 (525) Rents
32 TOTAL Ooeration (Enter Total of lines 23 thru 31)
33 Maintenance
34 (528) Meintenance Suoervision and Enoineerino
35 (529) Maintenance of Structures
36 (530) Maintenance of Reactor Plant Equipment
37 (531) Maintenance of Elec{ric Plant
38 (532) Maintenance of Miscellaneous Nuclear Plant
39 TOTAL Maintenance (Enter Total of lines 34 thru 38)
40 TOTAL Power Production Exoenses - Nuclear Power (Enter Total of lines 32 & 39)
4'.l C. Hydraulic Power Generation
42 Operation
43 (535) Ooeration SuDervision and Enqineerins 559.356 525.685
44 (536) Waterfor Power 2,'.t39 2.379
45 (537) Hvdraulic ExDenses 240.778 281 ,394
46 (538) Electric ExDenses
47 (539) Miscellaneous Hvdraulic Power Generation Expenses 1 .1 84.501 1,150.134
48 (540) Rents 100.275 75.780
49 Total of lines 43 thru 2,087,049 2,035,373
IDAHO SUPPLEMENT Page 3
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report ls:(1) X An Original(2) _ A resubmission
Date of Report
(Mo, Da, Yr)
May 19, 2020
Year of Report
Dec. 31, 2019
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES. IDAHO
lf the amount for previous year is not derived from previously reported figures, explain in footnotes.
Ltne
No.Account
(a)
Amounl ror
Current Year
(b)
Amounl ror
Previous Year
(c)
50 C. Hvdraulic Power Generation (Continued)
51 lVlaintenance
52 (541) Maintenance Suoervision and Enoineerino 23 29
53 f542) Meintenance of Struc'tures 34.224 44.458
54 (543) Maintenance of Reservoirs. Dams, and Waterways 104645 88 434
55 (5ll4) Maintenance of Eledric Plant 1 18.998 1 04,353
56 (545) Maintenance of Miscellaneous Hydraulic Plant 258.795 240.598
57 TOTAL Maintenance (Enter Total of lines 52 thru 56)520.689 477.872
58 TOTAL Power Produclion Expenses - Hydraulic Power (Enter Total of lines 49 & 57)2.607.738 2.513.245
59 D. Other Power Generation
30 Ooeretion
tl f546) Ooeration Suoervision and Enoineerino 21.O32 17.707
12 f5471 Fuel 1 8.275.033 '15.603_255
i3 f548) Generation Exoenses 1 .019.903 '1.092226
i4 (549) Miscellaneous Other Po,er Generation Expenses 455 878 31't 294
35 f550) Rents 168.480 249.926
,o TOTAL ODeration (Enter Total of lines 61 thru 65)1 9.940.326 17.274.408
)7 l\raintenance
68 Maintenance and
l9 f552) Maintenance of Structures 1 40.354 272.609
70 f553) Maintenance of Generation and Electric Plant 723.469 1 .101 .066
71 f554) Maintenance of Miscellaneous Other Po/ver Generation Plant 177.191 1 93.095
72 TOTAL Maintenance (Enter Total of lines 68 thru 71)1.M1.O14 1.566.770
73 Power 20.981.340 14.441.174
74 E. Other Power Suppv Expenses
75 (555) Purchased Por/er 40,093.922 43,924,705
76 f556) Svstem Control and Load DisDatchino 45.552 75.113
77 6.797.525 7.OO2.440
7A TOTAL Other Power Suoolv Exoenses (Enter Total of lines 75 thru 77)46 936 999 51 002 258
79 TOTAL Power Production Expenses - (Enter Total of lines 20, 40, 58, 73 and 78)136 376 897 143 342 972
80 2. TRANSMISSION EXPENSES
81 0peration
82 f560) ODeration Suoervision and Enoineerino 435.102 419.901
83 f56'l) Load Disoatchino 1.206.737 1.233.382
84 (562) Stetion Exoenses 184.669 179.91 9
85 (563) Overhead Line Exoenses 64.407 53.602
86 (5M) lJnderoround Line Exoenses
87 (565) Transmission of Elec,tricitv bv Others 8.650.055 8_369.141
88 (566) Mismllanmus Transmission ExDenses 177.709 177.269
89 f567) Rents 132.649 132.576
90 TOTAI Oberation (Enler Total of lines 82 thru 89)10 851 328 I 0 565 790
91 Maintenaner
92 (568) Maintenance Supervision and Enoineering 77 103 89 563
93 (569) Maintenance of Structures 342.147 382.730
94 Maintenance of Station 697,326 743,056
95 (571) Maintenance of Overhead Lines 957.687 1.001.154
96 Maintenance of 3,401 5.072
97 Maintenance of Miscellaneous 9.072 13.774
98 TOTAL Maintenance (Enter Total of lines 92 thru 97)2.086.736 2.235.349
99 12.938 c64 12.801.'139
100
'101 Deration
't02 438 136 436 443
103 ,U1 607 573,951
(l ) The ldaho amounts in Account 557 Other expenses are $5,961 ,983 for the current year and $6,016,898 for the previous year.
However, the amount for this year has been increased by $835,542 because of the impact of the 2020 Protocol Adjustment, while in
the prior year it was increased by 985,542 because of the impact of the 2017 Protocol Adjustrnent.
IDAHO SUPPLEMENT Page 4
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report ls:(1) X An Original(2) _ A resubmission
Date of Report
(Mo, Da, Yr)
May 19,2020
Year of Report
Dec. 31, 2019
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
lf the amount for previous year is not derived from previously reported figures, explain in footnotes
Ltne
No.Account
(a)
Amount tor
Current Year
(b)
Amount rcr
Previous Year
(c)
104 3. DISTRIBUTION EXPENSES (Continued)
'105 (582) Stetion Exoenses 472,115 453,365
'106 (583) Overhead Line Expenses 313,774 429,560
107 (584) Underqround Line Expenses
r08 (585) Street Liohtinq and Signal System Expenses 't1.201 12.318
109 (586) Meter Expenses 183.938 199,955
110 (587) Customer lnstallations Expenses 886,970 969,859
1't 1 (588) Miscellaneous Distribution Expenses (977\39,619
1't2 (589) Rents 34.956 40,588
113 TOTAL Oeeration (Enter Total of lines 102 thru 'l 12)2.947.784 3,155,658
114 Maintenance
115 (590) Maintenance SuDervision and Engineering 333.798 245.783
116 (59 1 ) Maintenance of Structures 148.372 116.697
117 (592) Maintenance of Station EouiDmenl 507,870 327.807
118 (593) Maintenance of Overhead Lines 2.587.944 4.697.065
119 (594) Maintenance of Underground Lines 902,1 67 759,91 0
120 (595) Maintenance of Line Transformers 50,1 26 48,446
121 [596) Maintenance of Street Lighting and Signal Systems 91.042 102,493
122 (597) Maintenance of Meters 36,291 16,860
123 (598) Maintenance of Miscellaneous Distribution Plant 287.462 319,595
't24 TOTAL Maintenance (Enter Total of lines 115 thru 123)4.945.072 6.634.656
't25 TOTAL Distribution Expenses (Enter Total of lines 113 and '124)7.892.856 9.790,3'14
126 4. CUSTOMER ACCOUNTS EXPENSES
't27 ODeration
128 (901) SuDervision 95.98'l 't03.732
129 (902) Meter Readino Exoenses 2.171.132 2.057.782
130 (903) Customer Records and Collection Expenses 1.989.916 2168.720
't31 (904) Uncollectible Accounts 657.699 433.2',t1
't32 (905) Miscellaneous Customer Accounts Expenses 756 642
133 TOTAL Customer Accounts Expenses (Enter Total of lines 1 28 thru 1 32)4,915,484 4.764.087
134 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
135 Ooeration
136 (907) Supervision 283 4,925
137 (908) Customer Assistance Expenses 132.712 103,768
138 (909) lnformational and lnstructional Expenses 266.394 235,807
139 (910) Miscellaneous Customer Service and lnformational Expenses 190 1.732
't40 TOTAL Cust. Service and lnformational Exp. (Enter Total of lines '136 thru 139)399.579 346.232
141 6. SALES EXPENSES
142 Ooeration
143 (911) Suoervision
'144 (9'12) Demonstratino and Sellinq Expenses
't45 (913) Advertisino ExDenses
t46 (916) Miscellaneous Sales Expenses
147 TOTAL Sales Expenses (Enter Total of lines 143 thru 146)
148 7. ADMINISTRATIVE AND GENERAL EXPENSES
t49 Ooeration
150 (920) Administrative and General Salaries 4.377.494 4.280,871
151 (921) Office SuoDlies and Expense 560.397 598.608
152 (Less) (922) Adminishative Expenses Transferred - Cr (1 .976.601)(1.890.263)
153 't.164.399 1.083.680
r54 421,773
155 357 962.U4
156 7 6.767,E04
157
(,1) Pensions and benefits expense is associated with labor and generally charged to operations and maintenance expense and
@nstruction work in progress.
IDAHO SUPPLEMENT Page 5
Name of Respondent
PacifiCorp
dba Rocky Mounlain Power
This Report ls:(1) X An Original
(2) _ A resubmission
Date of Report
(Mo, Da, Yr)
May 19, 2020
Year of Report
Dec.31,2019
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) - IDAHO
lf the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line
No.Account
(a)
Amounl tor
Cunent Year
o)
Amount for
PreMous Year
(c)
157 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
158 (92il Franchise Requirements
159 (928) Requlatory Commission Expenses 't.339.6't 0 't.161.503
160 (929) Duolicate Charoes - Cr 0.468.193)0.619.742\
161 (930.1) General Advertisinq Expenses 3.145 34
162 (930.2) Miscellaneous General Expenses 125.122 129,277
163 (931) Rents 125.510 141.241
164 TOTAL Operation (Enter Total of lines 150 thru 163)4,810,393 6,037,130
165 Maintenance
166 (935) Maintenance of General Plant 1,388,548 1.378.507
167 TOTAL Administrative and General Expenses (Enter Total of lines 164 & 166)6.'198.941 7.415.637
168 TOTAL Electric Operation and Matntenance Expenses (Enter I otal ot ltnes 79, 99
125, 133, 140, 147, and 167)168.721.821 178,460,381
SUMMARY OF ELECTRIC OPERATION AND MAINTENANCE EXPENSES. IDAHO
Line
No.
Functional Classifi cations
(a)
Operation
(b)
Maintenance
(c)
Total
(d)
169
170
171
172
173
174
175
176
177
178
179
180
181
182
183
Power Production Expenses
Electric Generation:
Steam Power
Nuclear Po\l,er
Hydraulic -Conventional
Other Power Generation
Other Power Suppty Expenses
Total Porrcr Production Expenses
Transmission Expenses
Distribution Expenses
Customer Accounts Expenses
Customer Service and lnformational Expenses
Sales Expenses
Adm. and General Expenses
Total Electric Operation and Maintenance Expenses
55,576,462
2,087,U9
19,940,326
46.936.999
10,274,358
520,689
1,U1,014
65,850,820
2,607,738
20,981,340
46,936,999
124,540,836 11,836,061 136.376.897
10,851,328
2,947,784
4,915,4U
399,579
4.810.393
2,086,736
4,945,072
1.388.548
12,938,004
7,892,856
4,915,484
399,579
6.198.941
148,465,404 20.256.417 168.72',t.821
IDAHO SUPPLEMENT Page 6
STATE OF IDAHO - ALLOCATED
(l) Depreciation e)eense associated with transportation equipment is generally charged to operations and maintenance
expense and construction uork in progress'
IDAHO SUPPLEMENT Page 7
Name of Respondent
PacifiCorp
dba Rocky Mountain Povver
This Report ls:(1) x An Original
(2) _ A resubmission
Date of Report
(Mo, Da, Yr)
May 19, 2020
Year of Report
Dec.31,2019
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Accounts 403, 404,405)
amortization of uisition
A.of Depreciation and Amortization
Depreciation
Expense
(Account 403) rl
Amortization of Amortization of
Other Electric
Plant (Acct. 405)
Line Functional Classifi cation Total
No.Plant (Acct. 404)
1 lntanoible Plant 2.634,017 7
2 Steam Production Plant 14,512,632 14.5'.12.632
3 Nuclear Produclion Plant
4 Hvdraulic Production Plant - Conventional 2,4*,040 18,425 2,472,465
5 Hvdraulic Production Plant' PumpqgllStqrage
6 Other Production Plant 7.581.927 7,581,927
7 Transmission Plant 6,650,467 6.650.467
8 Distribution Plant 7.262.954 7.262.954
I General Plant 2.M1,080 16.255 2.457.335
10 Common Plant - Electric
11 TOTAL 40,903,100 2,688,697 43,591,797
Name of Respondenl
PacifiCorp
dba Rocky Mountain Povver
This Report ls:(1) X An Original
(2) _ A resubmission
Date of Report
(Mo, Da, Yr)
May 19,2020
Year of Report
Dec.3'1,2019
STATE OF IDAHO . ALLOCATED
TAXES, OTHER THAN INCOME TAXES
ACCOUNT 408.1 (r)
(l) Payroll taxes are generally charged to operations and maintenance expense and construction \ ork in progress.
KIND OF TA)(AMUUN I
1 Prooertv 8.505.483
2 Other 883.641
3
4
5
f
I
10
1',1
12
13
14
15
16
17
'18
19
20 Total ( Must aoree with oaoe 1 , line 1 1.)9.389,124
IDAHO SUPPLEMENT Page 8
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Page 9IDAHO SUPPLEMENT
of Respondent Report ls:
-L An Original
Rocky Mountain Power
(1)
(21 _ A resubmission
Dale of Report
(Mo, Da, Y0
May 19, 2020
Year of Report
Dec.31.2019
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Line
No.Account
(a)
Amount for
Current Year
(b)
Amount br
Previous Year
(c)
1 UTILIW PLANT
2 ln Service
3 Plant ln SeMce (Classified)1 609 735 369 1 645 966 883
4 ProDertv Under Caoital Lease ll)
5 Plant Purchased or Sold
6 ComDleted Construclion not Clessifi ed 1 3.990.267 14.289.130
7 ExDerimental Plant Undassifi ed
8 Tolal fEnter Tolel of Lines 3 throuoh 7)1.623.725.636 1.660.256.013
9 Lased To Others
10 Held for Future use 743,669 780,006
11 Conslruciion Work ln Process (2)
12 Acouisition Adiustments 8.553.573 8.971.626
13 Total t tilitv Plant (Enter Total of Lines 8 throuqh 12)'t.633.022.974 't.670.007.645
14 Aeumulated Provision for DeDrecietion- Amortization & Deoletion 583.411 .736 626.334.1 25
15 Ne{ L}tilitv Plant (Enter Total of Line 13 less Line 14)1 .049.611 .242 1.043.673.520
16
OETAL OF ACCUUUUTED PROVISION FOR DEPRECIATION,
ATORIIZATION AND DEPLETION
17 ln SeMce
t8 Deormielion 538.669.948 582.574.935
19 of Natural Gas Land And Land
20 Amortization of Underoround Storaoe Land and Land Riohts
21 Amortization of other utilitv Plant 37 009 557 35 945 599
))Total ln SeMce (Enter Total of Lines 1 8 throuqh 21)575.679.505 618.520.534
23 Leased To O(hers
24 Deormiation
25 Amortization And t eoletion
26 Total Leesed to Others (Enter Tolal of Lines 24 and 25)
27 Held for Future use
28 DeDreciation
29 Amortization
30 Total Held for Future Use (Enter Total of Unes 28 and 29)
31 Abendonmenl of I Es* (Nalural Gas)
32 Aeumulaled Provision for Assel Acouisition Adiustment 7.732.231 7.813.591
33
Total Accumulated Provisions (Should Agree With Llne '14 above)
(Enter Total of Lines 22, 26, 30, 31 and 32)583.411 .736 626.334.125
34
(1) Capitalized lease assets are not included in rate base; they are included in operating expenso as rent expense.
(21 Construciion Work ln Process ("CW|P") is not included in rate base and it is not assigned allocation faclors until it
goes into seMce. On a tcltal company basis, CW|P was $2,002,448,524 at December 31, 2019.
IDAHO SUPPLEMENT Page 10
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
This Report ls:(1) X An Original
(2) _ Aresubmission
Date of Report
(Mo, Da, Yr)
May 19,2020
Year of Report
Dec.31,2019
ELECTRTC PLANT rN SERVTCE - STATE OF IDAHO (ALLOCATED)
(ln addition to Account 10'1, Electric Plant ln Service (Classified), this schedule includes Account 102, Electric Plant
Purchased or Sold, Account 103, Experimental Electric Plant Unclassified and
Account 1 06, Completed Construction Not Classified-Electric.)
1 . Report below the original cost of electric plant in
service according to prescribed accounts.
3. Credit adjustments of plant accounts should be
enclosed in parentheses to indicate the negative effect
of such amounts.
2. Do not include as adjustments, corections of
additions and retirements for the current or the
preceding year.
Line
No.Account
(a)
Beginning Balance
(b)
Balance at End of
Year
(o)
1 1. INTANGIBLE PLANT
2 101
3 3 12.558.231
4 Plant 4 44.7E6.124
5 TOTAL Totel of lines and 56 1
b
7 Plant
I 5,496,677
I 64.108.123 62,095,207
273.912.72E
Dilven
12 '14 Un 59,332.914
13 28.928,131
14 1,995,931
15 T Produciion Plant Total of lines 8 thru 431.761,5E6
16 B. Nuclear Production Phnt
'17 (320
18
19 Plant
20
2',i
22 Power Plant
23 TOTAL Nucleer Production Plant (Enler Total of lines 17 thru 22)
24
25 Land 2.t 2.146.926
26 17.11 16.485.450
27 31.30.497.570
28 Water enerators 4.4 7.266 8.387.526
29 (334 1 5.038.180
30 Misc.141 'ts't .171
31 1.523.981 1.474.512
32 TOTAL 25 thru 3'l 66.356.323 64.18't .335
ln Plant
34 rc4(3.007.808
35 141 ,|13.575.128
$42 1.003.663 956.906
37 34i 181 165.249.468
29.446.063
39 34f 7 19.171 .O41
40 987.300 941.306
232.351,720
42 TOTAL Production Plant (Enter Total of lines 15. 23, 32. and 41)768,805,935 728,294,643
IDAHO SUPPLEMENT Page 11
Name of Respondenl
PacifiCorp
dba Rocky Mountain Power
This Report ls:(1) X An Original
(2) _ A resubmission
Date of Report
(Mo, Da, Yr)
May 19, 2020
Year of Report
Dec.31,2019
ELECTRIC PLANT lN SERVICE (Gontinued) STATE OF IDAHO (ALLOCATED)
Line
No.Account
(a)
Beginning Balance
(b)
Balance End of
Year
(q)
43 3. TRANSMISSION PLANT
4 16,16.s87.09'l
45 17,006 996 16.70E.847
46 533 131.138.148
47 836 77.206.535
4A 59.'t62.O80 59.732.112
49 77,326,242 75.734,497
218 243 227,509
51 and 498 486,986
52 740 705.623
53 TOTAL Transmission Plant (Enter To 44 thru 387.5't 9.4't 3 378.527.v8
il 4. DISTRIBUTION PLANT
55 1,E35 ,903 1,835,903
56 and 3.366,731
57 026 37.524.250
58
Fixtures 91.20E 496 94,59E,436
60 40.464,0E3
6'l 10.668.846
62 U 28.695.233 29.478.412
63 E3,5 85.091.706
44.726.6E9
65 352 16.827,950
66 (371) lnstallations on Customer Pren ses 't69.414 170.194
67 on
68 73E,795 770,243
69 352.229 261 365.523.443
70 5. GENERAL PI-ANT
7',!686.4S8 67'.t.121
72 18.'t14.649
73 4.U5 991 3,912,030
74 8.466 379 E.277.652
75 879 873.089
76 3.826.980 3.706.858
77 2.108.U4 2.O54.313
78 (396) Pouer Ooerated Eouioment 13.709 362 14,021,353
79 27.920.207
80 396 373.337
81 80.836.656 79.924.609
82 121,'t20.971
83 6E3 80,045,580u8831.609.735.369
85
86
87
88 14.289,130 13,990,267
89 TOTAL Electric Plant in Service 1,O00.256 013 1,623,725,63ti
IDAHO SUPPLEMENT Page 12
STATE OF IDAHO --ALLOCATED
Name of Respondent
PacifiCorp
dba Rocky Mountain Pol,er
This Report ls:
(1)
(2)-L An Original
A l€submission
Date of Report
(Mo, Da, Y0
May 19, 2020
Year of Report
Oec.31,2019
MATERIALS AND SUPPLIES
1. For Account 154, r3port the amount of plant materials
and operating supplies under th€ primary tunctional
classifications as andicatBd in column (a); estimat$ of
amounts by function alt acceptable. ln column (d),
designate the d€partment or departments which use the
class of material.
2. Give an exdanation of important inventory adjusfnents
during the year (on a supdemental page) showing general
cla$es of material and supplies and the various
accounb (operating expense, clearing accounts, dant,
etc.) aff€cted - debited or credited. Show separately
debits or credits to sbres erpense clearing, if
applicable.
Line
No-
ACCOUNT
(a)
Ealance
Beginning of
Year
(b)
Balance
End of Year
(c)
Depanment or
Departmenb
Which Use Material
(d)
1 Fuel Stock (Account'l 51)Electric
2 Fuel Stock E)oenses Undistributed (Account 152)
3 Residuals and Exfadad Products (Account 'l 53)
4 Plant Materials and Ooeratino Supplies (Account 154)
5 Assioned to - Construction (Estimated)8_539.031 Electric
6 Assioned to - ODerations and Maintenance
7 Production Plant (Estimated)4.207.102 Electric
6 Transmission Plant (Estimated)40.177 Electric
I Distribution Plant (Estimated)607.427 Electric
10 Assioned to - O0rer fi6.643)Electric
11 TOTAL Account 1 54 (Enter Totel of lines 5 thru 10)13.317.094
12 Merchandis€ (Account 155)
13 Other MaGrials and Supplies (Account 156)
14 Nudear Matarials Held br Sale (Account 157) (Not appliceble to Gas
LJtilitiB'l
15 Stores Ercense Undistibutad (Account 163)
16
17
18
19
20 TOTAL 22.793,742
IOAHO SUPPLEMENT Page 13
THIS FILING IS
Item 1: An Initial (Original)
Submission
OR Resubmission No. ____X
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
OMB No.1902-0021
OMB No.1902-0029
OMB No.1902-0205
(Expires 11/30/2022)
(Expires 11/30/2022)
(Expires 11/30/2022)
Form 1 Approved
Form 1-F Approved
Form 3-Q Approved
FERC FORM No.1/3-Q (REV. 02-04)
Exact Legal Name of Respondent (Company) Year/Period of Report
End of 2019/Q4PacifiCorp
INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q
GENERAL INFORMATION
I. Purpose
FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others
(18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q)is a quarterly regulatory requirement which supplements the
annual financial reporting requirement (18 C.F.R. § 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.
II. 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. § 141.1), and FERC Form 3-Q (18 C.F.R. § 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 total annual sales,
(2) 100 megawatt hours of annual sales for resale,
(3) 500 megawatt hours of annual power exchanges delivered, or
(4) 500 megawatt hours of annual wheeling for others (deliveries plus losses).
III. 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-filing/forms/form-1/elec-subm-soft.asp. The software is
used to submit the electronic filing to the Commission via the Internet.
(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. 03-07) i
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. §§ 41.10-41.12 for specific qualifications.)
Reference Schedules Pages
Comparative Balance Sheet 110-113
Statement of Income 114-117
Statement of Retained Earnings 118-119
Statement of Cash Flows 120-121
Notes to Financial Statements 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. Insert parenthetical phrases only when exceptions are
reported.
“In connection with our regular examination of the financial statements of for the year ended on which we have
reported separately under date of , we have also reviewed schedules
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://www.ferc.gov/help/how-to.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.gov/docs-filing/forms/form-1/form-1.pdf and
http://www.ferc.gov/docs-filing/forms.asp#3Q-gas .
IV. When to Submit:

FERC Forms 1 and 3-Q must be filed by the following schedule:
FERC FORM 1 & 3-Q (ED. 03-07) ii
a) FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 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. §
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: Information Clearance Officer); and to the Office of Information 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)).
FERC FORM 1 & 3-Q (ED. 03-07) iii
GENERAL INSTRUCTIONS
I. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret
all accounting words and phrases in accordance with the USofA.
II. 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.
III 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.
IV. 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 VII. below).
VI. 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.
VII 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.
VIII. Do not make references to reports of previous periods/years or to other reports in lieu of required entries,
except as specifically authorized.
IX. 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 1 & 3-Q (ED. 03-07) iv
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.
DEFINITIONS
I. Commission Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or
any other Commission. Name the commission whose authorization was obtained and give date of the authorization.
II. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose
behalf 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-825r
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. It 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, all water
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 all water 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 shall file 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. 03-07) vi
"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) (2005), 16 U.S.C. § 825o(a).
FERC FORM 1 & 3-Q (ED. 03-07) vii
IDENTIFICATION
FERC FORM NO. 1/3-Q:
REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
Nikki L. Kobliha6LJQDWXUHRQILOH
825 N.E. Multnomah Street, Suite 1900, Portland, OR 97232
2019/Q4
825 N.E. Multnomah Street, Suite 1900, Portland, OR 97232
01 Exact Legal Name of Respondent
(1) An Original (2) A ResubmissionX
02 Year/Period of Report
End ofPacifiCorp
03 Previous Name and Date of Change (if name changed during year)
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
05 Name of Contact Person 06 Title of Contact Person
07 Address of Contact Person (Street, City, State, Zip Code)
08 Telephone of Contact Person,Including
Area Code
09 This Report Is 10 Date of Report
(Mo, Da, Yr)
01 Name
02 Title
03 Signature 04 Date Signed
(Mo, Da, Yr)
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 to any matter within its jurisdiction.
/ /
Mark Reis Corporate Accounting Director
[phone] / /
Nikki L. Kobliha
Vice President, CFO and Treasurer 04/10/2020
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.
FERC FORM No.1/3-Q (REV. 02-04)Page 1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LIST OF SCHEDULES (Electric Utility)
PacifiCorp X
/ /
2019/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
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".
101General Information 1
102Control Over Respondent 2
103Corporations Controlled by Respondent 3
104Officers 4
105Directors 5
106(a)(b)Information on Formula Rates 6
108-109Important Changes During the Year 7
110-113Comparative Balance Sheet 8
114-117Statement of Income for the Year 9
118-119Statement of Retained Earnings for the Year 10
120-121Statement of Cash Flows 11
122-123Notes to Financial Statements 12
122(a)(b)Statement of Accum Comp Income, Comp Income, and Hedging Activities 13
200-201Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 14
NA202-203Nuclear Fuel Materials 15
204-207Electric Plant in Service 16
NA213Electric Plant Leased to Others 17
214Electric Plant Held for Future Use 18
216Construction Work in Progress-Electric 19
219Accumulated Provision for Depreciation of Electric Utility Plant 20
224-225Investment of Subsidiary Companies 21
227Materials and Supplies 22
228(ab)-229(ab)Allowances 23
NA230Extraordinary Property Losses 24
NA230Unrecovered Plant and Regulatory Study Costs 25
231Transmission Service and Generation Interconnection Study Costs 26
232Other Regulatory Assets 27
233Miscellaneous Deferred Debits 28
234Accumulated Deferred Income Taxes 29
250-251Capital Stock 30
253Other Paid-in Capital 31
254Capital Stock Expense 32
256-257Long-Term Debt 33
261Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 34
262-263Taxes Accrued, Prepaid and Charged During the Year 35
266-267Accumulated Deferred Investment Tax Credits 36
FERC FORM NO. 1 (ED. 12-96) Page 2
LIST OF SCHEDULES (Electric Utility) (continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /
2019/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
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".
269Other Deferred Credits 37
272-273Accumulated Deferred Income Taxes-Accelerated Amortization Property 38
274-275Accumulated Deferred Income Taxes-Other Property 39
276-277Accumulated Deferred Income Taxes-Other 40
278Other Regulatory Liabilities 41
300-301Electric Operating Revenues 42
NA302Regional Transmission Service Revenues (Account 457.1) 43
304Sales of Electricity by Rate Schedules 44
310-311Sales for Resale 45
320-323Electric Operation and Maintenance Expenses 46
326-327Purchased Power 47
328-330Transmission of Electricity for Others 48
NA331Transmission of Electricity by ISO/RTOs 49
332Transmission of Electricity by Others 50
335Miscellaneous General Expenses-Electric 51
336-337Depreciation and Amortization of Electric Plant 52
350-351Regulatory Commission Expenses 53
352-353Research, Development and Demonstration Activities 54
354-355Distribution of Salaries and Wages 55
NA356Common Utility Plant and Expenses 56
397Amounts included in ISO/RTO Settlement Statements 57
398Purchase and Sale of Ancillary Services 58
400Monthly Transmission System Peak Load 59
NA400aMonthly ISO/RTO Transmission System Peak Load 60
401Electric Energy Account 61
401Monthly Peaks and Output 62
402-403Steam Electric Generating Plant Statistics 63
406-407Hydroelectric Generating Plant Statistics 64
NA408-409Pumped Storage Generating Plant Statistics 65
410-411Generating Plant Statistics Pages 66
FERC FORM NO. 1 (ED. 12-96) Page 3
LIST OF SCHEDULES (Electric Utility) (continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /
2019/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
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".
422-423Transmission Line Statistics Pages 67
424-425Transmission Lines Added During the Year 68
426-427Substations 69
429Transactions with Associated (Affiliated) Companies 70
450Footnote Data 71
Stockholders' Reports Check appropriate box:
X Two copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO. 1 (ED. 12-96) Page 4
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
GENERAL INFORMATION
PacifiCorp X
/ /2019/Q4
Nikki L. Kobliha, Vice President, Chief Financial Officer and Treasurer
825 N.E. Multnomah Street, Suite 1900
Portland, OR 97232
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.
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?
(1) Yes...Enter the date when such independent accountant was initially engaged:
(2) NoX
Not applicable.
PacifiCorp is a United States regulated electric utility company headquartered in Oregon that serves 1.9
million retail electric customers, including residential, commercial, industrial, irrigation and other
customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp is
principally engaged in the business of generating, transmitting, distributing and selling electricity. In
addition to retail sales, PacifiCorp buys and sells electricity on the wholesale market with other
utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp
delivers electricity to customers in Utah, Wyoming and Idaho under the trade name Rocky Mountain Power
and to customers in Oregon, Washington and California under the trade name Pacific Power.
FERC FORM No.1 (ED. 12-87) PAGE 101
Schedule Page: 101 Line No.: 1 Column: Item 2
PacifiCorp was initially incorporated in 1910 under the laws of the state of Maine under
the name Pacific Power & Light Company. In 1984, Pacific Power & Light Company changed its
name to PacifiCorp. In 1989, it merged with Utah Power and Light Company, a Utah
corporation, in a transaction wherein both corporations merged into a newly formed Oregon
corporation. The resulting Oregon corporation was re-named PacifiCorp, which is the
operating entity today.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
CONTROL OVER RESPONDENT
PacifiCorp X
/ /2019/Q4
1. If 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 extent of control. If control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. If 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 Inc.(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 Inc., 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, beneficially own 90.9%, 8.1% and 1.0%,
respectively, of BHE's voting common stock.
Page 102FERC FORM NO. 1 (ED. 12-96)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CORPORATIONS CONTROLLED BY RESPONDENT
PacifiCorp X
/ /
2019/Q4
Line
No.
Name of Company Controlled Kind of Business Percent Voting
Stock Owned(c)(b)(a)
Footnote
Ref.(d)
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual
agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the
Uniform System of Accounts, regardless of the relative voting rights of each party.
Mining 100.00 1 Energy West Mining Company
Mining 100.00 2 Fossil Rock Fuels, LLC
Mining 100.00 3 Glenrock Coal Company
Management services 100.00 4 Interwest Mining Company
Management services 100.00 5 Pacific Minerals, Inc.
Mining 66.67 6 Bridger Coal Company
Mining 21.40 7 Trapper Mining Inc.
Non-profit foundation 8 PacifiCorp Foundation
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO. 1 (ED. 12-96) Page 103
Schedule Page: 103 Line No.: 1 Column: a
Energy West Mining Company ceased mining operations in 2015.
Schedule Page: 103 Line No.: 3 Column: a
Glenrock Coal Company ceased mining operations in 1999.
Schedule Page: 103 Line No.: 5 Column: a
Pacific Minerals, Inc. is a wholly owned subsidiary of PacifiCorp that holds a 66.67%
ownership interest in Bridger Coal Company.
Schedule Page: 103 Line No.: 6 Column: a
Bridger Coal Company is a coal mining joint venture with Idaho Energy Resources Company, a
subsidiary of Idaho Power Company, and is jointly controlled by Pacific Minerals, Inc. and
Idaho Energy Resources Company.
Schedule Page: 103 Line No.: 7 Column: a
PacifiCorp is a minority owner in Trapper Mining Inc., a cooperative. The members are Salt
River Project Agricultural Improvement and Power District (32.10%), Tri-State Generation
and Transmission Association, Inc. (26.57%), PacifiCorp (21.40%) and Platte River Power
Authority (19.93%).
Schedule Page: 103 Line No.: 8 Column: c
The PacifiCorp Foundation is an independent non-profit foundation created by PacifiCorp in
1988. The PacifiCorp Foundation operates as the Rocky Mountain Power Foundation and the
Pacific Power Foundation. As of December 31, 2019, the Foundation's two directors, are
also directors of PacifiCorp.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OFFICERS
PacifiCorp X
/ /
2019/Q4
Line
No.
Title Name of Officer Salaryfor Year(c)(b)(a)
1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
Executive Officers as of December 31, 2019: 1
2
Chairman of the Board of Directors 3
and Chief Executive Officer, PacifiCorp William J. Fehrman 4
5
President and Chief Executive Officer, 6
Pacific Power 365,000Stefan A. Bird 7
8
President and Chief Executive Officer, 9
Rocky Mountain Power 350,000Gary W. Hoogeveen 10
11
Vice President, Chief Financial Officer and Treasurer, 12
PacifiCorp 239,571Nikki L. Kobliha 13
14
15
16
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18
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21
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25
26
27
28
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30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96) Page 104
Schedule Page: 104 Line No.: 1 Column: a
PacifiCorp sets forth compensation information for its "named executive officers" for the
year ended December 31, 2019, consistent with Item 402 of Regulation S-K promulgated by
the Securities and Exchange Commission, in its Annual Report on Form 10-K. Salary
information 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. §388.107(d)(f).

Schedule Page: 104 Line No.: 4 Column: c
William J. Fehrman received no direct compensation from PacifiCorp. PacifiCorp reimbursed
its indirect parent company, Berkshire Hathaway Energy Company ("BHE"), for the cost of
Mr. Fehrman’s time spent on matters supporting PacifiCorp, including compensation paid to
him by BHE, pursuant to an intercompany administrative services agreement among BHE and
its subsidiaries. For further information on executive compensation, refer to BHE’s Annual
Report on Form 10-K, for the year ended December 31, 2019.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DIRECTORS
PacifiCorp X
/ /
2019/Q4
Line Name (and Title) of Director Principal Business Address(b)(a)No.
1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated
titles of the directors who are officers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
PacifiCorp Board of Directors as of December 31, 2019: 1
2
William J. Fehrman 3
666 Grand Avenue, 27th Floor, Des Moines, IA 50309(Chairman of the Board of Directors and CEO, PacifiCorp) 4
5
Stefan A. Bird 6
825 N.E. Multnomah Street, Suite 2000, Portland, OR 97232(President and CEO, Pacific Power) 7
8
Gary W. Hoogeveen 9
1407 West North Temple, Suite 310, Salt Lake City, UT 84116(President and CEO, Rocky Mountain Power) 10
11
Nikki L. Kobliha 12
825 N.E. Multnomah Street, Suite 1900, Portland, OR 97232(VP, CFO and Treasurer, PacifiCorp) 13
14
666 Grand Avenue, 27th Floor, Des Moines, IA 50309Patrick J. Goodman 15
16
825 N.E. Multnomah Street, Suite 2000, Portland, OR 97232Natalie L. Hocken 17
18
1407 West North Temple, Suite 310, Salt Lake City, UT 84116Cindy A. Crane 19
20
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27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-95) Page 105
Schedule Page: 105 Line No.: 19 Column: a
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.
For further information, refer to Item 13 in Important Changes During the Year in this
Form No. 1.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
INFORMATION ON FORMULA RATES
PacifiCorp X
/ /2019/Q4
Line
No.FERC Rate Schedule or Tariff Number FERC Proceeding
Does the respondent have formula rates?Yes
No
X
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.
FERC Rate Schedule/Tariff Number FERC Proceeding
ER11-3643FERC Electric Tariff Volume No. 11, Attachment H-1 1
2
3
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FERC FORM NO. 1 (NEW. 12-08) Page 106
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.\ Filed DateAccession No.
Date
Docket No. Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
INFORMATION ON FORMULA RATES
Does the respondent file with the Commission annual (or more frequent)Yes
No
X
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
FERC Rate Schedule/Tariff Number FERC Proceeding
filings containing the inputs to the formula rate(s)?
Document
03/22/201920190322-5114 ER19-1419 1
05/15/201920190515-5253 ER11-3643 2
3
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FERC FORM NO. 1 (NEW. 12-08) Page 106a
Schedule Page: 1061 Line No.: 1 Column: d
PacifiCorp submits tariff filing per 35.13(a)(2)(iii): OATT Revised Attachment H-1
(Revised Depreciation Rates 2019) to be effective 6/1/2019 under FERC Docket No. ER19-1419
Schedule Page: 1061 Line No.: 1 Column: e
PacifiCorp's Volume No. 11 Open Access Transmission Tariff
Schedule Page: 1061 Line No.: 2 Column: d
Transmission Formula Rate Annual Update Informational Filing of PacifiCorp under FERC
Docket No. ER11-3643
Schedule Page: 1061 Line No.: 2 Column: e
PacifiCorp's Volume No. 11 Open Access Transmission Tariff

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.Page No(s). Schedule Column Line No
INFORMATION ON FORMULA RATES
1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from
Formula Rate Variances
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 reported 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.
204-207 Electric Plant in Service (b) 46 1
204-207 Electric Plant in Service (g) 46 2
204-207 Electric Plant in Service (b) 75 3
204-207 Electric Plant in Service (g) 75 4
204-207 Electric Plant in Service (b) 99 5
204-207 Electric Plant in Service (g) 99 6
204-207 Electric Plant in Service (b) 104 7
204-207 Electric Plant in Service (g) 104 8
219 Accum. Prov. for Depr. of Electric Utility Plant (c) 20 9
219 Accum. Prov. for Depr. of Electric Utility Plant (c) 22 10
219 Accum. Prov. for Depr. of Electric Utility Plant (c) 24 11
219 Accum. Prov. for Depr. of Electric Utility Plant (c) 26 12
219 Accum. Prov. for Depr. of Electric Utility Plant (c) 28 13
219 Accum. Prov. for Depr. of Electric Utility Plant (c) 29 14
320-323 Electric Operation and Maintenance Expenses (b) 185 15
320-323 Electric Operation and Maintenance Expenses (b) 197 16
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FERC FORM NO. 1 (NEW. 12-08) Page 106b
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report Year/Period of Report
End of
IMPORTANT CHANGES DURING THE QUARTER/YEAR
PacifiCorp X / /2019/Q4
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and
reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were
submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers
added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new
continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Page 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known
associate of any of these persons was a party or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred
during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash
management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
FERC FORM NO. 1 (ED. 12-96) Page 108
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(1)
None
Idaho(2)
Clifton 06/01/2019 06/01/2029 —
Dayton 05/01/2019 05/01/2029 —
Weston 05/01/2019 05/01/2029 —
Oregon(3)
Bend 09/30/2019 09/30/2029 7.0%
Gearhart 08/23/2019 08/23/2039 3.5%
Philomath 09/20/2019 09/20/2024 7.0%
Utah(4)
Aurora 03/01/2019 03/01/2024 —
Beaver City 11/01/2019 11/01/2039 —
Elsinore 02/01/2019 02/01/2029 —
Emigration Canyon 07/23/2019 07/23/2039 —
Kingston 03/01/2019 03/01/2039 —
Morgan 05/01/2019 05/01/2029 —
Summit County 11/14/2019 11/14/2029 —
Tooele County 08/15/2019 08/15/2044 —
Trenton 12/15/2019 12/15/2039 —
Uintah County 04/08/2019 04/08/2029 —
West Bountiful 02/19/2019 02/19/2029 —
Washington(5)
Granger 07/12/2019 07/12/2039 —
Harrah 09/23/2019 09/23/2039 —
Pasco 05/24/2019 05/24/2029 —
Yakima 09/25/2019 09/25/2039 —
Wyoming(6)
None
(1) In California, franchise agreement fees are an expense to PacifiCorp and are embedded in rates.
(2) In Idaho, PacifiCorp collects franchise agreement fees from customers and remits them directly to the applicable municipalities.
(3) In Oregon, the first 3.5% of the franchise agreement fee is an expense to PacifiCorp and is embedded in rates. Any amount above the 3.5% is collected from
customers and remitted directly to the applicable municipalities.
(4) In Utah, PacifiCorp collects associated taxes from customers and remits them directly to the applicable municipalities. If applicable, franchise agreement fees
are an expense to PacifiCorp and are embedded in rates.
(5) In Washington, PacifiCorp collects associated taxes from customers and remits them directly to the applicable municipalities.
(6) 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 1.0% is collected
from customers and remitted directly to the applicable municipalities.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.1
ITEM 2.
None.
ITEM 3.
None.
ITEM 4.
None.
ITEM 5.
In October 2019, PacifiCorp filed its 2019 Integrated Resource Plan ("IRP") with state commissions. The IRP includes new
transmission investments that will facilitate growth in new renewable energy resources, new storage resources and expansion in new
energy efficiency measures and demand-response programs. Delivery of new transmission infrastructure that will facilitate
approximately 4,400 MWs of new renewable energy resources, incremental to new renewable capacity that will come online by the
end of 2020, and the addition of approximately 600 MWs of new storage capacity is planned through 2023. The transmission
investments included in the Energy Vision 2020, as part of the Energy Gateway Transmission expansion program, includes plans to
construct the 140-mile, 500kV transmission line between Aeolus Substation near Medicine Bow in Wyoming and Jim Bridger
generating facility that is expected to be placed in-service in 2020.
During the year, PacifiCorp placed into service the 29-mile high-voltage McNary-Wallula transmission line. Refer to pages 424-425,
Transmission lines added or altered during the year in this Form No. 1 for additional information regarding transmission lines added
or removed during the year ended December 31, 2019.
ITEM 6.
Short-term Debt
Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of December 31, 2019, PacifiCorp had $130 million of
short-term debt outstanding at a weighted average interest rate of 2.05%.
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 ("FERC") – Docket No. ES18-3-000, dated December 20, 2017, letter order
effective January 1, 2018 through December 31, 2019 and Docket No. ES20-1-000, dated December 12, 2019, letter order
effective January 1, 2020 through December 31, 2021.
Idaho Public Utilities Commission ("IPUC") – Case No. PAC-E-16-03, Order No. 33476, dated March 4, 2016, effective
through April 30, 2021.
Oregon Public Utility Commission ("OPUC") – Docket No. UF-4120, Order No. 98-158, dated April 16, 1998.
Washington Utilities and Transportation Commission ("WUTC") – Docket No. UE-980404, dated April 8, 1998.
For further discussion, refer to Note 7 of Notes to Financial Statements in this Form No. 1.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.2
Long-term Debt
In April 2020, PacifiCorp issued $400 million of its 2.70% First Mortgage Bonds due September 2030 and $600 million of its 3.30%
First Mortgage Bonds due March 2051. PacifiCorp intends to use the net proceeds to fund capital expenditures, primarily for
renewable resources and associated transmission projects and for general corporate purposes.
In March 2019, PacifiCorp issued $400 million of its 3.50% First Mortgage Bonds due June 2029 and $600 million of its 4.15% First
Mortgage Bonds due February 2050. PacifiCorp used a portion of the net proceeds to repay the short-term debt that was partially
incurred in January 2019 to repay all of PacifiCorp's $350 million, 5.50% First Mortgage Bonds due January 2019. PacifiCorp used
the remaining net proceeds to fund capital expenditures and for general corporate purposes.
As of December 31, 2019, PacifiCorp had authorization from the OPUC and the 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. Also, as of December 31, 2019, PacifiCorp
had an effective shelf registration statement with the United States Securities and Exchange Commission to issue up to $1.0 billion
additional first mortgage bonds through October 2021.
State commission authorizations for the above issuance are as follows:
IPUC – Case No. PAC-E-18-10, Order No. 34205, dated December 7, 2018, effective through September 30, 2023.
OPUC – Docket No. UF-4304, Order No. 18-452, dated December 4, 2018.
PacifiCorp must make a notice filing with the WUTC prior to any future issuance.
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,
2019, PacifiCorp estimated it would be able to issue up to $10.8 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 further 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 of the mortgage on the basis of property additions, bond credits or deposits of cash.
In 2019, PacifiCorp completed a re-offering of variable rate pollution control bond obligations totaling $168 million, involving the
cancellation, at PacifiCorp's request, of $170 million of letters of credit support by the issuing banks. As a result, PacifiCorp's credit
facility support for outstanding variable rate pollution control bond obligations increased by $168 million.
For further discussion, refer to Note 8 of Notes to Financial Statements in this Form No. 1.
ITEM 7.
None.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.3
ITEM 8.
For the year ended December 31, 2019, PacifiCorp's bargaining unit wage scale changes were as follows:
Unions Represented % Increase(1)Effective Date(s)
Estimated Annual
Financial Impact(2)
IBEW 57 Combustion Turbine (UT) 2.33% 01/26/2019 $ 71,496
IBEW 57 Laramie (WY) 1.29% 06/26/2019 9,461
IBEW 57 Power Delivery (UT, ID & WY) 2.29% 01/26/2019 1,878,830
IBEW 57 Power Supply (UT, ID & WY) 2.33% 01/26/2019 860,494
IBEW 125 (OR, WA) 2.63% 09/11/2019 24,851
IBEW 659 (OR, CA) 1.71% 04/26/2019 522,295
IBEW 659 (OR, CA) 2.84% 08/11/2019 609,544
IBEW 77 (WA) 2.09% 01/26/2019 22,593
UWUA 127 (WY) 0.60% 09/26/2019 283,860
UWUA 197 (OR) 1.51% 05/26/2019 23,035
UWUA 197 (OR) 1.55% 09/11/2019 441,568
Total $4,748,027
(1) This percentage increase represents the increase in wages from the effective date of the increase to the end of the calendar year as compared to the wage scale
of the 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 14 of Notes to Financial Statements in this Form No. 1 for information regarding certain legal proceedings affecting
PacifiCorp.
ITEM 10.
For the year ended December 31, 2019, Fossil Rock Fuels, LLC, a wholly owned subsidiary of PacifiCorp, distributed $5.1 million of
dividends, consisting of $2.4 million unappropriated retained earnings distribution and $2.7 million return of capital to PacifiCorp.
Refer to page 429, Transactions with associated (affiliated) companies in this Form No. 1 for information regarding related-party
transactions.
There have been no officer, director or security holder transactions during the year ended December 31, 2019, other than preferred
and common stock dividends declared and paid.
ITEM 11.
(Reserved.)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.4
ITEM 12.
In July 2019, PacifiCorp completed a transaction with Eugene Water & Electric Board to acquire the remaining undivided interest in
the Foote Creek I joint-owned wind generating facility and terminate a power purchase agreement with a third-party. In August 2019,
PacifiCorp filed a notice of the transaction with the Wyoming Public Service Commission who approved PacifiCorp's application for
a certificate of public convenience and necessity in April 2019 (Docket No. 20000-553-EN-19, Record No. 15202) requesting to
repower the existing Foote Creek I wind facility.
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.
ITEM 14.
Not applicable.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.5
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
PacifiCorp / /2019/Q4
UTILITY PLANT 1
28,843,430,112 28,425,063,446200-201Utility Plant (101-106, 114) 2
2,002,448,524 1,194,168,876200-201Construction Work in Progress (107) 3
30,845,878,636 29,619,232,322TOTAL Utility Plant (Enter Total of lines 2 and 3) 4
10,870,776,722 11,032,877,405200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5
19,975,101,914 18,586,354,917Net Utility Plant (Enter Total of line 4 less 5) 6
0 0202-203Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 7
0 0Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 8
0 0Nuclear Fuel Assemblies in Reactor (120.3) 9
0 0Spent Nuclear Fuel (120.4) 10
0 0Nuclear Fuel Under Capital Leases (120.6) 11
0 0202-203(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 12
0 0Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 13
19,975,101,914 18,586,354,917Net Utility Plant (Enter Total of lines 6 and 13) 14
0 0Utility Plant Adjustments (116) 15
0 0Gas Stored Underground - Noncurrent (117) 16
OTHER PROPERTY AND INVESTMENTS 17
13,320,639 13,578,986Nonutility Property (121) 18
3,196,879 3,149,894(Less) Accum. Prov. for Depr. and Amort. (122) 19
69,928 69,928Investments in Associated Companies (123) 20
201,902,001 183,401,017224-225Investment in Subsidiary Companies (123.1) 21
(For Cost of Account 123.1, See Footnote Page 224, line 42) 22
0 0228-229Noncurrent Portion of Allowances 23
102,845,814 95,479,061Other Investments (124) 24
0 0Sinking Funds (125) 25
0 0Depreciation Fund (126) 26
0 0Amortization Fund - Federal (127) 27
36,427,872 14,919,564Other Special Funds (128) 28
0 0Special Funds (Non Major Only) (129) 29
2,278,492 2,565,604Long-Term Portion of Derivative Assets (175) 30
0 0Long-Term Portion of Derivative Assets – Hedges (176) 31
353,647,867 306,864,266TOTAL Other Property and Investments (Lines 18-21 and 23-31) 32
CURRENT AND ACCRUED ASSETS 33
0 0Cash and Working Funds (Non-major Only) (130) 34
10,421,766 20,006,166Cash (131) 35
0 0Special Deposits (132-134) 36
0 0Working Fund (135) 37
11,969,487 49,330,121Temporary Cash Investments (136) 38
2,405,884 5,068,150Notes Receivable (141) 39
420,564,473 426,619,902Customer Accounts Receivable (142) 40
30,462,387 48,930,705Other Accounts Receivable (143) 41
7,644,908 7,691,154(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42
0 0Notes Receivable from Associated Companies (145) 43
795,724 628,710Accounts Receivable from Assoc. Companies (146) 44
150,404,985 179,588,705227Fuel Stock (151) 45
0 0227Fuel Stock Expenses Undistributed (152) 46
0 0227Residuals (Elec) and Extracted Products (153) 47
244,022,924 237,694,431227Plant Materials and Operating Supplies (154) 48
0 0227Merchandise (155) 49
0 0227Other Materials and Supplies (156) 50
0 0202-203/227Nuclear Materials Held for Sale (157) 51
0 0228-229Allowances (158.1 and 158.2) 52
FERC FORM NO. 1 (REV. 12-03) Page 110
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
PacifiCorp / /2019/Q4
(Continued)
0 0(Less) Noncurrent Portion of Allowances 53
0 0227Stores Expense Undistributed (163) 54
0 0Gas Stored Underground - Current (164.1) 55
0 0Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 56
62,585,511 48,020,660Prepayments (165) 57
0 0Advances for Gas (166-167) 58
0 0Interest and Dividends Receivable (171) 59
924,623 1,128,478Rents Receivable (172) 60
244,728,000 229,061,000Accrued Utility Revenues (173) 61
0 0Miscellaneous Current and Accrued Assets (174) 62
13,451,134 27,458,631Derivative Instrument Assets (175) 63
2,278,492 2,565,604(Less) Long-Term Portion of Derivative Instrument Assets (175) 64
0 0Derivative Instrument Assets - Hedges (176) 65
0 0(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 66
1,182,813,498 1,263,278,901Total Current and Accrued Assets (Lines 34 through 66) 67
DEFERRED DEBITS 68
33,683,227 29,412,802Unamortized Debt Expenses (181) 69
0 0230aExtraordinary Property Losses (182.1) 70
0 0230bUnrecovered Plant and Regulatory Study Costs (182.2) 71
1,119,161,023 1,107,326,144232Other Regulatory Assets (182.3) 72
576,164 477,354Prelim. Survey and Investigation Charges (Electric) (183) 73
0 0Preliminary Natural Gas Survey and Investigation Charges 183.1) 74
0 0Other Preliminary Survey and Investigation Charges (183.2) 75
0 0Clearing Accounts (184) 76
-14,358 26,188Temporary Facilities (185) 77
114,194,930 83,176,009233Miscellaneous Deferred Debits (186) 78
0 0Def. Losses from Disposition of Utility Plt. (187) 79
0 0352-353Research, Devel. and Demonstration Expend. (188) 80
3,971,176 4,554,871Unamortized Loss on Reaquired Debt (189) 81
783,561,636 824,459,612234Accumulated Deferred Income Taxes (190) 82
0 0Unrecovered Purchased Gas Costs (191) 83
2,055,133,798 2,049,432,980Total Deferred Debits (lines 69 through 83) 84
23,566,697,077 22,205,931,064TOTAL ASSETS (lines 14-16, 32, 67, and 84) 85
FERC FORM NO. 1 (REV. 12-03) Page 111
Schedule Page: 110 Line No.: 77 Column: c
The credit balance represents a timing difference between work incurred and advances
received from customers.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Year/Period of ReportName of Respondent This Report is:
(1) An Original
(2) A Resubmission
x
Date of Report
(mo, da, yr)
end of
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
PacifiCorp / /2019/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
PROPRIETARY CAPITAL 1
3,417,945,8963,417,945,896Common Stock Issued (201) 2 250-251
2,397,6002,397,600Preferred Stock Issued (204) 3 250-251
00Capital Stock Subscribed (202, 205) 4
00Stock Liability for Conversion (203, 206) 5
00Premium on Capital Stock (207) 6
1,102,063,9561,102,063,956Other Paid-In Capital (208-211) 7 253
00Installments Received on Capital Stock (212) 8 252
00(Less) Discount on Capital Stock (213) 9 254
41,101,06141,101,061(Less) Capital Stock Expense (214) 10 254b
3,271,969,5003,846,833,944Retained Earnings (215, 215.1, 216) 11 118-119
104,399,245125,565,229Unappropriated Undistributed Subsidiary Earnings (216.1) 12 118-119
00(Less) Reaquired Capital Stock (217) 13 250-251
00 Noncorporate Proprietorship (Non-major only) (218) 14
-12,635,042-15,916,633Accumulated Other Comprehensive Income (219) 15 122(a)(b)
7,845,040,0948,437,788,931Total Proprietary Capital (lines 2 through 15) 16
LONG-TERM DEBT 17
7,055,275,0007,705,275,000Bonds (221) 18 256-257
00(Less) Reaquired Bonds (222) 19 256-257
00Advances from Associated Companies (223) 20 256-257
00Other Long-Term Debt (224) 21 256-257
36,02224,996Unamortized Premium on Long-Term Debt (225) 22
10,793,80713,445,289(Less) Unamortized Discount on Long-Term Debt-Debit (226) 23
7,044,517,2157,691,854,707Total Long-Term Debt (lines 18 through 23) 24
OTHER NONCURRENT LIABILITIES 25
18,996,63027,046,124Obligations Under Capital Leases - Noncurrent (227) 26
8,591,84110,159,611Accumulated Provision for Property Insurance (228.1) 27
23,791,64121,850,505Accumulated Provision for Injuries and Damages (228.2) 28
190,648,668159,048,125Accumulated Provision for Pensions and Benefits (228.3) 29
34,600,45934,314,273Accumulated Miscellaneous Operating Provisions (228.4) 30
2,551,0621,500,000Accumulated Provision for Rate Refunds (229) 31
24,683,75622,833,300Long-Term Portion of Derivative Instrument Liabilities 32
00Long-Term Portion of Derivative Instrument Liabilities - Hedges 33
227,371,811256,476,842Asset Retirement Obligations (230) 34
531,235,868533,228,780Total Other Noncurrent Liabilities (lines 26 through 34) 35
CURRENT AND ACCRUED LIABILITIES 36
30,000,000130,000,000Notes Payable (231) 37
523,289,313624,405,083Accounts Payable (232) 38
31,009,81760,042,489Notes Payable to Associated Companies (233) 39
136,903,471136,335,569Accounts Payable to Associated Companies (234) 40
49,781,90244,331,534Customer Deposits (235) 41
48,581,84771,717,476Taxes Accrued (236) 42 262-263
114,623,111117,354,090Interest Accrued (237) 43
40,47540,475Dividends Declared (238) 44
00Matured Long-Term Debt (239) 45
FERC FORM NO. 1 (rev. 12-03) Page 112
Year/Period of ReportName of Respondent This Report is:
(1) An Original
(2) A Resubmission
x
Date of Report
(mo, da, yr)
end of
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
PacifiCorp / /2019/Q4
(continued)COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
00Matured Interest (240) 46
20,623,59721,382,035Tax Collections Payable (241) 47
74,069,12282,553,117Miscellaneous Current and Accrued Liabilities (242) 48
1,788,6343,979,527Obligations Under Capital Leases-Current (243) 49
65,799,90729,690,179Derivative Instrument Liabilities (244) 50
24,683,75622,833,300(Less) Long-Term Portion of Derivative Instrument Liabilities 51
00Derivative Instrument Liabilities - Hedges (245) 52
00(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 53
1,071,827,4401,298,998,274Total Current and Accrued Liabilities (lines 37 through 53) 54
DEFERRED CREDITS 55
76,528,076100,135,630Customer Advances for Construction (252) 56
13,313,77711,203,507Accumulated Deferred Investment Tax Credits (255) 57 266-267
00Deferred Gains from Disposition of Utility Plant (256) 58
202,519,682201,430,606Other Deferred Credits (253) 59 269
2,044,239,9061,930,223,376Other Regulatory Liabilities (254) 60 278
00Unamortized Gain on Reaquired Debt (257) 61
180,339,430174,829,838Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277
2,910,580,0662,889,829,879Accum. Deferred Income Taxes-Other Property (282) 63
285,789,510297,173,549Accum. Deferred Income Taxes-Other (283) 64
5,713,310,4475,604,826,385Total Deferred Credits (lines 56 through 64) 65
22,205,931,06423,566,697,077TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 66
FERC FORM NO. 1 (rev. 12-03) Page 113
Schedule Page: 112 Line No.: 39 Column: c
Represents amounts due to Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp,
pursuant to an umbrella loan agreement for which the interest rate is determined daily and
is equal to the lowest cost of short-term borrowings PacifiCorp could otherwise incur
externally. At December 31, 2019, the interest rate on the outstanding loan balance was
2.05%.
Schedule Page: 112 Line No.: 39 Column: d
Represents amounts due to Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp,
pursuant to an umbrella loan agreement for which the interest rate is determined daily and
is equal to the lowest cost of short-term borrowings PacifiCorp could otherwise incur
externally. At December 31, 2018, the interest rate on the outstanding loan balance was
2.85%.
Schedule Page: 112 Line No.: 42 Column: c
As of December 31, 2019, Account 236, Taxes accrued, included $28,316,216 of income taxes
payable to Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.
Schedule Page: 112 Line No.: 42 Column: d
As of December 31, 2018, Account 236, Taxes accrued, included $4,894,465 of income taxes
payable to Berkshire Hathaway Energy Company, PacifiCorp's indirect parent company.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF INCOME
PacifiCorp X
/ /2019/Q4
Line
(c)(b)(a)
Title of Account
No.
Total
Current Year to
Date Balance for
Quarter/Year
(d)
(Ref.)
Page No.
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 (j) the quarter to date amounts for gas utility, and in column (l) the
quarter to date amounts for other utility function for the prior year quarter.
5. If additional columns are needed, place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
Total
Prior Year to
Date Balance for
Quarter/Year
UTILITY OPERATING INCOME 1
5,065,712,793 5,090,358,956300-301Operating Revenues (400) 2
Operating Expenses 3
2,427,820,299 2,470,313,861320-323Operation Expenses (401) 4
404,986,660 413,932,883320-323Maintenance Expenses (402) 5
879,989,526 908,461,901336-337Depreciation Expense (403) 6
336-337Depreciation Expense for Asset Retirement Costs (403.1) 7
49,689,883 46,883,718336-337Amort. & Depl. of Utility Plant (404-405) 8
5,083,195 5,083,195336-337Amort. of Utility Plant Acq. Adj. (406) 9
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10
Amort. of Conversion Expenses (407) 11
148,092 150,275Regulatory Debits (407.3) 12
(Less) Regulatory Credits (407.4) 13
199,137,026 201,255,354262-263Taxes Other Than Income Taxes (408.1) 14
151,665,847 162,384,813262-263Income Taxes - Federal (409.1) 15
34,920,585 41,626,061262-263 - Other (409.1) 16
1,188,782,866 450,529,508234, 272-277Provision for Deferred Income Taxes (410.1) 17
1,311,969,270 648,977,032234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.1) 18
-2,738,724 -3,152,015266Investment Tax Credit Adj. - Net (411.4) 19
(Less) Gains from Disp. of Utility Plant (411.6) 20
Losses from Disp. of Utility Plant (411.7) 21
173 181(Less) Gains from Disposition of Allowances (411.8) 22
Losses from Disposition of Allowances (411.9) 23
Accretion Expense (411.10) 24
4,027,515,812 4,048,492,341TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25
1,038,196,981 1,041,866,615Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 26
FERC FORM NO. 1/3-Q (REV. 02-04) Page 114
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF INCOME FOR THE YEAR (Continued)
PacifiCorp X
/ /2019/Q4
Line Previous Year to Date
(in dollars)
(k)(j)(g)
ELECTRIC UTILITY
No.Current Year to Date
(in dollars)
OTHER UTILITY
(l)
GAS UTILITY
Previous Year to Date
(in dollars)
Current Year to Date
(in dollars)
Previous Year to Date
(in dollars)
Current Year to Date
(in dollars)
(h) (i)
9. Use page 122 for important notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the
gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the
utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accounts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
1
5,065,712,793 5,090,358,956 2
3
2,427,820,299 2,470,313,861 4
404,986,660 413,932,883 5
879,989,526 908,461,901 6
7
49,689,883 46,883,718 8
5,083,195 5,083,195 9
10
11
148,092 150,275 12
13
199,137,026 201,255,354 14
151,665,847 162,384,813 15
34,920,585 41,626,061 16
1,188,782,866 450,529,508 17
1,311,969,270 648,977,032 18
-2,738,724 -3,152,015 19
20
21
173 181 22
23
24
4,027,515,812 4,048,492,341 25
1,038,196,981 1,041,866,615 26
FERC FORM NO. 1 (ED. 12-96) Page 115
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF INCOME FOR THE YEAR (continued)
PacifiCorp X
/ /2019/Q4
Line
Previous Year
(c)(b)(a)
Title of Account
No.
Current Year
TOTAL
(d)
(Ref.)
Page No.
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
1,038,196,981 1,041,866,615Net Utility Operating Income (Carried forward from page 114) 27
Other Income and Deductions 28
Other Income 29
Nonutilty Operating Income 30
2,141,746 1,500,711Revenues From Merchandising, Jobbing and Contract Work (415) 31
2,120,904 1,372,254(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32
Revenues From Nonutility Operations (417) 33
263,038 79,216(Less) Expenses of Nonutility Operations (417.1) 34
196,104 275,014Nonoperating Rental Income (418) 35
23,563,311 20,869,978119Equity in Earnings of Subsidiary Companies (418.1) 36
18,097,499 14,250,874Interest and Dividend Income (419) 37
72,317,120 34,835,895Allowance for Other Funds Used During Construction (419.1) 38
6,570,592 -728,378Miscellaneous Nonoperating Income (421) 39
3,595,254 939,906Gain on Disposition of Property (421.1) 40
124,097,684 70,492,530TOTAL Other Income (Enter Total of lines 31 thru 40) 41
Other Income Deductions 42
200,037 88,035Loss on Disposition of Property (421.2) 43
1,330,948 1,329,336Miscellaneous Amortization (425) 44
2,342,288 2,387,899 Donations (426.1) 45
-8,140,640 -3,252,632 Life Insurance (426.2) 46
-1,272,934 1,112,093 Penalties (426.3) 47
1,092,950 1,239,589 Exp. for Certain Civic, Political & Related Activities (426.4) 48
34,550,630 7,940,472 Other Deductions (426.5) 49
30,103,279 10,844,792TOTAL Other Income Deductions (Total of lines 43 thru 49) 50
Taxes Applic. to Other Income and Deductions 51
350,102 340,043262-263Taxes Other Than Income Taxes (408.2) 52
-2,461,788 1,079,374262-263Income Taxes-Federal (409.2) 53
-557,526 243,788262-263Income Taxes-Other (409.2) 54
63,463,964 109,004,879234, 272-277Provision for Deferred Inc. Taxes (410.2) 55
62,277,453 109,467,521234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.2) 56
Investment Tax Credit Adj.-Net (411.5) 57
352,431 236,733(Less) Investment Tax Credits (420) 58
-1,835,132 963,830TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59
95,829,537 58,683,908Net Other Income and Deductions (Total of lines 41, 50, 59) 60
Interest Charges 61
369,853,259 358,695,455Interest on Long-Term Debt (427) 62
3,892,240 4,027,405Amort. of Debt Disc. and Expense (428) 63
583,695 584,922Amortization of Loss on Reaquired Debt (428.1) 64
11,026 11,026(Less) Amort. of Premium on Debt-Credit (429) 65
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 66
177,870 69,069Interest on Debt to Assoc. Companies (430) 67
24,622,419 17,922,378Other Interest Expense (431) 68
36,284,269 18,446,680(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69
362,834,188 362,841,523Net Interest Charges (Total of lines 62 thru 69) 70
771,192,330 737,709,000Income Before Extraordinary Items (Total of lines 27, 60 and 70) 71
Extraordinary Items 72
Extraordinary Income (434) 73
(Less) Extraordinary Deductions (435) 74
Net Extraordinary Items (Total of line 73 less line 74) 75
262-263Income Taxes-Federal and Other (409.3) 76
Extraordinary Items After Taxes (line 75 less line 76) 77
771,192,330 737,709,000Net Income (Total of line 71 and 77) 78
FERC FORM NO. 1/3-Q (REV. 02-04) Page 117
Schedule Page: 114 Line No.: 6 Column: c
Depreciation expense associated with transportation equipment is generally charged to
operations and maintenance expense and construction work in progress. During the years
ended December 31, 2019 and 2018, depreciation expense associated with transportation
equipment was $16,386,376 and $15,829,896, respectively.
Schedule Page: 114 Line No.: 7 Column: c
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as
either a regulatory asset or liability.
Schedule Page: 114 Line No.: 14 Column: c
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress. During the years ended December 31, 2019 and 2018, payroll taxes were
$40,623,353 and $39,770,569, respectively.
Schedule Page: 114 Line No.: 24 Column: c
Generally, PacifiCorp records the accretion expense of asset retirement obligations as
either a regulatory asset or liability.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF RETAINED EARNINGS
PacifiCorp X
/ /
2019/Q4
Line
Current
Quarter/Year
Year to Date
Balance
(c)(b)(a)
Item
Contra Primary
No.
Account Affected
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436 -
439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Previous
Quarter/Year
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
2,948,638,352 3,227,391,376 1 Balance-Beginning of Period
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)
716,839,022 747,629,019 16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
( 8,732,124) -4,236,163215.1 18 Appropriation of excess earnings at certain hydroelectric generating facilities
19
20
21
( 8,732,124) -4,236,163 22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
( 161,902) -161,902238 24 Preferred Stock, various series and rates
25
26
27
28
( 161,902) -161,902 29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
( 450,000,000) -175,000,000238 31 Common Stock
32
33
34
35
( 450,000,000) -175,000,000 36 TOTAL Dividends Declared-Common Stock (Acct. 438)
20,808,028 2,397,327216.1 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
3,227,391,376 3,798,019,657 38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
39
40
FERC FORM NO. 1/3-Q (REV. 02-04)Page 118
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF RETAINED EARNINGS
PacifiCorp X
/ /
2019/Q4
Line
Current
Quarter/Year
Year to Date
Balance
(c)(b)(a)
Item
Contra Primary
No.
Account Affected
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436 -
439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Previous
Quarter/Year
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)
44,578,124 48,814,287 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
44,578,124 48,814,287 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
3,271,969,500 3,846,833,944 48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
104,337,295 104,399,245 49 Balance-Beginning of Year (Debit or Credit)
20,869,978 23,563,311 50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
( 20,808,028) -2,397,327 52 Transfers to/from Unappropriated Retained Earnings (Account 216)
104,399,245 125,565,229 53 Balance-End of Year (Total lines 49 thru 52)
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
Schedule Page: 118 Line No.: 24 Column: c
Outstanding shares of preferred stock as of December 31, 2019 and declared dividends on
preferred stock during the year ended December 31, 2019 were as follows:
Shares Dividend
6.00% Serial Preferred 5,930 $ 35,580
7.00% Serial Preferred 18,046 126,322
23,976 $161,902
Schedule Page: 118 Line No.: 24 Column: d
Outstanding shares of preferred stock as of December 31, 2018 and declared dividends on
preferred stock during the year ended December 31, 2018 were as follows:
Shares Dividend
6.00% Serial Preferred 5,930 $ 35,580
7.00% Serial Preferred 18,046 126,322
23,976 $161,902
Schedule Page: 118 Line No.: 37 Column: c
During the year ended December 31, 2019, paid distributions from subsidiaries of
PacifiCorp were as follows:
Fossil Rock Fuels, LLC 2,397,000
Trapper Mining Inc. 327
$ 2,397,327
Schedule Page: 118 Line No.: 37 Column: d
During the year ended December 31, 2018, paid distributions from subsidiaries of
PacifiCorp were as follows:
Pacific Minerals, Inc. $18,000,000
Fossil Rock Fuels, LLC 2,663,000
Trapper Mining Inc. 145,028
$20,808,028
Schedule Page: 118 Line No.: 46 Column: c
The balance in Account 215.1, Appropriated retained earnings - Amortization reserve,
Federal, is due to requirements of certain hydroelectric relicensing projects.
Schedule Page: 118 Line No.: 46 Column: d
The balance in Account 215.1, Appropriated retained earnings - Amortization reserve,
Federal, is due to requirements of certain hydroelectric relicensing projects.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and
Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be
reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes
to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of
the dollar amount of leases capitalized with the plant cost.
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF CASH FLOWS
PacifiCorp X
/ /2019/Q4
Line Description (See Instruction No. 1 for Explanation of Codes)Current Year to Date
Quarter/Year
(b)(a)No.
Previous Year to Date
Quarter/Year
(c)
1 Net Cash Flow from Operating Activities:
737,709,000 771,192,330 2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
926,028,121 897,855,483 4 Depreciation and Depletion
53,322,235 56,127,827 5 Amortization:
6
7
-198,910,166 -121,999,893 8 Deferred Income Taxes (Net)
-3,388,748 -3,091,155 9 Investment Tax Credit Adjustment (Net)
22,276,393 -1,814,992 10 Net (Increase) Decrease in Receivables
15,493,125 22,855,227 11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
88,063,038 -9,920,410 13 Net Increase (Decrease) in Payables and Accrued Expenses
-19,930,064 -64,974,675 14 Net (Increase) Decrease in Other Regulatory Assets
107,413,446 9,960,664 15 Net Increase (Decrease) in Other Regulatory Liabilities
34,835,895 72,317,120 16 (Less) Allowance for Other Funds Used During Construction
61,950 21,165,984 17 (Less) Undistributed Earnings from Subsidiary Companies
69,557,216 22,900,991 18 Amounts Due To/From Affiliates (Net)
14,900,000 12,400,000 19 Derivative Collateral (Net)
4,701,781 19,842,961 20 Other Operating Activities:
21
1,782,337,532 1,517,851,254 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
-1,291,567,102 -2,247,610,148 26 Gross Additions to Utility Plant (less nuclear fuel)
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
-34,835,895 -72,317,120 30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33
-1,256,731,207 -2,175,293,028 34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
4,229,118 7,608,830 37 Proceeds from Disposal of Noncurrent Assets (d)
38
39 Investments in and Advances to Assoc. and Subsidiary Companies
2,668,000 2,665,000 40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
FERC FORM NO. 1 (ED. 12-96) Page 120
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and
Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be
reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes
to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of
the dollar amount of leases capitalized with the plant cost.
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF CASH FLOWS
PacifiCorp X
/ /2019/Q4
Line Description (See Instruction No. 1 for Explanation of Codes)Current Year to Date
Quarter/Year
(b)(a)No.
Previous Year to Date
Quarter/Year
(c)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (Increase) Decrease in Receivables
50 Net (Increase ) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accrued Expenses
-2,495,368 733,463 53 Other Investing Activities:
54
55
56 Net Cash Provided by (Used in) Investing Activities
-1,252,329,457 -2,164,285,735 57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
593,102,815 989,337,013 61 Long-Term Debt (b)
62 Preferred Stock
63 Common Stock
64 Other (provide details in footnote):
65
99,950,000 66 Net Increase in Short-Term Debt (c)
22,000,000 29,000,000 67 Other (provide details in footnote):
68
69
615,102,815 1,118,287,013 70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
-586,200,000 -350,000,000 73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
-1,118,205 -802,544 76 Other (provide details in footnote):
-1,736,324 -1,479,581 77 Repayment of Finance Lease Principal in Capital Lease Obligations
-50,000,347 78 Net Decrease in Short-Term Debt (c)
79
-161,902 -161,902 80 Dividends on Preferred Stock
-450,000,000 -175,000,000 81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
-474,113,963 590,842,986 83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
55,894,112 -55,591,495 86 (Total of lines 22,57 and 83)
87
28,361,739 84,255,851 88 Cash and Cash Equivalents at Beginning of Period
89
84,255,851 28,664,356 90 Cash and Cash Equivalents at End of period
FERC FORM NO. 1 (ED. 12-96) Page 121
Schedule Page: 120 Line No.: 4 Column: b
Includes depreciation expense associated with transportation equipment and finance lease
assets of $17,865,957 and $17,566,220, during the years ended December 31, 2019 and 2018,
respectively.
Schedule Page: 120 Line No.: 5 Column: a
Years Ended December 31,
2019 2018
Amortization of software development & other intangibles $ 51,020,831 $ 48,213,054
Amortization of electric plant acquisition adjustments 5,083,195 5,083,195
Amortization of a regulatory asset 23,801 25,986
$ 56,127,827 $ 53,322,235
Schedule Page: 120 Line No.: 20 Column: a
Years Ended December 31,
2019 2018
Depreciation and depletion included in cost of fuel $ 2,078,082 $ 2,076,162
Net gain on sale of property (4,186,776) (955,310)
Write-off of assets under construction 6,610,739 1,903,891
Costs associated with the early retirement of Cholla
Unit No. 4 generating facility 23,431,738
Change in corporate owned life insurance cash surrender
value (8,109,131) (3,241,715)
Amortization of debt issuance expenses and bond
discount/premium 3,881,214 4,016,379
Changes in derivative contract assets/liabilities, net (822,620) (941,213)
Other (3,040,285) 1,843,587
$ 19,842,961 $ 4,701,781
Schedule Page: 120 Line No.: 37 Column: b
Represents proceeds from the disposal of fixed assets.
Schedule Page: 120 Line No.: 37 Column: c
Represents proceeds from the disposal of fixed assets.
Schedule Page: 120 Line No.: 53 Column: a
Years Ended December 31,
2019 2018
Other investments/special funds $ 915,947 $ 1,986,133
Investment in long-term incentive plan securities (182,484) (4,481,501)
$ 733,463 $ (2,495,368)
Schedule Page: 120 Line No.: 67 Column: a
Net proceeds of affiliate borrowing from subsidiary company, Pacific Minerals, Inc.

Schedule Page: 120 Line No.: 76 Column: a
Other deferred financing costs
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report Year/Period of Report
End of
NOTES TO FINANCIAL STATEMENTS
PacifiCorp X / /2019/Q4
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a
claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on
cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an
explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters
shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
FERC FORM NO. 1 (ED. 12-96) Page 122
PACIFICORP
NOTES TO FINANCIAL STATEMENTS
(1) 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 California. 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.
Investments in Subsidiaries
In accordance with FERC Order No. AC11-132-000, PacifiCorp accounts for its investment in subsidiaries using the equity
method for FERC reporting purposes rather than consolidating the assets, liabilities, revenues and expenses of subsidiaries 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. AC11-132-000, 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 provision for depreciation under the FERC accounting and reporting standards.
Income Taxes
Accumulated deferred 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 between FERC and GAAP
for amounts related to unrecognized tax benefits associated with temporary differences in accordance with FERC guidance.
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 under the FERC accounting and reporting standards.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.1
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 guidance, 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 of net 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.
Accounting for 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 deferrals, which will be recognized in earnings in the periods the corresponding 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 ability 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 recognized in net income, returned to customers or
re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value 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. Adjustments 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.2
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 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):
2019 2018
Cash (131) $ 10 $ 20
Other special funds (128) 7 15
Temporary cash investments (136) 12 49
Total cash and cash equivalents and restricted cash and cash equivalents $29 $84
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 December 31, 2019 and 2018,
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 earnings.
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. As of
December 31, 2019 and 2018, the allowance for doubtful accounts totaled $8 million, which is included in accumulated provision for
uncollectible accounts on the Comparative Balance Sheet.
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 qualify 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.
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 revenue or operating expenses on the Statement of Income.
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 of inclusion in rates, changes in the fair value are recognized
in earnings.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.3
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 Utility 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
of the 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
ultimately 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 construction 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 permitted to earn a return on these costs as a
component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
Asset 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 satisfy such liabilities is recorded as
a regulatory asset or liability.
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 occurrence 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
of regulated assets.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.4
Leases
PacifiCorp has non-cancelable operating leases primarily for land, office space, office equipment, and generating facilities and
finance leases consisting primarily of office buildings, natural gas pipeline facilities, and generating facilities. These leases generally
require PacifiCorp to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of
the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets,
in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset.
Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices.
PacifiCorp does not include options in its lease calculations unless there is a triggering event indicating PacifiCorp is reasonably
certain to exercise the option. PacifiCorp's accounting policy is to not recognize lease obligations and corresponding right-of-use
assets for leases with contract terms of one year or less and not separate lease components from non-lease components and instead
account for each separate lease component and the non-lease components associated with a lease as a single lease component.
Right-of-use assets will be evaluated for impairment in accordance with GAAP when a triggering event has occurred that might affect
the value and use of the assets being leased.
PacifiCorp's leases of generating facilities generally are in the form of long-term purchases of electricity, also known as power
purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a
lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable
lease payments as they are based on the amount of output.
PacifiCorp follows FERC accounting and reporting requirements and records operating and finance right-of-use assets in Account
101.1, Property under capital leases, and the current and noncurrent operating and finance lease liabilities are recorded in Account
243, Obligations under capital leases – Current and Account 227, Obligations under capital leases – Noncurrent, respectively.
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
commissions. 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 of contractual 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 return. Consistent with established regulatory
practice, PacifiCorp's provision for income taxes has been computed on a stand-alone basis.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.5
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 of the related properties or as prescribed by
various regulatory commissions.
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 Accounting Pronouncements
On November 21, 2019, the FERC issued Order 864, "Public Utility Transmission Rate Changes to Address Accumulated Deferred
Income Taxes" requiring public utility transmission providers with transmission rates under an Open Access Transmission Tariff to
account for changes caused by the Tax Cuts and Jobs Act, enacted on December 22, 2017 and effective January 1, 2018 ("2017 Tax
Reform"). The FERC is requiring public utilities with transmission formula rates to include a mechanism in those transmission
formula rates to deduct any excess accumulated deferred income taxes ("ADIT") from or add any deficient ADIT to their rate bases.
Public utilities with transmission formula rates are also required to incorporate a mechanism to decrease or increase their income tax
allowances by any amortized excess or deficient ADIT, respectively. Finally, the FERC is requiring public utilities with transmission
formula rates to incorporate a new permanent worksheet into their transmission formula rates that will annually track information
related to excess or deficient ADIT. The FERC is requiring each public utility with transmission formula rates to submit a filing to
demonstrate compliance with the final rule, including revisions to its transmission formula rates, as necessary, within the later of (1)
30 days of the effective date of this ruling or (2) the public utility's next annual informational filing following the issuance of this
order. PacifiCorp is implementing the adoption of this guidance in its transmission rates under the Open Access Transmission Tariff
in FERC Docket No. ER11-3643, to be filed by May 15, 2020.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.6
In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02,
which creates FASB Accounting Standards Codification ("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 liability 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. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the
implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. PacifiCorp has elected to utilize
various practical expedients available to adopt ASU No. 2016-02, including (1) the package of three not requiring a reassessment of
(i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and
(iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment
of whether existing or expired land easements that were not previously accounted for as leases under ASC Topic 840 are or contain a
lease under ASC Topic 842. PacifiCorp adopted this guidance for all applicable contracts in effect as of January 1, 2019 under a
modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption. For FERC
reporting, PacifiCorp follows the accounting guidance for leases in accordance with FERC Order No. AI19-1-000, "Accounting and
Financial Reporting for Leases".
Subsequent Events
PacifiCorp has evaluated the impact of events occurring after December 31, 2019 up to February 21, 2020, the date that PacifiCorp's
GAAP financial statements were filed with the United States Securities and Exchange Commission and has updated such evaluation
for disclosure purposes through April 10, 2020. These financial statements include all necessary adjustments and disclosures resulting
from these evaluations.
(3) Net Utility Plant
The average depreciation and amortization rate applied to depreciable utility plant was 3.3% and 3.5% for the years ended
December 31, 2019 and 2018, respectively, including the impacts of accelerated depreciation for Oregon's share of certain wind
equipment retired as a result of wind repowering projects placed into service in 2019 and accelerated depreciation for Utah's share of
certain thermal plant units in 2018.
PacifiCorp filed a depreciation study in 2018 with all of its state public utility commissions, except the California Public Utilities
Commission. PacifiCorp is currently working with the commissions and interested parties and anticipates revised depreciation rates to
be effective January 1, 2021.
(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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.7
The amounts shown in the table below represent PacifiCorp's share in each jointly owned facility included in net utility plant, as of
December 31, 2019 (dollars in millions):
Facility Accumulated Construction
PacifiCorp in Depreciation and Work-in-
Share Service Amortization Progress
Jim Bridger Nos. 1 - 4 67 % $ 1,481 $ 693 $ 9
Hunter No. 1 94 484 188 1
Hunter No. 2 60 305 118 2
Wyodak 80 473 238 1
Colstrip Nos. 3 and 4 10 254 141 2
Hermiston 50 181 92 5
Craig Nos. 1 and 2 19 368 127 —
Hayden No. 1 25 75 40 —
Hayden No. 2 13 43 24 —
Transmission and distribution facilities Various 808 306 103
Total $4,472 $1,967 $123
(5) Leases
The following table summarizes PacifiCorp's leases recorded on the Comparative Balance Sheet (in millions):
As of
December 31, 2019
Right-of-use assets:
Operating leases $12
Finance leases 19
Total right-of-use assets $31
Lease liabilities:
Operating leases $12
Finance leases 19
Total lease liabilities $31
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.8
The following table summarizes PacifiCorp's lease costs (in millions):
Year Ended
December 31, 2019
Variable $ 77
Operating 3
Finance:
Amortization 1
Interest 2
Short-term 2
Total lease costs $85
Weighted-average remaining lease term (years):
Operating leases 14.0
Finance leases 9.1
Weighted-average discount rate:
Operating leases 3.7%
Finance leases 10.6%
Cash payments associated with operating and finance lease liabilities approximated lease cost for the year ended December 31, 2019.
PacifiCorp has the following remaining lease commitments (in millions):
December 31, 2019
Operating Finance Total
2020 $2 $3 $5
2021 2 7 9
2022 2 3 5
2023 2 2 4
2024 1 2 3
Thereafter 7 14 21
Total undiscounted lease payments 16 31 47
Less - amounts representing interest (4)(12)(16)
Lease liabilities $12 $19 $31
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.9
(6) Regulatory Matters
Regulatory Assets
PacifiCorp had regulatory assets not earning a return on investment of $605 million and $631 million as of December 31, 2019 and
2018, respectively.
(7) Short-term Debt and Credit Facilities
The following table summarizes PacifiCorp's availability under its credit facilities as of December 31 (in millions):
2019:
Credit facilities $ 1,200
Less:
Short-term debt (130)
Tax-exempt bond support (256)
Net credit facilities $814
2018:
Credit facilities $ 1,200
Less:
Short-term debt (30)
Tax-exempt bond support (89)
Net credit facilities $1,081
As of December 31, 2019, PacifiCorp was in compliance with the covenants of its credit facilities and letter of credit arrangements.
PacifiCorp has a $600 million unsecured credit facility expiring in June 2022 and a $600 million unsecured credit facility expiring in
June 2022 with one remaining one-year extension option 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 of letters of credit, 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, 2019 and 2018, the weighted average interest rate on commercial paper borrowings outstanding was 2.05% and
2.85%, 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 of the last day of each quarter.
As of December 31, 2019 and 2018, PacifiCorp had $13 million and $184 million, respectively, of fully available letters of credit
issued under committed arrangements. As of December 31, 2019 and 2018, $13 million and $14 million, respectively, support certain
transactions required by third parties and generally 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.
(8) Long-term Debt
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.
In April 2020, PacifiCorp issued $400 million of its 2.70% First Mortgage Bonds due September 2030 and $600 million of its 3.30%
First Mortgage Bonds due March 2051. PacifiCorp intends to use the net proceeds to fund capital expenditures, primarily for
renewable resources and associated transmission projects and for general corporate purposes.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.10
In March 2019, PacifiCorp issued $400 million of its 3.50% First Mortgage Bonds due June 2029 and $600 million of its 4.15% First
Mortgage Bonds due February 2050. PacifiCorp used a portion of the net proceeds to repay the short-term debt that was partially
incurred in January 2019 to repay all of PacifiCorp's $350 million, 5.50% First Mortgage Bonds due January 2019. PacifiCorp used
the remaining net proceeds to fund capital expenditures and for general corporate purposes.
As of December 31, 2019, PacifiCorp had authorization 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
Washington Utilities and Transportation Commission ("WUTC") prior to any future issuance. Also, as of December 31, 2019,
PacifiCorp had an effective shelf registration statement filed with the United States Securities and Exchange Commission to issue up
to $1.0 billion additional first mortgage bonds through October 2021.
The issuance of PacifiCorp's first mortgage bonds is limited by available property, earnings tests and other provisions of PacifiCorp's
mortgage. Approximately $29 billion of PacifiCorp's eligible property (based on original cost) was subject to the lien of the mortgage
as of December 31, 2019.
As of December 31, 2019, the annual principal maturities of long-term debt for 2020 and thereafter, are as follows (in millions):
Long-term
Debt
2020 $ 38
2021 420
2022 605
2023 449
2024 591
Thereafter 5,602
Total 7,705
Unamortized discount (13)
Total $7,692
(9) Income Taxes
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
2019 2018
Current:
Federal $ 149 $ 163
State 34 42
Total 183 205
Deferred:
Federal (127) (190)
State 5 (9)
Total (122)(199)
Investment tax credits (3) (3)
Total income tax expense $58 $3
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.11
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 31:
2019 2018
Federal statutory income tax rate 21% 21%
State income taxes, net of federal income tax benefit 3 4
Amortization of excess deferred income taxes (11) (17)
Effects of ratemaking (2) —
Federal income tax credits (3) (7)
Other (1) (1)
Effective income tax rate 7%—%
Income tax credits relate primarily to production tax credits earned by PacifiCorp's wind-powered generating facilities. Federal
renewable electricity production tax credits are earned as energy from qualifying 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 for the credits for 10 years from the date the qualifying generating facilities are placed in-service. Amortization of excess
deferred income taxes is primarily attributable to the amortization of $91 million of Oregon allocated excess deferred income taxes
pursuant to the Oregon Renewable Adjustment Clause ("RAC") settlement, whereby a portion of Oregon allocated excess deferred
income taxes was used to accelerate depreciation on Oregon's share of certain repowered wind facilities. Amortization of excess
deferred income taxes in 2018 is primarily attributable to the amortization of $127 million of Utah allocated excess deferred income
taxes pursuant to a 2017 Tax Reform settlement approved by the Utah Public Service Commission, 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 31 (in millions):
2019 2018
Deferred income tax assets:
Regulatory liabilities $ 476 $ 503
Employee benefits 83 91
Derivative contracts and unamortized contract values 33 45
State carryforwards 70 77
Asset retirement obligations 61 53
Other 61 55
784 824
Deferred income tax liabilities:
Property, plant and equipment (3,065) (3,091)
Regulatory assets (276) (273)
Other (21)(12)
(3,362)(3,376)
Net deferred income tax liability $(2,578)$(2,552)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.12
The following table provides PacifiCorp's net operating loss and tax credit carryforwards and expiration dates as of December 31,
2019 (in millions):
State
Net operating loss carryforwards $ 1,140
Deferred income taxes on net operating loss carryforwards $ 51
Expiration dates 2023 - 2032
Tax credit carryforwards $ 19
Expiration dates 2020 - indefinite
The United States Internal Revenue Service has closed its examination of PacifiCorp's income tax returns through December 31,
2011. The statute of limitations for PacifiCorp's state income tax returns have expired through December 31, 2011, with the exception
of California, Utah and Oregon, for which the statutes have expired through December 31, 2009. In addition, Idaho's statute of
limitations has expired through December 31, 2015, 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.
2017 Tax Reform
2017 Tax Reform enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the United
States federal corporate income tax rate from 35% to 21%. In 2018, PacifiCorp agreed to refund or defer the impact of the tax law
change with each of its state regulatory commissions. Although PacifiCorp anticipated amortizing protected excess deferred income
taxes using the Average Rate Assumption Method as originally disclosed in its 2018 FERC Form No. 1, PacifiCorp will be using the
Reverse South Georgia Method to amortize protected excess deferred income taxes over the remaining regulatory life of each asset or
group of assets in all jurisdictions. The period of time over which non-protected excess deferred income taxes are amortized will be
determined in future proceedings, as previously disclosed, or as noted in the applicable state sections below.
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 no later than
PacifiCorp's next general rate proceeding. The settlement, which resulted in a rate reduction of $48 million, or 3.7%, effective
February 1, 2019, was approved by the OPUC in January 2019.
In December 2018, PacifiCorp filed a 2019 RAC application requesting recovery of $37 million, or a 2.8% increase in rates,
associated with repowering of approximately 900 megawatts of company-owned and installed wind facilities expected to be
completed in 2019. In March 2019, the application was updated to request recovery of $32 million, or a 2.5% increase in rates. In
August 2019, PacifiCorp filed an all-party settlement for the 2019 RAC that was approved by the OPUC in September 2019,
providing for a total rate increase of $24 million, or 1.8%, subject to final cost updates. The settlement agreement provides for rates to
be increased as the repowering projects are completed. Based on the in-service dates and final cost updates, the first rate increase of
$9 million or 0.7% was effective October 1, 2019, for four repowered facilities, the second rate increase of $1 million, or 0.1%, was
effective December 1, 2019, for one repowered facility and the third rate increase of $5 million or 0.4%, was effective January 1,
2020, for two repowered facilities. A final rate increase of $4.8 million, or 0.4 percent, was effective April 1, 2020 for the final two
remaining repowered facilities that were placed in service by the end of February 2020.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.13
As part of the commission-approved RAC settlement, parties agreed that the Oregon-allocated net book value of certain undepreciated
equipment replaced as a result of those repowerings captured in the 2019 RAC will be depreciated and offset with excess deferred
income taxes resulting from 2017 Tax Reform. In 2019, accelerated depreciation of $120 million and offsetting amortization of excess
deferred income taxes was recognized based on repowering activities completed through December 31, 2019.
In February 2020, PacifiCorp filed a general rate case in Oregon requesting an increase in base rates of $78 million, or 6.0%, effective
January 1, 2021, a separate tariff rider to recover costs associated with the early retirement of Cholla Unit 4 for an increase of $17
million annually from January 2021 through April 2025 and an annual credit to customers of $25 million for amortization of
remaining deferred income tax benefits associated with 2017 Tax Reform over a three-year period beginning January 2021. The
request for the increase in base rates reflects recovery of Energy Vision 2020 investments, updated depreciation rates and rate design
modernization proposals.
Wyoming
In March 2020, PacifiCorp filed a general rate case in Wyoming requesting an increase in base rates of $7 million, or 1.1 percent,
effective January 1, 2021. The increase reflects recovery of Energy Vision 2020 investments, updated depreciation rates and rate
design modernization proposals. The request includes a revision to the Energy Cost Adjustment Mechanism ("ECAM") to eliminate
the sharing band, approval to discontinue operations and cost recovery for the early retirement of Cholla Unit No. 4 generating
facility. The proposed increase reflects several rate mitigation measures that include use of the remaining 2017 Tax Reform benefits to
buy down plant balances and creation of regulatory assets for certain coal-fired generation units.
In April 2018, PacifiCorp filed a partial settlement related to the impact of 2017 Tax Reform with the Wyoming Public Service
Commission ("WPSC") that provided a rate reduction of $23 million, or 3.3%, effective July 1, 2018 through June 30, 2019, with the
remaining tax savings to be deferred with offsets to other costs. 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 balances. 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
and a $4 million offset to PacifiCorp's 2018 ECAM rates. The order reflected $20 million of current tax savings and was updated to
reflect a projection of $7 million for amortization of excess deferred income tax balances. In April 2019, PacifiCorp filed a new
application updating the amount of benefits being returned to customers. PacifiCorp continued the interim rate reduction that includes
the previously approved $23 million and an additional $4 million reduction to offset the 2019 ECAM, effective June 15, 2019. A
settlement agreement was filed in November 2019 in which the parties agreed to an additional rate reduction of $9 million effective
December 1, 2019 through the end of calendar year 2020. The WPSC approved the settlement agreement at its hearing held in
November 2019.
Washington
In December 2019, PacifiCorp submitted its 2021 general rate case with the WUTC requesting an overall decrease to rates of
approximately $4 million, or 1.1%, effective January 1, 2021. The case includes an increase in revenue requirement of $3 million,
offset by a proposed ten-year annual surcredit of $7 million, including interest, to customers primarily associated with the
amortization of excess deferred income taxes from 2017 Tax Reform. The case includes a request for approval of a new cost
allocation methodology, updated depreciation rates, recovery of Energy Vision 2020 investments, and rate design modernization
proposals.
Idaho
In May 2018, the IPUC approved a rate reduction of $6 million, or 2.2%, effective June 1, 2018 through May 31, 2019, to pass back a
portion of the current tax benefits associated with 2017 Tax Reform. In March 2019, an all-party settlement resolving the treatment of
the remaining tax savings was filed with the IPUC. In May 2019, the IPUC approved the all-party settlement, which includes the
amortization of non-protected excess deferred income taxes over 7 years, resulting in the rate reduction for current tax savings being
adjusted to $8 million per year, effective June 1, 2019, and $3 million related to amortization of excess deferred income taxes from
2017 Tax Reform being applied as an offset to the 2019 ECAM.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.14
California
In April 2018, PacifiCorp filed a general rate case with the California Public Utilities Commission ("CPUC") for an overall rate
increase of $1 million, or 0.9%, effective January 1, 2019. A CPUC decision was issued in February 2020, resulting in an
approximate $6 million, or 6%, rate decrease effective February 6, 2020. As part of the CPUC decision, non-protected excess deferred
income taxes are being returned to California customers over three years.
(10) 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"), and the Supplemental Executive Retirement Plan ("SERP"). The Retirement Plan is closed to all non-union
employees hired after January 1, 2008. All non-union Retirement Plan participants hired prior to January 1, 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 31, 2011 as they are now being
provided with enhanced 401(k) Plan benefits. However, certain limited union Retirement Plan participants continue to earn 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 31, 2018.
PacifiCorp's other postretirement benefit plan provides healthcare and life insurance benefits to eligible retirees.
Net Periodic Benefit Cost
For purposes of calculating the expected return on plan assets, a market-related value is used. The market-related value of plan 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 credit or cost for the plans included the following components for the years ended December 31 (in millions):
Pension Other Postretirement
2019 2018 2019 2018
Service cost $ — $ — $ 2 $ 2
Interest cost 44 43 12 11
Expected return on plan assets (67) (72) (21) (21)
Settlement — 22 — —
Net amortization 11 13 — (6)
Net periodic benefit (credit) cost $(12)$6 $(7)$(14)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.15
Funded Status
The following table is a reconciliation of the fair value of plan assets for the years ended December 31 (in millions):
Pension Other Postretirement
2019 2018 2019 2018
Plan assets at fair value, beginning of year $ 942 $ 1,111 $ 297 $ 332
Employer contributions 4 4 1 1
Participant contributions — — 5 5
Actual return on plan assets 181 (52) 55 (16)
Settlement — (52) — —
Benefits paid (91) (69) (24) (25)
Plan assets at fair value, end of year $1,036 $942 $334 $297
The following table is a reconciliation of the benefit obligations for the years ended December 31 (in millions):
Pension Other Postretirement
2019 2018 2019 2018
Benefit obligation, beginning of year $ 1,105 $ 1,251 $ 298 $ 331
Service cost — — 2 2
Interest cost 44 43 12 11
Participant contributions — — 5 5
Actuarial loss (gain) 109 (68) 11 (26)
Settlement — (52) — —
Benefits paid (91) (69) (24) (25)
Benefit obligation, end of year $1,167 $1,105 $304 $298
Accumulated benefit obligation, end of year $1,167 $1,105
The funded status of the plans and the amounts recognized on the Comparative Balance Sheet as of December 31 are as follows
(in millions):
Pension Other Postretirement
2019 2018 2019 2018
Plan assets at fair value, end of year $ 1,036 $ 942 $ 334 $ 297
Less - Benefit obligation, end of year 1,167 1,105 304 298
Funded status $(131)$(163)$30 $(1)
Amounts recognized on the Comparative Balance Sheet:
Other special funds (128) $ — $ — $ 30 $ —
Miscellaneous current and accrued liabilities (242) (4) (4) — —
Accumulated provision for pension and benefits (228.3) (127) (159) — (1)
Amounts recognized $(131)$(163)$30 $(1)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.16
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
$57 million and $52 million as of December 31, 2019 and 2018, respectively. These assets are not included in the plan assets in the
above table, but are reflected in temporary cash investments, totaling $- million and $1 million as of December 31, 2019 and 2018,
respectively, and other investments, totaling $57 million and $51 million as of December 31, 2019 and 2018, respectively, on the
Comparative Balance Sheet.
The projected benefit obligation and the accumulated benefit obligation for the pension plan were both in excess of the fair value of
the plan assets as of December 31, 2019.
Unrecognized Amounts
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in
millions):
Pension Other Postretirement
2019 2018 2019 2018
Net loss (gain) $ 442 $ 461 $ (26) $ (2)
Regulatory deferrals 1 (1) 6 7
Total $443 $460 $(20)$5
A reconciliation of the amounts not yet recognized as components of net periodic benefit cost for the years ended December 31, 2019
and 2018 is as follows (in millions):
Accumulated
Other
Regulatory Comprehensive
Asset Loss Total
Pension
Balance, December 31, 2017 $418 $20 $438
Net loss (gain) arising during the year 59 (2) 57
Net amortization (12) (1) (13)
Settlement (22)—(22)
Total 25 (3)22
Balance, December 31, 2018 443 17 460
Net (gain) loss arising during the year (11) 5 (6)
Net amortization (10)(1)(11)
Total (21)4 (17)
Balance, December 31, 2019 $422 $21 $443
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.17
Regulatory
Asset (Liability)
Other Postretirement
Balance, December 31, 2017 $(11)
Net loss arising during the year 10
Net amortization 6
Total 16
Balance, December 31, 2018 5
Net loss arising during the year (25)
Net amortization —
Total (25)
Balance, December 31, 2019 $(20)
Plan Assumptions
Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost were as follows:
Pension Other Postretirement
2019 2018 2019 2018
Benefit obligations as of December 31:
Discount rate 3.25% 4.25% 3.20% 4.25%
Rate of compensation increase N/A N/A N/A N/A
Interest crediting rates for cash balance plan(1)(2)2.27% 3.40% N/A N/A
Net periodic benefit cost for the years ended December 31:
Discount rate 4.25% 3.60% 4.25% 3.60%
Expected return on plan assets 7.00 7.00 6.86 6.86
Rate of compensation increase N/A N/A N/A N/A
(1) 2019 Cash Balance Interest Crediting Rate assumption is 2.27% for 2020-2021 and 2.10% for 2022 and all future years for nonunion participants and 2.16%
for 2020-2021 and 2.70% for 2022+ for union participants.
(2) 2018 Cash Balance Interest Crediting Rate assumption was 3.40% for 2019 and all future years for nonunion participants and 3.15% for 2019-2020 and
3.25% for 2021+ for union participants.
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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.18
Contributions and Benefit Payments
Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $- million,
respectively, during 2020. 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. PacifiCorp considers contributing additional amounts from time to time in order to achieve
certain funding levels specified under the Pension Protection Act of 2006, as amended. PacifiCorp evaluates a variety of factors,
including funded status, income tax laws and regulatory requirements, in determining contributions to its other postretirement benefit
plan.
The expected benefit payments to participants in PacifiCorp's pension and other postretirement benefit plans for 2020 through 2024
and for the five years thereafter are summarized below (in millions):
Projected Benefit Payments
Pension Other Postretirement
2020 $ 112 $ 27
2021 98 24
2022 94 23
2023 89 23
2024 83 21
2025-2029 350 94
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 alternative investments. 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 December 31, 2019:
Pension(1)
Other
Postretirement(1)
% %
Debt securities(2)30 - 43 33 - 37
Equity securities(2)48 - 65 62 - 66
Limited partnership interests 6 - 12 1 - 3
(1) 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 postretirement benefit plan include the separate account of the 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.19
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)Level 2(1)Level 3(1)Total
As of December 31, 2019:
Cash and cash equivalents $ — $ 24 $ — $ 24
Debt securities:
United States government obligations 21 — — 21
Corporate obligations — 94 — 94
Municipal obligations — 10 — 10
Agency, asset and mortgage-backed obligations — 42 — 42
Equity securities:
United States companies 355 — — 355
International companies 15 — — 15
Investment funds(2)55 ——55
Total assets in the fair value hierarchy $446 $170 $—616
Investment funds(2) measured at net asset value 327
Limited partnership interests(3) measured at net asset value 93
Investments at fair value $1,036
As of December 31, 2018:
Cash and cash equivalents $ — $ 11 $ — $ 11
Debt securities:
United States government obligations 4 — — 4
International government obligations — 1 — 1
Corporate obligations — 88 — 88
Municipal obligations — 10 — 10
Agency, asset and mortgage-backed obligations — 43 — 43
Equity securities:
United States companies 327 — — 327
International companies 15 — — 15
Investment funds(2)54 — — 54
Total assets in the fair value hierarchy $400 $153 $—553
Investment funds(2) measured at net asset value 285
Limited partnership interests(3) measured at net asset value 104
Investments at fair value $942
(1) Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.
(2) Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately
55% and 45% respectively, for 2019 and 2018, and are invested in United States and international securities of approximately 51% and 49%, respectively,
for 2019 and 68% and 32%, respectively, for 2018.
(3) Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.20
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 Fair Value Measurements
Level 1(1)Level 2(1)Level 3(1)Total
As of December 31, 2019:
Cash and cash equivalents $ 8 $ 1 $ — $ 9
Debt securities:
United States government obligations 12 — — 12
Corporate obligations — 26 — 26
Municipal obligations — 2 — 2
Agency, asset and mortgage-backed obligations — 22 — 22
Equity securities:
United States companies 74 — — 74
International companies 4 — — 4
Investment funds(2)44 ——44
Total assets in the fair value hierarchy $142 $51 $—193
Investment funds(2) measured at net asset value 136
Limited partnership interests(3) measured at net asset value 5
Investments at fair value $334
As of December 31, 2018:
Cash and cash equivalents $ 4 $ 1 $ — $ 5
Debt securities:
United States government obligations 3 — — 3
Corporate obligations — 23 — 23
Municipal obligations — 2 — 2
Agency, asset and mortgage-backed obligations — 17 — 17
Equity securities:
United States companies 83 — — 83
International companies 4 — — 4
Investment funds(2)38 ——38
Total assets in the fair value hierarchy $132 $43 $—175
Investment funds(2) measured at net asset value 116
Limited partnership interests(3) measured at net asset value 6
Investments at fair value $297
(1) Refer to Note 13 for additional discussion regarding the three levels of the fair value hierarchy.
(2) Investment funds are substantially comprised of mutual funds and collective trust funds. These funds consist of equity and debt securities of approximately
56% and 44%, respectively, for 2019 and 59% and 41%, respectively, for 2018, and are invested in United States and international securities of
approximately 79% and 21%, respectively, for 2019 and 90% and 10%, respectively, for 2018.
(3) Limited partnership interests include several funds that invest primarily in real estate, buyout, growth equity and venture capital.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.21
For level 1 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.
Multiemployer and Joint Trustee Pension Plans
PacifiCorp contributes to the PacifiCorp/IBEW Local 57 Retirement Trust Fund ("Local 57 Trust Fund") (plan number 001) 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 of the obligation considered probable of recovery 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 determined a withdrawal liability of $115 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.
The following table presents PacifiCorp's participation in individually significant joint trustee and multiemployer pension plans for
the years ended December 31 (dollars in millions):
PPA zone status or plan
funded status percentage for
plan years beginning July 1,Contributions(1)
Plan name
Employer
Identification
Number 2019 2018
Funding
improvement
plan
Surcharge
imposed under
PPA(1)2019 2018
Year contributions to plan
exceeded more than 5% of
total contributions(2)
Local 57
Trust Fund 87-0640888 At least 80% At least 80% None None $ 7 $ 7 2017, 2016
(1) 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.
(2) For the Local 57 Trust Fund, information is for plan years beginning July 1, 2017 and 2016. Information for the plan year beginning July 1, 2018 is not yet
available.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.22
The current collective bargaining agreements governing the Local 57 Trust Fund expire in 2023.
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, 2019, all participants 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 $40 million
and $39 million for the years ended December 31, 2019 and 2018, respectively.
(11) 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
$1,019 million and $994 million as of December 31, 2019 and 2018, respectively.
The following table reconciles the beginning and ending balances of PacifiCorp's ARO liabilities for the years ended December 31
(in millions):
2019 2018
Beginning balance $ 227 $ 215
Change in estimated costs 27 9
Additions 9 —
Retirements (15) (5)
Accretion 9 8
Ending balance $257 $227
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.
(12) 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.23
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 13 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, 2019:
Not designated as hedging contracts(1):
Commodity assets $ 15 $ 2 $ 4 $ — $ 21
Commodity liabilities (3)— (31) (50)(84)
Total 12 2 (27)(50)(63)
Total derivatives 12 2 (27) (50) (63)
Cash collateral receivable — — 20 27 47
Total derivatives - net basis $12 $2 $(7)$(23)$(16)
As of December 31, 2018:
Not designated as hedging contracts(1):
Commodity assets $ 36 $ 4 $ 10 $ 1 $ 51
Commodity liabilities (9) (1) (67) (71) (148)
Total 27 3 (57)(70)(97)
Total derivatives 27 3 (57) (70) (97)
Cash collateral (payable) receivable (2) — 16 45 59
Total derivatives - net basis $25 $3 $(41)$(25)$(38)
(1) PacifiCorp's commodity derivatives are generally included in rates and as of December 31, 2019 and 2018, a regulatory asset of $62 million and $96 million,
respectively, was recorded related to the net derivative liability of $63 million and $97 million, respectively.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.24
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 earnings for the years
ended December 31 (in millions):
2019 2018
Beginning balance $ 96 $ 101
Changes in fair value recognized in regulatory assets (37) 12
Net (losses) gains reclassified to operating revenue (34) (68)
Net gains (losses) reclassified to energy costs 37 (51)
Ending balance $62 $96
Derivative Contract Volumes
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 31 (in millions):
Unit of
Measure 2019 2018
Electricity sales Megawatt hours (2) (6)
Natural gas purchases Decatherms 129 117
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 counterparty credit risk, PacifiCorp
enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains
third-party guarantees, letters of credit and cash deposits. If required, 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 agreements, including 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 agreements 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" if there is a material adverse change in PacifiCorp's
creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2019, 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 fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features
totaled $80 million and $113 million as of December 31, 2019 and 2018, respectively, for which PacifiCorp had posted collateral of
$47 million and $61 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 December 31, 2019 and 2018, PacifiCorp would have been required to post
$27 million and $35 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.25
(13) 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 1 - 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 that are not active, inputs other than quoted prices that are observable for the asset
or liability and inputs that are derived principally from or corroborated 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.
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 1 Level 2 Level 3 Other(1)Total
As of December 31, 2019:
Assets:
Commodity derivatives $ — $ 21 $ — $ (7) $ 14
Money market mutual funds(2)17 — — — 17
Investment funds 25 ———25
$42 $21 $—$(7)$56
Liabilities - Commodity derivatives $—$(84)$—$54 $(30)
As of December 31, 2018:
Assets:
Commodity derivatives $ — $ 51 $ — $ (23) $ 28
Money market mutual funds(2)63 — — — 63
Investment funds 24 — — — 24
$87 $51 $—$(23)$115
Liabilities - Commodity derivatives $—$(148)$—$82 $(66)
(1) Represents netting under master netting arrangements and a net cash collateral receivable of $47 million and $59 million as of December 31, 2019 and 2018,
respectively.
(2) Amounts are included in other investments and special funds and temporary cash investments on the Comparative Balance Sheet. The fair value of these
money market mutual funds approximates cost.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.26
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 qualify 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 internal 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 commodity prices, interest rates, currency rates, related volatility,
counterparty creditworthiness and duration of contracts. Refer to Note 12 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 of a quoted market price or net asset value of an 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 31 (in millions):
2019 2018
Carrying Fair Carrying Fair
Value Value Value Value
Long-term debt $7,692 $9,280 $7,045 $7,833
(14) Commitments and Contingencies
Legal Matters
PacifiCorp is party 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.27
Hydroelectric Relicensing
PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve
disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA does not guarantee dam removal.
Instead, it establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether
dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a
contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds;
(2) complete indemnification from harms associated with dam removal; (3) transfer of the FERC license to a third-party dam removal
entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate
the facilities for the benefit of customers until dam removal commences.
In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem
Klamath dams from PacifiCorp to the KRRC. Over the past two years, the KRRC has been supplementing the application with
additional information about its financial, technical, and legal capacity to become the licensee. In July 2019, the KRRC provided the
FERC with additional information about its financial capacity to become a licensee, including updated cost estimates, and its
insurance, bonding and liability transfer package. The FERC is evaluating the KRRC's information and the proposed license transfer.
The KRRC will continue to refine its insurance, bonding and liability transfer package, and PacifiCorp will review the KRRC's
capacity to fulfill its indemnity obligation under the KHSA. If certain conditions in the amended KHSA are not satisfied (e.g.,
inadequate funding or inability of KRRC to satisfy its indemnification obligation) and the license does not transfer to the KRRC,
PacifiCorp will resume relicensing with the FERC.
The United States Court of Appeals for the District of Columbia Circuit issued a decision in the Hoopa Valley Tribe v. FERC
litigation, in January 2019, finding that the states of California and Oregon have waived their Clean Water Act, Section 401, water
quality certification authority over the Klamath hydroelectric project relicensing. This decision has the potential to limit the ability of
the States to impose water quality conditions on new and relicensed projects. Environmental interests, supported by California,
Oregon and other states, asked the court to rehear the case, which was denied. Subsequently, environmental groups, supported by
numerous states, filed a petition for certiorari before the United States Supreme Court, which was denied on December 9, 2019,
thereby allowing the circuit court opinion to stand as a final and unappealable decision.
As of December 31, 2019, PacifiCorp's assets included $29 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 in Utah, Wyoming and Idaho through December 31, 2022.
Hydroelectric Commitments
Certain of PacifiCorp's hydroelectric licenses contain requirements for PacifiCorp to make certain capital and operating expenditures
related to its hydroelectric facilities. PacifiCorp estimates it is obligated to make capital expenditures of approximately $168 million
over the next 10 years related to these licenses.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.28
Commitments
PacifiCorp has the following firm commitments that are not reflected on the Comparative Balance Sheet. Minimum payments as of
December 31, 2019 are as follows (in millions):
2020 2021 2022 2023 2024
2025 and
Thereafter Total
Contract type:
Purchased electricity contracts -
commercially operable $ 279 $ 177 $ 174 $ 168 $ 164 $ 1,810 $ 2,772
Purchased electricity contracts -
non-commercially operable 7 52 52 53 53 987 1,204
Fuel contracts 832 519 316 245 248 775 2,935
Construction commitments 844 6 — — 4 — 854
Transmission 101 86 77 71 56 429 820
Easements 10 12 12 12 11 349 406
Maintenance, service and
other contracts 329 49 41 34 32 204 689
Total commitments $2,402 $901 $672 $583 $568 $4,554 $9,680

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 solar or 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. Refer to Note 5
for information on lease commitments.
Included in the minimum fixed annual payments for purchased electricity above are commitments to purchase electricity from several
hydroelectric systems under long-term arrangements with public utility districts. These purchases are made on a "cost-of-service"
basis for a stated percentage of system output and for a like percentage of system operating expenses and debt service. These costs are
included in operating 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 electricity is produced. These arrangements accounted for less than 5% of PacifiCorp's 2019
and 2018 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.
Construction 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.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.29
Transmission
PacifiCorp has contracts for the right to transmit electricity over other entities' transmission lines to facilitate delivery to PacifiCorp's
customers.
Easements
PacifiCorp has non-cancelable easements for land on which certain of its assets, primarily wind-powered generating facilities, are
located.
Guarantees
PacifiCorp has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not
expected to have a material impact on PacifiCorp's financial results.
(15) 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.
(16) Common Shareholder's Equity
Through PPW Holdings, BHE is the sole shareholder of PacifiCorp's common stock. The state regulatory orders that authorized
BHE'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 December 31, 2019, 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 44% of its total capitalization, excluding short-term
debt and current maturities of long-term debt. As of December 31, 2019, PacifiCorp's actual common equity percentage, as calculated
under this measure, was 53%, and PacifiCorp would have been permitted to dividend $2.4 billion under this commitment.
These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings or BHE 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 December 31, 2019, 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 7.
(17) Supplemental Cash Flow Disclosures
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
2019 2018
Interest paid, net of amounts capitalized $ 340 $ 349
Income taxes paid, net(1)$160 $131
Supplemental disclosure of non-cash investing and financing activities:
Accounts payable related to utility plant additions $293 $184
(1) PacifiCorp is party to a tax-sharing agreement and is part of the Berkshire Hathaway United States federal income tax return. Amounts substantially
represent income taxes paid to BHE.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.30
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
PacifiCorp X
/ /2019/Q4
Line
No.
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Other
Adjustments
(e)
Foreign Currency
Hedges
(d)
Minimum Pension
Liability adjustment
(net amount)
(c)
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Item
(a)
( 15,266,178)
Balance of Account 219 at Beginning of
Preceding Year
1
696,196
Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
2
1,934,940
Preceding Quarter/Year to Date Changes in
Fair Value
3
2,631,136Total (lines 2 and 3) 4
( 12,635,042)
Balance of Account 219 at End of Preceding
Quarter/Year
5
( 12,635,042)
Balance of Account 219 at Beginning of
Current Year
6
578,074
Current Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
7
( 3,859,665)
Current Quarter/Year to Date Changes in
Fair Value
8
( 3,281,591)Total (lines 7 and 8) 9
( 15,916,633)
Balance of Account 219 at End of Current
Quarter/Year
10
FERC FORM NO. 1 (NEW 06-02)Page 122a
Other Cash Flow
Hedges
[Insert Footnote at Line 1
to specify]
(g)
Other Cash Flow
Hedges
Interest Rate Swaps
(f)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
PacifiCorp X
/ /2019/Q4
Line
No.
Total
Comprehensive
Income
(j)
Net Income (Carried
Forward from
Page 117, Line 78)
(i)
Totals for each
category of items
recorded in
Account 219
(h)
( 15,266,178) 1
696,196 2
1,934,940 3
737,709,000 740,340,136 2,631,136 4
( 12,635,042) 5
( 12,635,042) 6
578,074 7
( 3,859,665) 8
771,192,330 767,910,739( 3,281,591) 9
( 15,916,633) 10
FERC FORM NO. 1 (NEW 06-02)Page 122b
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
PacifiCorp X
/ /2019/Q4
Line
No.(b)(a)
Classification Electric
(c)
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Total Company for the
Current Year/Quarter Ended
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (h) common function.
Utility Plant 1
In Service 2
28,339,337,805 28,339,337,805Plant in Service (Classified) 3
31,316,357 31,316,357Property Under Capital Leases 4
Plant Purchased or Sold 5
290,417,407 290,417,407Completed Construction not Classified 6
Experimental Plant Unclassified 7
28,661,071,569 28,661,071,569Total (3 thru 7) 8
Leased to Others 9
25,890,060 25,890,060Held for Future Use 10
2,002,448,524 2,002,448,524Construction Work in Progress 11
156,468,483 156,468,483Acquisition Adjustments 12
30,845,878,636 30,845,878,636Total Utility Plant (8 thru 12) 13
10,870,776,722 10,870,776,722Accum Prov for Depr, Amort, & Depl 14
19,975,101,914 19,975,101,914Net Utility Plant (13 less 14) 15
Detail of Accum Prov for Depr, Amort & Depl 16
In Service: 17
10,085,581,074 10,085,581,074Depreciation 18
Amort & Depl of Producing Nat Gas Land/Land Right 19
Amort of Underground Storage Land/Land Rights 20
652,942,422 652,942,422Amort of Other Utility Plant 21
10,738,523,496 10,738,523,496Total In Service (18 thru 21) 22
Leased to Others 23
Depreciation 24
Amortization and Depletion 25
Total Leased to Others (24 & 25) 26
Held for Future Use 27
Depreciation 28
Amortization 29
Total Held for Future Use (28 & 29) 30
Abandonment of Leases (Natural Gas) 31
132,253,226 132,253,226Amort of Plant Acquisition Adj 32
10,870,776,722 10,870,776,722Total Accum Prov (equals 14) (22,26,30,31,32) 33
FERC FORM NO. 1 (ED. 12-89) Page 200
(g)
Common
(h)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
PacifiCorp X
/ /2019/Q4
Line
No.
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Gas Other (Specify)
(d) (e) (f)
Other (Specify)Other (Specify)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
FERC FORM NO. 1 (ED. 12-89) Page 201
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
PacifiCorp X
/ /2019/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account
103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of
plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)
1. INTANGIBLE PLANT 1
(301) Organization 2
(302) Franchises and Consents 209,604,815 299,406 3
(303) Miscellaneous Intangible Plant 760,827,206 53,832,204 4
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 970,432,021 54,131,610 5
2. PRODUCTION PLANT 6
A. Steam Production Plant 7
(310) Land and Land Rights 92,989,902 5,142 8
(311) Structures and Improvements 1,039,610,644 19,609,447 9
(312) Boiler Plant Equipment 4,664,914,276 91,788,280 10
(313) Engines and Engine-Driven Generators 11
(314) Turbogenerator Units 1,001,145,420 14,875,454 12
(315) Accessory Electric Equipment 489,701,921 4,130,116 13
(316) Misc. Power Plant Equipment 33,490,333 1,775,555 14
(317) Asset Retirement Costs for Steam Production 131,258,959 29,760,022 15
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 7,453,111,455 161,944,016 16
B. Nuclear Production Plant 17
(320) Land and Land Rights 18
(321) Structures and Improvements 19
(322) Reactor Plant Equipment 20
(323) Turbogenerator Units 21
(324) Accessory Electric Equipment 22
(325) Misc. Power Plant Equipment 23
(326) Asset Retirement Costs for Nuclear Production 24
TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 25
C. Hydraulic Production Plant 26
(330) Land and Land Rights 36,320,104 109,062 27
(331) Structures and Improvements 278,438,856 5,652,967 28
(332) Reservoirs, Dams, and Waterways 511,877,153 7,016,515 29
(333) Water Wheels, Turbines, and Generators 138,470,585 6,105,107 30
(334) Accessory Electric Equipment 84,803,729 1,776,898 31
(335) Misc. Power PLant Equipment 2,374,352 241,126 32
(336) Roads, Railroads, and Bridges 24,974,420 150,384 33
(337) Asset Retirement Costs for Hydraulic Production 34
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 1,077,259,199 21,052,059 35
D. Other Production Plant 36
(340) Land and Land Rights 45,432,889 5,525,956 37
(341) Structures and Improvements 229,031,081 2,574,473 38
(342) Fuel Holders, Products, and Accessories 16,188,175 29,789 39
(343) Prime Movers 2,940,730,523 658,563,917 40
(344) Generators 478,615,156 54,099,740 41
(345) Accessory Electric Equipment 329,144,345 1,663,251 42
(346) Misc. Power Plant Equipment 15,924,321 206,595 43
(347) Asset Retirement Costs for Other Production 16,855,215 2,241,187 44
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 4,071,921,705 724,904,908 45
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 12,602,292,359 907,900,983 46
Page 204FERC FORM NO. 1 (REV. 12-05)
(f)
Transfers Balance atEnd of Year
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent’s plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
1
2
209,624,286 279,935 3
806,258,510 8,400,900 4
1,015,882,796 8,680,835 5
6
7
92,993,849 1,195 8
1,056,453,683 2,766,408 9
4,657,546,678 642,560 99,798,438 10
11
1,008,433,107 7,587,767 12
492,434,835 -642,560 754,642 13
34,262,485 1,003,403 14
159,106,198 -1,912,783 15
7,501,230,835 -1,912,783 111,911,853 16
17
18
19
20
21
22
23
24
25
26
36,429,166 27
281,578,484 -1,588 2,511,751 28
517,856,965 1,588 1,038,291 29
143,899,365 676,327 30
86,336,749 243,878 31
2,577,272 38,206 32
25,037,292 87,512 33
34
1,093,715,293 4,595,965 35
36
50,958,845 37
231,545,463 60,091 38
16,218,012 -48 39
2,796,951,544 802,342,896 40
498,116,230 34,598,666 41
325,115,884 5,691,712 42
16,130,916 43
19,096,402 44
3,954,133,296 842,693,317 45
12,549,079,424 -1,912,783 959,201,135 46
Page 205FERC FORM NO. 1 (REV. 12-05)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
3. TRANSMISSION PLANT 47
(350) Land and Land Rights 272,900,490 9,643,723 48
(352) Structures and Improvements 275,874,995 8,107,097 49
(353) Station Equipment 2,265,701,408 20,786,559 50
(354) Towers and Fixtures 1,301,155,918 6,284,080 51
(355) Poles and Fixtures 960,420,522 58,083,941 52
(356) Overhead Conductors and Devices 1,253,499,035 37,297,336 53
(357) Underground Conduit 3,520,058 328,768 54
(358) Underground Conductors and Devices 8,035,354 -1,070,700 55
(359) Roads and Trails 11,937,200 56
(359.1) Asset Retirement Costs for Transmission Plant 57
TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 6,353,044,980 139,460,804 58
4. DISTRIBUTION PLANT 59
(360) Land and Land Rights 64,555,204 774,777 60
(361) Structures and Improvements 120,762,525 4,312,286 61
(362) Station Equipment 1,043,475,099 45,188,274 62
(363) Storage Battery Equipment 63
(364) Poles, Towers, and Fixtures 1,220,758,561 54,673,840 64
(365) Overhead Conductors and Devices 774,459,766 35,931,593 65
(366) Underground Conduit 385,158,148 15,846,482 66
(367) Underground Conductors and Devices 898,121,842 40,026,257 67
(368) Line Transformers 1,390,837,792 52,469,821 68
(369) Services 818,443,527 43,705,175 69
(370) Meters 229,675,682 43,363,562 70
(371) Installations on Customer Premises 8,806,482 60,744 71
(372) Leased Property on Customer Premises 72
(373) Street Lighting and Signal Systems 62,888,188 1,205,599 73
(374) Asset Retirement Costs for Distribution Plant 1,344,766 74
TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 7,019,287,582 337,558,410 75
5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT 76
(380) Land and Land Rights 77
(381) Structures and Improvements 78
(382) Computer Hardware 79
(383) Computer Software 80
(384) Communication Equipment 81
(385) Miscellaneous Regional Transmission and Market Operation Plant 82
(386) Asset Retirement Costs for Regional Transmission and Market Oper 83
TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 84
6. GENERAL PLANT 85
(389) Land and Land Rights 21,540,621 2,075,036 86
(390) Structures and Improvements 250,401,291 10,349,685 87
(391) Office Furniture and Equipment 88,315,352 5,850,337 88
(392) Transportation Equipment 117,676,889 6,499,183 89
(393) Stores Equipment 14,919,759 509,554 90
(394) Tools, Shop and Garage Equipment 63,668,918 3,394,734 91
(395) Laboratory Equipment 34,874,025 1,372,258 92
(396) Power Operated Equipment 191,826,835 7,260,916 93
(397) Communication Equipment 482,950,536 22,787,545 94
(398) Miscellaneous Equipment 8,268,735 555,298 95
SUBTOTAL (Enter Total of lines 86 thru 95) 1,274,442,961 60,654,546 96
(399) Other Tangible Property 1,854,828 97
(399.1) Asset Retirement Costs for General Plant 39,748 98
TOTAL General Plant (Enter Total of lines 96, 97 and 98) 1,276,337,537 60,654,546 99
TOTAL (Accounts 101 and 106) 28,221,394,479 1,499,706,353 100
(102) Electric Plant Purchased (See Instr. 8) 101
(Less) (102) Electric Plant Sold (See Instr. 8) 102
(103) Experimental Plant Unclassified 103
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 28,221,394,479 1,499,706,353 104
Page 206FERC FORM NO. 1 (REV. 12-05)
(f)
Transfers Balance atEnd of Year
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
47
281,363,904 -3,205 1,177,104 48
283,787,044 195,048 49
2,279,276,707 5,800 7,217,060 50
1,307,439,631 367 51
1,015,701,010 2,803,453 52
1,287,027,290 -1,273,814 2,495,267 53
3,848,826 54
8,238,468 1,273,814 55
11,937,200 56
57
6,478,620,080 2,595 13,888,299 58
59
65,329,981 60
124,996,790 78,021 61
1,085,813,833 -5,800 2,843,740 62
63
1,267,917,057 7,515,344 64
806,824,019 3,567,340 65
399,131,386 1,873,244 66
935,090,905 3,057,194 67
1,433,055,320 10,252,293 68
860,892,630 1,256,072 69
245,107,614 27,931,630 70
8,802,174 65,052 71
72
62,338,943 1,754,844 73
1,344,766 74
7,296,645,418 -5,800 60,194,774 75
76
77
78
79
80
81
82
83
84
85
23,615,657 86
257,936,605 3,249 2,817,620 87
72,082,727 -53,009 22,029,953 88
119,232,266 90,144 5,033,950 89
14,958,720 89,347 559,940 90
63,565,114 -393,726 3,104,812 91
34,959,699 101,810 1,388,394 92
190,961,993 -101,775 8,023,983 93
501,800,356 112,721 4,050,446 94
8,519,781 151,239 455,491 95
1,287,632,918 47,464,589 96
1,854,828 97
39,748 98
1,289,527,494 47,464,589 99
28,629,755,212 -3,205 -1,912,783 1,089,429,632 100
101
102
103
28,629,755,212 -3,205 -1,912,783 1,089,429,632 104
Page 207FERC FORM NO. 1 (REV. 12-05)
Schedule Page: 204 Line No.: 46 Column: b
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance
Beg. of Year
(b)
TOTAL Production Plant 46(b) $12,602,292,359
Less: (317) Asset Retirement Costs for Steam Production(1) 15(b) 131,258,959
Less: (326) Asset Retirement Costs for Nuclear Production(1) 24(b) -
Less: (337) Asset Retirement Costs for Hydraulic Production(1) 34(b) -
Less: (347) Asset Retirement Costs for Other Production(1) 44(b) 16,855,215
Revised TOTAL Production Plant $12,454,178,185
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
Schedule Page: 204 Line No.: 46 Column: g
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance
End of Year
(g)
TOTAL Production Plant 46(g) $12,549,079,424
Less: (317) Asset Retirement Costs for Steam Production(1) 15(g) 159,106,198
Less: (326) Asset Retirement Costs for Nuclear Production(1) 24(g) -
Less: (337) Asset Retirement Costs for Hydraulic Production(1) 34(g) -
Less: (347) Asset Retirement Costs for Other Production(1) 44(g) 19,096,402
Revised TOTAL Production Plant $12,370,876,824
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.

Schedule Page: 204 Line No.: 55 Column: c
The credit represents reimbursements of settlement fees for contracted work performed,
return of materials and supplies to inventory and allocated overhead credits.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 204 Line No.: 75 Column: b
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance at
Beg. of Year
(b)
TOTAL Distribution Plant 75(b) $ 7,019,287,582
Less: (374) Asset Retirement Costs for Distribution Plant(1) 74(b) 1,344,766
Revised TOTAL Distribution Plant $ 7,017,942,816
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
Schedule Page: 204 Line No.: 75 Column: g
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance at
End of Year
(g)
TOTAL Distribution Plant 75(g) $ 7,296,645,418
Less: (374) Asset Retirement Costs for Distribution Plant(1) 74(g) 1,344,766
Revised TOTAL Distribution Plant $ 7,295,300,652
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
Schedule Page: 204 Line No.: 97 Column: b
Account 399.21, Land owned in fee
Schedule Page: 204 Line No.: 97 Column: g
Refer to footnote on page 204, line no. 97, column (b)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 204 Line No.: 99 Column: b
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance at
Beg. of Year
(b)
TOTAL General Plant 99(b) $ 1,276,337,537
Less: (399) Other Tangible Property(1) 97(b) 1,854,828
Less: (399.1) Asset Retirement Costs for General Plant(2) 98(b) 39,748
Revised TOTAL General Plant $ 1,274,442,961
(1) To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for mining assets
related to production plant.
(2) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.
Schedule Page: 204 Line No.: 99 Column: g
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance at
End of Year
(g)
TOTAL General Plant 99(g) $ 1,289,527,494
Less: (399) Other Tangible Property(1) 97(g) 1,854,828
Less: (399.1) Asset Retirement Costs for General Plant(2) 98(g) 39,748
Revised TOTAL General Plant $ 1,287,632,918
(1) To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for mining assets
related to production plant.
(2) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 204 Line No.: 104 Column: b
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance at
Beg. of Year
(b)
TOTAL Intangible Plant 5(b) $ 970,432,021
Revised TOTAL Production Plant(1) 12,454,178,185
TOTAL Transmission Plant 58(b) 6,353,044,980
Revised TOTAL Distribution Plant(2) 7,017,942,816
Revised TOTAL General Plant(3) 1,274,442,961
(102) Electric Plant Purchased 101(b) -
(Less) (102) Electric Plant Sold 102(b) -
(103) Experimental Plant Unclassified 103(b) -
Revised TOTAL Electric Plant in Service $28,070,040,963
(1) Refer to footnote on page 204, line no. 46, column (b)
(2) Refer to footnote on page 204, line no. 75, column (b)
(3) Refer to footnote on page 204, line no. 99, column (b)
Schedule Page: 204 Line No.: 104 Column: g
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Balance at
End of Year
(g)
TOTAL Intangible Plant 5(g) $ 1,015,882,796
Revised TOTAL Production Plant(1) 12,370,876,824
TOTAL Transmission Plant 58(g) 6,478,620,080
Revised TOTAL Distribution Plant(2) 7,295,300,652
Revised TOTAL General Plant(3) 1,287,632,918
(102) Electric Plant Purchased 101(g) -
(Less) (102) Electric Plant Sold 102(g) -
(103) Experimental Plant Unclassified 103(g) -
Revised TOTAL Electric Plant in Service $28,448,313,270
(1) Refer to footnote on page 204, line no. 46, column (g)
(2) Refer to footnote on page 204, line no. 75, column (g)
(3) Refer to footnote on page 204, line no. 99, column (g)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
PacifiCorp X
/ /2019/Q4
Line Description and Location Date Originally Included Balance atEnd of Year(c)(b)(a)Of Property in This Account Date Expected to be usedin Utility Service (d)No.
1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held
for future 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 transferred to Account 105.
Land and Rights: 1
2007Barnes Butte Substation 746,2682027 2
2007Wild Horse Wind Plant 6,763,0942039 3
2007Twelve Mile Wind Plant 2,160,2072039 4
2008Jumbers Point Substation 1,173,2762027 5
2009Mountain Green Substation 284,9962026 6
2009Hoggard Substation 254,3972025 7
2009Oquirrh-Terminal 345kV Transmission Line 396,0202024 8
2010Bend Service Center 2,982,3212021 9
2010Legacy Substation 562,2762021 10
2011Aeolus Substation 1,013,5772020 11
2011Anticline Substation 964,0432020 12
2011Populus Substation 254,7532024 13
2012Lassen Substation 683,3182021 14
2012Old Mill Substation 1,838,2812027 15
2013Chimney Butte-Paradise 230kV Transmission Line 598,4572026 16
2016Fiddlers Canyon Substation 1,136,5872028 17
2017Gateway Area Substation 3,166,1882023 18
Miscellaneous, each under $250,000: 912,001 19
20
Other Property: 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 (ED. 12-96) Page 214
47 Total 25,890,060
Schedule Page: 214 Line No.: 3 Column: c
Land purchased for future development with an estimated utility service date of 2039,
subject to business strategy and development plans.
Schedule Page: 214 Line No.: 4 Column: c
Land purchased for future development with an estimated utility service date of 2039,
subject to business strategy and development plans.
Schedule Page: 214 Line No.: 11 Column: c
Property is expected to be placed in-service in 2020, as part of the Energy Vision 2020
project, subject to environmental and economic reviews.
Schedule Page: 214 Line No.: 12 Column: c
Property is expected to be placed in-service in 2020, as part of the Energy Vision 2020
project, subject to environmental and economic reviews.
Schedule Page: 214 Line No.: 19 Column: c
Various dates and plans.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
PacifiCorp X
/ /2019/Q4
Line
No.
Description of Project Construction work in progress -
(b)(a)Electric (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Intangible: 1
5,268,765 Customer Relationship Management Focused Software Upgrade 2
3,840,009 Customer Revenue, Billing and Tariff Analysis Software 3
2,952,488 Mapping System Consolidation Software 4
2,160,095 Prospect No. 3 Hydro Relicensing 5
1,632,830 Cutler Hydro Relicensing 6
1,321,749 Weber Hydro Relicensing 7
1,103,582 Computer Aided Distribution Operations System Software Upgrade 8
Production: 9
202,243,593 TB Flats Wind Project 500 MW** 10
137,446,545 Marengo Wind Repowering** 11
116,380,702 Ekola Flats Wind Project 250 MW** 12
98,993,227 Dunlap Ranch 1 Wind Repowering** 13
64,633,874 Pryor Mountain Wind Project 240 MW 14
62,822,559 Marengo II Wind Repowering** 15
13,141,125 Foote Creek Wind Repowering** 16
11,347,161 Lewis River System Relicensing Implementation 17
10,929,821 Lake Side 2 Steam Turbine Generator Stator Replacement and Rotor Rewind 18
9,112,993 Safe Harbor Equipment Purchases 19
3,777,309 Hermiston U1 & U2 Low Pressure Evaporator and Feedwater Heater Replacement 20
3,397,890 Toketee Dam Rehabilitation Evaluation 21
3,021,694 Merwin Spillway Gate Wood Extension Replacement 22
2,931,193 Merwin Hydro Spillway Gate Hoist Platform Retrofit 23
2,406,676 Cedar Springs Wind Project 200 MW** 24
1,909,696 Jim Bridger Coal Combustion Residual Flue Gas Desulfurization Pond 4 Stage 1 25
1,823,249 Huntington Waste Water Redirect 26
1,613,117 Jim Bridger U4 Catalyst Replacement, Selective Catalytic Reduction System 27
1,432,093 Soda Hydro Spinning Reserve 28
1,358,491 Yale Dam Spillway Upgrades Evaluation 29
1,330,906 Hunter U3 East & West Waterwall Replacement 30
1,326,346 Blundell Plant and Steam Field Controls Update 31
1,246,828 Viva Naughton FERC Production Compliance 32
1,221,259 Oneida Dam Concrete Section Replacement 33
1,171,263 Wallowa Falls Relicensing Implementation 34
1,134,406 Bear River Hydro Flood and Structural Assessment Project 35
1,064,023 Blundell U2 Generator Replacement 36
Transmission: 37
492,989,748 Aeolus - Bridger/Anticline 500kV Line** 38
122,483,758 Aeolus - Mona 500kV Line 39
78,364,837 Boardman - Hemingway 500kV Line 40
65,939,122 Populus - Hemingway 500kV Line 41
46,204,915 Anticline - Populus 500kV Line 42
FERC FORM NO. 1 (ED. 12-87) Page 216
43 TOTAL 2,002,448,524
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
PacifiCorp X
/ /2019/Q4
Line
No.
Description of Project Construction work in progress -
(b)(a)Electric (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
45,232,734 Vantage - Pomona Heights 230kV Line 1
32,629,477 Q712 Cedar Springs Wind 1** 2
29,115,009 Q707 TB Flats 1** 3
20,233,158 Vitesse - Facebook 60 MW Load Addition 4
16,302,631 Goshen - Sugarmill - Rigby 161kV Line 5
15,087,754 Oquirrh - Terminal 345kV Line 6
13,808,847 Windstar - Shirley Basin 230kV Line 7
8,629,805 Goshen Substation Install 3rd 345 - 161kV 700 MVA Transformer TPL 8
8,374,239 Sams Valley New 500 - 230kV Substation 9
7,431,750 Rexburg Substation - Install 161kV Source from Rigby 10
5,941,576 Populus - Terminal 345kV Line - Staker Relocation 11
5,109,490 Jordanelle - Midway 138kV Line 12
3,425,131 Spanish Fork Substation 345 - 138kV Transformer Upgrade TPL 13
3,152,267 Q737 Cove Mountain Solar 2, LLC 14
2,707,709 Q641 Cove Mountain Solar 15
1,968,620 Bull River to Saratoga Rebuild for Network Customer 16
1,961,182 Outlook Substation: Replace Transformer 17
1,773,320 State Prison at Salt Lake City 8 MW Transmission Load 18
1,651,357 El Monte Substation Expansion 19
1,282,453 Hunter U2 Generator Step-Up Transformer Replacement 20
1,277,862 90th South Substation Bus Tie Breaker Upgrade 21
1,255,177 Yreka Substation 115 - 69kV Transformer Addition 22
1,224,580 Siphon Tap - Pingree Junction 138kV Line Reconductor 23
1,062,514 Idaho Power: Borah-Adelaide-Midpoint #1: Replace Wood Poles with Steel 24
1,006,829 Dry Gulch Substation Replace 115 - 69kV Fixed-Ratio Transformer 25
Distribution: 26
16,621,150 Utah Advanced Metering Infrastructure 27
8,743,465 Boise White Paper, LLC Interconnect Load Addition 28
6,774,948 Naples New 138 - 12.5kV Substation TPL 29
5,326,569 Draper Increase Capacity and Convert to 138kV 30
4,341,869 Lassen Substation - New Substation 31
3,537,945 CPC International Apple Co. Load Addition 32
2,588,767 Kennedy Substation Convert to Distribution 33
2,248,800 Idaho Advanced Metering Infrastructure 34
1,020,686 Murphy Brown LLC - 15.29 kW Load 35
General: 36
2,174,321 Monarch PAC6 Upgrade and Hardware 37
1,161,601 Replacement of DMX Fiber Optic Communications Infrastructure/Equip - Southern Oregon 38
39
132,782,995Miscellaneous Projects each under $1,000,000 40
41
** Energy Vision 2020 projects 42
FERC FORM NO. 1 (ED. 12-87) Page 216.1
43 TOTAL 2,002,448,524
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
PacifiCorp X
/ /2019/Q4
Line
No.
Item Total
(c)(b)(a)(d)
Section A. Balances and Changes During Year
(c+d+e)Electric Plant inService Electric Plant Held for Future Use Electric PlantLeased to Others(e)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Balance Beginning of Year 1 10,291,136,026 10,291,136,026
Depreciation Provisions for Year, Charged to 2
(403) Depreciation Expense 3 879,989,526 879,989,526
(403.1) Depreciation Expense for Asset
Retirement Costs
4
(413) Exp. of Elec. Plt. Leas. to Others 5
Transportation Expenses-Clearing 6
Other Clearing Accounts 7
Other Accounts (Specify, details in footnote): 8 22,051,799 22,051,799
9
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
10 902,041,325 902,041,325
Net Charges for Plant Retired: 11
Book Cost of Plant Retired 12 1,080,709,354 1,080,709,354
Cost of Removal 13 69,673,217 69,673,217
Salvage (Credit) 14 3,872,248 3,872,248
TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
15 1,146,510,323 1,146,510,323
Other Debit or Cr. Items (Describe, details in
footnote):
16 38,914,046 38,914,046
17
Book Cost or Asset Retirement Costs Retired 18
Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
19 10,085,581,074 10,085,581,074
Steam Production 20
Section B. Balances at End of Year According to Functional Classification
3,818,512,531 3,818,512,531
Nuclear Production 21
Hydraulic Production-Conventional 22 452,937,506 452,937,506
Hydraulic Production-Pumped Storage 23
Other Production 24 530,489,089 530,489,089
Transmission 25 1,863,152,997 1,863,152,997
Distribution 26 2,926,917,777 2,926,917,777
Regional Transmission and Market Operation 27
General 28 493,571,174 493,571,174
TOTAL (Enter Total of lines 20 thru 28) 29 10,085,581,074 10,085,581,074
Page 219FERC FORM NO. 1 (REV. 12-05)
Schedule Page: 219 Line No.: 4 Column: b
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as
either a regulatory asset or liability.

Schedule Page: 219 Line No.: 8 Column: b
Account 143, Other accounts receivable: depreciation expense
billed to joint owners $ 245,756
Account 182.3, Other regulatory assets or Account 254, Other regulatory
liabilities: asset retirement obligations asset depreciation 9,036,800
Account 182.3, Other regulatory assets: deferral of Carbon depreciation (5,081,468)
Account 182.3, Other regulatory assets: deferral of increased depreciation,
due to depreciation study rates, net of amortization (560,206)
Transportation depreciation charged to operations and maintenance
expense and construction work in progress based on usage activity 16,386,376
Account 503, Steam from other sources: Blundell depreciation 2,024,541
Total Other Accounts $ 22,051,799

Schedule Page: 219 Line No.: 16 Column: b
Reclassification of accrued removal and spend on asset retirement
obligations that were included in lines 3 and 13 $ 11,194,379
Other items include: 27,719,667
- Recovery from third parties for asset relocations and damaged property
- Insurance recoveries
- Adjustments of reserve related to electric plant sold and/or purchased
- Reclassifications from electric plant
Total Other Debit or Cr. Items $ 38,914,046

Schedule Page: 219 Line No.: 20 Column: c
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service
(c)
Steam Production 20(c) $ 3,818,512,531
Less: Asset retirement obligations related cost components(1) 68,821,875
Revised Steam Production $ 3,749,690,656
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 219 Line No.: 22 Column: c
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service
(c)
Hydraulic Production - Conventional 22(c) $ 452,937,506
Less: Asset retirement obligations related cost components(1) 2,675,845
Revised Hydraulic Production - Conventional $ 450,261,661
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.

Schedule Page: 219 Line No.: 24 Column: c
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service
(c)
Other Production 24(c) $ 530,489,089
Less: Asset retirement obligations related cost components(1) (954,086)
Revised Other Production $ 531,443,175
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.

Schedule Page: 219 Line No.: 26 Column: c
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service
(c)
Distribution 26(c) $ 2,926,917,777
Less: Asset retirement obligations related cost components(1) 972,066
Revised Distribution $ 2,925,945,711
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 219 Line No.: 28 Column: c
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service
(c)
General 28(c) $ 493,571,174
Less: Asset retirement obligations related cost components(1) (184,898)
Revised General $ 493,756,072
(1) In accordance with 18 C.F.R. §35.18(a-c) a public utility that files a transmission
rate schedule, tariff or service agreement under §35.12 or §35.13 and has recorded an
asset retirement obligation on its books, but is not seeking recovery of the asset
retirement costs in rates, must remove all asset-retirement-obligations-related cost
components from the cost of service supporting its proposed rates.

Schedule Page: 219 Line No.: 29 Column: c
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Item
(a)
Ref.
Line No.
(Column)
Electric Plant
in Service
(c)
Revised Steam Production(1) $ 3,749,690,656
Nuclear Production 21(c) -
Revised Hydraulic Production - Conventional(2) 450,261,661
Hydraulic Production - Pumped Storage 23(c) -
Revised Other Production(3) 531,443,175
Revised Transmission 25(c) 1,863,152,997
Revised Distribution(4) 2,925,945,711
Regional Transmission and Market Operation 27(c) -
Revised General(5) 493,756,072
Revised TOTAL $10,014,250,272
(1) Refer to footnote on page 219, line no. 20, column (c)
(2) Refer to footnote on page 219, line no. 22, column (c)
(3) Refer to footnote on page 219, line no. 24, column (c)
(4) Refer to footnote on page 219, line no. 26, column (c)
(5) Refer to footnote on page 219, line no. 28, column (c)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
PacifiCorp X
/ /2019/Q4
Line
No.
Description of Investment Date Acquired
(c)(b)(a)
Amount of Investment atBeginning of YearDate Of Maturity (d)
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),(f),(g) and (h)
(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
1973Pacific Minerals, Inc. 1
1 Common Stock 2
47,960,000 Paid-in Capital 3
96,380,655 Undistributed Subsidiary Earnings 4
144,340,656 SUBTOTAL 5
6
1990Energy West Mining Company 7
1,000 Common Stock 8
1,000 SUBTOTAL 9
10
1991Glenrock Coal Company 11
1 Common Stock 12
1 SUBTOTAL 13
14
1992Interwest Mining Company 15
1,000 Common Stock 16
1,000 SUBTOTAL 17
18
1992Trapper Mining Inc. 19
6,038,000 Members' Equity 20
8,017,743 Undistributed Subsidiary Earnings 21
14,055,743 SUBTOTAL 22
23
2011Fossil Rock Fuels, LLC 24
25,001,770 Paid-in Capital 25
847 Undistributed Subsidiary Earnings 26
25,002,617 SUBTOTAL 27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89) Page 224
42 Total Cost of Account 123.1 $TOTAL 183,401,017 76,336,772
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
Equity in Subsidiary Earnings of Year Revenues for Year Amount of Investment atEnd of Year Gain or Loss from InvestmentDisposed of(e) (f) (g) (h)
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.1
1
1 2
47,960,000 3
115,793,091 19,412,436 4
163,753,092 19,412,436 5
6
7
1,000 8
1,000 9
10
11
1 12
1 13
14
15
1,000 16
1,000 17
18
19
6,038,000 20
9,771,559 1,754,143 21
15,809,559 1,754,143 22
23
24
22,336,770 25
579 2,396,732 26
22,337,349 2,396,732 27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89) Page 225
42 23,563,311 201,902,001
Schedule Page: 224 Line No.: 1 Column: a
Pacific Minerals, Inc. is a wholly owned subsidiary of PacifiCorp that holds a 66.67%
ownership interest in Bridger Coal Company. Bridger Coal Company is a coal mining joint
venture with Idaho Energy Resources Company, a subsidiary of Idaho Power Company.

Schedule Page: 224 Line No.: 21 Column: g
During the year ended December 31, 2019, Trapper Mining Inc., a subsidiary of PacifiCorp,
paid a distribution of $327 to PacifiCorp.
Schedule Page: 224 Line No.: 25 Column: g
During the year ended December 31, 2019, Fossil Rock Fuels, LLC, a wholly owned subsidiary
of PacifiCorp, returned $2,665,000 of capital to PacifiCorp.
Schedule Page: 224 Line No.: 26 Column: g
During the year ended December 31, 2019, Fossil Rock Fuels, LLC, a wholly owned subsidiary
of PacifiCorp, paid distributions of $2,397,000 to PacifiCorp.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MATERIALS AND SUPPLIES
PacifiCorp X
/ /2019/Q4
Line
No.
Account Balance Balance
(c)(b)(a)
Department orDepartments which
(d)
Beginning of Year End of Year Use Material
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
179,588,705 Electric 150,404,985 1 Fuel Stock (Account 151)
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
161,139,297 Electric 162,913,741 5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
63,541,336 Electric 67,226,405 7 Production Plant (Estimated)
786,256 Electric 852,235 8 Transmission Plant (Estimated)
12,201,122 Electric 13,010,416 9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant
(Estimated)
26,420 Electric 20,127 11 Assigned to - Other (provide details in footnote)
237,694,431 244,022,924 12 TOTAL Account 154 (Enter Total of lines 5 thru 11)
13 Merchandise (Account 155)
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
417,283,136 394,427,909 20 TOTAL Materials and Supplies (Per Balance Sheet)
Page 227FERC FORM NO. 1 (REV. 12-05)
Schedule Page: 227 Line No.: 11 Column: b
General plant materials and supplies
Schedule Page: 227 Line No.: 11 Column: c
General plant materials and supplies

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Allowances (Accounts 158.1 and 158.2)
PacifiCorp X
/ /2019/Q4
Line
No.
SO2 Allowances Inventory Current Year
(b)(a)(Account 158.1)No. Amt.(c)No.(d)Amt.(e)
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
Instruction 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), starting with the following year, and allowances for the remaining
succeeding years in columns (j)-(k).
5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
2020
936,977.00 156,646.00Balance-Beginning of Year 1
2
Acquired During Year: 3
Issued (Less Withheld Allow) 4
Returned by EPA 5
6
7
Purchases/Transfers: 8
9
10
11
12
13
14
Total 15
16
Relinquished During Year: 17
25,625.00 Charges to Account 509 18
Other: 19
20
Cost of Sales/Transfers: 21
22
23
24
25
26
27
Total 28
911,352.00 156,646.00Balance-End of Year 29
30
Sales: 31
Net Sales Proceeds(Assoc. Co.) 32
Net Sales Proceeds (Other) 33
Gains 34
Losses 35
Allowances Withheld (Acct 158.2)
2,259.00 2,259.00Balance-Beginning of Year 36
Add: Withheld by EPA 37
Deduct: Returned by EPA 38
2,259.00Cost of Sales 39
2,259.00Balance-End of Year 40
41
Sales: 42
Net Sales Proceeds (Assoc. Co.) 43
Net Sales Proceeds (Other) 44
Gains 45
Losses 46
FERC FORM NO. 1 (ED. 12-95) Page 228a
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Allowances (Accounts 158.1 and 158.2)
PacifiCorp X
/ /2019/Q4
Line
No.(f) (j)No. Amt.(g)No.(h)Amt.(i)No. Amt. No. Amt.(k) (l) (m)
Future Years Totals
(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. Report 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.
2021 2022
1 4,072,755.00 156,647.00 156,646.00 5,479,671.00
2
3
4 156,644.00 156,644.00
5
6
7
8
9
10
11
12
13
14
15
16
17
18 25,625.00
19
20
21
22
23
24
25
26
27
28
29 4,229,399.00 156,647.00 156,646.00 5,610,690.00
30
31
32
33
34
35
36 110,921.00 2,259.00 2,259.00 119,957.00
37 4,528.00 4,528.00
38
39 2,269.00 4,528.00
40 113,180.00 2,259.00 2,259.00 119,957.00
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-95) Page 229a
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. In column (a) provide the name of the study.
4. In column (b) report the cost incurred to perform the study at the end of period.
5. In column (c) report the account charged with the cost of the study.
6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
7. In column (e) report the account credited with the reimbursement received for performing the study.
the Period
Transmission Studies 0.0 0 1
181Q2469 561.6 2
149Q2517 561.6 3
1,267Q2518 561.6 4
149Q2527 561.6 5
149Q2528 561.6 6
14,846Q2574 561.6 7
972Q2578 561.6 972 456 8
2,512Q2587 561.6 2,512 456 9
1,071Q2588 561.6 10
447Q2591 561.6 11
298Q2592 561.6 12
149Q2594 561.6 149 456 13
21,446Q2599 561.6 14
1,531Q2602 561.6 1,531 456 15
4,987Q2612 561.6 4,987 456 16
1,877Q2629 561.6 17
380Q2651 561.6 380 456 18
809Q2652 561.6 809 456 19
149Q2687 561.6 20
Generation Studies 0.0 0 21
1,615GIQ0409 561.7 1,615 456 22
346GIQ0650 561.7 346 456 23
9,103GIQ0687 561.7 9,103 456 24
1,526GIQ0707 561.7 1,526 456 25
1,217GIQ0708 561.7 1,217 456 26
11,087GIQ0712 561.7 11,087 456 27
5,668GIQ0713 561.7 5,668 456 28
270GIQ0715 561.7 270 456 29
9,013GIQ0718 561.7 9,013 456 30
643GIQ0719 561.7 643 456 31
76GIQ0721 561.7 76 456 32
37GIQ0737 561.7 37 456 33
2,918GIQ0738 561.7 2,918 456 34
15,313GIQ0739 561.7 15,313 456 35
115GIQ0741 561.7 115 456 36
4,740GIQ0745 561.7 4,740 456 37
308GIQ0763 561.7 308 456 38
423GIQ0777 561.7 423 456 39
346GIQ0778 561.7 346 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 0.0 0 1
1,795Q2702 561.6 2
( 10,559)Order 45045642 561.6 ( 10,559) 456 3
37,718Pre-Application Studies - East 561.6 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
5,616GIQ0783 561.7 5,616 456 22
115GIQ0784 561.7 115 456 23
803GIQ0785 561.7 803 456 24
312GIQ0786 561.7 312 456 25
2,349GIQ0787 561.7 2,349 456 26
1,443GIQ0788 561.7 1,443 456 27
1,462GIQ0789 561.7 1,462 456 28
421GIQ0792 561.7 421 456 29
5,540GIQ0799 561.7 5,540 456 30
2,955GIQ0801 561.7 2,955 456 31
4,215GIQ0802 561.7 4,215 456 32
4,174GIQ0804 561.7 4,174 456 33
26,842GIQ0805 561.7 26,842 456 34
5,049GIQ0807 561.7 5,049 456 35
2,397GIQ0811 561.7 2,397 456 36
214GIQ0815 561.7 214 456 37
21,612GIQ0820 561.7 38
29,715GIQ0821 561.7 39
11,991GIQ0822 561.7 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 0.0 0 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
19,537GIQ0823 561.7 22
15,963GIQ0824 561.7 15,963 456 23
4,675GIQ0825 561.7 4,675 456 24
5,039GIQ0835 561.7 5,039 456 25
837GIQ0836 561.7 837 456 26
1,425GIQ0838 561.7 1,425 456 27
307GIQ0839 561.7 307 456 28
1,093GIQ0840 561.7 1,093 456 29
616GIQ0846 561.7 616 456 30
192GIQ0849 561.7 192 456 31
4,898GIQ0850 561.7 4,898 456 32
375GIQ0853 561.7 375 456 33
3,721GIQ0855 561.7 3,721 456 34
2,624GIQ0858 561.7 35
5,472GIQ0859 561.7 36
1,987GIQ0860 561.7 37
3,058GIQ0861 561.7 38
9,714GIQ0862 561.7 9,714 456 39
149GIQ0863 561.7 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
19GIQ0864 561.7 19 456 22
19GIQ0865 561.7 19 456 23
115GIQ0867 561.7 115 456 24
6,475GIQ0868 561.7 6,475 456 25
77GIQ0871 561.7 77 456 26
38GIQ0872 561.7 38 456 27
7,878GIQ0876 561.7 28
103GIQ0877 561.7 103 456 29
38GIQ0883 561.7 38 456 30
154GIQ0898 561.7 154 456 31
458GIQ0905 561.7 458 456 32
7,735GIQ0906 561.7 7,735 456 33
7,815GIQ0907 561.7 7,815 456 34
173GIQ0915 561.7 173 456 35
135GIQ0916 561.7 135 456 36
135GIQ0917 561.7 135 456 37
550GIQ0918 561.7 38
193GIQ0919 561.7 39
38GIQ0920 561.7 38 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
38GIQ0925 561.7 38 456 22
58GIQ0933 561.7 58 456 23
19GIQ0934 561.7 19 456 24
77GIQ0938 561.7 77 456 25
499GIQ0940 561.7 499 456 26
350GIQ0941 561.7 350 456 27
230GIQ0947 561.7 230 456 28
191GIQ0948 561.7 191 456 29
153GIQ0949 561.7 153 456 30
3,411GIQ0953 561.7 3,411 456 31
( 51)GIQ0955 561.7 ( 51) 456 32
272GIQ0957 561.7 272 456 33
154GIQ0958 561.7 154 456 34
77GIQ0959 561.7 77 456 35
77GIQ0961 561.7 77 456 36
77GIQ0965 561.7 77 456 37
154GIQ0968 561.7 154 456 38
( 13)GIQ0971 561.7 ( 13) 456 39
7,780GIQ0974 561.7 7,780 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
77GIQ0976 561.7 77 456 22
115GIQ0995 561.7 115 456 23
38GIQ0996 561.7 38 456 24
116GIQ0999 561.7 116 456 25
1,559GIQ1003 561.7 1,559 456 26
317GIQ1007 561.7 317 456 27
481GIQ1008 561.7 481 456 28
4,123GIQ1009 561.7 4,123 456 29
138GIQ1012 561.7 138 456 30
77GIQ1014 561.7 77 456 31
568GIQ1019 561.7 568 456 32
72GIQ1026 561.7 33
77GIQ1027 561.7 77 456 34
58GIQ1028 561.7 58 456 35
4,402GIQ1029 561.7 4,402 456 36
58GIQ1031 561.7 58 456 37
58GIQ1032 561.7 58 456 38
58GIQ1033 561.7 58 456 39
38GIQ1034 561.7 38 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
96GIQ1035 561.7 96 456 22
19GIQ1036 561.7 19 456 23
77GIQ1037 561.7 24
114GIQ1038 561.7 114 456 25
37GIQ1039 561.7 37 456 26
1,045GIQ1043 561.7 1,045 456 27
38GIQ1045 561.7 38 456 28
58GIQ1046 561.7 58 456 29
19GIQ1051 561.7 19 456 30
38GIQ1052 561.7 38 456 31
58GIQ1053 561.7 58 456 32
58GIQ1054 561.7 58 456 33
3,217GIQ1055 561.7 3,217 456 34
19GIQ1057 561.7 19 456 35
19GIQ1058 561.7 19 456 36
19GIQ1059 561.7 19 456 37
19GIQ1060 561.7 19 456 38
19GIQ1061 561.7 19 456 39
1,631GIQ1063 561.7 1,631 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.6
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
115GIQ1065 561.7 115 456 22
19GIQ1066 561.7 19 456 23
19GIQ1067 561.7 19 456 24
96GIQ1068 561.7 96 456 25
102GIQ1070 561.7 102 456 26
19GIQ1071 561.7 19 456 27
19GIQ1072 561.7 19 456 28
71GIQ1073 561.7 71 456 29
148GIQ1074 561.7 148 456 30
419GIQ1075 561.7 419 456 31
143GIQ1076 561.7 143 456 32
267GIQ1077 561.7 267 456 33
228GIQ1078 561.7 228 456 34
14,992GIQ1079 561.7 14,992 456 35
157GIQ1080 561.7 157 456 36
72GIQ1081 561.7 72 456 37
259GIQ1083 561.7 259 456 38
363GIQ1084 561.7 363 456 39
256GIQ1085 561.7 256 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
4,002GIQ1086 561.7 4,002 456 22
448GIQ1087 561.7 448 456 23
1,191GIQ1088 561.7 1,191 456 24
226GIQ1089 561.7 226 456 25
226GIQ1090 561.7 226 456 26
264GIQ1091 561.7 264 456 27
1,639GIQ1092 561.7 1,639 456 28
1,164GIQ1093 561.7 1,164 456 29
931GIQ1094 561.7 931 456 30
782GIQ1095 561.7 782 456 31
1,373GIQ1096 561.7 1,373 456 32
1,720GIQ1097 561.7 1,720 456 33
1,416GIQ1098 561.7 1,416 456 34
1,586GIQ1099 561.7 1,586 456 35
1,328GIQ1100 561.7 1,328 456 36
931GIQ1101 561.7 931 456 37
1,086GIQ1102 561.7 1,086 456 38
1,882GIQ1103 561.7 1,882 456 39
1,291GIQ1104 561.7 1,291 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.8
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
1,528GIQ1105 561.7 1,528 456 22
1,381GIQ1106 561.7 1,381 456 23
231GIQ1107 561.7 231 456 24
1,469GIQ1108 561.7 1,469 456 25
1,327GIQ1109 561.7 1,327 456 26
1,599GIQ1110 561.7 1,599 456 27
741GIQ1111 561.7 741 456 28
1,012GIQ1112 561.7 1,012 456 29
5,431GIQ1113 561.7 5,431 456 30
6,964GIQ1114 561.7 6,964 456 31
347GIQ1115 561.7 347 456 32
1,383GIQ1116 561.7 1,383 456 33
2,096GIQ1117 561.7 2,096 456 34
1,865GIQ1118 561.7 1,865 456 35
1,014GIQ1119 561.7 1,014 456 36
1,420GIQ1120 561.7 1,420 456 37
1,034GIQ1121 561.7 1,034 456 38
58GIQ1122 561.7 58 456 39
1,578GIQ1123 561.7 1,578 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.9
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
996GIQ1124 561.7 996 456 22
561GIQ1125 561.7 561 456 23
1,241GIQ1126 561.7 1,241 456 24
1,457GIQ1127 561.7 1,457 456 25
792GIQ1128 561.7 792 456 26
1,270GIQ1129 561.7 1,270 456 27
1,655GIQ1130 561.7 1,655 456 28
1,552GIQ1131 561.7 1,552 456 29
1,456GIQ1132 561.7 1,456 456 30
977GIQ1133 561.7 977 456 31
662GIQ1134 561.7 662 456 32
959GIQ1135 561.7 959 456 33
671GIQ1136 561.7 671 456 34
538GIQ1137 561.7 538 456 35
600GIQ1138 561.7 600 456 36
447GIQ1139 561.7 447 456 37
5,622GIQ1140 561.7 5,622 456 38
250GIQ1141 561.7 250 456 39
250GIQ1142 561.7 250 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.10
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
1,472GIQ1143 561.7 1,472 456 22
1,399GIQ1144 561.7 1,399 456 23
1,023GIQ1145 561.7 1,023 456 24
1,245GIQ1146 561.7 1,245 456 25
1,729GIQ1147 561.7 1,729 456 26
1,391GIQ1148 561.7 1,391 456 27
1,427GIQ1149 561.7 1,427 456 28
752GIQ1150 561.7 752 456 29
980GIQ1151 561.7 980 456 30
1,559GIQ1152 561.7 1,559 456 31
1,001GIQ1153 561.7 1,001 456 32
472GIQ1154 561.7 472 456 33
509GIQ1155 561.7 509 456 34
435GIQ1156 561.7 435 456 35
1,504GIQ1157 561.7 1,504 456 36
3,973GIQ1158 561.7 3,973 456 37
1,721GIQ1159 561.7 1,721 456 38
1,359GIQ1160 561.7 1,359 456 39
1,190GIQ1161 561.7 1,190 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.11
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
616GIQ1162 561.7 616 456 22
674GIQ1163 561.7 674 456 23
515GIQ1164 561.7 515 456 24
1,660GIQ1165 561.7 1,660 456 25
1,111GIQ1166 561.7 1,111 456 26
789GIQ1167 561.7 789 456 27
1,232GIQ1168 561.7 1,232 456 28
1,475GIQ1169 561.7 1,475 456 29
1,320GIQ1170 561.7 1,320 456 30
1,018GIQ1171 561.7 1,018 456 31
1,741GIQ1172 561.7 1,741 456 32
1,139GIQ1173 561.7 1,139 456 33
1,480GIQ1174 561.7 1,480 456 34
1,493GIQ1175 561.7 1,493 456 35
1,160GIQ1176 561.7 1,160 456 36
626GIQ1177 561.7 626 456 37
774GIQ1178 561.7 774 456 38
417GIQ1179 561.7 417 456 39
554GIQ1180 561.7 554 456 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.12
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
PacifiCorp X
/ /2019/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 0.0 0 21
466GIQ1181 561.7 466 456 22
1,020GIQ1182 561.7 1,020 456 23
1,047GIQ1183 561.7 1,047 456 24
250GIQ1184 561.7 250 456 25
1,383GIQ1186 561.7 1,383 456 26
583GIQ1188 561.7 583 456 27
907GIQ1189 561.7 907 456 28
400GIQ1190 561.7 400 456 29
58GIQ1191 561.7 58 456 30
12,578Pre-Application Studies - East 561.7 12,578 456 31
7,058Pre-Application Studies - West 561.7 7,058 456 32
44Customer Studies Accrual 561.7 33
34
35
36
37
38
39
40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page 231.13
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER REGULATORY ASSETS (Account 182.3)
PacifiCorp X
/ /
2019/Q4
Line
No.
Description and Purpose of Debits CREDITS
Written off During the
Quarter /Year Account
Charged (d)(c)(a)
Balance at end of
Current Quarter/Year
(e)
Other Regulatory Assets Written off During
the Period Amount
(f)
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.
Balance at Beginning
of Current
Quarter/Year
(b)
8,587,281 8,019,942 9,803,790908 9,236,451DSM Balancing Account - WY 1
96,833 158,773 134,304908 196,244Irrigation Load Control - OR 2
6,009,612 5,982,332 2,662,501555 2,635,221Deferred Excess Net Power Costs - CA 3
18,176,983 25,040,842 11,701,152555 18,565,011Deferred Excess Net Power Costs - ID 4
2,980,283 2,980,283Deferred Excess Net Power Costs - OR 5
30,371,764 53,028,498 10,095,099182.3,555 32,751,833Deferred Excess Net Power Costs - UT 6
5,512,772 18,775,811 319,363555 13,582,402Deferred Excess Net Power Costs - WY 7
1,038,542 1,059,536456 20,994Deferred Excess RECs in Rates - UT 8
764,224 172,562 606,758456 15,096Deferred Excess RECs in Rates - WY 9
36,250 34,344 2,328282,283 422Solar ITC Basis Adjustment Regulatory Asset 10
442,471,226 421,866,172 22,230,289 1,625,235Pension 11
5,713,302 6,004,602 291,300Other Postretirement 12
862,273 449,069 413,204Postemployment Costs 13
51,728 27,927 23,801407.3Powerdale Decommissioning - ID (10) 14
957,276 478,637 478,639403Carbon Plant Regulatory Asset - ID (6) 15
6,889,283 3,444,642 3,444,641403Carbon Plant Regulatory Asset - UT (6) 16
2,316,375 1,158,187 1,158,188403Carbon Plant Regulatory Asset - WY (6) 17
3,118,823 3,118,823Carbon Plant Inventory Regulatory Asset 18
25,487,600 25,487,600Cholla Plant Unit No. 4 Regulatory Asset 19
1,600,540 1,472,497 128,043403Depreciation Study Deferral - UT (17) 20
5,527,386 5,085,195 442,191403Depreciation Study Deferral - WY (17) 21
525,000 490,000 35,000557Generating Plant Liquidated Damages - UT 22
1,190,128 1,135,840 54,288557Generating Plant Liquidated Damages - WY 23
15,672,342 12,002,814 4,263,002404 593,474Klamath Hydroelectric Relicensing Costs - UT (10) 24
108,755 56,567 52,188456Washington Colstrip Unit No. 3 (22) 25
82,555,814 85,346,686 5,328,927 8,119,799Environmental Costs (10) 26
118,653,129 140,206,260 21,553,131Asset Retirement Obligations Regulatory Difference 27
78,751,716 60,164,142 18,587,574242Unamortized Contract Values 28
95,777,883 62,098,272 33,679,611175,244Unrealized Loss on Derivative Contracts 29
5,125,795 5,634,041 4,789,865555,908 5,298,111Solar Feed-In Tariff Deferral - OR (1) 30
497,724 106,426908 604,150Oregon Community Solar Program 31
1,663,323 1,724,900 137,691908 199,268Solar Incentive Subscriber Program - UT 32
115,099 635,668555 520,569Renewable Portfolio Standards Compliance - OR (1) 33
47,829 47,903 161,079555 161,153Renewable Portfolio Standards Compliance - WA (1) 34
150,000 300,000 150,000Protocol - MSP Deferral - ID 35
8,800,000 13,200,000 4,400,000Protocol - MSP Deferral - UT 36
2,399,998 4,000,000 1,600,002Protocol - MSP Deferral - WY 37
41,995 43,749 1,754Deferred Intervenor Funding Grants - CA 38
66,865 66,865Deferred Intervenor Funding Grants - ID 39
926,951 1,496,800 569,849Deferred Intervenor Funding Grants - OR 40
2,179,411 1,053,102 1,468,918924 342,609Catastrophic Event Regulatory Asset - CA (2) 41
281,623 9,665 271,958142Alternative Rate for Energy (CARE) - CA 42
974,878 974,878Washington Low Income Program 43
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER REGULATORY ASSETS (Account 182.3)
PacifiCorp X
/ /
2019/Q4
Line
No.
Description and Purpose of Debits CREDITS
Written off During the
Quarter /Year Account
Charged (d)(c)(a)
Balance at end of
Current Quarter/Year
(e)
Other Regulatory Assets Written off During
the Period Amount
(f)
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.
Balance at Beginning
of Current
Quarter/Year
(b)
493,494 378,170 1,499,231501 1,383,907Deferred Overburden Cost - ID 1
1,388,565 1,064,073 4,218,452501 3,893,960Deferred Overburden Cost - WY 2
7,129,334 8,545,344 1,416,010BPA Balancing Account - OR 3
197,289 197,289BPA Balancing Account - WA 4
1,084,466 942,723 937,095421.1,501 795,352Property Sales Balancing Account - OR 5
3,053,229 10,647,303 7,068,568924 14,662,642Property Insurance Reserve - OR 6
265,765 291,933 26,168Misc. Regulatory Assets/Liabilities - OR 7
6,648 6,648254Depreciation Deferral - WA 8
137,874,223 124,908,231 16,037,465 3,071,473Utah Mine Disposition 9
429,848 347,317 82,531407.3Preferred Stock Redemption Loss - UT (10) 10
68,808 55,490 13,318407.3Preferred Stock Redemption Loss - WA (10) 11
148,133 119,691 28,442407.3Preferred Stock Redemption Loss - WY (10) 12
198,710 203,210 4,500Mobile Home Park Conversion - CA 13
48,792 817,388 768,596Transportation Electrification Program - OR 14
137,015 137,015Transportation Electrification Program - WA 15
3,173,502 3,173,502Wildfire Mitigation Plan - CA 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
1,107,326,144TOTAL :44 1,119,161,023 170,172,374 182,007,253
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232.1
Schedule Page: 232 Line No.: 3 Column: a
Weighted average remaining life is approximately one year for deferred excess net power
cost mechanisms being amortized.
Schedule Page: 232 Line No.: 4 Column: a
Weighted average remaining life is approximately one year for deferred excess net power
cost mechanisms being amortized.
Schedule Page: 232 Line No.: 6 Column: a
Weighted average remaining life is approximately one year for deferred excess net power
cost mechanisms being amortized.
Schedule Page: 232 Line No.: 7 Column: a
Weighted average remaining life is approximately one year for deferred excess net power
cost mechanisms being amortized.

Schedule Page: 232 Line No.: 8 Column: a
Weighted average remaining life is approximately one year for deferred excess renewable
energy credits in rates being amortized.
Schedule Page: 232 Line No.: 9 Column: a
Weighted average remaining life is approximately one year for deferred excess renewable
energy credits in rates being amortized.
Schedule Page: 232 Line No.: 11 Column: a
Weighted average remaining life being amortized is 21 years. Substantially represents
amounts not yet recognized as a component of net periodic benefit cost that are expected
to be included in rates when recognized.
Schedule Page: 232 Line No.: 11 Column: d
Pensions are associated with labor and generally charged to operations and maintenance
expense and construction work in progress. Pension settlements, curtailments and
remeasurement date changes are charged to Account 926, Employee pensions and benefits.

Schedule Page: 232 Line No.: 12 Column: a
Weighted average remaining life of portion being amortized is 13 years. Substantially
represents amounts not yet recognized as a component of net periodic benefit cost that are
expected to be included in rates when recognized.

Schedule Page: 232 Line No.: 12 Column: d
Other postretirement costs are associated with labor and generally charged to operations
and maintenance expense and construction work in progress. Other postretirement
remeasurement date changes and Wyoming's share of settlement losses are charged to Account
926, Employee pensions and benefits.
Schedule Page: 232 Line No.: 13 Column: a
Weighted average remaining life is five years.
Schedule Page: 232 Line No.: 13 Column: d
Other postemployment costs are associated with labor and generally charged to operations
and maintenance expense and construction work in progress.

Schedule Page: 232 Line No.: 22 Column: a
Weighted average remaining life is 14 years.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 232 Line No.: 23 Column: a
Weighted average remaining life is 23 years.

Schedule Page: 232 Line No.: 26 Column: d
Account 514, Maintenance of miscellaneous steam plant
Account 545, Maintenance of miscellaneous hydraulic plant
Account 554, Maintenance of miscellaneous other power generation plant
Account 598, Maintenance of miscellaneous distribution plant
Account 935, Maintenance of general plant

Schedule Page: 232 Line No.: 28 Column: a
Weighted average remaining life is four years. Represents frozen values of contracts
previously accounted for as derivatives and recorded at fair value.
Schedule Page: 232 Line No.: 29 Column: a
Weighted average remaining life is three years.
Schedule Page: 232.1 Line No.: 9 Column: a
Weighted average remaining life is approximately three years for closure costs incurred to
date considered probable of recovery.
Schedule Page: 232.1 Line No.: 9 Column: d
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 501, Fuel
Account 506, Miscellaneous steam power expenses

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MISCELLANEOUS DEFFERED DEBITS (Account 186)
PacifiCorp X
/ /2019/Q4
Line
No.
Description of Miscellaneous Debits CREDITS
Account
(c)(b)(a)
Balance at
End of Year
(d)
Deferred Debits Amount
(e)
Balance at
Beginning of Year
(f)Charged
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. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
140,970 95,250 45,720557Lacomb Irrigation (24) 1
870,320 829,040 41,280557Bogus Creek (41) 2
Mead Phoenix Availability and 3
10,434,083 9,847,472 586,611565Transmission Charge 4
16,763 1,290 15,473557TGS Buyout (23) 5
979,032 1,061,472 67,560 150,000 131Point-to-Point Transmission 6
3,018,937 2,847,244 171,693557Hermiston Swap (40) 7
Deferred Coal Costs - Wyodak 8
1,340,726 1,005,544 335,182501Settlement (22) 9
106,895 67,510 39,385931LT Lease Commissions Prepaid 10
21,681,927 29,772,237 8,090,310Lake Side Maintenance Prepaid 11
8,719,256 14,099,522 5,380,266Lake Side 2 Maintenance Prepaid 12
12,812,284 17,691,254 4,878,970Chehalis Maintenance Prepaid 13
11,103,203 17,007,357 5,904,154Currant Creek Maint. Prepaid 14
679,935 679,935Seven Mile Hill Maint. Prepaid 15
133,927 133,927Seven Mile Hill II Main Prepaid 16
65,248 69,087 134,335 454Lease Incentives 17
1,849,374 1,683,361 701,013 535,000 427,431Credit Agreement Costs 18
644 644427PCRB LOC/SBBPA Costs 19
285,232 434,104 118,672 267,544 427PCRB Mode Conversion Costs 20
342,821 284,052 58,769427'94 Series Restruct. Costs (16) 21
313,467 163,501 149,966181Deferred S-3 Shelf Regis. Costs 22
1,371,194 498,496 973,234 100,536 565BPA LT Transmission Prepaid 23
306,510 306,510Emission Reduction Credits 24
7,290,380 11,101,465 3,811,085Unamortized Contract Values 25
Sales of Electric Utility 26
61,240 61,240 100 100 539Facilities & Properties 27
128,680 75,000 53,680921IT Licenses and Maint. Prepaid 28
Deferred Software 29
734,762 734,762Implementation Costs 30
3,646,923 3,646,923Prepaid Coal Costs - Wyodak 31
2,071 1,214 1,196 339 181Other Deferred Charges 32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-94) Page 233
49 TOTAL
47 Misc. Work in Progress
48 Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
83,176,009 114,194,930
Schedule Page: 233 Line No.: 4 Column: a
The amortization period will end when the Cholla Plant, Unit 4 has been retired from
service and all costs of terminating Unit 4 have been paid.

Schedule Page: 233 Line No.: 10 Column: a
The weighted average remaining life is two years.
Schedule Page: 233 Line No.: 17 Column: a
The weighted average remaining life is two years.

Schedule Page: 233 Line No.: 18 Column: a
The weighted average remaining life is three years.
Schedule Page: 233 Line No.: 20 Column: a
The weighted average remaining life is five years.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
PacifiCorp X
/ /2019/Q4
Line
No.
Description and Location Balance of Begining
(c)(b)(a)
Balance at Endof Year of Year
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.
Electric 1
82,774,477 91,494,740Employee benefits 2
33,070,119 45,186,081Derivative contracts and unamortized contract values 3
70,298,021 76,749,053State carryforwards 4
60,936,151 53,101,152Asset retirement obligations 5
475,895,161 503,204,846Regulatory liabilities 6
60,587,707 54,723,740Other 7
783,561,636 824,459,612TOTAL Electric (Enter Total of lines 2 thru 7) 8
Gas 9
10
11
12
13
14
Other 15
TOTAL Gas (Enter Total of lines 10 thru 15 16
Other (Specify) 17
783,561,636 824,459,612TOTAL (Acct 190) (Total of lines 8, 16 and 17) 18
Notes
FERC FORM NO. 1 (ED. 12-88) Page 234
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CAPITAL STOCKS (Account 201 and 204)
PacifiCorp X
/ /2019/Q4
Line
No.
Class and Series of Stock and Number of shares
(c)(b)(a)
Call Price at
End of Year
Par or Stated
Value per share
(d)
Name of Stock Series Authorized by Charter
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series
of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
750,000,000Account 201, Common stock issued 1
750,000,000TOTAL COMMON STOCK 2
3
Account 204, Preferred stock issued 4
100.00 126,533 5% Cumulative Preferred 5
3,500,000 Serial Preferred, Cumulative: 6
100.00 6.00% Series 7
100.00 7.00% Series 8
16,000,000 No Par Serial Preferred 9
19,626,533TOTAL PREFERRED STOCK 10
11
Authorized and Unissued Capital Stock 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
FERC FORM NO. 1 (ED. 12-91) Page 250
AS REACQUIRED STOCK (Account 217)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CAPITAL STOCKS (Account 201 and 204) (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT
IN SINKING AND OTHER FUNDS
Shares(g)Cost(h)Shares SharesAmount
(Total amount outstanding without reductionfor amounts held by respondent)
Amount(e) (f)(i) (j)
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.
3,417,945,896 357,060,915 1
3,417,945,896 357,060,915 2
3
4
5
6
593,000 5,930 7
1,804,600 18,046 8
9
2,397,600 23,976 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
FERC FORM NO. 1 (ED. 12-88) Page 251
Schedule Page: 250 Line No.: 1 Column: a
Berkshire Hathaway Energy Company indirectly owns all of the shares of PacifiCorp's
outstanding common stock. Therefore, there is no public market for PacifiCorp's common
stock.
Schedule Page: 250 Line No.: 1 Column: d
This class of stock is not redeemable.
Schedule Page: 250 Line No.: 7 Column: d
This series of preferred stock is not redeemable.
Schedule Page: 250 Line No.: 8 Column: d
This series of preferred stock is not redeemable.
Schedule Page: 250 Line No.: 12 Column: a
Authorizations for the issuance of common stock are as follows:
- Idaho Public Utilities Commission - Case No. PAC-E-06-7, Order No. 30099, dated
July 7, 2006.
- Oregon Public Utility Commission - Docket No. UF-4228, Order No. 06-417, dated
July 17, 2006.
- Washington Utilities and Transportation Commission - Docket No. UE-060974,
Order No. 1, dated June 28, 2006.
PacifiCorp has regulatory approval from the aforementioned commissions for the issuance of
an additional 30,000,000 shares of common stock out of the 750,000,000 authorized
(357,060,915 outstanding) by PacifiCorp's articles of incorporation.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line Item Amount(b)(a)
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
No.
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 112. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such
change.
(a) Donations Received from Stockholders (Account 208)-State amount and 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 which 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 211)-Classify amounts included in this account according to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
Account 211, Miscellaneous paid-in capital 1
Additional Paid-in Capital: 2
1,973,218 Share based payments 3
14,422,979 Tax benefit from stock option exercises 4
-3,575,760 Benefit plan separation 5
1,089,950,000 Capital contributions 6
136,208 Gain on sale of ScottishPower plc stock 7
-1,275,241 Qualified production activity tax deduction 8
432,552 Contribution of Intermountain Geothermal 9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
FERC FORM NO. 1 (ED. 12-87) Page 253
40 TOTAL 1,102,063,956
Schedule Page: 253 Line No.: 3 Column: b
Represents the fair value of stock options granted by ScottishPower plc for which certain
performance measures were met in March 2005. These options became fully vested in
May 2005.

Schedule Page: 253 Line No.: 4 Column: b
Represents the income tax deduction attributable to the exercise of stock options granted
by ScottishPower plc.

Schedule Page: 253 Line No.: 5 Column: b
Represents the effect of transferring certain benefit plan obligations and assets to PPM
Energy, Inc. as a result of the sale of PacifiCorp by ScottishPower plc.

Schedule Page: 253 Line No.: 6 Column: b
Represents capital contributions to PacifiCorp (with no shares of stock issued) from its
indirect parent Berkshire Hathaway Energy Company ("BHE"). During the year being reported,
no capital contributions were made by BHE to PacifiCorp.

Schedule Page: 253 Line No.: 7 Column: b
Represents a realized gain on stock related to separation of PPM Energy, Inc. participants
from the deferred compensation plan, which invested in ScottishPower plc stock.
Schedule Page: 253 Line No.: 8 Column: b
Represents amounts associated with Internal Revenue Code Section 199 qualified production
activities.

Schedule Page: 253 Line No.: 9 Column: b
Represents contribution of Intermountain Geothermal Company to PacifiCorp from BHE in
March 2006, subsequent to the sale of PacifiCorp to BHE. Intermountain Geothermal Company
was merged with and into its direct parent, PacifiCorp, on August 31, 2007, with
PacifiCorp surviving.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CAPITAL STOCK EXPENSE (Account 214)
PacifiCorp X
/ /2019/Q4
Line
No.
Class and Series of Stock Balance at End of Year(b)(a)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
41,101,061Common Stock 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
FERC FORM NO. 1 (ED. 12-87) Page 254b
22 TOTAL 41,101,061
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224)
PacifiCorp X
/ /2019/Q4
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as
specified by the Uniform System of Accounts.
Account 221, Bonds 1
First Mortgage Bonds: 2
2,515,793 350,000,000 5.50% Series due January 15, 2019 3
2,292,500 4 D
3,007,139 400,000,000 3.85% Series due June 15, 2021 5
744,000 6 D
2,424,350 350,000,000 2.95% Series due February 1, 2022 7
308,000 8 D
254,129 100,000,000 2.95% Series due February 1, 2022 9
-81,000 10 P
1,859,352 300,000,000 2.95% Series due June 1, 2023 11
900,000 12 D
3,345,164 425,000,000 3.60% Series due April 1, 2024 13
255,000 14 D
2,121,421 250,000,000 3.35% Series due July 1, 2025 15
320,000 16 D
2,134,659 400,000,000 3.50% Series due June 15, 2029 17
740,000 18 D
2,874,150 300,000,000 7.70% Series due November 15, 2031 19
864,000 20 D
1,892,365 200,000,000 5.90% Series due August 15, 2034 21
722,000 22 D
2,912,021 300,000,000 5.25% Series due June 15, 2035 23
1,080,000 24 D
2,907,881 350,000,000 6.10% Series due August 1, 2036 25
1,141,000 26 D
589,216 600,000,000 5.75% Series due April 1, 2037 27
24,000 28 D
5,127,281 600,000,000 6.25% Series due October 15, 2037 29
750,000 30 D
2,290,333 300,000,000 6.35% Series due July 15, 2038 31
1,671,000 32 D
FERC FORM NO. 1 (ED. 12-96)Page 256
33 TOTAL 8,055,275,000 88,227,487
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.Nominal Dateof Issue Date ofMaturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding withoutreduction for amounts held byrespondent)
Interest for YearAmount(d) (e) (f) (g) (h) (i)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year,
describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
1
2
802,08301/15/201901/08/200901/15/201901/08/2009 3
4
400,000,000 15,400,00006/15/202105/12/201106/15/202105/12/2011 5
6
350,000,000 10,325,00002/01/202201/06/201202/01/202201/06/2012 7
8
100,000,000 2,950,00002/01/202203/06/201202/01/202203/06/2012 9
10
300,000,000 8,850,00006/01/202306/06/201306/01/202306/06/2013 11
12
425,000,000 15,300,00004/01/202403/13/201404/01/202403/13/2014 13
14
250,000,000 8,375,00007/01/202506/19/201507/01/202506/19/2015 15
16
400,000,000 11,627,77806/15/202903/01/201906/15/202903/01/2019 17
18
300,000,000 23,100,00011/15/203111/21/200111/15/203111/21/2001 19
20
200,000,000 11,800,00008/15/203408/24/200408/15/203408/24/2004 21
22
300,000,000 15,750,00006/15/203506/13/200506/15/203506/13/2005 23
24
350,000,000 21,350,00008/01/203608/10/200608/01/203608/10/2006 25
26
600,000,000 34,500,00004/01/203703/14/200704/01/203703/14/2007 27
28
600,000,000 37,500,00010/15/203710/03/200710/15/203710/03/2007 29
30
300,000,000 19,050,00007/15/203807/17/200807/15/203807/17/2008 31
32
FERC FORM NO. 1 (ED. 12-96)Page 257
33 7,705,275,000 369,853,259
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224)
PacifiCorp X
/ /2019/Q4
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as
specified by the Uniform System of Accounts.
6,134,687 650,000,000 6.00% Series due January 15, 2039 1
6,175,000 2 D
2,737,911 300,000,000 4.10% Series due February 1, 2042 3
987,000 4 D
5,640,085 600,000,000 4.125% Series due January 15, 2049 5
1,344,000 6 D
5,149,489 600,000,000 4.15% Series due February 15, 2050 7
2,790,000 8 D
115,202 15,000,000 8.53% Series C Medium-Term Notes due December 16, 2021 9
38,400 5,000,000 8.375% Series C Medium-Term Notes due December 31, 2021 10
33,243 5,000,000 8.26% Series C Medium-Term Notes due January 7, 2022 11
30,594 4,000,000 8.27% Series C Medium-Term Notes due January 10, 2022 12
131,471 15,000,000 8.05% Series E Medium-Term Notes due September 1, 2022 13
70,118 8,000,000 8.07% Series E Medium-Term Notes due September 9, 2022 14
438,238 50,000,000 8.12% Series E Medium-Term Notes due September 9, 2022 15
105,177 12,000,000 8.11% Series E Medium-Term Notes due September 9, 2022 16
87,648 10,000,000 8.05% Series E Medium-Term Notes due September 14, 2022 17
208,198 26,000,000 8.08% Series E Medium-Term Notes due October 14, 2022 18
200,190 25,000,000 8.08% Series E Medium-Term Notes due October 14, 2022 19
37,914 5,000,000 8.23% Series E Medium-Term Notes due January 20, 2023 20
30,331 4,000,000 8.23% Series E Medium-Term Notes due January 20, 2023 21
-81,560 22 P
246,981 27,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 23
100,622 11,000,000 7.26% Series F Medium-Term Notes due July 21, 2023 24
137,211 15,000,000 7.23% Series F Medium-Term Notes due August 16, 2023 25
274,423 30,000,000 7.24% Series F Medium-Term Notes due August 16, 2023 26
38,250 5,000,000 6.75% Series F Medium-Term Notes due September 14, 2023 27
15,300 2,000,000 6.75% Series F Medium-Term Notes due September 14, 2023 28
15,300 2,000,000 6.72% Series F Medium-Term Notes due September 14, 2023 29
152,326 20,000,000 6.75% Series F Medium-Term Notes due October 26, 2023 30
121,861 16,000,000 6.75% Series F Medium-Term Notes due October 26, 2023 31
91,396 12,000,000 6.75% Series F Medium-Term Notes due October 26, 2023 32
FERC FORM NO. 1 (ED. 12-96)Page 256.1
33 TOTAL 8,055,275,000 88,227,487
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.Nominal Dateof Issue Date ofMaturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding withoutreduction for amounts held byrespondent)
Interest for YearAmount(d) (e) (f) (g) (h) (i)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year,
describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
650,000,000 39,000,00001/15/203901/08/200901/15/203901/08/2009 1
2
300,000,000 12,300,00002/01/204201/06/201202/01/204201/06/2012 3
4
600,000,000 24,681,25001/15/204907/13/201801/15/204907/13/2018 5
6
600,000,000 20,680,83302/15/205003/01/201902/15/205003/01/2019 7
8
15,000,000 1,279,50012/16/202112/16/199112/16/202112/16/1991 9
5,000,000 418,75012/31/202112/31/199112/31/202112/31/1991 10
5,000,000 413,00001/07/202201/08/199201/07/202201/08/1992 11
4,000,000 330,80001/10/202201/09/199201/10/202201/09/1992 12
15,000,000 1,207,50009/01/202209/18/199209/01/202209/18/1992 13
8,000,000 645,60009/09/202209/09/199209/09/202209/09/1992 14
50,000,000 4,060,00009/09/202209/11/199209/09/202209/11/1992 15
12,000,000 973,20009/09/202209/11/199209/09/202209/11/1992 16
10,000,000 805,00009/14/202209/14/199209/14/202209/14/1992 17
26,000,000 2,100,80010/14/202210/15/199210/14/202210/15/1992 18
25,000,000 2,020,00010/14/202210/15/199210/14/202210/15/1992 19
5,000,000 411,50001/20/202301/20/199301/20/202301/20/1993 20
4,000,000 329,20001/20/202301/29/199301/20/202301/29/1993 21
22
27,000,000 1,960,20007/21/202307/22/199307/21/202307/22/1993 23
11,000,000 798,60007/21/202307/22/199307/21/202307/22/1993 24
15,000,000 1,084,50008/16/202308/16/199308/16/202308/16/1993 25
30,000,000 2,172,00008/16/202308/16/199308/16/202308/16/1993 26
5,000,000 337,50009/14/202309/14/199309/14/202309/14/1993 27
2,000,000 135,00009/14/202309/14/199309/14/202309/14/1993 28
2,000,000 134,40009/14/202309/14/199309/14/202309/14/1993 29
20,000,000 1,350,00010/26/202310/26/199310/26/202310/26/1993 30
16,000,000 1,080,00010/26/202310/26/199310/26/202310/26/1993 31
12,000,000 810,00010/26/202310/26/199310/26/202310/26/1993 32
FERC FORM NO. 1 (ED. 12-96)Page 257.1
33 7,705,275,000 369,853,259
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224)
PacifiCorp X
/ /2019/Q4
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as
specified by the Uniform System of Accounts.
904,467 100,000,000 6.71% Series G Medium-Term Notes due January 15, 2026 1
82,487,227 7,799,000,000Subtotal - First Mortgage Bonds 2
3
Pollution Control Obligations - Secured: 4
510,479 21,260,000 Poll Ctrl Rev Refunding Bonds, Sweetwater County, WY, Series 1994 5
209,777 8,190,000 Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1994 6
3,274,246 121,940,000 Poll Ctrl Rev Refunding Bonds, Emery County, UT, Series 1994 7
422,858 15,060,000 Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1994 8
132,043 5,300,000 Environ. Imprvmnt Rev Bonds, Converse County, WY, Series 1995 9
404,262 22,000,000 Environ. Imprvmnt Rev Bonds, Lincoln County, WY, Series 1995 10
4,953,665 193,750,000Subtotal Pollution Control Obligations - Secured 11
12
Pollution Control Obligations - Unsecured: 13
167,524 9,335,000 Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Series 1992A 14
242,163 22,485,000 Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 15
151,908 6,305,000 Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Series 1992B 16
225,000 24,400,000 Environ. Imprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 17
786,595 62,525,000Subtotal - Pollution Control Obligations - Unsecured 18
19
88,227,487 8,055,275,000TOTAL ACCOUNT 221 20
21
Account 222, Reacquired bonds 22
23
Account 223, Advances from associated companies 24
25
Account 224, Other long-term debt 26
27
Long-term debt authorized but unissued 28
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 256.2
33 TOTAL 8,055,275,000 88,227,487
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.Nominal Dateof Issue Date ofMaturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding withoutreduction for amounts held byrespondent)
Interest for YearAmount(d) (e) (f) (g) (h) (i)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year,
describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
100,000,000 6,710,00001/15/202601/23/199601/15/202601/23/1996 1
7,449,000,000 364,908,994 2
3
4
21,260,000 421,71211/01/202411/17/199411/01/202411/17/1994 5
8,190,000 154,45611/01/202411/17/199411/01/202411/17/1994 6
121,940,000 2,326,67811/01/202411/17/199411/01/202411/17/1994 7
15,060,000 299,77811/01/202411/17/199411/01/202411/17/1994 8
5,300,000 98,51011/01/202511/17/199511/01/202511/17/1995 9
22,000,000 434,03511/01/202511/17/199511/01/202511/17/1995 10
193,750,000 3,735,169 11
12
13
9,335,000 182,37312/01/202009/29/199212/01/202009/29/1992 14
22,485,000 438,14912/01/202009/29/199212/01/202009/29/1992 15
6,305,000 123,38312/01/202009/29/199212/01/202009/29/1992 16
24,400,000 465,19111/01/202512/14/199511/01/202512/14/1995 17
62,525,000 1,209,096 18
19
7,705,275,000 369,853,259 20
21
22
23
24
25
26
27
28
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 257.2
33 7,705,275,000 369,853,259
Schedule Page: 256 Line No.: 17 Column: a
In March 2019, PacifiCorp issued $400 million of its 3.50% First Mortgage Bonds due June
2029. State authorizations for this issuance were as follows:
- Idaho Public Utilities Commission ("IPUC") - Case No. PAC-E-18-10, Order No. 34205,
dated December 7, 2018, effective through September 30, 2023.
- Oregon Public Utility Commission ("OPUC") - Docket No. UF-4304, Order No. 18-452,
dated December 4, 2018.
Schedule Page: 256.1 Line No.: 7 Column: a
In March 2019, PacifiCorp issued $600 million of its 4.15% First Mortgage Bonds due
February 2050. State authorizations for this issuance were as follows:
- IPUC - Case No. PAC-E-18-10, Order No. 34205, dated December 7, 2018, effective
through September 30, 2023.
- OPUC - Docket No. UF-4304, Order No. 18-452, dated December 4, 2018.
Schedule Page: 256.2 Line No.: 11 Column: a
Secured by pledged first mortgage bonds registered to and held by the pollution control
bond trustee generally with the same interest rates, maturity dates and redemption
provisions as the pollution control bond obligations.
Schedule Page: 256.2 Line No.: 20 Column: h
Refer to Item 6 in Important Changes During the Year and Note 8 in Notes to Financial
Statements in this Form No. 1 for a discussion of PacifiCorp's long-term debt.

Schedule Page: 256.2 Line No.: 20 Column: i
Account represents interest expense charged 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, Notes
payable to associated companies during the year.

Schedule Page: 256.2 Line No.: 28 Column: a
For authorization for the issuance of long-term debt ($2.0 billion authorized; $1.0
billion available as of December 31, 2019), refer to Item 6 in Important Changes During
the Year in this Form No. 1.
Authorization to borrow the proceeds of pollution control revenue refunding bonds issued
by the counties of Emery, Utah; Carbon, Utah; Converse, Wyoming; Lincoln, Wyoming;
Sweetwater, Wyoming; and Moffat, Colorado (total of $300,345,000 authorized and
$166,450,000 available as of December 31, 2019) and authorization to borrow the proceeds
of new pollution control revenue bonds issued by one or more of the following counties or
municipalities: Emery, Utah; Converse, Wyoming; Lincoln, Wyoming; Sweetwater, Wyoming;
City of Gillette, Wyoming; Navajo County, Arizona; and Routt County, Colorado (total of
$150,000,000 authorized and available as of December 31, 2019) 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 July 29, 2008.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
PacifiCorp X
/ /2019/Q4
Particulars (Details)(b)(a)Amount LineNo.
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate
return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax
assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the
above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
771,192,330Net Income for the Year (Page 117) 1
2
3
Taxable Income Not Reported on Books 4
5
6
7
148,901,480Other 8
Deductions Recorded on Books Not Deducted for Return 9
10
11
12
1,250,045,963Other 13
Income Recorded on Books Not Included in Return 14
15
16
17
45,923,493Other 18
Deductions on Return Not Charged Against Book Income 19
20
21
22
23
24
1,262,853,409Other 25
-40,340,612State Tax Deductions 26
821,022,259Federal Tax Net Income 27
Show Computation of Tax: 28
29
172,414,674Federal Income Tax at 21.00% 30
4,632,010Provision to Return Adjustment 31
-34,325Tax Reserve Changes 32
-15,800Research and Experimentation Credits 33
-27,792,500Renewable Energy Production Tax Credits 34
35
149,204,059Federal Income Tax Accrual 36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96)Page 261
Schedule Page: 261 Line No.: 8 Column: a
Particulars (Details) Amounts
Contribution in Aid of Construction $ 114,942,433
MCI F.O.G. Wire Lease 647
Regulatory Asset - Alt Rate for Energy Program (CARE) - CA 271,958
Regulatory Asset - REC Sales Deferral - OR 115,099
Regulatory Asset - REC Sales Deferral - UT 1,038,541
Regulatory Asset - REC Sales Deferral - WY 591,662
Regulatory Asset - WA Colstrip #3 52,188
Regulatory Liability - Deferred Excess NPC - OR 5,478,956
Regulatory Liability - Depreciation Decrease - OR 1,304,531
Regulatory Liability - Excess Income Tax Deferral - CA 4,017,282
Regulatory Liability - Excess Income Tax Deferral - ID 252,190
Regulatory Liability - Excess Income Tax Deferral - OR 2,398,647
Regulatory Liability - Excess Income Tax Deferral - UT 130,948
Regulatory Liability - Excess Income Tax Deferral - WA 469,566
Regulatory Liability - OR Direct Access 5 Year Opt Out 1,917,733
Regulatory Liability - Sales of REC - OR 22,637
Regulatory Liability - Sales of REC - UT 648,864
Regulatory Liability - Sales of REC - WY 61,621
Regulatory Liability - UT Home Energy Lifeline 46,693
Regulatory Liability - WA Accel Depreciation 12,611,581
Reimbursements 2,372,063
Unearned Joint Use Power Contact Revenue 155,640
Total $ 148,901,480
Schedule Page: 261 Line No.: 13 Column: a
Particulars (Details) Amounts
Fed/State Tax Expense $ 58,476,068
Fed/State Tax Expense - Interest 269,756
Accrued Royalties 448,793
Accrued Vacation 139,027
Avoided Costs 67,459,367
Book Depreciation 943,502,237
Book Depreciation Allocated to Medicare and M&E 147,603
Capitalization of Test Energy 4,130,399
Capitalized Labor and Benefit Costs 7,658,810
Coal Pile Inventory Adjustment 110,446
Company Plane - Nonbusiness Use 42,810
Contra PP&E Cholla U4 Closure 25,281,533
CWIP Reserve 2,584,651
Deferred Compensation 1,449,597
Environmental Liability - Regulated 836,946
Executive Compensation - IRS Section 162(m) 160,925
FAS 112 Book Reserve - Postemployment Benefits 2,363,728
Fuel Cost Adjustment 219,302
Hermiston Swap 171,693
Hydro Relicensing Obligation 1,330,948
Injuries & Damages Reserve - OR 1,845,855
Inventory Reserve 865,878
Inventory Reserve - Cholla U4 6,106,205
Lease Liability (Operating Leases) 11,932,093
Lewis River Settlement Agreement 14,627
Liquidated Damages - Cholla U4 19,606,070
Lobbying Expenses 1,097,826
LT Incentive Plan 1,221,595
Meals and Entertainment 1,947,043
Non-deductible Fringe Benefits 478,957
Non-deductible Parking Costs 470,243
Prepaid Taxes - OPUC 52,091
Prepaid Taxes - UPSC 35,535
Prepaid Water Rights 161,250
Property Insurance Reserve - ID 113,544
Property Insurance Reserve - UT 1,104,416
Property Insurance Reserve - WY 349,810
Regulatory Asset - Asset Sales Balancing Account - OR 141,743
Regulatory Asset - Carbon Unrecovered Plant - ID 478,639
Regulatory Asset - Carbon Unrecovered Plant - UT 3,444,641
Regulatory Asset - Carbon Unrecovered Plant - WY 1,158,188
Regulatory Asset - Catastrophic Event Deferral - CA 1,126,309
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Regulatory Asset - Deferred Excess NPC - CA 27,280
Regulatory Asset - Deferred Overburden Costs - ID 115,324
Regulatory Asset - Deferred Overburden Costs - WY 324,492
Regulatory Asset - Demand Side Management 187,760
Regulatory Asset - Depreciation Increase - UT 128,043
Regulatory Asset - Depreciation Increase - WY 442,191
Regulatory Asset - Environmental Costs - WA 140,390
Regulatory Asset - FAS 158 Pension Liability 13,021,776
Regulatory Asset - Goodnoe Hills Settlement - WY 21,250
Regulatory Asset - Klamath Hydroelectric Relicensing Costs - UT 3,669,527
Regulatory Asset - Lakeside Settlement - WY 27,331
Regulatory Asset - Liquidated Damages - UT 35,000
Regulatory Asset - Liquidated Damages - WY 5,708
Regulatory Asset - Postemployment Costs 413,204
Regulatory Asset - Post Merger Loss - Reacquired Debt 583,695
Regulatory Asset - Postretirement Settlement Loss 353,077
Regulatory Asset - Postretirement Settlement Loss CC - WY 22,244
Regulatory Asset - Powerdale Decommissioning - ID 23,801
Regulatory Asset - Preferred Stock Redemption Loss - UT 82,531
Regulatory Asset - Preferred Stock Redemption Loss - WA 13,318
Regulatory Asset - Preferred Stock Redemption Loss - WY 28,442
Regulatory Asset - STEP Pilot Program Balance Account - UT 5,046,761
Regulatory Asset - Utah Mine Disposition 12,965,992
Regulatory Liability - ARO/Reg Diff - Trojan - WA Portion 2,168
Regulatory Liability - Blue Sky - CA 56,886
Regulatory Liability - Blue Sky - ID 51,976
Regulatory Liability - Blue Sky - WA 161,628
Regulatory Liability - Blue Sky - WY 186,193
Regulatory Liability - Clean Fuels Program - OR 2,538,520
Regulatory Liability - Contra-Carbon Decommissioning - ID 34,621
Regulatory Liability - Contra-Carbon Decommissioning - UT 250,441
Regulatory Liability - Contra-Carbon Decommissioning - WY 623,945
Regulatory Liability - Energy Savings Assistance - CA 202,496
Regulatory Liability - FAS 158 Postretirement Liability 18,354,603
Regulatory Liability - WA Decoupling Mechanism 14,685,491
Reserve for Bad Debts 52,155
TGS Buyout 15,473
Trapper Mine Contract Obligation 305,157
Western Coal Carrier Retiree Medical Accrual 157,000
Intercompany Adjustment 4,150,876
Total $1,250,045,963

Schedule Page: 261 Line No.: 18 Column: a
Particulars (Details) Amounts
Book Fixed Asset Gain/Loss $ (4,186,776)
Deferred Revenue - Lease Incentives (31,062)
Dividend Received Deduction - Deferred Compensation (81,060)
Officer's Life Insurance (7,841,596)
Regulatory Asset - BPA Balancing Account - OR (1,416,010)
Regulatory Asset - BPA Balancing Account - WA (197,289)
Regulatory Asset - Community Solar - OR (497,724)
Regulatory Asset - REC Sales Deferral - OR (74)
Regulatory Liability - BPA Balancing Account - ID (471,764)
Regulatory Liability - BPA Balancing Account - WA (469,946)
Regulatory Liability - Excess Income Tax Deferral - WY (4,672,783)
Regulatory Liability - GHG Allowance Revenues - CA (26,552)
Regulatory Liability - WA Low Income Program (1,478,905)
Transmission Service Deposits (191,377)
Trapper Mining Stock Basis (797,264)
Equity Earnings in Subsidiaries (23,563,311)
Total $ (45,923,493)

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 261 Line No.: 25 Column: a
Particulars (Details) Amounts
Accrued Bonus $ (120,940)
Accrued Final Reclamation (5,597,035)
Accrued Retention (1,830,471)
Accrued Severance (686,710)
Amortization NOPAs 99-00 RAR (64,313)Basis Intangible Difference (266,104)
Bear River Settlement Agreement (54,918)
Capitalized Depreciation (6,684,051)
Cholla SHL NOPA (Lease Amortization) (377,111)
Contra Receivable from Joint Owners (665,619)
Cost of Removal (69,673,217)
Debt AFUDC (36,195,338)
Deferred Compensation Mark-to-Market Gain/Loss (1,177,006)
Deferred Revenue - Citibank (210,829)
Deferred Revenue - Other (575,944)
Deseret Settlement Receivable (76,495)
Dividend Deduction at 50% (17,443)
Environmental Liability - Non-regulated (227,637)
Equity AFUDC (72,139,947)
FAS 158 Pension Liability (24,625,770)FAS 158 Postretirement Asset (6,170,884)
FAS 158 Postretirement Liability (1,268,785)
FAS 158 SERP Liability (1,498,622)
Federal Tax Depreciation (684,399,818)
Federal Tax Fixed Asset Gain/Loss (16,502,317)
Injuries and Damages Accrual - Cash Basis (3,786,990)
LT Incentive Plan Mark-to-Market Gain/Loss (1,894,857)
Miscellaneous Current and Accrued Liability (1,696,314)
N Umpqua Settlement Agreement (649,083)
Oregon Regulatory Asset/Regulatory Liability Consolidation (26,167)
Penalties (1,268,517)
Pension/Retirement Accrual (74,561)
Pre-1943 Preferred Stock Dividend - Deduction (107,935)
Prepaid - FSA O&M - East (252,452)
Prepaid Aircraft Maintenance (327,259)Prepaid Membership Fees (126,064)
Prepaid Taxes - IPUC (40,121)
Prepaid Taxes - Property Taxes (1,736,838)
Property Insurance Reserve - OR (7,594,074)
Regulatory Asset - Protocol - MSP Deferral - ID (150,000)
Regulatory Asset - Protocol - MSP Deferral - UT (4,400,000)
Regulatory Asset - Protocol - MSP Deferral - WY (1,600,002)
Regulatory Asset - CA Mobile Home Park Conversion (4,500)
Regulatory Asset - Cholla U4 (25,487,600)
Regulatory Asset - Contra Regulatory Asset - Pension Plan CTG (1,640,983)
Regulatory Asset - Deferred Excess NPC - ID (6,863,859)
Regulatory Asset - Deferred Excess NPC - OR (2,980,283)
Regulatory Asset - Deferred Excess NPC - UT (22,656,734)
Regulatory Asset - Deferred Excess NPC - WY '09 & After (13,263,038)
Regulatory Asset - Deferred Intervenor Funding Grants - CA (1,754)Regulatory Asset - Deferred Intervenor Funding Grants - OR (569,849)
Regulatory Asset - Depreciation Increase - ID (10,028)
Regulatory Asset - Environmental Costs (2,931,261)
Regulatory Asset - FAS 158 Postretirement Liability (18,354,603)
Regulatory Asset - Fire Risk Mitigation - CA (3,173,502)
Regulatory Asset - Lease Depreciation - Timing Difference (539,026)
Regulatory Asset - Pension Settlement - WA (1,419,060)
Regulatory Asset - Postretirement Settlement Loss CC - UT (291,300)
Regulatory Asset - Solar Feed-In Tariff Deferral - OR (508,246)
Regulatory Asset - Solar Incentive Program - UT (5,046,761)
Regulatory Asset - Transportation Electrification Program - CA (61,654)
Regulatory Asset - Transportation Electrification Program - OR (768,596)
Regulatory Asset - Transportation Electrification Program - WA (137,015)
Regulatory Asset - UT Subscriber Solar Program (61,577)
Regulatory Liability - 50% Bonus Tax Depreciation - WY (810,660)Regulatory Liability - Blue Sky - OR (122,949)
Regulatory Liability - Blue Sky - UT (1,327,673)
Regulatory Liability - Deferred Excess NPC - WA (14,326,872)
Regulatory Liability - OR Energy Conservation Charge (603,039)
Regulatory Liability - Solar Feed-in Tariff Deferral - CA (2,458,183)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Repairs Deduction (155,652,559)
Rogue River - Habitat Enhancement Liability (73,640)
Right of Way Asset (Operating Leases) (12,161,674)
Sales & Use Tax Audit Exposure (250,977)
Sec. 481a Adjustment (11,174,667)
Tax Depletion - SRC (30,909)
Tax Percentage Depletion - Blundell Steam Field (9,453)
Trojan Decommissioning (60,836)
Wasatch Workers Compensation Reserve (179,531)
Total $(1,262,853,409)
Schedule Page: 261 Line No.: 36 Column: b
Berkshire Hathaway Inc. includes PacifiCorp in its United States Federal Income Tax Return. PacifiCorp's
provision for income taxes has been computed on a stand-alone basis.
Names of group members who will file a consolidated United States Federal Income Tax Return:
Under Berkshire Hathaway Energy Company ("BHE"):
PPW Holdings LLC Sub-Group:
PacifiCorp
PPW Holdings LLC
PacifiCorp Sub-Group:
Energy West Mining Company
Glenrock Coal Company
Interwest Mining Company
Pacific Minerals, Inc.
BHE Sub-Group:
ABA Holding, LLC BHH Iowa Affiliates, LLC
ABA Management, L.L.C. BHH KC Real Estate, LLC
Aeronavis LLC Bishop Hill Energy II, LLC
Alamo 6 Solar Holdings, LLC Bishop Hill II Holdings, LLC
Alamo 6, LLC BRER Affiliates, LLC
Alaska Gas Transmission Company, LLC CalEnergy Company, Inc.
Allie Beth Allman Real Estate, Ltd CalEnergy Generation Operating Company
Ambassador Real Estate Company CalEnergy International Services, Inc.
Ambassador Real Estate-Lincoln, LLC CalEnergy Minerals LLC
Apex Home Maintenance, LLC CalEnergy Operating Corporation
ARE Commercial Real Estate, LLC CalEnergy Pacific Holdings Corp
ARE Iowa, LLC California Energy Development Corporation
Arizona HomeServices, LLC California Energy Yuma Corporation
Attorneys Title Holdings, Incorporated California Utility Holdco, LLC
Berkshire Hathaway Energy Company Capitol Title Company
BH2H Holdings, LLC CBSHome Real Estate Company
BHE AC Holding, LLC CBSHome Real Estate of Iowa, Inc.
BHE America Transco, LLC CE Electric (NY), Inc.
BHE Canada LLC CE Generation LLC
BHE Community Solar, LLC CE Geothermal, Inc.
BHE Compression Services, LLC CE International Investments, Inc.
BHE CS Holdings, LLC CE Leathers Company
BHE Gas, Inc. CE Salton Sea Inc.
BHE Geothermal, LLC CE Turbo LLC
BHE Hydro, LLC Champion Realty, Inc.
BHE Midcontinent Transmission Holdings LLC Chancellor Title Services, Inc.
BHE Pearl Solar Holdings, LLC Columbia Title of Florida, Inc.
BHE Pearl Solar, LLC Commonsite, Inc.
BHE Renewables, LLC Conejo Energy Company
BHE Solar, LLC Cordova Energy Company, LLC
BHE Southwest Transmission Holdings LLC CTRE, L.L.C.
BHE Texas Transco, LLC Dakota Dunes Development Company
BHE U.K. Electric, Inc. DCCO, Inc.
BHE U.K. Inc. Del Ranch Company
BHE U.K. Power, Inc. Denver Rental, LLC
BHE U.S. Transmission, LLC Desert Valley Company
BHE Wind, LLC Ebby Halliday Properties, Inc.
BHER Power Resources, Inc. Ebby Halliday Real Estate, Inc.
BHER Santa Rita Holdings, LLC Edina Financial Services, Inc.
BHER Santa Rita Investment, LLC Edina Realty Referral Network, Inc.
BHES CSG Holdings, LLC Edina Realty Title, Inc.
BHES Pearl Solar Holdings, LLC Edina Realty, Inc.
BHH Affiliates, LLC Elmore Company
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Esslinger-Wooten-Maxwell, Inc. Intero Franchise Services, Inc.
E-W-M Referral Services, Inc. Intero Nevada, LLC
F&R/T LLC Intero Real Estate Holdings, Inc.
Falcon Power Operating Company Intero Real Estate Services, Inc.
FFR, Inc. Intero Referral Services, Inc.
First Network Realty, Inc. Iowa Realty Company, Inc.
First Realty Group, Inc. Iowa Realty Insurance Agency, Inc.
First Realty, Ltd Iowa Title Company
First Reserve Insurance, Inc. JBRC, Inc.
First Weber Illinois, LLC Jim Huff Realty, Inc.
First Weber, Inc. JRHBW Realty, Inc. d/b/a RealtySouth
Fishlake Power LLC Jumbo Road Holdings, LLC
Florida Network LLC Kansas City Title, Inc.
Florida Network Property Management, LLC Kanstar Transmission, LLC
For Rent, Inc. Kentucky Residential Referral Service, LLC
Fort Dearborn Land Title Company, LLC Kentwood City Properties, LLC
FRTC, LLC Kentwood Commercial, LLC
Geronimo Community Solar Gardens Holding Company, LLC Kentwood DTC, LLC
Geronimo Community Solar Gardens, LLC Kentwood Real Estate Services, LLC
Gibraltar Title Services, LLC Kentwood, LLC
GPWH Holdings, LLC Kern River Gas Transmission Company
Grande Prairie Land Holding, LLC Keystone Partners, LLC
Grande Prairie Wind Holdings, LLC KR Holding, LLC
Grande Prairie Wind II, LLC L&F/Fonville Morisey Real Estate, LLC
Grande Prairie Wind, LLC L&F/Fonville Morisey Title, LLC
Greystone Partners of Virginia, LLC Lands of Sierra, Inc.
Guarantee Appraisal Corporation Larabee School of Real Estate, Inc.
Guarantee Real Estate LFFS, Inc.
HMSV Financial Services, Inc. Long & Foster Institute of Real Estate, Inc.
HN Real Estate Group N.C., Inc. Long & Foster Insurance Agency, Inc.
HN Real Estate Group, LLC Long & Foster Licensing Company, Inc.
HN Referral Corporation Long & Foster Mortgage Ventures, Inc.
HomeServices Insurance, Inc. Long & Foster Real Estate Ventures, Inc.
HomeServices Lending, LLC Long & Foster Real Estate, Inc.
HomeServices MidAtlantic, LLC Long & Foster Settlement Services, LLC
HomeServices Northeast, LLC Lovejoy Realty Inc.
HomeServices of Alabama, Inc. Lovejoy Referral Network, LLC
HomeServices of America, Inc. M & M Ranch Acquisition Company LLC
HomeServices of California, Inc. M & M Ranch Holding Company LLC
HomeServices of Colorado, LLC Magma Land Company I
HomeServices of Connecticut, LLC Magma Power Company
HomeServices of Florida, Inc. Marshall Wind Energy Holdings, LLC
HomeServices of Georgia, LLC Marshall Wind Energy, LLC
HomeServices of Illinois Holdings, LLC MEC Construction Services Company
HomeServices of Illinois, LLC MEHC Investment, Inc.
HomeServices of Iowa, Inc. Merlin Realty Technologies, LLC
HomeServices of Kentucky Real Estate Academy, LLC MES Holding, LLC
HomeServices of Kentucky, Inc. Metro Referral Associates, Inc.
HomeServices of Minnesota, LLC MHC Investment Company
HomeServices of MOKAN, LLC MHC, Inc.
HomeServices of Nebraska, Inc. Mid-America Referral Network, Inc.
HomeServices of New Jersey, LLC MidAmerican Central California Transco LLC
HomeServices of New York, LLC MidAmerican Energy Company
HomeServices of Oregon, LLC MidAmerican Energy Machining Services LLC
HomeServices of Texas, LLC MidAmerican Energy Services, LLC
HomeServices of the Carolinas, Inc. MidAmerican Funding, LLC
HomeServices of Washington, LLC MidAmerican Geothermal Development Corp
HomeServices of Wisconsin, LLC MidAmerican Wind Tax Equity Holdings, LLC
HomeServices Referral Network, LLC Midland Escrow Services, Inc.
HomeServices Relocation, LLC Mid-States Title Insurance Agency, Inc.
Houlihan/Lawrence Inc. Midwest Capital Group, Inc.
HS Franchise Holding, LLC Midwest Power Midcontinent Transmission Development, LLC
HSF Affiliates LLC Midwest Power Transmission Arkansas LLC
HSGA Real Estate Group, L.L.C. Midwest Power Transmission Iowa LLC
HSN Holding, LLC Midwest Power Transmission Kansas, LLC
HSTX Title, LLC Midwest Power Transmission Oklahoma, LLC
HSW Affiliates Holding, LLC Midwest Power Transmission Texas, LLC
Huff Commercial Group, LLC Midwest Preferred Realty, Inc.
Huff-Drees Realty, Inc. Midwest Realty Ventures, LLC
IES Holding II LLC MPT Heartland Development, LLC
IMO Company, Inc. MTL Canyon Holdings LLC
Imperial Magma LLC Nebraska Referral, Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Nevada Power Company d/b/a NV Energy S.W. Hydro, Inc.
Niguel Energy Company Sage Title Group, LLC
NNGC Acquisition LLC Salton Sea Brine Processing Company
Northeast Referral Group, LLC Salton Sea Power Company
Northern Natural Gas Company Salton Sea Power Generation Company
NRS Referral Services, LLC Salton Sea Power LLC
NV Energy, Inc. San Felipe Energy Company
NVE Holdings, LLC Santa Rita Wind Energy LLC
NVE Insurance Co, Inc. Saranac Energy Company, Inc.
NW Referral Services, LLC SCS Realty Investment Group, LLC
PCG Agencies, Inc. Sequoia Aviation Corporation
PCRE, L.L.C. Sierra Gas Holding Company
Pickford Escrow Company, Inc. Sierra Pacific Power Company d/b/a NV Energy
Pickford Holdings, LLC Silvermine Ventures LLC
Pickford Real Estate, Inc. Solar San Antonio LLC
Pickford Services Company, Inc. Solar Star 3, LLC
Pilot Butte, LLC Solar Star 4, LLC
Pinyon Pines Funding, LLC Solar Star California XIX, LLC
Pinyon Pines I Holding Company, LLC Solar Star California XX, LLC
Pinyon Pines II Holding Company, LLC Solar Star Funding, LLC
Pinyon Pines Projects Holding, LLC Solar Star Projects Holdings, LLC
Pinyon Pines Wind I, LLC Southwest Relocation, LLC
Pinyon Pines Wind II, LLC SSC XIX, LLC
PNW Referral, LLC SSC XX, LLC
Preferred Carolinas Realty, Inc. The Escrow Firm
Preferred Carolinas Title Agency, LLC The Kentwood Company at Cherry Creek, LLC
Premier Service Abstract, LLC The Long & Foster Companies, Inc.
Prime Alliance Real Estate Services, LLC The Referral Company
Priority Title Corporation Thoroughbred Title Services, LLC
Professional Referral Organization, Inc. TIAC LLC
Prosperity First Title, LLC TitleSouth, LLC
Prosperity Home Mortgage, LLC TLTC LLC
Pru-One, Inc. Topaz Solar Farms, LLC
Real Estate Knowledge Services, L.L.C. TPZ Holding, LLC
Real Estate Links, LLC TRMC LLC
Real Estate Referral Network, Inc. Two Rivers, Inc.
Real Living Real Estate, LLC TX Jumbo Road Wind, LLC
Reece & Nichols Alliance, Inc. TX Referral Alliance, Inc.
Reece & Nichols Realtors, Inc. Volantes LLC
Reece Commercial, Inc. VPC Geothermal LLC
Referral Associates of Georgia, LLC Vulcan Power Company
Referral Network of IL LLC Vulcan/BN Geothermal Power Company
Referral Network of NY/NJ, LLC Wailuku Holding Company LLC
Relocation Advantage Partners, LLC Wailuku Investment LLC
RGS Settlements of Pennsylvania, LLC Wailuku River Hydroelectric Power Co, Inc.
RGS Title of Baltimore, LLC Walker Jackson Mortgage Corporation
RGS Title, LLC Walnut Ridge Wind, LLC
RHL Referral Company, LLC Watermark Realty Referral, Inc.
Roberts Brothers, Inc. Watermark Realty, Inc.
Roy H. Long Realty Company, Inc. Weathervane Referral Network, Inc.
With respect to members of the BHE Sub-Group, BHE requires all subsidiaries to pay or receive from BHE an amount
of tax based primarily on the stand-alone method of allocation. The computation includes all tax benefits from
tax deductions from costs borne by utility customers.
Berkshire Hathaway Inc. Sub-Group:
121 Acquisition Co., LLC Aerocraft Heat Treating Co., Inc.
21 SPC, Inc. Aero-Hose Corporation
21st Communities, Inc. Aerospace Dynamics International Inc.
21st Mortgage Corporation Affiliated Agency Operations Co.
2K Polymer Systems, Inc. Affordable Housing Partners, Inc.
A.E. Company, Inc. AIPCF V CHI Blocker, Inc.
Accra Manufacturing Inc. AJF Warehouse Distributors, Inc.
Accurate Installations, Inc. Albacor Shipping (USA) Inc.
Acme Brick Company Albecca, Inc.
Acme Building Brands, Inc. Alpha Cargo Motor Express, Inc.
Acme Management Company Alu-Forge, Inc.
Acme Ochs Brick and Stone, Inc. Ambucor Health Solutions, Inc.
Acme Services Company, LLC American All Risk Insurance Services, Inc.
Adalet/Scott Fetzer Company American Commercial Claims Administrators Inc.
AEG Processing Center No. 35, Inc. American Dairy Queen Corporation
AEG Processing Center No. 58, Inc. American Employers Group, Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
AmGUARD Insurance Company Camp Manufacturing Company
Andrews Laser Works Corporation Cannon Equipment LLC
Angelo Po America, Inc. Cannon-Muskegon Corporation
Applied Group Insurance Holdings, Inc. Carefree/Scott Fetzer Company
Applied Investigations Inc. Carlton Forge Works
Applied Logistics, Inc. Cavalier Homes, Inc.
Applied Premium Finance, Inc. CCC Lonestar LLC
Applied Processing Center No. 60, Inc. Central States Indemnity Co. of Omaha
Applied Risk Services of New York, Inc. Central States of Omaha Companies, Inc.
Applied Risk Services, Inc. Charter Brokerage Holdings Corp.
Applied Underwriters Captive Risk Assurance Co., Inc. Chemtool Incorporated
Applied Underwriters, Inc. CJE II
Arcturus Manufacturing Corporation Claims Services, Inc.
Artform International Inc. Clayton Commercial Buildings, Inc.
Atlantic Precision, Inc. Clayton Education Corp.
AU Captive Risk Assurance Co. Clayton Homes, Inc.
AU Holding Company, Inc. Clayton Properties Group II, Inc.
Avibank Manufacturing Inc. Clayton Properties Group, Inc.
AzGUARD Insurance Company Clayton Supply, Inc.
Bayport Systems, Inc. Clayton, Inc.
BDT I-A Plum Corp. CMH Capital, Inc.
Ben Bridge Jeweler, Inc. CMH Hodgenville, Inc.
Benjamin Moore & Co. CMH Homes, Inc.
Benson Industries, Inc. CMH Manufacturing West, Inc.
Benson, Ltd. CMH Manufacturing, Inc.
Berkshire Hathaway Assurance Corporation CMH of KY, Inc.
Berkshire Hathaway Automotive Inc. CMH Services, Inc.
Berkshire Hathaway Credit Corporation CMH Transport, Inc.
Berkshire Hathaway Direct Insurance Company Coil Master Corporation
Berkshire Hathaway Finance Corporation Columbia Insurance Company
Berkshire Hathaway Global Insurance Services, LLC Combined Claims Services, Inc.
Berkshire Hathaway Homestate Insurance Company Commercial General Indemnity, Inc.
Berkshire Hathaway Life Insurance Company of Nebraska Complementary Coatings Corporation
Berkshire Hathaway Specialty Concierge, LLC Composites Horizons LLC
Berkshire Hathaway Specialty Insurance Company Consumer Value Products, Inc.
Berkshire Indemnity Group Inc. Continental Divide Insurance Company
BH Columbia Inc. Continental Indemnity Company
BH Credit LLC Cornelius Inc.
BH Finance, Inc. Cornelius Renew, Inc.
BH Holding LLC Cort Business Services Corporation
BH Media Group, Inc. Coverage Dynamics Group, Inc.
BH Shoe Holdings, Inc. Criterion Insurance Agency
BHA Minority Interest Holdco, Inc. Crowd Supply, Inc.
BHG Life Insurance Company Crown Holdco One, Inc.
BHG Structured Settlements, Inc. Crown Holdco Two, Inc.
BHSF, Inc. Crown Parent, Inc.
biBERK Insurance Services, Inc. CSI Life Insurance Company
Blue Chip Stamps, Inc. CTB Credit Corp
BN Leasing Corporation CTB Inc.
BNSF Communications, Inc. CTB International Corp
BNSF Logistics International, Inc. CTB IW Inc.
BNSF Logistics Ocean Line, Inc. CTB Midwest Inc.
BNSF Logistics, LLC CTB MN Investments
BNSF Railway Company CTB Technology Holding Inc.
BNSF Railway International Services, Inc. CTMS North America, Inc.
BNSF Spectrum, Inc. Cubic Designs, Inc.
Boat America Corporation Cumberland Asset Management, Inc.
Boat Owners Association of the United States Cypress Insurance Company
Boat/U.S, Inc. D.I. Properties Inc.
Borsheim Jewelry Company, Inc. Dairy Queen Corporate Stores, Inc.
BR Agency, Inc. DCI Marketing Inc.
Brainy Toys, Inc. Denver Brick Company
Brilliant National Services, Inc. Designed Metal Connections, Inc.
Brittain Machine Inc. Dickson Testing Co., Inc.
Brooks Sports, Inc. Display Technologies LLC
Brookwood Insurance Company DL Trading Holdings I, Inc.
Burlington Northern Railroad Holdings, Inc. DQ Funding Corporation
Burlington Northern Santa Fe, LLC DQF, Inc.
Business Wire, Inc. DQGC, Inc.
C Flow, Inc. DragonFly Aeronautics LLC
Caledonian Alloys Inc. DTTF, Inc.
California Insurance Company Duracell Industrial Operations, Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
Duracell U.S. Operations Inc. GRD Holdings Corporation
EastGUARD Insurance Company Greenville Metals Inc.
Eco Color Company GUARDco, Inc.
Ecodyne Corporation H.H. Brown Shoe Company, Inc.
Ellis & Watts Global Industries, Inc. H.J. Justin & Sons, Inc.
Elm Street Corporation Hackney Ladish Inc.
Empire Distributors of Colorado, Inc. Halex/Scott Fetzer Company
Empire Distributors of North Carolina, Inc. Hamilton Aviation Inc.
Empire Distributors of Tennessee, Inc. Hawthorn Life International, Ltd.
Empire Distributors, Inc. HeatPipe Technology, Inc.
Environment One Corporation Helicomb International Inc.
Exacta Aerospace Inc. Helzberg's Diamond Shops, Inc.
Executive Jet Management, Inc. Henley Holdings, LLC
Exsif Worldwide, Inc. Hohmann & Barnard, Inc.
ExtruMed, Inc. Homefirst Agency, Inc.
Fatigue Technology Inc. Homemakers Plaza, Inc.
Financial Services Plus, Inc. Howell Penncraft, Inc.
Finial Holdings, Inc. Huntington Alloys Corporation
Finial Reinsurance Company IdeaLife Insurance Company
First Berkshire Hathaway Life Insurance Company Illinois Insurance Company
FlightSafety Capital Corp. Ingersoll Cutting Tool Company
FlightSafety Development Corp. Innovative Building Products, Inc.
FlightSafety International Inc. Innovative Coatings Technology Corporation
FlightSafety International Middle East Inc. Interco Tobacco Retailers, Inc.
FlightSafety New York, Inc. International Dairy Queen, Inc.
FlightSafety Properties, Inc. International Insurance Underwriters, Inc.
FlightSafety Services Corporation Intrepid JSB, Inc.
Floors, Inc. Ironwood Plastics Inc.
Focused Technology Solutions, Inc. Iscar Metals Inc.
Fontaine Commercial Trailer, Inc. ITTI Group USA Holdings, Inc.
Fontaine Engineered Products, Inc. ITTI Investment Holdings, Inc.
Fontaine Fifth Wheel Company J&L Fiber Services Inc.
Fontaine Modification Company J.L. Mining Company
Fontaine Spray Suppression Company Johns Manville China, Ltd.
Fontaine Trailer Company LLC Johns Manville Corporation
Forest River Holdings, Inc. Johns Manville, Inc.
Forest River Manufacturing LLC Jordan's Furniture, Inc.
Forest River, Inc. Joyce Crane, Inc.
Freedom Warehouse Corp. Joyce Steel Erection, Ltd.
Fruit of the Loom Direct, Inc. Justin Brands, Inc.
Fruit of the Loom Trading Company Kahn Ventures, Inc.
Fruit of the Loom, Inc. Karmelkorn Shoppes, Inc.
Fruit of the Loom, Inc. (Sub) Ken's Spray Equipment, Inc.
FTI Manufacturing Inc. Kinexo, Inc.
FTL Regional Sales Co., Inc. KITCO Fiber Optics, Inc.
Garan Central America Corp. Klune Holdings Inc.
Garan Incorporated Klune Industries Inc.
Garan Manufacturing Corp. Kova Solutions, Inc.
Garan Services Corp L.A. Terminals, Inc.
Gateway Underwriters Agency, Inc. LeachGarner, Inc.
GEICO Advantage Insurance Company Lipotec USA, Inc.
GEICO Casualty Co. LiquidPower Specialty Products, Inc.
GEICO Choice Insurance Company LJ Aero Holdings Inc.
GEICO Corporation LJ Synch Holdings Inc.
GEICO General Insurance Co. LMG Ventures, LLC
GEICO Indemnity Co. Lockwood Street Urban Renewal Corporation
GEICO Insurance Agency Los Angeles Junction Railway Company
GEICO Marine Insurance Company LSPI Holdings Inc.
GEICO Products, Inc. Lubrizol Advanced Materials Holding Corporation
GEICO Secure Insurance Company Lubrizol Advanced Materials, Inc.
Gen Re Intermediaries Corporation Lubrizol Global Management, Inc.
General Re Corporation Lubrizol Inter-Americas Corporation
General Re Financial Products Corporation Lubrizol International Management Corporation
General Re Life Corporation Lubrizol International, Inc.
General Reinsurance Corporation Lubrizol Overseas Trading Corporation
General Star Indemnity Company M&C Products, Inc.
General Star Management Company M&M Manufacturing, Inc.
General Star National Insurance Company Mapletree Transportation, Inc.
Genesis Insurance Company Marathon Suspension Systems, Inc.
Genesis Management and Insurance Services Corp. Marmon Beverage Technologies, Inc.
Government Employees Financial Corp. Marmon Crane Services, Inc.
Government Employees Insurance Co. Marmon Distribution Services, Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
Marmon Energy Services Company NetJets International, Inc.
Marmon Engineered Components Company NetJets Sales, Inc.
Marmon Foodservice Technologies LLC NetJets Services, Inc.
Marmon Holdings, Inc. NetJets U.S., Inc.
Marmon Link Inc. New England Asset Management, Inc.
Marmon Retail & Highway Technologies Co. LLC NewCo D&W LLC
Marmon Retail Products, Inc. NFM of Kansas, Inc.
Marmon Retail Store Equipment LLC NFM SERVICES, LLC
Marmon Retail Technologies Company NJE Holdings, LLC
Marmon Tubing, Fittings & Wire Products, Inc. NJI Sales, Inc.
Marmon Water, Inc. Noranco Manufacturing (USA) Ltd.
Marmon Wire & Cable, Inc. NorGUARD Insurance Company
Marmon-Herrington Company North American Casualty Co.
Marquis Jet Holdings, Inc. Northern States Agency, Inc.
Marquis Jet Partners, Inc. Noveon Hilton Davis, Inc.
Maryland Ventures, Inc. NSS Technologies Inc.
McCarty-Hull Cigar Company, Inc. Oak River Insurance Company
McLane Beverage Distribution, Inc. Old United Casualty Company
McLane Beverage Holding, Inc. Orange Julius Of America
McLane Company, Inc. Oriental Trading Company, Inc.
McLane Eastern, Inc. OTC Brands, Inc.
McLane Express, Inc. OTC Direct, Inc.
McLane Foods, Inc. OTC Worldwide Holdings, Inc.
McLane Foodservice Distribution, Inc. Particle Sciences, Inc.
McLane Foodservice, Inc. PCC Flow Technologies Holdings Inc.
McLane Mid-Atlantic, Inc. PCC Flow Technologies Inc.
McLane Midwest, Inc. PCC Rollmet Inc.
McLane Minnesota, Inc. PCC Structurals Inc.
McLane Network Solutions, Inc. Penn Coal Land, Inc.
McLane New Jersey, Inc. Pennsylvania Insurance Company
McLane Ohio, Inc. Perfection Hy-Test Company
McLane Southern, Inc. Permaswage Holdings, Inc.
McLane Suneast, Inc. Pine Canyon Land Company
McLane Tri-States, Inc. Plasma Coating Corporation
McLane Western, Inc. Plaza Financial Services Co.
McWilliams Forge Company Plaza Resources Co.
Medical Liability Services, Inc. PLICO
Medical Protective Finance Corporation PLICO Financial, Inc.
MedPro Group, Inc. Precision Brand Products, Inc.
MedPro Risk Retention Services, Inc. Precision Castparts Corp.
Merit Distribution Services, Inc. Precision Founders Inc.
Metalac Fasteners Inc. Precision Steel Warehouse, Inc.
Meyn LLC Press Forge Company
MFS Fleet, Inc. Primus International Holding Company
Midwest Northwest Properties, Inc. Primus International Inc.
Miller-Sage, Inc. Princeton Insurance Company
Mindware Corporation Princeton Risk Protection, Inc.
MiTek Holdings, Inc. Priority One Financial Services, Inc.
MiTek Inc. PRISM Holdings LLC
MiTek Industries, Inc. PRISM Plastics, Inc.
MLMIC Insurance Company Pro Installations, Inc.
MLMIC Services, Inc. Procrane Holdings, Inc.
Morgantown-National Supply, Inc. Progressive Incorporated
Mount Vernon Fire Insurance Company Promesa Health, Inc.
Mount Vernon Specialty Insurance Company Protective Coating Inc.
Mouser Electronics, Inc. QS Partners LLC
Mouser JV 1, Inc. QS Security Services LLC
Mouser JV 2 R.C. Willey Home Furnishings
MPP Co., Inc. Radnor Specialty Insurance Company
MPP Pipeline Corporation Railserve, Inc.
MS Property Company Railsplitter Holdings Corporation
MW Wholesale, Inc. RathGibson Holding Co LLC
National Fire & Marine Insurance Company RCP Investment, Inc.
National Indemnity Company Redwood Fire and Casualty Insurance Company
National Indemnity Company of Mid-America RENTCO Trailer Corporation
National Indemnity Company of the South Resolute Management Inc.
National Liability & Fire Insurance Company RFMW, Ltd.
Nationwide Uniforms Richline Group, Inc.
Nebraska Furniture Mart, Inc. Ringwalt & Liesche Co.
NetJets Aviation, Inc. Rio Grande, Inc.
NetJets Europe Holdings, LLC Roxell USA, Inc.
NetJets Inc. Sager Electrical Supply Co. Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
Santa Fe Pacific Insurance Company Total Quality Apparel Resources
Santa Fe Pacific Pipeline Holdings, Inc. TPC European Holdings, LTD.
Santa Fe Pacific Pipelines, Inc. TPC North America, Ltd.
Santa Fe Pacific Railroad Company Transco Railcar Repair Inc.
Schulz Investment Corporation Transco Railway Products Inc.
Scott Fetzer Financial Group, Inc. Transco, Inc.
ScottCare Corporation Transportation Technology Services, Inc.
See's Candies, Inc. TRH Holding Corp.
See's Candy Shops, Incorporated Triangle Suspension Systems, Inc.
Serpentec, Inc. Tricycle, Inc.
Seventeenth Street Realty, Inc. TS City Leasing Inc.
SFEG Corp. TSE Brakes, Inc.
Shaw Contract Flooring Services, Inc. TTI JV 1
Shaw Diversified Services, Inc. TTI JV 2
Shaw Floors, Inc. TTI, Inc.
Shaw Funding Company Tucker Safety Products, Inc.
Shaw Industries Group, Inc. TXFM, Inc.
Shaw Industries, Inc. U.S. Investment Corporation
Shaw International Services, Inc. U.S. Underwriters Insurance Co.
Shaw Retail Properties, Inc. UCFS Europe Company
Shaw Sports Turf California, Inc. UCFS International Holding Company
Shaw Transport, Inc. Unified Supply Chain, Inc.
Shultz Steel Company Uni-Form Components Co.
SHX Flooring, Inc. Union Sales, LLC
SidePlate Systems, Inc. Union Tank Car Company
Smilemakers Canada Inc. Union Underwear Co., Inc.
Smilemakers, Inc. United Consumer Financial Services Company
SN Management, Inc. United Direct Finance, Inc.
Snappy ADP, Inc. United States Aviation Underwriters, Inc.
Soco West, Inc. United States Liability Insurance Company
Sonnax Transmission Company University Swaging Corporation
SOS Metals, Inc. UTLX Company
Southern Energy Homes, Inc. Van Enterprises, Inc.
Southwest United Industries Inc. Vanderbilt ABS Corp.
Special Metals Corporation Vanderbilt Mortgage and Finance, Inc.
Specialized Pipe Services, Inc. Vanity Fair, Inc.
Spectra Contract Flooring Puerto Rico, Inc. Velocity Freight Transport, Inc.
SPS International Investment Company Veritas Insurance Group, Inc.
SPS Technologies LLC Vesta Funding, Inc.
SPS Technologies Mexico LLC Vesta Intermediate Funding, Inc.
SSP-SiMatrix Inc. VFI-Mexico, Inc.
Stahl/Scott Fetzer Company Visilinx, Inc.
Star Furniture Company Vision Retailing, Inc.
Star Lake Railroad Company VT Insurance Acquisition Sub Inc.
Strategic Staff Management, Inc. Warwick Chemicals USA, Inc.
StratoFlight Wayne/Scott Fetzer Company
Summit Distribution Services, Inc. Weaver Manufacturing Inc.
SXP CRA-OCTG Inc. Webb Wheel Products, Inc.
TBS USA, Inc. Wellfleet Insurance Company
Technical Power Systems, Inc. Wellfleet New York Insurance Company
Texas Honing Inc. Western Builders Supply, Inc.
Texas Insurance Company Western Fruit Express Company
The Ben Bridge Corporation Western/Scott Fetzer Company
The Buffalo News, Inc. WestGUARD Insurance Company
The BVD Licensing Corporation Whittaker, Clark & Daniels, Inc.
The Duracell Company World Book Encyclopedia, Inc.
The Fechheimer Brothers Co. World Book, Inc.
The Indecor Group, Inc. World Book/Scott Fetzer Company
The Lubrizol Corporation World Investments, Inc.
The Medical Protective Company Worldwide Containers, Inc.
The Pampered Chef, Ltd. WPLG, Inc.
The Scott Fetzer Company Wyman Gordon Company
The Zia Company Wyman Gordon Forgings Cleveland Inc.
THI Acquisition Inc. Wyman Gordon Forgings Inc.
TIMET ASIA Inc. Wyman Gordon Investment Castings Inc.
TIMET Real Estate Corporation Wyman Gordon Pennsylvania LLC
Titanium Metals Corporation X-L-Co., Inc.
TM City Leasing Inc. XTRA Companies, Inc.
TMCA International Inc. XTRA Corporation
TMI Climate Solutions, Inc. XTRA Finance Corporation
Tool-Flo Manufacturing, Inc. XTRA Intermodal, Inc.
Top Five Club, Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2019/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a) (b) (c) (d) (e) (f)
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Federal: 1
127,940,482 149,204,059 4,019,911 Income 2
37,713,512 37,718,198 543,289 FICA 3
229,261 229,759 6,435 Unemployment 4
-1,522,888 1,522,888 Foreign Withholding Taxes 5
165,883,255 185,629,128 6,092,523Subtotal 6
7
State: 8
9
Arizona: 10
2,783,711 2,694,681 1,436,370 Property 11
217,989 75,715 1,756 Income 12
3,001,700 2,770,396 1,438,126Subtotal 13
14
California: 15
2,362,204 2,362,204 Property 16
21,718 20,536 1,532 Unemployment 17
1,799,700 1,398,520 621,704 Franchise-Income 18
339,047 350,979 10,045 Use 19
1,216,077 1,207,395 1,373,864 Local Franchise 20
5,738,746 5,339,634 2,007,145Subtotal 21
22
Colorado: 23
3,000,214 2,980,214 2,850,000 Property 24
1,769 Income 25
3,000,214 2,981,983 2,850,000Subtotal 26
27
Idaho: 28
6,302,994 6,226,628 3,698,211 Property 29
1,521,033 1,665,153 69,593 Income 30
57,888 58,058 17,170 KWh 31
28,492 27,777 1,557 Unemployment 32
507,357 490,384 36,473 Use 33
8,417,764 8,468,000 3,823,004Subtotal 34
35
Missouri: 36
285 285 Unemployment 37
285 285Subtotal 38
39
40
13,873,220
FERC FORM NO. 1 (ED. 12-96)Page 262
TOTAL41 438,272,040 415,419,512 48,581,847
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEARPrepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)(g) (h) (i) (j) (k) (l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (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 footnote the basis (necessity) of apportioning such tax.
1
-2,461,788 151,665,847 25,283,488 2
37,718,198 547,975 3
229,759 6,933 4
-1,522,888 5
33,963,281 151,665,847 25,838,396 6
7
8
9
10
2,694,681 1,347,340 11
5,322 70,393 -140,518 12
5,322 2,765,074 1,206,822 13
14
15
275,100 2,087,104 16
20,536 350 17
-32,160 1,430,680 220,524 18
350,979 21,977 19
1,207,395 1,365,182 20
614,455 4,725,179 1,608,033 21
22
23
1,472 2,978,742 2,830,000 24
-21 1,790 1,769 25
1,451 2,980,532 2,831,769 26
27
28
105,073 6,121,555 3,621,845 29
-38,366 1,703,519 213,713 30
58,058 17,340 31
27,777 842 32
490,384 19,500 33
584,868 7,883,132 3,873,240 34
35
36
285 37
285 38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 263
41 14,156,321 385,723,458 52,548,582 71,717,476
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2019/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a) (b) (c) (d) (e) (f)
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Montana: 1
5,410,425 5,149,080 2,833,586 Property 2
182,540 209,085 9,454 Corporate License-Income 3
145 145 Unemployment 4
228,670 228,670 60,000 Energy License 5
162,925 162,925 42,000 Wholesale Energy 6
5,984,705 5,749,905 2,945,040Subtotal 7
8
Nevada: 9
34,881 34,881 18,000 Commerce Tax 10
34,881 34,881 18,000Subtotal 11
12
New Mexico: 13
21,147 21,147 Property 14
178,437 123,702 6,916 Income 15
199,584 144,849 6,916Subtotal 16
17
Oregon: 18
26,802,684 26,347,870 13,011,465 228,143 Property 19
1,337,256 1,336,269 58,423 Unemployment 20
13,565,592 15,573,591 -482,078 Excise-Income 21
85,985 65,757 12,745 City of Portland-Income 22
1,499,390 1,611,450 861,755 Department of Energy 23
1,069,547 1,099,504 392,119 Tri-Met 24
567 567 Lane County 25
29,871,656 30,247,957 4,552,678 Franchise 26
74,232,677 76,282,965 13,873,220 4,762,030Subtotal 27
28
Texas: 29
32 32 Unemployment 30
32 32Subtotal 31
32
South Carolina: 33
25 Public Utility 34
25Subtotal 35
36
37
38
39
40
13,873,220
FERC FORM NO. 1 (ED. 12-96)Page 262.1
TOTAL41 438,272,040 415,419,512 48,581,847
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEARPrepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)(g) (h) (i) (j) (k) (l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (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 footnote the basis (necessity) of apportioning such tax.
1
5,149,080 2,572,241 2
-2,997 212,082 35,999 3
145 4
228,670 60,000 5
162,925 42,000 6
-2,852 5,752,757 2,710,240 7
8
9
34,881 18,000 10
34,881 18,000 11
12
13
21,147 14
-1,471 125,173 -47,819 15
-1,471 146,320 -47,819 16
17
18
1,539,568 24,808,302 13,406,626 168,490 19
1,336,269 57,436 20
-235,894 15,809,485 1,525,921 21
-1,222 66,979 -7,483 22
1,611,450 749,695 23
1,099,504 422,076 24
567 25
30,247,957 4,928,979 26
3,738,792 72,544,173 14,156,321 7,095,419 27
28
29
32 30
32 31
32
33
-25 34
-25 35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 263.1
41 14,156,321 385,723,458 52,548,582 71,717,476
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
PacifiCorp X
/ /2019/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a) (b) (c) (d) (e) (f)
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Utah: 1
79,172,999 79,286,151 742,013 Property 2
14,653,584 15,249,767 634,464 Income 3
70,635 70,665 1,738 Unemployment 4
4,821,575 5,005,170 318,777 Use 5
98,718,793 99,611,753 1,696,992Subtotal 6
7
Washington: 8
10,675,320 9,275,320 12,000,000 Property 9
20,228 29,438 720 Unemployment 10
3,973 6,032 Family & Medical Leave 11
22,814 23,114 3,300 Business & Occupation 12
12,224,320 12,517,338 -483,627 Public Utility 13
2,702,405 2,955,292 139,156 Natural Gas Use Tax 14
866,643 2,179,741 102,048 Use 15
39,757 39,757 Forest Excise Tax 16
3,121 3,121 Franchise 17
26,558,581 27,029,153 11,761,597Subtotal 18
19
Wyoming: 20
17,748,296 18,375,708 8,554,150 Property 21
2,045,353 2,050,814 2,031,616 Wind Generation Tax 22
84,887 84,146 2,665 Unemployment 23
1,895,550 1,916,550 287,200 Franchise 24
1,371,551 1,227,046 225,526 Use 25
76,984 76,984 Annual Report 26
23,222,621 23,731,248 11,101,157Subtotal 27
28
Miscellaneous: 29
29,054 29,054 Goshute Possessory 30
271,335 271,335 Sho-Ban Possessory 31
14,814 14,993 7,317 Navajo Possessory 32
40,695 40,695 Ute Possessory 33
72,000 72,000 Crow Possessory 34
69,751 69,751 Umatilla Possessory 35
425,649 497,828 79,317Subtotal 36
37
38
39
40
13,873,220
FERC FORM NO. 1 (ED. 12-96)Page 262.2
TOTAL41 438,272,040 415,419,512 48,581,847
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEARPrepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)(g) (h) (i) (j) (k) (l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (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 footnote the basis (necessity) of apportioning such tax.
1
162,779 79,123,372 855,165 2
-250,717 15,500,484 1,230,647 3
70,665 1,768 4
4,796,788 208,382 502,372 5
4,779,515 94,832,238 2,589,952 6
7
8
773,084 8,502,236 10,600,000 9
29,438 9,930 10
6,032 2,059 11
23,114 3,600 12
12,517,338 -190,609 13
2,955,292 392,043 14
2,179,741 1,415,146 15
39,757 16
3,121 17
5,983,344 21,045,809 12,232,169 18
19
20
1,570,368 16,805,340 9,181,562 21
2,050,814 2,037,077 22
84,146 1,924 23
1,916,550 308,200 24
1,227,046 81,021 25
76,984 26
2,881,560 20,849,688 11,609,784 27
28
29
29,054 30
271,335 31
14,993 7,496 32
40,695 33
72,000 144,000 34
69,751 35
497,828 151,496 36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 263.2
41 14,156,321 385,723,458 52,548,582 71,717,476
Schedule Page: 262 Line No.: 2 Column: l
Account 409.2, Income taxes, other income and deductions, which represents federal income
tax applicable to other income and deductions.
Schedule Page: 262 Line No.: 3 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 4 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 5 Column: l
$(1,271,911) Account 426.3, Penalties
(250,977) Account 431, Other interest expense
$(1,522,888)
Schedule Page: 262 Line No.: 12 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.
Schedule Page: 262 Line No.: 16 Column: l
$ 139,809 Account 408.2, Taxes other than income taxes, other income and deductions
135,291 Account 107, Construction work in progress
$ 275,100
Schedule Page: 262 Line No.: 17 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 18 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.
Schedule Page: 262 Line No.: 19 Column: l
Charged to same account as related goods.
Schedule Page: 262 Line No.: 24 Column: l
Account 408.2, Taxes other than income taxes, other income and deductions

Schedule Page: 262 Line No.: 25 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.
Schedule Page: 262 Line No.: 29 Column: l
$ 1,080 Account 408.2, Taxes other than income taxes, other income and deductions
103,993 Account 107, Construction work in progress
$ 105,073
Schedule Page: 262 Line No.: 30 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 262 Line No.: 32 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262 Line No.: 33 Column: l
Charged to same account as related goods.
Schedule Page: 262 Line No.: 37 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 3 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.
Schedule Page: 262.1 Line No.: 4 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 15 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.
Schedule Page: 262.1 Line No.: 19 Column: l
$ 26,613 Account 408.2, Taxes other than income taxes, other income and deductions
170,849 Account 589, Rents
1,342,106 Account 107, Construction work in progress
$ 1,539,568
Schedule Page: 262.1 Line No.: 20 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 21 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.
Schedule Page: 262.1 Line No.: 22 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.
Schedule Page: 262.1 Line No.: 24 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 25 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.1 Line No.: 30 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 262.2 Line No.: 2 Column: l
$ 69,378 Account 408.2, Taxes other than income taxes, other income and deductions
93,401 Account 107, Construction work in progress
$ 162,779
Schedule Page: 262.2 Line No.: 3 Column: l
Account 409.2, Income taxes, other income and deductions, which represents state income
tax applicable to other income and deductions.
Schedule Page: 262.2 Line No.: 4 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.2 Line No.: 5 Column: l
Charged to same account as related goods.
Schedule Page: 262.2 Line No.: 9 Column: l
$ 36,882 Account 408.2, Taxes other than income taxes, other income and deductions
736,202 Account 107, Construction work in progress
$ 773,084
Schedule Page: 262.2 Line No.: 10 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.2 Line No.: 11 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.2 Line No.: 14 Column: l
Account 151, Fuel stock
Schedule Page: 262.2 Line No.: 15 Column: l
Charged to same account as related goods.
Schedule Page: 262.2 Line No.: 16 Column: l
Account 408.2, Taxes other than income taxes, other income and deductions
Schedule Page: 262.2 Line No.: 21 Column: l
$ 3,249 Account 408.2, Taxes other than income taxes, other income and deductions
13,753 Account 589, Rents
1,553,366 Account 107, Construction work in progress
$ 1,570,368
Schedule Page: 262.2 Line No.: 23 Column: l
Payroll taxes are generally charged to operations and maintenance expense and construction
work in progress.
Schedule Page: 262.2 Line No.: 25 Column: l
Charged to same account as related goods.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
PacifiCorp X
/ /2019/Q4
Line
No.
Account Balance at Beginning
(c)(b)(a)
of YearSubdivisions AdjustmentsDeferred for Year Allocations toCurrent Year's IncomeAccount No. Amount Account No. Amount(d) (e) (f)(g)
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).Include in column (i) the average
period over which the tax credits are amortized.
Electric Utility 1
3% 2
4% 3
7% 4
10% 8,880,380 411.4,420 2,759,658 5
30% 222,376 420 11,696 6
Idaho 82,772 411.4,420 13,641 7
TOTAL 9,185,528 2,784,995 8
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
9
10
Idaho 190 -42,947 4,128,249 1,023,832 420 306,160 11
Total Nonutility -42,947 4,128,249 1,023,832 306,160 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-89) Page 266
Balance at End
(i)(h)
of Year
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued)
PacifiCorp X
/ /2019/Q4
Line
No.ADJUSTMENT EXPLANATIONAverage Periodof Allocationto Income
1
2
3
4
6,120,722 38.82 and 30 5
210,680 24 6
69,131 38.82 and 30 7
6,400,533 8
9
10
4,802,974 30 11
4,802,974 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-89) Page 267
Schedule Page: 266 Line No.: 5 Column: b
The electric utility subdivision of 10% accumulated deferred investment tax credits are as
follows:
Acct. Beginning Deferred for Yr. Allocat. to CY Adj. Ending Avg.
Sub. Balance Acct. Amount Acct. Amount Balance Per.
(a) (b) (c) (d) (e) (f) (g) (h) (i)
10% $ 8,823,458 - $ - 411.4(1) $2,730,882 $ - $ 6,092,576 38.82
10% 56,922 - - 420(2) 28,776 - 28,146 30
$ 8,880,380 $ - $2,759,658 $ - $ 6,120,722
(1) Internal Revenue Code 46(f)2
(2) Internal Revenue Code 46(f)1

Schedule Page: 266 Line No.: 6 Column: e
Internal Revenue Code 46(f)1

Schedule Page: 266 Line No.: 7 Column: b
The electric utility subdivision of Idaho accumulated deferred investment tax credits are
as follows:
Acct. Beginning Deferred for Yr. Allocat. to CY Adj. Ending Avg.
Sub. Balance Acct. Amount Acct. Amount Balance Per.
(a) (b) (c) (d) (e) (f) (g) (h) (i)
Idaho $ 41,660 - $ - 411.4(1) $ 7,842 $ - $ 33,818 38.82
Idaho 41,112 - - 420(2) 5,799 - 35,313 30
$ 82,772 $ - $ 13,641 $ - $ 69,131
(1)Internal Revenue Code 46(f)2
(2)Internal Revenue Code 46(f)1
Schedule Page: 266 Line No.: 11 Column: g
Represents an adjustment to the balance at beginning of year credited to Account 190,
Accumulated deferred income taxes.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER DEFFERED CREDITS (Account 253)
PacifiCorp X
/ /2019/Q4
Line
No.
Description and Other DEBITS
Credits
Account(c)(b)(a)
Balance at
End of Year
(d)
Deferred Credits Amount
(e)
Balance at
Beginning of Year Contra
(f)
1. Report below the particulars (details) called for concerning other deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
5,574,362Working Capital Deposits 5,374,091 26,729 227,000131 1
6,498,181Reclamation Costs - Trapper Mine 6,723,040 224,859 2
Western Coal Carriers Benefits 3
10,479,000 Obligation 10,636,000 882,579 725,579131 4
8,609,477Deferred Compensation Plans 10,059,074 2,410,219 960,622131 5
20,751,400Long-Term Incentive Plan 21,972,995 6,745,025 5,523,430131 6
Regulated Environmental 7
55,506,640 Liabilities 56,343,586 12,976,108 12,139,162131,182.3 8
Non-Regulated Environmental 9
1,947,013 Liabilities 1,719,376 88,624 316,261131,426.5 10
Unearned Joint Use 11
2,876,703 Pole Contact Revenue 3,032,343 6,461,038 6,305,398454 12
119,307Misc. Security Deposits 109,551 29,225 38,981415 13
155,310Lease Incentives 124,248 31,062931 14
126,656Cowlitz/Lewis River O&M (1) 129,410 310,582 307,828539 15
18,900Employee Housing Security Deposits 22,000 4,700 1,600131 16
413,417Cogeneration Bonds-Sunnyside 413,417 17
7,735,000Transmission Security Deposits 10,488,050 4,190,279 1,437,229131 18
2,335,548Transmission Service Deposits 2,144,171 533,283 724,660131,235 19
558,002MCI F.O.G. Wire Lease (1) 558,649 3,351,896 3,351,249454 20
67,454,522Unamortized Contract Values 53,496,372 13,958,150242 21
2,420,292Accrued Right-of-Way Obligations 2,829,321 409,029 22
886,164Facility Use Fee 843,553 106,035 148,646451,456 23
Energy Supply Management 24
579,167 Deferral (1) 45,834 533,333456 25
7,182,957Deer Creek Accrued Royalties 7,630,811 447,854 26
291,664Deferred Revenue - Other 70,277 221,387456,921 27
Coal Contract Costs - Naughton 6,664,437 6,664,437 28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-94) Page 269
47 TOTAL 45,862,501 46,951,577 201,430,606 202,519,682
Schedule Page: 269 Line No.: 12 Column: a
The weighted average remaining life is one year.
Schedule Page: 269 Line No.: 14 Column: a
The weighted average remaining life is four years.
Schedule Page: 269 Line No.: 23 Column: a
The weighted average remaining life is 13 years.
Schedule Page: 269 Line No.: 27 Column: a
The weighted average remaining life is one year for amounts being amortized to Account
921, Office supplies and expenses.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
PacifiCorp X
/ /2019/Q4
Line
No.Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
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.
1 Accelerated Amortization (Account 281)
2 Electric
3 Defense Facilities
7,271,333 1,761,741 180,339,430 4 Pollution Control Facilities
5 Other (provide details in footnote):
6
7
7,271,333 1,761,741 180,339,430 8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilities
11 Pollution Control Facilities
12 Other (provide details in footnote):
13
14
15 TOTAL Gas (Enter Total of lines 10 thru 14)
16
7,271,333 1,761,741 180,339,430 17 TOTAL (Acct 281) (Total of 8, 15 and 16)
18 Classification of TOTAL
4,952,107 459,880 147,039,137 19 Federal Income Tax
2,319,226 1,301,861 33,300,293 20 State Income Tax
21 Local Income Tax
FERC FORM NO. 1 (ED. 12-96)Page 272
NOTES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES _ ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of YearDebitsCreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 AccountCredited Amount DebitedAccount Amount
(e)(f)(h)(j)(k)(g)(i)
3. Use footnotes as required.
1
2
3
174,829,838 4
5
6
7
174,829,838 8
9
10
11
12
13
14
15
16
174,829,838 17
18
142,546,910 19
32,282,928 20
21
FERC FORM NO. 1 (ED. 12-96)Page 273
NOTES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
PacifiCorp X
/ /2019/Q4
Line
No.Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
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.
Account 282 1
Electric 2,910,580,066 332,718,514 493,943,276 2
Gas 3
4
TOTAL (Enter Total of lines 2 thru 4) 2,910,580,066 332,718,514 493,943,276 5
Nonutility 6
7
8
TOTAL Account 282 (Enter Total of lines 5 thru 8) 2,910,580,066 332,718,514 493,943,276 9
Classification of TOTAL 10
Federal Income Tax 2,397,447,703 214,925,144 372,073,979 11
State Income Tax 513,132,363 117,793,370 121,869,297 12
Local Income Tax 13
FERC FORM NO. 1 (ED. 12-96)Page 274
NOTES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of YearDebitsCreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 AccountCredited Amount DebitedAccount Amount
(e)(f)(h)(j)(k)(g)(i)
3. Use footnotes as required.
1
182.3,254 2,889,829,879 10,856,821182.3,254 151,331,396 2
3
4
2,889,829,879 10,856,821 151,331,396 5
6
7
8
2,889,829,879 10,856,821 151,331,396 9
10
2,377,767,057 9,036,261 146,504,450 11
512,062,822 1,820,560 4,826,946 12
13
FERC FORM NO. 1 (ED. 12-96)Page 275
NOTES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
PacifiCorp X
/ /2019/Q4
Line
No.Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited to Account 410.1 to Account 411.1
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.
Account 283 1
Electric 2
27,003,311 51,134,439 273,373,737Regulatory Assets 3
12,355,184 15,037,286 12,415,773Other 4
5
6
7
8
39,358,495 66,171,725 285,789,510TOTAL Electric (Total of lines 3 thru 8) 9
Gas 10
11
12
13
14
15
16
TOTAL Gas (Total of lines 11 thru 16) 17
18
39,358,495 66,171,725 285,789,510TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19
Classification of TOTAL 20
31,934,563 53,796,638 233,251,811Federal Income Tax 21
7,423,932 12,375,087 52,537,699State Income Tax 22
Local Income Tax 23
FERC FORM NO. 1 (ED. 12-96)Page 276
NOTES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
Debits CreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 AccountCredited Amount DebitedAccount Amount
(e) (f) (h) (j) (k)(g) (i)
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
1
2
276,140,020 7,425,764 35,907,554 23,056,830 15,939,885 3
21,033,529 5,356,639190,283190,283 6,850,299 8,224,329 795,015 4
5
6
7
8
297,173,549 12,782,403 42,757,853 31,281,159 16,734,900 9
10
11
12
13
14
15
16
17
18
297,173,549 12,782,403 42,757,853 31,281,159 16,734,900 19
20
242,528,418 10,622,931 34,801,434 25,438,621 13,845,586 21
54,645,131 2,159,472 7,956,419 5,842,538 2,889,314 22
23
FERC FORM NO. 1 (ED. 12-96)Page 277
NOTES (Continued)
Schedule Page: 276 Line No.: 3 Column: g
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Account 283, Accumulated deferred income taxes-other
Schedule Page: 276 Line No.: 3 Column: i
Account 182.3, Other regulatory assets
Account 190, Accumulated deferred income taxes
Account 283, Accumulated deferred income taxes-other
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER REGULATORY LIABILITIES (Account 254)
PacifiCorp X
/ /2019/Q4
Line
No.
Description and Purpose of DEBITS
CreditsAccount
(d)(c)(a)
Balance at End
of Current
Quarter/Year
(e)
Other Regulatory Liabilities Amount
(f)
Credited
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining
of Current
Quarter/Year
(b)
2,922,817 3,068,342 1,467,265 1,612,790DSM Balancing Account - CA 440,442,444 1
1,541,064 4,988,861 1,066,780 4,514,577DSM Balancing Account - ID 440,442,444 2
13,057,310 64,279,369 14,306,725 65,528,784DSM Balancing Account - UT 3
1,757,029 9,421,797 3,714,452 11,379,220DSM Balancing Account - WA 440,442,444 4
1,594,641 1,594,641DSM Balancing Account - WY 440,442,444 5
4,375,327 33,594,629 3,772,288 32,991,590Oregon Energy Conservation Charge 440,442,444 6
23,066,215 15,803,826 8,739,343 1,476,954Deferred Excess Net Power Costs - WA 555 7
648,863 648,863Deferred Excess RECs in Rates - UT 8
61,621 61,621Deferred Excess RECs in Rates - WY 9
3,322,101 3,149,670 18,007,592 17,835,161Decoupling Mechanism - WA 440,442 10
738,932 1,188,392 449,460Income Tax Reg. Liability - Flow Through - WA 11
2,359,058 728,701 1,630,571 214Investment Tax Credit Regulatory Liability 190 12
1,800,050,610 315,159,490 1,650,254,838 165,363,718Deferred Income Tax Electric 190,282,411.1 13
68,343,778 21,464,040 70,939,627 24,059,889Excess Income Tax Deferral 440,442,444 14
2,066,824 1,528,422 1,256,164 717,762Tax on Bonus Depreciation - WY (1)440,442,444 15
18,354,603 18,354,603Other Postretirement 16
86,905 1,914,765 76,877 1,904,737Depreciation Study Deferral - ID (1)403 17
3,421,452 3,350,356 71,096Asset Retirement Obligations Reg. Difference 230 18
3,375,158 4,039,385 3,348,606 4,012,833Greenhouse Gas Allowance Compliance - CA 456,555,131 19
623,230 623,230Solar Feed-In Tariff Deferral - CA 20
14,258,175 8,869,138 6,753,231 1,364,194Solar Incentive Program - UT 21
9,734,546 11,318,294 14,781,307 16,365,055STEP Pilot Program - UT 22
22,637 22,637Renewable Portfolio Standards Compliance - OR 23
107,882 107,882Independent Evaluator Costs - UT 24
1,510,555 198,273 1,557,248 244,966Utah Home Energy Lifeline 142 25
504,027 504,027Washington Low Income Program 142 26
435,264 616,464 637,760 818,960California Energy Savings Assistance Program 142 27
30,455,865 6,952,834 35,934,821 12,431,790FERC Rate True-up - OR (3)456 28
3,363,350 471,764 2,891,586BPA Balancing Account - ID 440,442 29
469,946 469,946BPA Balancing Account - WA 440,442 30
214,432 271,318 56,886Blue Sky - CA 31
2,563,475 310,849 2,440,526 187,900Blue Sky - OR 440,442 32
241,534 293,510 51,976Blue Sky - ID 33
9,991,032 2,001,273 8,663,361 673,602Blue Sky - UT 107 34
380,902 542,530 161,628Blue Sky - WA 35
466,343 652,536 186,193Blue Sky - WY 36
5,223,348 6,527,879 1,304,531Depreciation Deferral - OR 37
27,034,388 6,648 39,639,321 12,611,581Deferred Steam Accel. Depreciation - WA 182.3 38
3,432 3,432Merwin Fish Collector Project - WA 39
3,633,859 1,684,530 5,551,592 3,602,263Direct Access 5-Year Opt Out - OR (10)442 40
FERC FORM NO. 1/3-Q (REV 02-04) Page 278
41 TOTAL 403,548,690 517,565,220 1,930,223,376 2,044,239,906
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER REGULATORY LIABILITIES (Account 254)
PacifiCorp X
/ /2019/Q4
Line
No.
Description and Purpose of DEBITS
CreditsAccount
(d)(c)(a)
Balance at End
of Current
Quarter/Year
(e)
Other Regulatory Liabilities Amount
(f)
Credited
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining
of Current
Quarter/Year
(b)
457,600 71,231 395,946 9,577Transportation Electrification Program - CA 232,908 1
487,500 3,655 3,026,020 2,542,175Oregon Clean Fuels Program 232,908 2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/3-Q (REV 02-04) Page 278.1
41 TOTAL 403,548,690 517,565,220 1,930,223,376 2,044,239,906
Schedule Page: 278 Line No.: 3 Column: c
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Account 908, Customer Assistance Expenses

Schedule Page: 278 Line No.: 12 Column: a
Weighted average remaining life is 39 years.
Schedule Page: 278 Line No.: 13 Column: a
Amounts primarily represent income tax liabilities related to the federal tax rate change
from 35% to 21% that are probable to be passed on to customers, offset by income tax
benefits related to certain property-related basis differences and other various
differences that were previously passed on to customers and will be included in regulated
rates when the temporary differences reverse.
Schedule Page: 278 Line No.: 14 Column: a
Weighted average remaining life is approximately one year for excess income tax defferals
in rates being amortized.
Schedule Page: 278 Line No.: 19 Column: a
Includes California Solar on Multifamily Affordable Housing
Schedule Page: 278 Line No.: 21 Column: c
Account 182.3, Other regulatory assets
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Schedule Page: 278 Line No.: 22 Column: c
Account 107, Construction work in progress
Account 440, Residential sales
Account 442, Commercial and industrial sales
Account 444, Public street and highway lighting
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC OPERATING REVENUES (Account 400)
PacifiCorp X
/ /2019/Q4
Line
No.Title of Account
(c)(b)(a)
Operating Revenues Year
to Date Quarterly/Annual
1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), 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 (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are
added for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the
close of each month.
4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.
Operating Revenues
Previous year (no Quarterly)
Sales of Electricity 1
1,774,237,100(440) Residential Sales 1,815,760,353 2
(442) Commercial and Industrial Sales 3
1,541,492,719Small (or Comm.) (See Instr. 4) 1,547,127,608 4
1,322,455,444Large (or Ind.) (See Instr. 4) 1,316,469,104 5
18,155,451(444) Public Street and Highway Lighting 18,198,044 6
(445) Other Sales to Public Authorities 7
(446) Sales to Railroads and Railways 8
(448) Interdepartmental Sales 9
4,656,340,714TOTAL Sales to Ultimate Consumers 4,697,555,109 10
254,214,730(447) Sales for Resale 192,271,657 11
4,910,555,444TOTAL Sales of Electricity 4,889,826,766 12
(Less) (449.1) Provision for Rate Refunds 13
4,910,555,444TOTAL Revenues Net of Prov. for Refunds 4,889,826,766 14
Other Operating Revenues 15
9,811,199(450) Forfeited Discounts 9,415,631 16
6,172,987(451) Miscellaneous Service Revenues 8,845,804 17
54,615(453) Sales of Water and Water Power 53,658 18
17,246,955(454) Rent from Electric Property 17,459,728 19
(455) Interdepartmental Rents 20
29,900,870(456) Other Electric Revenues 28,198,210 21
116,616,886(456.1) Revenues from Transmission of Electricity of Others 111,912,996 22
(457.1) Regional Control Service Revenues 23
(457.2) Miscellaneous Revenues 24
25
179,803,512TOTAL Other Operating Revenues 175,886,027 26
5,090,358,956TOTAL Electric Operating Revenues 5,065,712,793 27
Page 300FERC FORM NO. 1/3-Q (REV. 12-05)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC OPERATING REVENUES (Account 400)
PacifiCorp X
/ /2019/Q4
Line
No.
MEGAWATT HOURS SOLD
Previous Year (no Quarterly)Current Year (no Quarterly)
AVG.NO. CUSTOMERS PER MONTH
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)
(d) (e) (f) (g)
6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by
the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of
classification in a footnote.)
7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
9. Include unmetered sales. Provide details of such Sales in a footnote.
1
16,227,117 1,651,326 1,681,634 16,668,416 2
3
18,078,160 211,800 214,182 18,150,545 4
20,679,901 33,186 33,151 20,395,896 5
130,278 3,501 3,565 127,750 6
7
8
9
55,115,456 1,899,813 1,932,532 55,342,607 10
8,309,472 5,479,628 11
63,424,928 1,899,813 1,932,532 60,822,235 12
13
63,424,928 1,899,813 1,932,532 60,822,235 14
Page 301
Line 12, column (b) includes $ of unbilled revenues.
Line 12, column (d) includes MWH relating to unbilled revenues
244,728,000
2,903,366
FERC FORM NO. 1/3-Q (REV. 12-05)
Schedule Page: 300 Line No.: 11 Column: f
For a complete list of the number of customers see pages 310-311, Sales for resale, in
this FERC Form No. 1.
Schedule Page: 300 Line No.: 11 Column: g
For a complete list of the number of customers see pages 310-311, Sales for resale, in
PacifiCorp's December 31, 2018 FERC Form No. 1.
Schedule Page: 300 Line No.: 17 Column: b
Account 451, Miscellaneous service revenues, includes the following items that were
$250,000 or greater during the years ended December 31:
2019 2018
Account service charges - application fees,
disconnects, reconnects and returned check charges $ 7,556,998 $ 5,274,993
Customer contract flat rate billings and facility
buyout charges 1,272,737 873,886
Schedule Page: 300 Line No.: 21 Column: b
Account 456, Other electric revenues, includes the following items that were $250,000 or
greater during the years ended December 31:
2019 2018
Amortization of California greenhouse gas
allowance revenue $ 12,254,503 $ 9,591,652
Wind-based ancillary services 9,193,455 11,169,083
Flyash/by-product sales 4,075,964 4,258,230
Renewable energy credit sales, including
amortization and deferrals 2,878,143 3,300,207
Timber sales 649,985 506,102
Steam sales 557,219 689,865
Revenues for assigned purchased power agreement 533,333 350,000
Maintenance charges for work on transmission facilities 471,749 432,874
Revenues from generation interconnection and
transmission service request studies 400,637 1,659,764
Phase shifting equipment fee from
Western Electricity Coordinating Council (a) 1,380,032
Revenues from other requested customer studies (a) 266,676
Net loss on sales of materials and supplies inventory (331,617) (a)
Deferral of Oregon retail customers' allocated share of
the incremental Open Access Transmission Tariff revenues
associated with FERC Docket No. ER11-3643-000, net of
amortization (3,135,370) (4,129,687)
(a) Amount is less than $250,000.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 RESIDENTIAL SALES
2 CALIFORNIA
1 3 06CHCK000R - CA RES CHECK M
3,087 4 06LNX00311 - LINE EXT 80% GTY
2,333 434 5,376 0.1074 250,518 5 06NETMT135 - CA RES NET MTR
264 280 943 0.2877 75,948 6 06OALT015R - OUTD AR LGT SR
165,982 17,334 9,576 0.1260 20,920,308 7 06RESD000D - RES SRVC
75,330 6,904 10,911 0.1282 9,654,880 8 06RESD00DN - DEL NORTE CTY
116,934 11,348 10,304 0.1270 14,846,440 9 06RESDDL06 - CA LOW INCOME
1,396 478 2,921 0.2148 299,859 10 06RGNSV025 - CA SMALL GEN
1 93 11 06RNM25135 - CA NET MTR, GEN
167 7 23,857 0.1057 17,645 12 06RESD0DM9 - MULTI FAMILY
1,538 18 85,444 0.0861 132,440 13 06RESD0DS8 - MULT FAM SBMET
-184,385 14 REVENUE - ACCT ADJ
-1,931,372 15 INCOME TAX DEFERRAL ADJ
1,540,309 16 DSM REVENUE - RESIDENTIAL
25,290 17 BLUE SKY REV - RESIDENTIAL
28,114 18 OTHER CUST RETAIL REV
-437 -1.1922 521,000 19 UNBILLED REVENUE
-3,000 20 UNBILLED REV - UNCOLLECTIBLE
21
22 IDAHO
1,173 23 07LNX00010 - MNTHLY 80%GTY
2,650 24 07LNX00035 - ADV 80%MO GTY
7,230 889 8,133 0.0857 619,805 25 07NETMT135 - ID RES NET MTR
10 1 10,000 0.3805 3,805 26 07OALCO007 - CUST OWN LIGHT
94 118 797 0.4100 38,536 27 07OALT07AR - SECURITY AR LG
518,009 54,003 9,592 0.1125 58,299,042 28 07RESD0001 - RES SRVC
193,631 11,225 17,250 0.0957 18,531,010 29 07RESD0036 - RES SRVC-OPTIO
304 3 101,333 0.0840 25,546 30 07RGNSV06A - LRG GEN SVC-RES
9,374 1,098 8,537 0.1109 1,039,560 31 07RGNSV23A - SM GEN SVC-RES
253 6 42,167 0.0836 21,161 32 07RNM23135 - NET MTR SMALL
-275,674 33 REVENUE - ACCT ADJ
-49,462 34 INCOME TAX DEFERRAL ADJ
1,995,565 35 DSM REVENUE - RESIDENTIAL
9,092 36 BLUE SKY REV - RESIDENTIAL
6,252 0.0952 595,000 37 UNBILLED REVENUE
9,000 38 UNBILLED REV - UNCOLLECTIBLE
39
40
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 OREGON
1 2 01CHCK000R - RES CHECK MTR
5,060,497 0.0613 310,044,448 3 01COST0004 - 01RESD0004
95,894 0.0619 5,933,876 4 01COSTR023 - RES GEN SRV CST
48,432 0.0616 2,983,843 5 01COSTR028 - OR RES GEN SVC
-4 6 01FXRENEWR - FIXED
54,244 0.0601 3,261,741 7 01HABIT004 - 01RESD0004
203 0.0634 12,863 8 01HABTR023 - RES GEN SVC HAB
9,729 9 01LNX00102 - LINE EXT 80% GTY
3,889 10 01LNX00109 - REF/NREF ADV +
142 11 01LNX00300 - LINE EXT 80% GTY
5,798 2,394,056 12 01NETMT135 - NET METERING
32 -23,782 13 01NMTOU135 - TOU NET
2,037 2,373 858 0.1602 326,228 14 01OALTB15R - OR OUTD AR LGT
13,196 0.0629 829,919 15 01PTOU0004 - 01RESD0004
4 0.0568 227 16 01PTOU0005 - 01RESEV05T TOU
408,656 0.0593 24,225,804 17 01RENEW004 - 01RESD0004
780 0.0604 47,084 18 01RENWR023 - RENEW USAGE
504,087 277,400,261 19 01RESD0004 - RES SRVC
986 667,762 20 01RESD004T - RES TIME OPT
1 290 21 01RESEV05T- RES ELECT
17,041 6,995,462 22 01RGNSB023 - SM GEN SVC-RES
213 1,218,657 23 01RGNSB028 - GEN SVC > 30 KW -
131 52,721 24 01RNETM023 - NET MTR RES GEN
4 51,682 25 01RNETM028 - NET MTR RES GEN
2 26 01UPPL000R - BASE SCH FALL
471 360,131 27 01VIR04136 - VOLUME INCENTIVE
-3,042,695 28 REVENUE - ACCT ADJ
17,150 29 OR GAIN ON SALE OF ASSET
215,593 30 INCOME TAX DEFERRAL ADJ
19,782,965 31 DSM REVENUE - RESIDENTIAL
616,900 32 BLUE SKY REV - RESIDENTIAL
1,839,427 33 SOLAR FEED-IN REVENUE
50,481 34 COMMUNITY SOLAR REVENUE
38,169 0.1353 5,165,000 35 UNBILLED REVENUE
-40,000 36 UNBILLED REV - UNCOLLECTIBLE
37
38
39
40
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.1
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 UTAH
713 2 08CFR00001 - MTH FACILITY S
209 26 8,038 0.1112 23,241 3 08CGENR136 - UT RES TRANS
36,356 5,027 7,232 0.1078 3,917,392 4 08CGR01136 - UT RES TRANS
21 4 5,250 0.1063 2,232 5 08CGR02136 - UT RES TOU TRANS
257 34 7,559 0.1069 27,466 6 08CGR03136 - UT LOW INC RES
117 3 39,000 0.0837 9,795 7 08CGR23136 - RES SMALL GEN
1 8 08CHCK000R - UT RES CHECK M
99,763 1,573 9 08COOLKPRR - COOL KEEPER
2,895 10 08LNX00001 - MTHLY 80% GUAR
396 11 08LNX00005 - MTHLY MIN GUAR
27,115 12 08LNX00013 - 80% MNTHLY MIN
1,656 13 08LNX00108 - ANN COST MTHLY
11,618 8 1,452,250 0.0738 857,261 14 08MHTP0006 - MOBILE HOME &
114 1 114,000 0.0774 8,826 15 08MHTP0023 - MOBILE HOME &
117,500 29,676 3,959 0.1176 13,815,643 16 08NETMT135 - NET MTR
1,102 193 5,710 0.1082 119,182 17 08NMT03135 - LOW INC RES NET
2,253 2,277 989 0.2777 625,708 18 08OALT007R - SECURITY AR LG
1 2 500 0.1050 105 19 08PTLD000R - POST TOP LIGHT
28 5 5,600 0.1205 3,374 20 08RCG23136 - RES NET MTR,
6,510,293 767,739 8,480 0.1069 695,965,278 21 08RESD0001 - RES SRVC
3,071 385 7,977 0.1052 323,128 22 08RESD0002 - RES SRVC-OPTIO
152,216 21,009 7,245 0.1052 16,009,140 23 08RESD0003 - LIFELINE PRGRM
4,043 285 14,186 0.0846 342,218 24 08RESD002E - RES ELECT
124,273 289 430,010 0.0742 9,226,908 25 08RGNSV006 - GEN SRVC-RES
451 1 451,000 0.0710 32,041 26 08RGNSV008 - UT RES GEN SVC
101,822 13,824 7,366 0.1067 10,867,749 27 08RGNSV023 - GEN SRVC-RES
8,683 28 310,107 0.0847 735,569 28 08RGNSV06A - UT SMALL GEN
25 1 25,000 0.1400 3,499 29 08RGNSV06B - UT SMALL GEN
3,782 13 290,923 0.0855 323,190 30 08RNM06135 - UT NET MTR, GEN
1,240 435 2,851 0.1300 161,144 31 08RNM23135 - UT NET MTR, GEN
6 2 3,000 0.8905 5,343 32 08RNM6A135 - RES GEN SVC NET
446 33 08RTCVLNGA - TCV LNX GAR
34,093 0.0941 3,208,694 34 08SSLR0001 - RES SUBSCRB
263 23 11,435 0.0957 25,160 35 08SSLR0003 - RES LOW INC
69 17 4,059 0.1129 7,787 36 08SSLRRG23 - RES SMALL GEN
4 37 08UPPL000R - BASE SCH FALL
-1,227,136 38 REVENUE - ACCT ADJ
2,405,361 39 REVENUE ADJ - DEF NPC
3,637,605 40 DSM REVENUE - RESIDENTIAL
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.2
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
2,162,997 1 BLUE SKY REV - RESIDENTIAL
1,838,486 2 SOLAR FEED-IN REVENUE
40,159 0.1158 4,651,000 3 UNBILLED REVENUE
-28,000 4 UNBILLED REV - UNCOLLECTIBLE
5
6 WASHINGTON
1,715 7 02LNX00109 - REF/NREF ADV +
13,159 1,187 11,086 0.0981 1,290,703 8 02NETMT135 - WA RES NET MTR
930 1,021 911 0.1546 143,785 9 02OALTB15R - WA OUTD AR LGT
1,526,978 101,802 14,999 0.0916 139,840,256 10 02RESD0016 - WA RES SRVC
83,924 5,327 15,754 0.0918 7,701,465 11 02RESD0017 - BILL ASSISTANC
2,132 78 27,333 0.1007 214,603 12 02RESD0018 - WA 3 PHASE RES
300 12 25,000 0.0987 29,624 13 02RESD018X - WA 3 PHASE RES
20,859 3,430 6,081 0.1152 2,403,776 14 02RGNSB024 - WA SMALL GEN
1,728 2 864,000 0.0723 124,882 15 02RGNSB036 - RES LRG GEN SVC
239 30 7,967 0.1070 25,564 16 02RNM24135 - RES NET MTR
-9,616,349 17 REVENUE - ACCT ADJ
63,916 18 REVENUE ADJ - DEF NPC
-8,218,174 19 ALT REVENUE PROGRAM ADJ
4,266,925 20 DSM REVENUE - RESIDENTIAL
148,960 21 BLUE SKY REV - RESIDENTIAL
4,410 1.1506 5,074,000 22 UNBILLED REVENUE
-24,000 23 UNBILLED REV - UNCOLLECTIBLE
24
25 WYOMING
723 26 05LNX00102 - LINE EXT 80% GTY
2,082 220 9,464 0.1156 240,739 27 05NETMT135 - EXP PARTIAL REQ
821 971 846 0.1395 114,512 28 05OALT015R - OUTD AR LGT SR
898,279 102,250 8,785 0.1066 95,745,797 29 05RESD0002 - WY RES SRVC
9,368 1,536 6,099 0.1199 1,123,451 30 05RGNSV025 - WY SMALL GEN
-78 31 09OALT207R - SECURITY AR LG
407,880 32 REVENUE - ACCT ADJ
556,518 33 INCOME TAX DEFERRAL ADJ
-33,044 34 REVENUE ADJ - DEF NPC
1,513,434 35 DSM REVENUE - RESIDENTIAL
35,795 36 DSM REVENUE - RES GEN SVC
11,465 37 BLUE SKY REV - RESIDENTIAL
12,828 0.1035 1,328,000 38 UNBILLED REVENUE
-23,000 39 UNBILLED REV - UNCOLLECTIBLE
115,513 12,514 9,231 0.1079 12,466,911 40 05RESD0002 - WY RES SRVC
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.3
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
478 146 3,274 0.1609 76,915 1 05RGNSV025 - WY SMALL GEN
68 82 829 0.2374 16,141 2 09OALT207R - SECURITY AR LG
359 3 05LNX00109 - REF/NREF ADV +
499 42 11,881 0.1138 56,803 4 05NETMT135 - EXP PARTIAL REQ
17 5 05OALT015R - OUTD AR LGT SR
1 6 09RES00002
4 7 09RESD0002
149,520 8 DSM REVENUE - RESIDENTIAL
3,489 9 DSM REVENUE - RES GEN SVC
20,342 10 BLUE SKY REV - RESIDENTIAL
-1,020 0.1088 -111,000 11 UNBILLED REVENUE
12
-125,384 13 LESS MULTIPLE BILLINGS
14
16,668,416 1,681,634 9,912 0.1089 1,815,760,353 15 TOTAL RESIDENTIAL SALES
16
17 COMMERCIAL SALES
18 CALIFORNIA
53,118 6,547 8,113 0.1803 9,579,774 19 06GNSV0025 - CA GEN SRVC
921 85 10,835 0.1972 181,643 20 06GNSV025F - GEN SRVC-< 20
85,913 1,072 80,143 0.1547 13,289,482 21 06GNSV0A32 - GEN SRVC-20 KW
27,778 8 3,472,250 0.1028 2,854,691 22 06LGSV048T - LRG GEN SERV
2,697 1 2,697,000 0.1003 270,619 23 06NMT48135 - GEN SVC NET
61,648 151 408,265 0.1313 8,095,749 24 06LGSV0A36 - LRG GEN SRVC-O
2,785 25 06LNX00102 - LINE EXT 80% GTY
116,858 26 06LNX00109 - REF/NREF ADV +
28,229 27 06LNX00311 - LINE EXT 80% GTY
2,617 28 06LNX00312 - CA IRG LINE EXT
2,759 6 459,833 0.1350 372,431 29 06NMT36135 - GEN SVC NET
645 467 1,381 0.2907 187,532 30 06OALT015N - OUTD AR LGT SR
155 37 4,189 0.2295 35,573 31 06RCFL0042 - AIRWAY & ATHLE
123 25 4,920 0.1949 23,967 32 06NMT25135 - GEN SVC NET
1,985 26 76,346 0.1709 339,240 33 06NMT32135 - GEN SVC NET
-121,540 34 REVENUE - ACCT ADJ
-1,207,583 35 INCOME TAX DEFERRAL ADJ
969,334 36 DSM REVENUE - COMMERCIAL
2,542 37 BLUE SKY REV - COMMERCIAL
27,894 38 OTHER CUST RETAIL REV
83 1.1566 96,000 39 UNBILLED REVENUE
40
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.4
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 IDAHO
5,011 85 58,953 0.0843 422,586 2 07CISH0019 - COMM & IND SPA
247,330 1,030 240,126 0.0800 19,777,516 3 07GNSV0006 - GEN SRVC-LRG P
41,868 2 20,934,000 0.0622 2,602,114 4 07GNSV0009 - GEN SRVC-HI VO
156,930 7,145 21,964 0.0977 15,327,910 5 07GNSV0023 - GEN SRVC-SML P
273 2 136,500 0.0796 21,739 6 07GNSV0035 - GEN SRVCOPTION
22,920 176 130,227 0.0857 1,965,011 7 07GNSV006A - GEN SRVC-LRG P
27,252 1,282 21,257 0.0970 2,643,564 8 07GNSV023A - GEN SRVC-SML P
6 4 1,500 0.2805 1,683 9 07GNSV023F - GEN SRVC SML P
18,736 10 07LNX00010 - MNTHLY 80%GUAR
238,488 11 07LNX00035 - ADV 80%MO GUAR
37,305 12 07LNX00040 - ADV+REFCHG+80%
247 168 1,470 0.3866 95,495 13 07OALT007N - SECURITY AR LG
10 10 1,000 0.3862 3,862 14 07OALT07AN - SECURITY AR LG
17,694 15 07LNX00312 - ID LINE EXT
1,667 4 416,750 0.0821 136,778 16 07NMT06135 - ID NET MTR - LG
1,175 32 36,719 0.0796 93,549 17 07NMT23135 - ID NET MTR -
485 18 07LNX00015 - ANNUAL 80% GTY
34,378 19 07LNX00311 - LINE EXT 80% GTY
4,049 20 07LNX00300 - 80% MONTHLY MIN
-158,391 21 REVENUE - ACCT ADJ
-35,510 22 INCOME TAX DEFERRAL ADJ
1,103,786 23 DSM REVENUE - COMMERCIAL
891 24 BLUE SKY REV - COMMERCIAL
7,872 0.0816 642,000 25 UNBILLED REVENUE
26
27 OREGON
1,025,836 0.0596 61,109,229 28 01COST0023 - OR GEN SRV
1,112,645 0.0493 54,828,942 29 01COST0048 - 01LGSV0048
3,003 0.0633 190,220 30 01COST023F - OR GEN SRV
24,832 0.0605 1,502,746 31 01COSTB023 - OR GEN SRV
181 0.0622 11,257 32 01COSTEV45 - ELECT VEHICLE
-72 0.0341 -2,453 33 01COSTL028 - OR LRG SRV
1,124,721 0.0529 59,530,529 34 01COSTL030 - OR LRG GEN SRV
1,927,277 0.0617 118,905,766 35 01COSTS028 - OR GEN SERV
2,840 1,545,369 36 01GNSB0023 - OR GEN SRV BPA
288 1,721,490 37 01GNSB0028 - OR GEN SRV, BPA
45 24,662 38 01GNSB023T - OR GEN SRV - TOU
16 39,137 39 01GNSEV45T - ELECT VEHICLE
58,967 51,436,098 40 01GNSV0023 - OR GEN SRV, < 30
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.5
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
9,004 51,799,330 1 01GNSV0028 - OR GEN SRV > 30
10,779 782 13,784 0.1543 1,663,217 2 01GNSV023F - OR GEN SRV - FLAT
78 2 39,000 0.1456 11,355 3 01GNSV023M - OR GEN SRV,
188 143,714 4 01GNSV023T - OR GEN SRV, TOU
2 5,860 5 01GNSV0723 - OR GEN SVC DIR
3,442 0.0602 207,226 6 01HABT0023 - OR HABITAT
7 0.0633 443 7 01HABTB023 - OR HABITAT
21 861,092 8 01LGSB0030 - GEN DEL SRV, > 200
-1,805 9 01LGSV0028 - OR LRG GEN SRV <
653 27,101,958 10 01LGSV0030 - OR LRG GEN SRV >
92 16,200,470 11 01LGSB0048 - LG GEN SVC > 1000
61,439 1 61,439,000 0.0607 3,731,108 12 01LGSV048M - LRG GEN SRVC 1
4,189 13 01LNX00100 - LINE EXT 60% GTY
930,703 14 01LNX00102 - LINE EXT 80% GTY
6,936 15 01LNX00103 - LINE EXT 80% GTY
11,841 16 01LNX00105 - CNTRCT $ MIN GTY
1,254,885 17 01LNX00109 - REF/NREF ADV +
8,348 18 01LNX00110 - REF/NREF ADV +
227,261 19 01LNX00311 - LINE EXT 80% GTY
1,496 20 01LNX00312 - OR IRG LINE EXT
1,202 21 01LNX00120 - LINE EXT 60% GTY
308,225 22 01LNX00300 - LINE EXT 80% GTY
35,804 5 7,160,800 0.0984 3,522,825 23 01LPRS047M - PART REQ SRVC
1 1,487 24 01NM23T135 - OR NET MTR TOU
429 353,883 25 01NMT23135 - OR NET MTR, GEN,
235 1,639,713 26 01NMT28135 - OR NET MTR, GEN,
32 1,369,084 27 01NMT30135 - OR NET MTR, GEN,
4 499,504 28 01NMT48135 - NET MTR GEN SVC
-725 29 01NMTEV45T - OR NET MTR, EV
5,213 2,730 1,910 0.1447 754,282 30 01OALT015N - OUTD AR LGT NR
1,366 1,005 1,359 0.1654 225,878 31 01OALTB15N - OR OUTD AR LGT
2,808 0.0593 166,652 32 01PTOU0023 - OR GEN SRV, TOU
403 0.0613 24,704 33 01PTOUB023 - OR GEN SRV, TOU
1,458 105 13,886 0.0961 140,169 34 01RCFL0054 - REC FIELD LGT
13,964 0.0607 847,837 35 01RENW0023 - OR RENW USAGE
181 0.0576 10,422 36 01RENWB023 - OR RENEWABLE
3,541 0.0644 228,033 37 01STDAY023 - OR DAY STD OFR,
12,797 0.0649 830,083 38 01STDAY028 - OR DAY STD OFF,
5,348 0.0578 309,206 39 01STDAY030 - OR STD DAY OFF,
122 177,940 40 01VIR23136 - OR VOL INCENTIVE
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.6
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
89 533,681 1 01VIR28136 - OR VOL INCENTIVE >
7 267,302 2 01VIR30136 - OR VOL INCENTIVE >
1 110,455 3 01VIR48136 - OR VOL INCENTIVE >
62 4 01ZZMERGCR - MERGER CREDITS
1 77,015 5 01LGSB0048 - LG GEN SVC >
487 1 487,000 0.0894 43,551 6 01LGSV028M - OR LGSV, <1000
2 38,004 7 01GNSV0728 - OR GEN SVC DIR
14 1,661,406 8 01GNSV0730 - OR GEN SVC DIR
3 8,385,483 9 01GNSV0748 - LG GEN SVC DIR
-1,045,125 10 REVENUE - ACCT ADJ
15,978 11 OR GAIN ON SALE OF ASSET
200,893 12 INCOME TAX DEFERRAL ADJ
12,093,786 13 DSM REVENUE - COMMERCIAL
101 759,886 14 BLUE SKY REV - COMMERCIAL
1,710,007 15 SOLAR FEED-IN REVENUE
41,114 16 COMMUNITY SOLAR REVENUE
39,305 0.0690 2,713,000 17 UNBILLED REVENUE
18
19 UTAH
1,303 20 08ABL-NRES - APPLICANT BUILT
3,864 21 08ABTCLXGN - LINE EXT 80%
33,483 22 08CFR00051 - MTH FAC SRVCHG
2 23 08CFR00052 - ANN FAC SVCCHG
1,065 2 532,500 0.1077 114,689 24 08CGM06136 - UT NET MTR
210 8 26,250 0.1013 21,281 25 08CGM23136 - UT NET MT SM GEN
1,346 1 1,346,000 0.0944 127,011 26 08CGN08136 - UT NET MTR GEN
4,529 17 266,412 0.1021 462,369 27 08CGN06136 - UT GEN SVC
919 37 24,838 0.0941 86,473 28 08CGN23136 - UT NET MTR SMALL
262 1 262,000 0.0957 25,073 29 08CGN6A136 - UT GEN SVC TRAN
2,234 35 30 08COOLKPRN - A/C DIRECT LOAD
4,991,880 11,243 443,999 0.0816 407,124,779 31 08GNSV0006 - GEN SRVC-DISTR
862,835 42 20,543,690 0.0559 48,229,220 32 08GNSV0009 - GEN SRVC-HI VO
1,241,510 74,122 16,750 0.0970 120,457,881 33 08GNSV0023 - GEN SRVC-DISTR
245,369 1,950 125,830 0.1154 28,309,110 34 08GNSV006A - GEN SRVC-ENERG
3,270 14 233,571 0.0957 313,077 35 08GNSV006B - GEN SRVC-DEM&
60 2 30,000 0.0746 4,475 36 08GNSV006M - MNL DIST VOLTG
22,540 2 11,270,000 0.0657 1,480,551 37 08GNSV009A - GEN SRVC HI VO
236,384 1 236,384,000 0.0557 13,174,610 38 08GNSV009M - MANL HIGH VOLT
1,307 129 10,132 0.1398 182,672 39 08GNSV023F - GEN SRVC FIXED
245 3 81,667 0.0740 18,124 40 08GNSV023M - GNSV DIST VOLT
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.7
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
80 1 80,000 0.2203 17,622 1 08GNSV06AM - MNL ENERGY TOD
36,945 640 57,727 0.0789 2,916,357 2 08GNSV06MN - GNSV DIST VOLT
711,182 3 08LNX00002 - MTHLY 80% GUAR
52,594 4 08LNX00004 - ANNUAL 80%GUAR
2,847 5 08LNX00006 - FIXD MTHLY MIN
350 6 08LNX00008 - ANNUALMIN GUAR
1,990,862 7 08LNX00014 - 80% MIN MNTHLY
321,880 8 08LNX00017 - ADV/REF&80%ANN
31,062 9 08LNX00158 - ANNUALCOST MTH
186,737 10 08LNX00300 - LINE EXT 80% PLUS
68,315 11 08LNX00310 - IRR, 80% ANNUAL
13,022 12 08LNX00312 - UT IRG LINE EXT
123,797 267 463,659 0.0841 10,411,052 13 08NMT06135 - UT NET MTR GEN
57,651 11 5,241,000 0.0756 4,355,700 14 08NMT08135 - NET MTR GEN SVC
9,741 819 11,894 0.1048 1,020,794 15 08NMT23135 - UT NET MTR, GEN,
10,517 89 118,169 0.1294 1,360,824 16 08NMT6A135 - NET MTR GEN SVC
7,230 3,861 1,873 0.2280 1,648,722 17 08OALT007N - SECURITY AR LG
1 129 18 08POLE0075 - POLES W/LIGHT
134,486 4 33,621,500 0.0615 8,265,787 19 08PRSV031M - BKUP MNT&SUPPL
6 2 3,000 0.0753 452 20 08PTLD000N - POST TOP LIGHT
13,073 0.0645 842,610 21 08REFS032M - UT RENEWABLE
4,654 9 517,111 0.0988 459,631 22 08SSLR0006 - GENERAL SVC
4,043 0.0860 347,797 23 08SSLR0023 - SMALL GEN SVC
40,024 319 125,467 0.0994 3,976,960 24 08SSLR006A - GEN SVC TOU
3,536 25 08TCVLAACN - UT TCV LNX
27,146 26 08TCVLNXGN - TCV LNX - 80%
2,197 27 08TCVLXACN - GAR ADDED
171 20 8,550 0.0893 15,277 28 08TOSS015F - TRAFFIC SIG NM
3,062 1,067 2,870 0.1033 316,345 29 08TOSS0015 - TRAF & OTHER S
14,554 538 27,052 0.0721 1,049,399 30 08MONL0015 - MTR OUTDONIGHT
291,799 31 08LNX00311 - LINE EXT 80%
915,089 127 7,205,425 0.0709 64,836,573 32 08GNSV0008 - UT GEN SVC TOU >
16,898 3 5,632,667 0.0795 1,343,144 33 08GNSV008M - UT GEN SVC TOU >
-1,600,450 34 REVENUE - ACCT ADJ
3,097,804 35 REVENUE ADJ - DEF NPC
4,684,682 36 DSM REVENUE - COMMERCIAL
443,358 37 BLUE SKY REV - COMMERCIAL
2,367,741 38 SOLAR FEED-IN REVENUE
47,985 0.0894 4,289,000 39 UNBILLED REVENUE
40
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.8
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 WASHINGTON
139 2 02GN24EV45 - WA ELECTRIC
28,242 1,518 18,605 0.0936 2,643,931 3 02GNSB0024 - WA GEN SRVC DO
153 6 25,500 0.1255 19,205 4 02GNSB024F - GEN SRVC DOM/F
149 72 2,069 0.4446 66,245 5 02GNSB24FP - WA GEN SVC
481,488 14,410 33,413 0.0882 42,471,530 6 02GNSV0024 - WA GEN SRVC
1,070 104 10,288 0.1360 145,497 7 02GNSV024F - WA GEN SRVC-FL
50,588 87 581,471 0.0781 3,951,952 8 02LGSB0036 - LRG GEN SVC IRG
775,889 874 887,745 0.0751 58,293,473 9 02LGSV0036 - WA LRG GEN SRV
182,073 36 5,057,583 0.0712 12,972,346 10 02LGSV048T - LRG GEN SRVC 1
56,006 11 02LNX00102 - LINE EXT 80% GTY
119,754 12 02LNX00103 - LINE EXT 80% GTY
2,011 13 02LNX00105 - CNTRCT $ MIN GTY
297,156 14 02LNX00109 - REF/NREF ADV +
32,999 15 02LNX00110 - REF/NREF ADV +
669 16 02LNX00112 - YR INCURRED CH
15,986 17 02LNX00300 - LINE EXT 80% GTY
1,928 18 02LNX00310 - IRG, 80% ANNUAL
53,743 19 02LNX00311 - LINE EXT 80% GTY
14,333 20 02LNX00312 - WA IRG LINE EXT
100 20 5,000 0.1370 13,702 21 02NMB24135 - WA NET METERING
1,424 766 1,859 0.1439 204,978 22 02OALT015N - WA OUTD AR LGT
504 464 1,086 0.1571 79,165 23 02OALTB15N - WA OUTD AR LGT
292 27 10,815 0.0897 26,191 24 02RCFL0054 - WA REC FIELD L
-1 25 02RFNDCEN - CENTRALIA RFND
4,184 95 44,042 0.0902 377,256 26 02NMT24135 - NET MTR, WA
12,533 16 783,313 0.0805 1,009,040 27 02NMT36135 - WA NET MTR LRG
10,901 2 5,450,500 0.0702 765,701 28 02NMT48135 - WA LG SVC NET
-8,247,772 29 REVENUE - ACCT ADJ
63,079 30 REVENUE ADJ - DEF NPC
-7,194,658 31 ALT REVENUE PROGRAM ADJ
3,409,065 32 DSM REVENUE - COMMERCIAL
2 18,143 33 BLUE SKY REV - COMMERCIAL
-3,088 0.0576 -178,000 34 UNBILLED REVENUE
35
36
37
38
39
40
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.9
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 WYOMING
1 2 05CHCK000N - WY NRES CHECK
227,847 18,005 12,655 0.0955 21,761,916 3 05GNSV0025 - WY GEN SRVC
846,815 3,169 267,218 0.0824 69,805,696 4 05GNSV0028 - GEN SVC > 15 KW
987 173 5,705 0.1563 154,295 5 05GNSV025F - GEN SRVC-FL RA
151,675 13 11,667,308 0.0704 10,673,105 6 05LGSV0046 - WY LRG GEN SRV
11,886 1 11,886,000 0.0715 849,341 7 05LGSV048T - LRG GENSRV TIM
13,622 8 05LNX00100 - LINE EXT 60% GTY
506,511 9 05LNX00102 - LINE EXT 80% GTY
1,255 10 05LNX00103 - LINE EXT 80% GTY
5,410 11 05LNX00105 - CNTRCT $ MIN GTY
330,803 12 05LNX00109 - REF/NREF ADV +
2,610 13 05LNX00110 - REF/NREF ADV +
134 14 05LNX00114 - TEMP SVC 12MO>
403 33 12,212 0.0927 37,376 15 05NMT25135 - WY NET MTR, GEN,
8,039 23 349,522 0.0827 664,563 16 05NMT28135 - NET MTR SMALL
2,546 1,566 1,626 0.1391 354,275 17 05OALT015N - OUTD AR LGT SR
969 60 16,150 0.0672 65,079 18 05RCFL0054 - WY REC FIELD L
-7 19 09OALT207N - SECURITY AR LG
131,021 20 05LNX00300 - LINE EXT 80% GTY
1,628 21 05LNX00310 - LINE EXT
39,540 22 05LNX00311 - LINE EXT 80% GTY
5,646 23 05LNX00312 - WY IRG LINE EXT
476,506 24 REVENUE - ACCT ADJ
798,601 25 INCOME TAX DEFERRAL ADJ
-47,418 26 REVENUE ADJ - DEF NPC
2,559,184 27 DSM REVENUE - SM
31,998 28 DSM REVENUE - LG COMMERCIAL
1,340 29 BLUE SKY REV - COMMERCIAL
5,483 0.0751 412,000 30 UNBILLED REVENUE
33,382 2,435 13,709 0.0938 3,130,358 31 05GNSV0025 - WY GEN SRVC
90,549 374 242,110 0.0821 7,433,956 32 05GNSV0028 - GEN SVC > 15 KW
199 33 6,030 0.1234 24,561 33 05GNSV025F - GEN SRVC-FL RA
114,456 34 05LNX00102 - LINE EXT 80% GTY
1,044 35 05LNX00103 - LINE EXT 80% GTY
132,650 36 05LNX00109 - REF/NREF ADV +
760 37 05LNX00110 - REF/NREF ADV +
84 4 21,000 0.0813 6,825 38 05NMT25135 - WY NET MTR, GEN,
477 3 159,000 0.0825 39,366 39 05NMT28135 - NET MTR SMALL
274 140 1,957 0.2058 56,384 40 09OALT207N - SECURITY AR LG
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.10
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
287 12 23,917 0.0571 16,383 1 09MONL0213 - WY MTR OUTDOOR
5,533 2 05LNX00300 - LINE EXT 80% GTY
4,355 3 05LNX00311 - LINE EXT 80% GTY
407,391 4 DSM REVENUE - SM
767 5 BLUE SKY REV - COMMERCIAL
1,175 0.0834 98,000 6 UNBILLED REVENUE
7
-24,101 8 LESS MULTIPLE BILLINGS
9
18,150,545 214,182 84,744 0.0852 1,547,127,608 10 TOTAL COMMERCIAL SALES
11
12 INDUSTRIAL SALES
13 CALIFORNIA
515 82 6,280 0.1888 97,209 14 06GNSV0025 - CA GEN SRVC
2,609 23 113,435 0.1676 437,371 15 06GNSV0A32 - GEN SRVC-20 KW
48,066 10 4,806,600 0.1059 5,089,527 16 06LGSV048T - LRG GEN SERV
5,806 13 446,615 0.1433 831,922 17 06LGSV0A36 - LRG GEN SRVC-O
-4,119 18 REVENUE - ACCT ADJ
-294,813 19 INCOME TAX DEFERRAL ADJ
211,145 20 DSM REVENUE - INDUSTRIAL
57 21 BLUE SKY REV - INDUSTRIAL
12,200 22 OTHER CUST RETAIL REV
-400 0.2575 -103,000 23 UNBILLED REVENUE
24
25 IDAHO
2,217 26 07CFR00001 - MTH FACILITY S
18 1 18,000 0.0941 1,693 27 07CISH0019 - COMM & IND SPA
86,800 101 859,406 0.0702 6,090,305 28 07GNSV0006 - GEN SRVC-LRG P
70,669 14 5,047,786 0.0648 4,580,013 29 07GNSV0009 - GEN SRVC-HI VO
15,768 309 51,029 0.0933 1,471,491 30 07GNSV0023 - GEN SRVC-SML P
3,180 23 138,261 0.0821 260,931 31 07GNSV006A - GEN SRVC-LRG P
2,077 138 15,051 0.1018 211,352 32 07GNSV023A - GEN SRVC-SML P
5 1 5,000 0.1214 607 33 07GNSV023S - ID TRAFFIC
1,996 34 07LNX00108 - ANN COST MTHLY
24 35 07LNX00311 - LINE EXT 80% GTY
13 16 813 0.3778 4,911 36 07OALT007N - SECURITY AR LG
1 221 37 07OALT07AN - SECURITY AR LG
1,479,600 1 1,479,600,000 0.0608 89,981,592 38 07SPCL0001
93,929 1 93,929,000 0.0595 5,584,278 39 07SPCL0002
12,700 40 REVENUE - ACCT ADJ
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.11
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
-127,568 1 INCOME TAX DEFERRAL ADJ
559,684 2 DSM REVENUE - INDUSTRIAL
4 3 BLUE SKY REV - INDUSTRIAL
-104,317 0.0586 -6,112,000 4 UNBILLED REVENUE
5
6 OREGON
17,919 0.0599 1,072,730 7 01COST0023 - OR GEN SRV, COST
1,273,163 0.0501 63,727,562 8 01COST0048 - 01LGSV0048
1 0.0660 66 9 01COST023F - OR GEN SRV -
111 0.0606 6,726 10 01COSTB023 - OR GEN SRV,
180,706 0.0531 9,596,480 11 01COSTL030 - OR LRG GEN SRV,
88,092 0.0615 5,421,632 12 01COSTS028 - OR GEN SERV,
11 7,387 13 01GNSB0023 - OR GEN SRV, BPA,
2 8,549 14 01GNSB0028 - OR GEN SRV, BPA,
960 937,394 15 01GNSV0023 - OR GEN SRV, < 30
423 3,051,305 16 01GNSV0028 - OR GEN SRV > 30
2 2 1,000 0.3390 678 17 01GNSV023F - OR GEN SRV - FLAT
1 311 18 01GNSV023M - OR GEN SRV,
3 2,764 19 01GNSV023T - OR GEN SRV, TOU
3 1,524,624 20 01GNSV0748 - LG GEN SVC DIR
58 0.0501 2,907 21 01HABT0023 - OR HABITAT
129 6,515,907 22 01LGSV0030 - OR LRG GEN SRV, >
81 20,744,433 23 01LGSV0048 - 1000KW AND OVR
79,237 3 26,412,333 0.0710 5,623,063 24 01LGSV048M - LRG GEN SRVC 1
130,335 25 01LNX00102 - LINE EXT 80% GTY
496 26 01LNX00109 - REF/NREF ADV +
12,758 27 01LNX00300 - LINE EXT 80% GTY
2,728 1 2,728,000 0.3916 1,068,196 28 01LPRS047M - PART REQ SRVC
5 3,474 29 01NMT23135 - OR NET MTR, GEN,
5 36,961 30 01NMT28135 - OR NET MTR, GEN,
3 87,609 31 01NMT30135 - OR NET MTR, GEN,
266 120 2,217 0.1405 37,376 32 01OALT015N - OUTD AR LGT NR
3 3 1,000 0.1310 393 33 01OALTB15N - OR OUTD AR LGT
45 0.0640 2,879 34 01PTOU0023 - OR GEN SRV, TOU
52 0.0613 3,188 35 01RENW0023 - OR RENW USAGE
172 0.0698 12,005 36 01STDAY028 - OR DAY STD OFF,
1 854 37 01VIR23136 - OR VOLUME
2 12,419 38 01VIR28136 - OR VOLUME
1 62,555 39 01VIR30136 - OR VOLUME
-1,123,729 40 REVENUE - ACCT ADJ
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.12
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
5,078 1 OR GAIN ON SALE OF ASSET
63,857 2 INCOME TAX DEFERRAL ADJ
1,050,078 3 DSM REVENUE - INDUSTRIAL
23 441,826 4 BLUE SKY REV - INDUSTRIAL
555,573 5 SOLAR FEED-IN REVENUE
12,363 6 COMMUNITY SOLAR REVENUE
-18,728 0.0460 -861,000 7 UNBILLED REVENUE
8
9 UTAH
18,115 10 08CFR00051 - MTH FAC SRVCHG
728 0.0795 57,861 11 08CGN06136 - UT GEN SVC
254 0.0615 15,632 12 08EFOP0021 - ELEC FURNACE O
1,002 2 501,000 0.1413 141,601 13 08EFOP021M - ELEC FURNACE O
603,315 958 629,765 0.0849 51,239,228 14 08GNSV0006 - GEN SRVC-DISTR
2,914,667 103 28,297,738 0.0546 159,058,471 15 08GNSV0009 - GEN SRVC-HI VO
53,175 3,148 16,892 0.0970 5,157,782 16 08GNSV0023 - GEN SRVC-DISTR
44,646 229 194,961 0.1208 5,392,827 17 08GNSV006A - GEN SRVC-ENERG
7 0.3937 2,756 18 08GNSV006B - GEN SRVC-DEM&
17,623 7 2,517,571 0.0890 1,569,320 19 08GNSV009A - GEN SRVC HI VO
678,976 11 61,725,091 0.0523 35,477,102 20 08GNSV009M - MANL HIGH VOLT
4 1 4,000 0.6393 2,557 21 08GNSV023F - GEN SRVC FIXED
1,039 22 47,227 0.0889 92,338 22 08GNSV06MN - GNSV DIST VOLT
744,979 23 08LNX00002 - MTHLY 80% GTY
10,323 24 08LNX00014 - 80% MIN MNTHLY
638 25 08LNX00017 - ADV/REF&80%ANN
5 26 08LNX00311 - LINE EXT 80% GTY
49,310 27 08LNX00300 - LINE EXT 80% PLUS
948 394 2,406 0.2105 199,529 28 08OALT007N - SECURITY AR LG
48 12 4,000 0.0967 4,640 29 08TOSS0015 - TRAF & OTHER S
13 6 2,167 0.1766 2,296 30 08MONL0015 - MTR OUTDONIGHT
2,230 6 371,667 0.0937 208,871 31 08NMT06135 - UT NET MTR GEN
177 17 10,412 0.1147 20,298 32 08NMT23135 - UT NET MTR, GEN,
4,051 13 311,615 0.1383 560,063 33 08NMT6A135 - NET MTR GEN SVC
49,625 3 16,541,667 0.0757 3,757,081 34 08PRSV031M - BKUP MNT&SUPPL
602,656 1 602,656,000 0.0507 30,565,663 35 08SPCL0001
809,246 1 809,246,000 0.0449 36,340,880 36 08SPCL0002
1,287,046 1 1,287,046,000 0.0522 67,226,917 37 08SPCL0003
268 2 134,000 0.0832 22,291 38 08SSLR0006 - GEN SVC SUBSCR
153 18 8,500 0.1116 17,075 39 08SSLR0023 - SMALL GEN SVC
11,084 30 369,467 0.0937 1,038,931 40 08SSLR006A - GEN SVC TOU
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.13
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
283 2 141,500 0.1194 33,798 1 08GNSV06AM - MNL ENERGY TOD
984,500 101 9,747,525 0.0731 71,986,863 2 08GNSV0008 - UT GEN SVC TOU >
27,264 4 6,816,000 0.0787 2,146,613 3 08GNSV008M - UT GEN SVC TOU >
-258,416 4 REVENUE - ACCT ADJ
2,734,869 5 REVENUE ADJ - DEF NPC
4,135,250 6 DSM REVENUE - INDUSTRIAL
7 116,729 7 BLUE SKY REV - INDUSTRIAL
2,090,339 8 SOLAR FEED-IN REVENUE
-83,578 0.0746 -6,231,000 9 UNBILLED REVENUE
10
11 WASHINGTON
885 43 20,581 0.1052 93,109 12 02GNSB0024 - WA GEN SRVC DO
3 1 3,000 0.1603 481 13 02GNSB24FP - WA GEN SVC
14,843 328 45,253 0.0895 1,328,298 14 02GNSV0024 - WA GEN SRVC
33 4 8,250 0.2614 8,627 15 02GNSV024F - WA GEN SRVC-FL
98,809 95 1,040,095 0.0784 7,745,502 16 02LGSV0036 - WA LRG GEN SRV
660,419 29 22,773,069 0.0610 40,313,189 17 02LGSV048T - LRG GEN SRVC 1
31,621 18 02LNX00103 - LINE EXT 80% GTY
9,016 19 02LNX00300 - LINE EXT 80% GTY
11 1 11,000 0.1176 1,294 20 02NMT24135 - NET MTR, WA
96 37 2,595 0.1323 12,700 21 02OALT015N - WA OUTD AR LGT
27 14 1,929 0.1489 4,019 22 02OALTB15N - WA OUTD AR LGT
2,377 1 2,377,000 0.1446 343,720 23 02PRSV47TM - LRG PART REQMT
1,437 9 159,667 0.1169 167,923 24 02LGSB0036 - LRG GEN SVC IRG
-2,461,355 25 REVENUE - ACCT ADJ
27,593 26 REVENUE ADJ - DEF NPC
-1,494,763 27 ALT REVENUE PROGRAM ADJ
1,363,237 28 DSM REVENUE - INDUSTRIAL
1 11 29 BLUE SKY REV - INDUSTRIAL
-1,886 -0.2179 411,000 30 UNBILLED REVENUE
31
32 WYOMING
28,711 1,180 24,331 0.0845 2,426,382 33 05GNSV0025 - WY GEN SRVC
267,109 433 616,880 0.0717 19,142,713 34 05GNSV0028 - GEN SVC > 15 KW
26 8 3,250 0.1596 4,150 35 05GNSV025F - GEN SRVC-FL RA
1,689,000 59 28,627,119 0.0647 109,309,343 36 05LGSV0046 - WY LRG GEN SRV
9,761 1 9,761,000 0.0747 729,408 37 05LGSV046M - WY LRG GEN SRV
245,448 1 245,448,000 0.0558 13,689,662 38 05LGSV048M - TOU>1000KW MAN
1,875,002 11 170,454,727 0.0553 103,649,692 39 05LGSV048T - LRG GENSRV TIM
47,374 40 05LNX00100 - LINE EXT 60% GTY
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.14
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1,095,342 1 05LNX00102 - LINE EXT 80% GTY
45,261 2 05LNX00105 - CNTRCT $ MIN GTY
167,837 3 05LNX00109 - REF/NREF ADV +
569 4 05LNX00110 - REF/NREF ADV +
62,394 5 05LNX00300 - LINE EXT 80% GTY
17,596 6 05LNX00311 - LINE EXT 80% GTY
69 38 1,816 0.1264 8,720 7 05OALT015N - OUTD AR LGT SR
1,324,577 9 147,175,222 0.0641 84,903,997 8 05PRSV033M - PART SERV REQ
1,868,963 9 REVENUE - ACCT ADJ
3,944,662 10 INCOME TAX DEFERRAL ADJ
-234,218 11 REVENUE ADJ - DEF NPC
589,785 12 DSM REVENUE - SM INDUSTRIAL
395,501 13 DSM REVENUE - LG INDUSTRIAL
-15 14 BLUE SKY REV - INDUSTRIAL
56,149 0.0599 3,365,000 15 UNBILLED REVENUE
3,646 283 12,883 0.0958 349,286 16 05GNSV0025 - WY GEN SRVC
68,582 71 965,944 0.0687 4,711,667 17 05GNSV0028 - GEN SVC > 15 KW
4,005 3 1,335,000 0.0589 236,064 18 05GNSV028M - GEN SVC > 15 KW
27,813 3 9,271,000 0.0651 1,811,426 19 05LGSV0046 - WY LRG GEN SRV
133,236 2 66,618,000 0.0605 8,059,325 20 05LGSV048M - TOU>1000KW MAN
1,133,288 12 94,440,667 0.0601 68,163,237 21 05LGSV048T - LRG GENSRV TIM
450,121 22 05LNX00102 - LINE EXT 80% GTY
2,009,444 23 05LNX00109 - REF/NREF ADV +
10 0.0809 809 24 05NMT25135 - WY NET MTR, GEN,
34 1 34,000 0.1178 4,005 25 05NMT28135 - NET MTR SMALL
89,483 2 44,741,500 0.0616 5,509,816 26 05PRSV033M - PART SERV REQ
3 2 1,500 0.1940 582 27 09OALT207N - SECURITY AR LG
203,468 28 DSM REVENUE - SM INDUSTRIAL
684,018 29 DSM REVENUE - LG INDUSTRIAL
29 30 BLUE SKY REV - INDUSTRIAL
-23,780 0.0588 -1,398,000 31 UNBILLED REVENUE
32
-870 33 LESS MULTIPLE BILLINGS
34
19,048,841 9,427 2,020,668 0.0624 1,188,343,074 35 TOTAL INDUSTRIAL SALES
36
37
38
39
40
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.15
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 IRRIGATION SALES
2 CALIFORNIA
9,334 748 12,479 0.1483 1,384,232 3 06APSV0020 - AG PMP SRVC
35 2 17,500 0.1389 4,862 4 06APSV0115 - CA AGRI PUMP TOU
48,069 591 81,335 0.1459 7,013,491 5 06APSV020L - AG PMP SRVC
734 9 81,556 0.1430 104,940 6 06APSV115L - CA AGRI PUMP TOU
3,405 1 3,405,000 0.1097 373,647 7 06LGSV048T - LRG GEN SERV
1,207 8 06LNX00103 - LINE EXT 80% GTY
409 9 06LNX00109 - REF/NREF ADV +
32,806 10 06LNX00110 - REF/NREF ADV +
6,431 11 06LNX00310 - IRG, 80% ANNUAL
29,248 12 06LNX00312 - CA IRG LINE EXT
2,149 24 89,542 0.1722 370,088 13 06NML20135 - AGRI PUMP-NET
173 10 17,300 0.1656 28,648 14 06NMT20135 - AGRI PUMP-NET
3,129 273 11,462 0.1832 573,273 15 06USBR0020 - KLAM IRG ONPRJ
4 1 4,000 0.5108 2,043 16 06USBR0115 - CA AGR PMP TOU
14,661 344 42,619 0.1685 2,470,639 17 06USBR020L - KLAM IRG ONPRJ
567 9 63,000 0.1506 85,379 18 06USBR115L - CA AGR PMP TOU
-19,620 19 REVENUE - ACCT ADJ
-454,004 20 INCOME TAX DEFERRAL ADJ
338,227 21 DSM REVENUE - IRRIGATION
12 22 BLUE SKY REV - IRRIGATION
2,871 23 OTHER CUST RETAIL REV
-952 0.0798 -76,000 24 UNBILLED REVENUE
25
26 IDAHO
335,763 2,364 142,032 0.0909 30,528,310 27 07APSA010L - IRG & PUMP LG
5,710 327 17,462 0.1065 607,966 28 07APSA010S - IRG & PUMP SM
218,411 1,823 119,809 0.0921 20,107,391 29 07APSAL10X - IRG & PUMP - LG
7,240 528 13,712 0.1112 804,860 30 07APSAS10X - IRG & PUMP - SM
250 1 250,000 0.1003 25,085 31 07APSV006A - LRG POWER OPT
211 4 52,750 0.0983 20,742 32 07APSV023A - SM POWER OPT
12,571 37 339,757 0.0817 1,026,551 33 07APSVCNLL - LRG LOAD CANAL
22 11 2,000 0.1778 3,912 34 07APSVCNLS - SML LOAD CANAL
104 1 104,000 0.0904 9,405 35 07GNSV023A - GEN SRVC-SML P
71,421 36 07LNX00015 - ANNUAL 80% GTY
2,830 37 07LNX00035 - ADV 80% MO GTY
120,907 38 07LNX00040 - ADV+REFCHG+80%
801 39 07LNX00310 - 80% ANNUAL GTY
50,622 40 07LNX00312 - ID LINE EXT
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.16
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
6,565 35 187,571 0.0889 583,656 1 07APSN010L - ID LG IRR & PUMP
18 3 6,000 0.1450 2,610 2 07APSN010S - IRR, SMALL, 3
226 17 13,294 0.1212 27,386 3 07APSNS10X - IRR, SMALL, 3
-196,101 4 REVENUE - ACCT ADJ
-39,466 5 INCOME TAX DEFERRAL ADJ
1,317,344 6 DSM REVENUE - IRRIGATION
19 7 BLUE SKY REV - IRRIGATION
224 0.0982 22,000 8 UNBILLED REVENUE
9
10 OREGON
2,435 1,150,108 11 01APSV0041 - AG PMP SRVC BP
11 20,817 12 01APSV0215 - OR IRR TOU PILOT
704 1,824,096 13 01APSV041L - OR PUMP SRV
53 24,609 14 01APSV041T - AGR PUMP
2,464 1,026,589 15 01APSV041X - AG PMP SRVC
461 1,545,562 16 01APSV41XL - OR PUMP SRV NO
117,134 0.0601 7,040,996 17 01COST0041 -
110,150 0.0505 5,559,706 18 01COST0048 - 01LGSV0048
3,726 0.0446 166,330 19 01COST0215 - OR TOU PILOT
63,085 0.0601 3,791,604 20 01CSTUSB41 - USBR IRR
1 1,839 21 01GNSV023T - OR GEN SRV, TOU
10 0.0628 628 22 01HABIT041 - 01APSV0041 AG
3 829,516 23 01LGSB0048 - LG GEN SVC >
3 1,203,135 24 01LGSV0048 - 1000KW AND OVR
35,262 25 01LNX00103 - LINE EXT 80% GTY
363 26 01LNX00109 - REF/NREF ADV +
101,424 27 01LNX00110 - REF/NREF ADV +
13,768 28 01LNX00310 - LINE EXT
49 0.0560 2,745 29 01PTOU0023 - OR GEN SRV, TOU
511 0.0593 30,313 30 01PTOU0041 - 01APSV0041 AG
149 0.0610 9,095 31 01RENEW041 - 01APSV0041 AG
121 0.0572 6,918 32 01STDAY041 - DAILY STANDARD
72 123,374 33 01USBR0215 - OR IRG TOU PILOT
9 62,991 34 01USBRGV41 - IRG TOU W/O BPA
481 1,085,545 35 01USBROF41 - KLAMATH BASIN
1,113 1,548,154 36 01USBRON41 - KLAMATH BASIN
26 47,409 37 01VIR41136 - OR VOL
104 286,355 38 01VRU41136 - OR VOL INCENTIVE
6 28,812 39 01VRU41215 - OR VOL INCENTIVE
26,397 40 01LNX00312 - OR IRG LINE EXT
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.17
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
30 29,236 1 01NMT41135 - NETMTR AG PMP
12 27,096 2 01NMU41135 - OR NET MTR -
-144,576 3 REVENUE - ACCT ADJ
110 4 OR GAIN ON SALE OF ASSET
12,825 5 INCOME TAX DEFERRAL ADJ
610,919 6 DSM REVENUE - IRRIGATION
291 7 BLUE SKY REV - IRRIGATION
107,630 8 SOLAR FEED-IN REVENUE
2,333 9 COMMUNITY SOLAR REVENUE
-10,120 -0.0179 181,000 10 UNBILLED REVENUE
11
12 UTAH
172,333 3,060 56,318 0.0775 13,355,183 13 08APSV0010 - IRR & SOIL DRA
27,968 296 94,486 0.0736 2,059,511 14 08APSV10NS - IRR LG SOIL DRAIN
9,815 15 08LNX00004 - ANNUAL 80% GTY
4,845 16 08LNX00014 - 80% MIN MNTHLY
165,901 17 08LNX00017 - ADV/REF&80%ANN
30,405 18 08LNX00310 - IRR, 80% ANNUAL
1,163 19 08LNX00311 - LINE EXT 80% GTY
11,217 20 08LNX00312 - UT IRG LINE EXT
246 4 61,500 0.0933 22,960 21 08NMT010NS - IRR & SOIL DRAIN
8,072 62 130,194 0.0790 638,006 22 08NMT10135 - UT IRR_SOIL DRNG
316 23 08TCVLAACN - UT TCV LNX
7,961 24 08TCVLNAGN - UT LNX ANNUAL
-6,271 25 REVENUE - ACCT ADJ
91,308 26 REVENUE ADJ - DEF NPC
137,781 27 DSM REVENUE - IRRIGATION
69,789 28 SOLAR FEED-IN REVENUE
393 0.0611 24,000 29 UNBILLED REVENUE
30
31 WASHINGTON
90,870 2,800 32,454 0.0835 7,590,342 32 02APSV0040 - WA AG PMP SRVC
63,711 2,347 27,146 0.0837 5,333,476 33 02APSV040X - WA AG PMP SRVC
2,699 34 02LNX00102 - LINE EXT 80% GTY
1,483 35 02LNX00103 - LINE EXT 80% GTY
79 36 02LNX00105 - CNTRCT $ MIN GTY
143,814 37 02LNX00110 - REF/NREF ADV +
6,750 38 02LNX00310 - IRG, 80% ANNUAL
33,920 39 02LNX00312 - WA IRG LINE EXT
168 9 18,667 0.0884 14,851 40 02NMT40135 - WA NET MTR-IRG
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.18
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
41 6 6,833 0.1830 7,501 1 02NMX40135 - WA NET MTR-IRG
-466,231 2 REVENUE - ACCT ADJ
6,491 3 REVENUE ADJ - DEF NPC
-885,712 4 ALT REVENUE PROGRAM ADJ
363,742 5 DSM REVENUE - IRRIGATION
524 6 BLUE SKY REV - IRRIGATION
3,938 0.3418 1,346,000 7 UNBILLED REVENUE
8
9 WYOMING
16,724 709 23,588 0.0857 1,433,166 10 05APS00040 - AG PUMP SVC
1,644 28 58,714 0.0821 135,051 11 05APSNS040 - AG PUMP SVC
740 12 05LNX00103 - LINE EXT 80% GTY
854 13 05LNX00109 - REF/NREF ADV +
25,035 14 05LNX00110 - REF/NREF ADV +
870 15 05LNX00310 - LINE EXT
4,139 16 05LNX00312 - WY IRG LINE EXT
11 1 11,000 0.1233 1,356 17 09APSNS210 - IRR & SOIL DRA
9,436 18 REVENUE - ACCT ADJ
14,920 19 INCOME TAX DEFERRAL ADJ
-886 20 REVENUE ADJ - DEF NPC
-4,237 21 DSM REVENUE - IRRIGATION
4 22 BLUE SKY REV - IRRIGATION
1,352 0.0451 61,000 23 UNBILLED REVENUE
132 6 22,000 0.0840 11,086 24 05APS00040 - AG PUMP SVC
976 25 05LNX00103 - LINE EXT 80% GTY
13,855 26 05LNX00110 - REF/NREF ADV +
460 5 92,000 0.0944 43,405 27 09APSNS210 - IRR & SOIL DRA
5,528 96 57,583 0.0794 438,668 28 09APSV0210 - IRR & SOIL DRA
18,569 29 DSM REVENUE - IRRIGATION
26 0.0769 2,000 30 UNBILLED REVENUE
31
-856 32 LESS MULTIPLE BILLINGS
33
1,347,055 23,724 56,780 0.0951 128,126,030 34 TOTAL IRRIGATION SALES
35
36
37
38
39
40
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.19
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 PUBLIC STREET & HWY LIGHTING
2 CALIFORNIA
1,086 107 10,150 0.1769 192,092 3 06CUSL053E - SPECIAL CUST O
52 20 2,600 0.1987 10,333 4 06CUSL058F - CUST OWND STR
687 77 8,922 0.3218 221,050 5 06SLCO0051 - COMPANY OWNED
1 263 6 06OALT015N - OUTD AR LGT SR
-3,856 7 REVENUE - ACCT ADJ
-7,806 8 INCOME TAX DEFERRAL ADJ
9,326 9 DSM REVENUE - PSHL
153 10 OTHER CUST RETAIL REV
-132 0.2121 -28,000 11 UNBILLED REVENUE
12
13 IDAHO
147 23 6,391 0.1184 17,401 14 07GNSV023S - ID TRAFFIC
153 56 2,732 0.4702 71,941 15 07SLCO0011 - STR LGT CO-OWN
434 51 8,510 0.1089 47,242 16 07SLCU012E - ENGY STR LGT
1,761 183 9,623 0.1977 348,215 17 07SLCU012F - FULL MNT STR LGT
194 16 12,125 0.1438 27,891 18 07SLCU012P - PART MNT STR LGT
-2,973 19 REVENUE - ACCT ADJ
-183 20 INCOME TAX DEFERRAL ADJ
12,482 21 DSM REVENUE - PSHL
13 0.1538 2,000 22 UNBILLED REVENUE
23
24 OREGON
364 35 10,400 0.1496 54,451 25 01COSL0052 - STR LGT SRVC C
598 0.0635 37,981 26 01COST023F - OR GEN SRV
497 72 6,903 0.0726 36,061 27 01CUSL0053 - CUS-OWNED MTRD
14 104,478 28 01GNSV023F - OR GEN SRV - FLAT
10,544 225 46,862 0.0723 762,071 29 01CUSL053E - STR LGT SVC
116 9 12,889 0.0944 10,945 30 01CUSL053F - STR LGT SRVC C
1 1 1,000 0.0590 59 31 01CUSL53E2 - STR LGT SVC
19,217 751 25,589 0.2062 3,962,490 32 01HPSV0051 - HI PRESSURE SO
675 85 7,941 0.3446 232,601 33 01LEDSL051 - OR LED PILOT
7,938 230 34,513 0.1256 997,174 34 01MVSL0050 - MERC VAPSTR LG
35 18 1,944 0.1788 6,257 35 01OALT015N - OUTD AR LGT NR
7 9 778 0.1657 1,160 36 01OALTB15N - OR OUTD AR LGT
-17,649 37 REVENUE - ACCT ADJ
1,019 38 OR GAIN ON SALE OF ASSET
1,401 39 INCOME TAX DEFERRAL ADJ
187,725 40 DSM REVENUE - PSHL
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.20
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
11,748 1 SOLAR FEED-IN REVENUE
136 2 COMMUNITY SOLAR REVENUE
1,074 0.1574 169,000 3 UNBILLED REVENUE
4
5 UTAH
54 6 08CFR00012 - STR LGTS
4,529 7 08CFR00051 - MTH FAC SRVCHG
73 8 08CFR00062 - STREET LIGHTS
363 194 1,871 0.2582 93,722 9 08OALT007N - SECURITY AR LG
1,151 121 9,512 0.0880 101,248 10 08TOSS015F - TRAFFIC SIG NM
13,487 717 18,810 0.3022 4,076,143 11 08SLCO0011 - STR LGT CO-OWN
3,138 1,477 2,125 0.1113 349,127 12 08TOSS0015 - TRAF & OTHER S
849 95 8,937 0.0808 68,636 13 08MONL0015 - MTR OUTDONIGHT
3,021 170 17,771 0.1239 374,185 14 08SLCU012P - STR LGT CUST-O
951 67 14,194 0.1334 126,854 15 08SLCU012F - STR LGT CUST-O
41,473 1,004 41,308 0.0637 2,642,632 16 08SLCU012E - DECOR CUST-OWN
-21,686 17 REVENUE - ACCT ADJ
23,341 18 REVENUE ADJ - DEF NPC
35,258 19 DSM REVENUE - PSHL
17,840 20 SOLAR FEED-IN REVENUE
-2,392 0.1154 -276,000 21 UNBILLED REVENUE
22
23 WASHINGTON
91 24 02CFR00012 - STR LGTS
90 9 10,000 0.2035 18,312 25 02COSL0052 - WA STR LGT SRV
2,950 120 24,583 0.0696 205,219 26 02CUSL053F - WA STR LGT SRV
731 112 6,527 0.0695 50,830 27 02CUSL053M - WA STR LGT SRV
3,197 219 14,598 0.2372 758,342 28 02SLCO0051 - WA COMPANY ST
1,165 25 46,600 0.1278 148,853 29 02MVSL0057 - WA MERC VAPSTR
-49,424 30 REVENUE - ACCT ADJ
18,829 31 DSM REVENUE - PSHL
-487 0.1109 -54,000 32 UNBILLED REVENUE
33
34 WYOMING
238 15 15,867 0.2028 48,276 35 05COSL0057 - CO-OWND STR LG
49 10 4,900 0.0555 2,718 36 05CUSL0058 - CUST OWND STR
1,079 33 32,697 0.0554 59,759 37 05CUSL0E58 - WY CUST OWNED
44 3 14,667 0.0679 2,989 38 05CUSL0M58 - CUST OWNED ST
5,655 186 30,403 0.1838 1,039,113 39 05HPSV0051 - HI PRESSURE SO
3,521 225 15,649 0.1129 397,679 40 05MVS00053 - MERCURY VAPOR
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.21
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
38 4 9,500 0.1138 4,325 1 05OALT015N - OUTD AR LGT SR
9,877 2 REVENUE - ACCT ADJ
7,221 3 INCOME TAX DEFERRAL ADJ
-429 4 REVENUE ADJ - DEF NPC
49,115 5 DSM REVENUE - PSHL
612 0.1438 88,000 6 UNBILLED REVENUE
10 7 05HPSV0051 - HI PRESSURE SO
29 1 29,000 0.0944 2,738 8 09MONL0213 - WY MTR OUTDOOR
1,496 51 29,333 0.2193 328,000 9 09SLCO0211 - STR LGT CO-OWN
34 5 6,800 0.1420 4,829 10 09SLCUP212 - CUST OWNED ST
48 15 3,200 0.0492 2,361 11 09TOSS0213 - WY TRAFFIC &
12,776 12 DSM REVENUE - PSHL
-241 0.2116 -51,000 13 UNBILLED REVENUE
14
-3,296 15 LESS MULTIPLE BILLINGS
16
127,750 3,565 35,835 0.1425 18,198,044 17 TOTAL PUBLIC STREET & HWY LT
18
19 FORFEITED DISCOUNTS
20 CALIFORNIA
187,973 21 06LPAY0300 - RES-LATEFEE
55,479 22 06LPAY0300 - COM-LATEFEE
67,570 23 06LPAY0300 - IND-LATEFEE
876 24 06LPAY0300 - OTHER-LATEFEE
25
26 IDAHO
219,668 27 07LPAY0300 - RES-LATEFEE
27,909 28 07LPAY0300 - COM-LATEFEE
82,723 29 07LPAY0300 - IND-LATEFEE
4,584 30 07LPAY0300 - OTHER-LATEFEE
31
32 OREGON
3,027,099 33 01LPAY0300 - RES-LATEFEE
777,068 34 01LPAY0300 - COM-LATEFEE
225,412 35 01LPAY0300 - IND-LATEFEE
45,333 36 01LPAY0300 - OTHER-LATEFEE
37
38 UTAH
2,368,447 39 08LPAY0300 - RES-LATEFEE
664,395 40 08LPAY0300 - COM-LATEFEE
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.22
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
198,342 1 08LPAY0300 - IND-LATEFEE
79,748 2 08LPAY0300 - OTHER-LATEFEE
493 3 OTHER
4
5 WASHINGTON
567,301 6 02LPAY0300 - RES-LATEFEE
136,148 7 02LPAY0300 - COM-LATEFEE
28,465 8 02LPAY0300 - IND-LATEFEE
2,355 9 02LPAY0300 - OTHER-LATEFEE
10
11 WYOMING
461,390 12 05LPAY0300 - RES-LATEFEE
118,729 13 05LPAY0300 - COM-LATEFEE
71,962 14 05LPAY0300 - IND-LATEFEE
-3,838 15 05LPAY0300 - OTHER-LATEFEE
16
9,415,631 17 TOTAL FORFEITED DISCOUNTS
18
19 MISC SERVICE REVENUE
20 CALIFORNIA
1,820 21 06APSV0020 - AG PMP SRVC
1,454 22 06CFR00003 - MTH MAINTENANC
33,165 23 06CONN0300 - CA RECONNECTIO
75,765 24 06FCBUYOUT
13,700 25 06GNSV0025 - CA GEN SRVC
200 26 06GNSV0A32 - GEN SRVC-20 KW
150 27 06NEMAGG35 - CALIF NET METER
5,526 28 06NETMT135 - CA RES NET
425 29 06NML20135 - AGRI PUMP-NET
560 30 06NMT20135 - AGRI PUMP-NET
465 31 06NMT25135 - CA GEN SVC NET
25 32 06NMT32135 - CA GEN SVC NET
3,255 33 06NSMTR300 - NON-STND MTR
11,904 34 06RCHK0300 - CA RET CHK CHR
227,700 35 06RESD000D - RES SRVC
23,120 36 06RESD00DN - CA RES SRVC -
200 37 06RESD0DS8 - MULT FAM SBMET
121,408 38 06RESDDL06 - CA LOW INCOME
2,040 39 06RGNSV025 - CA SMALL
35 40 06RNM25135 - CA NET MTR, GEN
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.23
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
750 1 06TAMP0300 - CA TAMP & UNAU
1,700 2 06TEMP0300 - CA TEMP SRVC C
462 3 06XMTRTAMP - TAMP
-14,674 4 OTHER
5
6 IDAHO
1,213 7 07CFR00001 - MTH FAC SRVCHG
8,390 8 07CONN0300 - ID RECONNECTIO
10,953 9 07FCBUYOUT - FAC CHG BUYOUT
35,920 10 07RCHK0300 - ID RET CHK CHR
75 11 07TAMP0300
32,020 12 07TEMP0014 - TEMP SRVC CONN
835 13 OTHER
14
15 OREGON
18,561 16 01ADMINFEE - SCH 272 ANN
3,160 17 01APSV0041 - AG PMP SRVC BP
334 18 01APSV041T - AGR PUMP
5,695 19 01APSV041X - AG PMP SRVC
99,124 20 01CFR00001 - MTH FACILITY S
17,817 21 01CFR00003 - MTH MAINTENANC
25,609 22 01CFR00004 - EMRGNCY ST&BY
37,082 23 01CFR00005 - INTERMTNT SRVC
49,169 24 01CFR00013 - MTH MISC CHRG
13,439 25 01CGENAFOR - CUST GEN APP
282,262 26 01CONN0300 - RECONNECTION
31,433 27 01CONTSERV - OR 3RD PARTY
1,738 28 01ESSC0600 - ESS CHG
172,869 29 01FCBUYOUT - FAC CHG BUYOUT
13,641 30 01GNSB0023 - OR GEN SRV, BPA,
107,325 31 01GNSV0023 - OR GEN SRV, < 30
8,334 32 01GNSV0028 - OR GEN SRV > 30
118 33 01GNSV023T - OR GEN SRV, TOU
334 34 01LGSV0030 - OR LRG GEN SRV, >
37,092 35 01NETMT135 - NET METERING
2,692 36 01NMT23135 - OR NET MTR, GEN,
406 37 01NMT28135 - OR NET MTR, GEN,
334 38 01NMTOU135 - TOU NET
50,700 39 01NSMTR300 - OR STD METER
320,420 40 01RCHK0300 - RET CHECK
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.24
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1,973,949 1 01RESD0004 - RES SRVC
4,856 2 01RESD004T - RES TIME OPT
70,418 3 01RGNSB023 - SMALL GEN
334 4 01RGNSB028 - GENERAL SVC > 30
1,480 5 01RNETM023 - NET METER RES
5,025 6 01TAMP0300 - TAMP & UNAUTH
2 7 01XTRN0011 - SALE ORDERS
156,060 8 01TEMP0300 - TEMP SRVC CHRG
956 9 01USBRON41 - KLAMATH BASIN
2,040 10 01VIR04136 - OR RES VOL
918 11 01XMTRTAMP - TAMP - UNAUTH
-73,559 12 OTHER
13
14 UTAH
84,037 15 08CFR00051 - MTH FAC SRVCHG
424 16 08CFR00052 - ANN FAC SVCCHG
11,760 17 08CFR00053 - MTHLY MAINTFEE
4,976 18 08CFR00054 - NRES EMERGENCY
2,343 19 08CFR00063 - MTH MISC CHARG
6,660 20 08CFR00064 - ANN MISC CHARG
29,101 21 08CGENFEEN - NRES CSTMR GEN
381,889 22 08CGENFEER - RES CSTMR GEN
4 23 08CGM23136 - UT NET METER SM
158,380 24 08CONN0300 -
93,000 25 08CONTSERV - 3RD PARTY O/S
605,036 26 08FCBUYOUT - FAC CHG BUYOUT
3,175 27 08NCON0300 - UT FEE NRES RE
264 28 08NETMT135 - NET METERING
849 29 08NSMTR300 - UT NON
561,400 30 08RCHK0300 - UT RET CHK CHR
1,799,720 31 08RCON0001 - CONNECT FEE
5,226 32 08RESD0001 - RES SRVC
13,800 33 08SOLRXFEE - SUBSCRI SOLAR
264 34 08SSLR0001 - RES SUBSCRB
3,150 35 08TAMP0300 - TAMP&UNAU
632,104 36 08TEMP0014 - TEMP SRVC CONN
69 37 08XMTRTAMP - TAMP - UNAUTH
19,985 38 08VISIT300 - UT VISIT SRV CALL
675 39 ENERGY FINANSWER NEW COM
-108,031 40 OTHER
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.25
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 WASHINGTON
1,320 2 02CFR00003 - MTH MAINTENANC
5,892 3 02CFR00004 - EMRGNCY ST&BY
4,281 4 02CFR00005 - INTERMTNT SRVC
100 5 02CGENAFWA - CUSTOMER GEN
29,195 6 02CGENAMWA - CUSTOMER GEN
40,020 7 02CONN0300 - WA RECONNECTIO
31,072 8 02FCBUYOUT - FAC CHG BUYOUT
240 9 02NSMTR300 - WA STD METER
64,340 10 02RCHK0300 - WA RET CHK CHR
762 11 02RESD0016 - WA RES SRVC
1,500 12 02TAMP0300 - WA TAMP & UNAU
26,245 13 02TEMP0300 - WA TEMP SRVC C
2,304 14 02XMTRTAMP - TAMP - UNAUTH
-7,707 15 OTHER
16
17 WYOMING
1,768 18 05CFR00003 - MTH MAINTENANC
18,134 19 05CFR00004 - EMRGNCY ST&BY
9,922 20 05CFR00005 - INTERMTNT SRVC
3,186 21 05CFR00013 - MTH MISC CHRG
57,857 22 05CONN0300 - WY RECONNECTIO
45,856 23 05FCBUYOUT - FAC CHG BUYOUT
85,950 24 05RCHK0300 - WY RET CHK CHR
1,008 25 05RESD0002 - WY RES SRVC
975 26 05TAMP0300
39,950 27 05TEMP0300 - WY TEMP SRVC C
54 28 05XMTRTAMP - TAMP - UNAUTH
339 29 09CFR00005 - INTERMTNT SRVC
332 30 OTHER
6,974 31 05CONN0300 - WY RECONNECTIO
6,347 32 05FCBUYOUT - FAC CHG BUYOUT
9,420 33 05RCHK0300 - WY RET CHK CHR
75 34 05TAMP0300
35 35 05XMTRTAMP - TAMP - UNAUTH
5,067 36 09CFR00001 - MTH FAC SRVCHG
3 37 09CFR00014 - YR MISC CHRG
38
8,845,804 39 TOTAL MISC SERVICE REVENUE
40
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.26
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 SALES OF WATER & WATER PWR
2 UTAH
53,658 3 WATER & WATER PWR SALES
4
53,658 5 TOTAL SALES OF WATER &
6
7 RENT FROM ELEC PROPERTIES
8 CALIFORNIA
1,710 9 06CFR00006 - MTH RNTAL CHRG
1,250 10 RENT REVENUE - HYDRO
4,800 11 RENT REVENUE - SUBLEASES
572,863 12 JOINT USE
13
14 IDAHO
782 15 07CFR00009 - YR LSE CHRG-EQ
149 16 07INVCHG00 - INVEST MNT CHG
266 17 07POLE0075 - STEEL POLES US
62,260 18 RENT REVENUE - HYDRO
250 19 RENT REVENUE- TRANSMISSION
1,662 20 RENT REVENUE - SUBLEASES
184,580 21 JOINT USE
22
23 OREGON
853,418 24 01CFR00006 - MTH RNTAL CHRG
1,247,005 25 RENTS - COMMON
3,108 26 RENT REVENUE - DISTRIBUTION
65,035 27 RENT REVENUE - GENERAL
2,450 28 RENT REVENUE - HYDRO
3,390 29 RENT REVENUE - SUBLEASES
291,549 30 RENT REVENUE - TRANSMISSION
3,351,249 31 MCI FOGWIRE REVENUE
3,119,392 32 JOINT USE
33
34 UTAH
33 35 08CFR00056 - MTH EQUIP RENT
518,752 36 08CFR00058 - MTH EQUIP LEAS
3,596 37 08INVCHG0N - INVEST MNT CHG
216 38 08INVCHG0R - INVEST MNT CHG
51,405 39 08POLE0075 - STEEL POLES US
1,000,019 40 RENTS - COMMON
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.27
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
-1,500 1 RENTS - NON-COMMON
8,464 2 RENT REVENUE - CORPORATE
455,611 3 RENT REVENUE - DISTRIBUTION
-2,862 4 RENT REVENUE - GENERAL
39,394 5 RENT REVENUE - HYDRO
112,400 6 RENT REVENUE - STEAM
619,413 7 RENT REVENUE - SUBLEASES
911,876 8 RENT REVENUE - TRANSMISSION
2,230,776 9 JOINT USE
10
11 WASHINGTON
2,114 12 02CFR00001 - MTH FACILITY S
8,869 13 02CFR00006 - MTH RNTAL CHRG
282,337 14 RENTS - COMMON
2,866 15 RENT REVENUE - GENERAL
97,189 16 RENT REVENUE - HYDRO
5,911 17 RENT REVENUE - TRANSMISSION
740,154 18 JOINT USE
19
20 WYOMING
11,524 21 05CFR00001 - MTH FACILITY S
2,482 22 05CFR00006 - MTH RNTAL CHRG
9,000 23 RENT REVENUE - DISTRIBUTION
66,217 24 RENT REVENUE - GENERAL
45,103 25 RENT REVENUE - STEAM
43,399 26 RENT REVENUE - SUBLEASES
383,059 27 JOINT USE
18,313 28 09POLE0075 - STEEL POLES US
26,430 29 RENT REVENUE - STEAM
30
17,459,728 31 TOTAL RENT FROM ELEC
32
33 OTHER ELECTRIC REVENUE
4,613,077 34 M&S INVENTORY REVENUE
34,984 35 MISC OTHER REVENUE
609,086 36 NON-WHEELING SYSTEM REV
2,878,143 37 RENEWABLE ENERGY CREDITS
9,193,455 38 WIND BASED ANCILLARY SVC
39
40
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.28
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
PacifiCorp X
/ /2019/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 CALIFORNIA
28,701 2 3RD PARTY TRANS O&M
12,254,503 3 CA GHG ALLOW REV AMORT
9,261 4 FISH, WILDLIFE, RECR
5
6 OREGON
160,036 7 3RD PARTY TRANS O&M
14,860 8 EIM REVENUE
-3,135,370 9 FERC TRANSMISSION REFUND
760,660 10 MISC OTHER REVENUE
11
12 UTAH
211,034 13 3RD PARTY TRANS O&M
54,509 14 ELEC INCOME - OTHER
2,820 15 FISH, WILDLIFE, RECR
1,561,903 16 FLYASH SALES
17
18 WASHINGTON
649,985 19 TIMBER SALES - UTILITY
-52,188 20 WASH COLSTRIP 3
21
22 WYOMING
71,978 23 3RD PARTY TRANS O&M
2,514,061 24 FLYASH SALES
150,187 25 WY REG RECOVERY FEE
26
32,585,685 27 TOTAL OTHER ELEC REVENUE
28
29
30
31
32
33
34
35
36
37
38
39
40
55,342,607 4,765,915,615 1,932,532 28,637 0.0861
15,944 15,667,000 0 0 0.9826
55,326,663 4,750,248,615 1,932,532 28,629 0.0859
FERC FORM NO. 1 (ED. 12-95) Page 304.29
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Requirement Sales: 1
Helper City 111T-6RQ 2
Helper City Annex 111T-6RQ 3
Navajo Tribal Utility Authority 323534T-12RQ 4
Navajo Tribal Util. Auth. (Mexican Hat)000T-6RQ 5
Navajo Tribal Util. Auth. (Red Mesa)122T-6RQ 6
Accrual NANANANARQ 7
8
Non-Requirement Sales: 9
Arizona Electric Power Cooperative, Inc NANANAT-12SF 10
Arizona Public Service Company NANANAT-12SF 11
Avangrid Renewables, LLC NANANAT-12SF 12
Avangrid Renewables, LLC NANANAT-13SF 13
Avista Corporation NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the 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.
1
110,701 118,889 229,590 6,265 2
65,338 69,536 134,874 3,698 3
9,175,358 5,540,429 -1,065,485 13,650,302 283,052 4
15,624 16,263 31,887 897 5
162,332 143,458 305,790 9,319 6
-122,000 -122,000 -631 7
8
9
1,958,485 1,958,485 72,467 10
343,785 343,785 9,532 11
16,488,799 16,488,799 521,800 12
2,136 2,136 73 13
1,678,045 1,678,045 49,805 14
FERC FORM NO. 1 (ED. 12-90) Page 311
9,529,353
386,671,884
396,201,237
302,600
5,177,028
5,479,628
-1,187,485 14,230,443
-209,626,333
-210,813,818
178,041,214
192,271,657
5,888,575
995,663
6,884,238
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Avista Corporation NANANAT-13SF 1
Barclays Bank PLC NANANAT-12SF 2
Basin Electric Power Cooperative, Inc.NANANAT-12SF 3
Black Hills Power, Inc.485050441LF 4
Black Hills Power, Inc.NANANAT-12SF 5
Bonneville Power Administration NANANAT-12AD 6
Bonneville Power Administration NANANAT-12LU 7
Bonneville Power Administration NANANAT-12SF 8
Bonneville Power Administration NANANAT-13SF 9
Bonneville Power Administration NANANAWSPP-QSF 10
BP Energy Company NANANAT-12AD 11
BP Energy Company NANANAT-12SF 12
British Columbia Hydro and Power NANANAT-13SF 13
Brookfield Energy Marketing LP NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.1
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the 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.
990 990 35 1
2
179,408 179,408 6,453 3
6,452,663 995,663 7,448,326 310,745 4
969,173 969,173 39,740 5
-14,010 -14,010 6
1,304,026 4,045,261 5,349,287 19,498 7
6,658,554 6,658,554 197,283 8
3,290 3,290 95 9
614,877 614,877 23,735 10
80,348 80,348 1,843 11
6,791,967 6,791,967 253,031 12
430 430 12 13
23,800 23,800 825 14
FERC FORM NO. 1 (ED. 12-90) Page 311.1
9,529,353
386,671,884
396,201,237
302,600
5,177,028
5,479,628
-1,187,485 14,230,443
-209,626,333
-210,813,818
178,041,214
192,271,657
5,888,575
995,663
6,884,238
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
California Independent System Operator NANANAT-12SF 1
Calpine Energy Services, L.P.NANANAT-12SF 2
Citigroup Energy, Inc.NANANAT-12SF 3
City of Anaheim NANANAT-12SF 4
City of Burbank NANANAT-12SF 5
City of Glendale NANANAT-12SF 6
City of Hurricane NANANA560IF 7
City of Redding NANANAT-12SF 8
City of Roseville NANANAT-12SF 9
Clatskanie People's Utility District NANANAT-12SF 10
ConocoPhillips Company NANANAT-12SF 11
Direct Energy Business Marketing, LLC NANANAT-12SF 12
DTE Energy Trading, Inc.NANANAT-12SF 13
EDF Trading North America, LLC NANANAT-12AD 14
FERC FORM NO. 1 (ED. 12-90) Page 310.2
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the 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.
131,343 131,343 3,311 1
1,305,615 1,305,615 47,040 2
38,175,396 38,175,396 1,232,262 3
216 216 24 4
408,160 408,160 13,536 5
38,800 38,800 1,400 6
5,658 5,658 112 7
52,600 52,600 1,480 8
323,221 323,221 9,689 9
324,459 324,459 8,253 10
3,142,181 3,142,181 131,005 11
2,747,592 2,747,592 94,678 12
16,906,912 16,906,912 554,806 13
22,293 22,293 304 14
FERC FORM NO. 1 (ED. 12-90) Page 311.2
9,529,353
386,671,884
396,201,237
302,600
5,177,028
5,479,628
-1,187,485 14,230,443
-209,626,333
-210,813,818
178,041,214
192,271,657
5,888,575
995,663
6,884,238
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
EDF Trading North America, LLC NANANAT-12SF 1
EDF Trading North America, LLC NANANAWSPP-QSF 2
El Paso Electric Company NANANAT-12SF 3
Energy Keepers, Inc.NANANAT-12SF 4
Eugene Water & Electric Board NANANAT-12SF 5
Exelon Generation Company, LLC NANANAT-12AD 6
Exelon Generation Company, LLC NANANAT-12SF 7
Exelon Generation Company, LLC NANANAWSPP-QSF 8
Gridforce Energy Management, LLC NANANAT-13SF 9
Idaho Power Company NANANAT-12SF 10
Idaho Power Company NANANAT-13SF 11
Idaho Power Company NANANAWSPP-QSF 12
Imperial Irrigation District NANANAT-12SF 13
Los Angeles Dept. of Water and Power NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.3
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the 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.
15,176,662 15,176,662 495,888 1
4,682 4,682 160 2
163,294 163,294 4,295 3
2,800 2,800 50 4
898,596 898,596 26,606 5
550 550 25 6
21,553,284 21,553,284 701,884 7
81,916 81,916 2,984 8
18,919 18,919 569 9
59,404 59,404 2,400 10
3,207 3,207 100 11
141,000 141,000 6,200 12
12,967 12,967 308 13
153,800 153,800 6,200 14
FERC FORM NO. 1 (ED. 12-90) Page 311.3
9,529,353
386,671,884
396,201,237
302,600
5,177,028
5,479,628
-1,187,485 14,230,443
-209,626,333
-210,813,818
178,041,214
192,271,657
5,888,575
995,663
6,884,238
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Macquarie Energy LLC NANANAT-12AD 1
Macquarie Energy LLC NANANAT-12SF 2
Macquarie Energy LLC NANANAWSPP-QSF 3
Modesto Irrigation District NANANAT-12SF 4
Morgan Stanley Capital Group, Inc.NANANAT-12AD 5
Morgan Stanley Capital Group, Inc.NANANAT-12SF 6
Morgan Stanley Capital Group, Inc.NANANAWSPP-QSF 7
Municipal Energy Agency of Nebraska NANANAT-12SF 8
NaturEner Power Watch, LLC NANANAT-13AD 9
NaturEner Power Watch, LLC NANANAT-13SF 10
Nevada Power Company NANANAWSPP-QSF 11
NextEra Energy Marketing, LLC NANANAT-12SF 12
NorthWestern Corporation NANANAT-12SF 13
NorthWestern Corporation NANANAT-13SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.4
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the 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.
1,267 1,267 1
2,768,437 2,768,437 91,606 2
360,436 360,436 13,160 3
1,118,561 1,118,561 30,544 4
47,299 47,299 1,075 5
44,719,442 44,719,442 1,710,940 6
275,179 275,179 9,665 7
60,157 60,157 1,984 8
-34 -34 9
5,028 5,028 173 10
258,607 258,607 6,939 11
113,600 113,600 4,800 12
600 600 25 13
3,236 3,236 102 14
FERC FORM NO. 1 (ED. 12-90) Page 311.4
9,529,353
386,671,884
396,201,237
302,600
5,177,028
5,479,628
-1,187,485 14,230,443
-209,626,333
-210,813,818
178,041,214
192,271,657
5,888,575
995,663
6,884,238
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
NorthWestern Corporation NANANAWSPP-QSF 1
Portland General Electric Company NANANAT-12SF 2
Portland General Electric Company NANANAT-13SF 3
Portland General Electric Company NANANAWSPP-QSF 4
Powerex Corporation NANANAT-12SF 5
Public Service Company of Colorado NANANAT-12AD 6
Public Service Company of Colorado NANANAT-12SF 7
Public Service Company of Colorado NANANAT-13SF 8
Public Service Company of New Mexico NANANAT-12SF 9
PUD No. 1 of Chelan County NANANAT-12SF 10
PUD No. 1 of Chelan County NANANAT-13SF 11
PUD No. 1 of Douglas County NANANAT-12SF 12
PUD No. 1 of Douglas County NANANAT-13SF 13
PUD No. 1 of Snohomish County NANANAT-12SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.5
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the 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.
455,047 455,047 12,556 1
1,498,409 1,498,409 42,083 2
4,758 4,758 140 3
82,000 82,000 1,600 4
5,775,666 5,775,666 209,377 5
-1,367 -1,367 -35 6
105,474,480 105,474,480 3,830,356 7
2,536 2,536 68 8
2,198,741 2,198,741 60,019 9
51,340 51,340 2,000 10
321 321 11 11
147,950 147,950 2,600 12
12 12 4 13
84,655 84,655 3,100 14
FERC FORM NO. 1 (ED. 12-90) Page 311.5
9,529,353
386,671,884
396,201,237
302,600
5,177,028
5,479,628
-1,187,485 14,230,443
-209,626,333
-210,813,818
178,041,214
192,271,657
5,888,575
995,663
6,884,238
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
PUD No. 2 of Grant County NANANAT-13SF 1
Puget Sound Energy, Inc.NANANAT-12SF 2
Puget Sound Energy, Inc.NANANAT-13SF 3
Rainbow Energy Marketing Corporation NANANAT-12SF 4
Rainbow Energy Marketing Corporation NANANAWSPP-QSF 5
Sacramento Municipal Utility District NANANAT-12SF 6
Sacramento Municipal Utility District NANANAT-13SF 7
Salt River Project NANANAT-12SF 8
Seattle City Light NANANAT-12SF 9
Seattle City Light NANANAT-13SF 10
Sempra Gas & Power Marketing, LlC NANANAT-12AD 11
Sempra Gas & Power Marketing, LlC NANANAT-12SF 12
Shell Energy North America (US), L.P.NANANAT-12SF 13
Shell Energy North America (US), L.P.NANANAWSPP-QSF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.6
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the 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.
40 40 4 1
1,695,388 1,695,388 47,406 2
1,123 1,123 33 3
244,919 244,919 5,122 4
24,000 24,000 1,200 5
188,270 188,270 5,229 6
1,091 1,091 32 7
425,151 425,151 9,190 8
560,971 560,971 14,645 9
54 54 3 10
55,520 55,520 1,934 11
8,550,435 8,550,435 344,140 12
20,847,120 -985 20,846,135 574,795 13
1,465,960 1,465,960 51,591 14
FERC FORM NO. 1 (ED. 12-90) Page 311.6
9,529,353
386,671,884
396,201,237
302,600
5,177,028
5,479,628
-1,187,485 14,230,443
-209,626,333
-210,813,818
178,041,214
192,271,657
5,888,575
995,663
6,884,238
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Sierra Pacific Power Company NANANAT-13SF 1
Southern California Edison Company NANANAT-12SF 2
Tacoma Power NANANAT-12SF 3
Tacoma Power NANANAT-13SF 4
Tenaska Power Services Co.NANANAT-12SF 5
Tenaska Power Services Co.NANANAWSPP-QSF 6
The Energy Authority, Inc.NANANAT-12SF 7
TransAlta Energy Marketing (U.S.) Inc.NANANAT-12SF 8
TransCanada Energy Sales Ltd.NANANAT-12SF 9
Tri-State Gen. and Trans. Assoc.NANANAT-12SF 10
Tucson Electric Power Company NANANAT-12SF 11
Turlock Irrigation District NANANAT-12SF 12
UNS Electric, Inc.NANANAT-12SF 13
Utah Associated Municipal Power Systems NANANAWSPP-QSF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.7
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the 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.
3,327 3,327 102 1
2,769,846 2,769,846 95,880 2
666,238 666,238 21,275 3
265 265 7 4
2,559,233 2,559,233 70,402 5
2,166,244 2,166,244 82,194 6
2,334,820 2,334,820 58,069 7
5,852,472 5,852,472 187,854 8
56,700 56,700 1,200 9
141,374 141,374 5,404 10
6,676,710 6,676,710 164,894 11
8,116,256 8,116,256 262,060 12
1,343,739 1,343,739 35,480 13
471,547 471,547 15,469 14
FERC FORM NO. 1 (ED. 12-90) Page 311.7
9,529,353
386,671,884
396,201,237
302,600
5,177,028
5,479,628
-1,187,485 14,230,443
-209,626,333
-210,813,818
178,041,214
192,271,657
5,888,575
995,663
6,884,238
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Vitol Inc.NANANAT-12SF 1
Westar Energy, Inc.NANANAT-12SF 2
Western Area Power Adm CO MO NANANAT-12SF 3
Western Area Power Adm CO MO NANANAT-13SF 4
Western Area Power Adm Lower CO NANANAT-12SF 5
Western Area Power Adm Sierra Nevada NANANAT-12SF 6
Western Area Power Adm Upper CO NANANAT-12SF 7
Western Area Power Adm Great Plains NANANAT-13SF 8
Transmission Loss Sales Revenue NANANAT-11AD 9
Transmission Loss Sales Revenue NANANAT-11OS 10
Test Generation NANANANA 11
Netting - Bookouts NANANANA 12
Netting - Trading NANANANA 13
Accrual NANANANA 14
FERC FORM NO. 1 (ED. 12-90) Page 310.8
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the 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.
169,210 169,210 6,600 1
53,792 53,792 2,000 2
2,118,921 2,118,921 60,751 3
3,207 3,207 132 4
130,160 130,160 3,640 5
110,850 110,850 3,800 6
6,214,111 6,214,111 173,518 7
66 66 3 8
-132,904 -132,904 9
6,755,864 6,755,864 199,203 10
-4,906,847 -4,906,847 -251,009 11
-212,766,314 -212,766,314 -8,044,824 12
-3,167,676 -3,167,676 13
301,366 301,366 80,167 14
FERC FORM NO. 1 (ED. 12-90) Page 311.8
9,529,353
386,671,884
396,201,237
302,600
5,177,028
5,479,628
-1,187,485 14,230,443
-209,626,333
-210,813,818
178,041,214
192,271,657
5,888,575
995,663
6,884,238
Schedule Page: 310 Line No.: 4 Column: j
$ (796,534) Load retention
(6,355) Settlement adjustment
(262,596) Customer service charges related to:
- Schedule 94, Utah Energy Balancing Account
- Schedule 98, Utah Renewable Energy Credits Revenue Adjustment
- Schedule 196, Utah Sustainable Transportation and Energy Plan Cost
Adjustment Pilot Program
- Schedule 197, Utah Federal Tax Act Adjustment
$(1,065,485)
Schedule Page: 310 Line No.: 5 Column: a
Complete name is Navajo Tribal Utility Authority (Mexican Hat).
Schedule Page: 310 Line No.: 6 Column: a
Complete name is Navajo Tribal Utility Authority (Red Mesa).
Schedule Page: 310 Line No.: 7 Column: j
Represents the difference between actual requirement sales revenues for the period as
reflected on the individual line items within this schedule and the accruals charged to
Account 447, Sales for resale, during the period.
Schedule Page: 310 Line No.: 13 Column: j
Reserve share.
Schedule Page: 310.1 Line No.: 1 Column: j
Reserve share.
Schedule Page: 310.1 Line No.: 4 Column: b
Black Hills Power, Inc. - contract termination date: December 31, 2023.
Schedule Page: 310.1 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 6 Column: c
Service Agreement 37

Schedule Page: 310.1 Line No.: 6 Column: j
Settlement adjustment.
Schedule Page: 310.1 Line No.: 7 Column: c
Service Agreement 37

Schedule Page: 310.1 Line No.: 7 Column: j
Termination payment for Foote Creek.
Schedule Page: 310.1 Line No.: 9 Column: j
Reserve share.
Schedule Page: 310.1 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 310.1 Line No.: 11 Column: j
Settlement adjustment.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 310.1 Line No.: 13 Column: a
Complete name is British Columbia Hydro and Power Authority.
Schedule Page: 310.1 Line No.: 13 Column: j
Reserve share.
Schedule Page: 310.2 Line No.: 1 Column: a
Complete name is California Independent System Operator Corporation.
Schedule Page: 310.2 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 310.2 Line No.: 14 Column: j
Settlement adjustment.
Schedule Page: 310.3 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 310.3 Line No.: 6 Column: j
Settlement adjustment.
Schedule Page: 310.3 Line No.: 9 Column: j
Reserve share.
Schedule Page: 310.3 Line No.: 11 Column: j
Reserve share.
Schedule Page: 310.3 Line No.: 14 Column: a
Complete name is Los Angeles Department of Water and Power.
Schedule Page: 310.4 Line No.: 1 Column: b
Settlement adjustment.
Schedule Page: 310.4 Line No.: 1 Column: j
Settlement adjustment.
Schedule Page: 310.4 Line No.: 5 Column: b
Settlement adjustment.
Schedule Page: 310.4 Line No.: 5 Column: j
Settlement adjustment.
Schedule Page: 310.4 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 310.4 Line No.: 9 Column: j
Settlement adjustment.
Schedule Page: 310.4 Line No.: 10 Column: j
Reserve share.
Schedule Page: 310.4 Line No.: 11 Column: a
Nevada Power Company is a wholly owned subsidiary of NV Energy, Inc., which is an indirect
wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
company.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 310.4 Line No.: 14 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 3 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 6 Column: b
Settlement adjustment.
Schedule Page: 310.5 Line No.: 6 Column: j
Settlement adjustment.
Schedule Page: 310.5 Line No.: 8 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 10 Column: a
This footnote applies to all occurrences of "PUD No. 1 of Chelan County" on pages 310-311.
Complete name is Public Utility District No. 1 of Chelan County.
Schedule Page: 310.5 Line No.: 11 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 12 Column: a
This footnote applies to all occurrences of "PUD No. 1 of Douglas County" on pages
310-311. Complete name is Public Utility District No. 1 of Douglas County.
Schedule Page: 310.5 Line No.: 13 Column: j
Reserve share.
Schedule Page: 310.5 Line No.: 14 Column: a
Complete name is Public Utility District No. 1 of Snohomish County.
Schedule Page: 310.6 Line No.: 1 Column: a
Complete name is Public Utility District No. 2 of Grant County.
Schedule Page: 310.6 Line No.: 1 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 3 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 7 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 10 Column: j
Reserve share.
Schedule Page: 310.6 Line No.: 11 Column: b
Settlement adjustment.
Schedule Page: 310.6 Line No.: 11 Column: j
Settlement adjustment.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 310.6 Line No.: 13 Column: j
Liquidated damages.
Schedule Page: 310.7 Line No.: 1 Column: a
Sierra Pacific Power Company is a wholly owned subsidiary of NV Energy, Inc., which is an
indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's
indirect parent company.
Schedule Page: 310.7 Line No.: 1 Column: j
Reserve share.
Schedule Page: 310.7 Line No.: 4 Column: j
Reserve share.
Schedule Page: 310.7 Line No.: 10 Column: a
Complete name is Tri-State Generation and Transmission Association, Inc.
Schedule Page: 310.8 Line No.: 3 Column: a
This footnote applies to all occurrences of "Western Area Power Adm CO MO" on pages
310-311. Complete name is Western Area Power Administration - Colorado Missouri.
Schedule Page: 310.8 Line No.: 4 Column: j
Reserve share.

Schedule Page: 310.8 Line No.: 5 Column: a
Complete name is Western Area Power Administration - Lower Colorado.
Schedule Page: 310.8 Line No.: 6 Column: a
Complete name is Western Area Power Administration - Sierra Nevada.
Schedule Page: 310.8 Line No.: 7 Column: a
Complete name is Western Area Power Administration - Upper Colorado.
Schedule Page: 310.8 Line No.: 8 Column: a
Complete name is Western Area Power Administration - Upper Great Plains West.
Schedule Page: 310.8 Line No.: 8 Column: j
Reserve share.

Schedule Page: 310.8 Line No.: 9 Column: b
Settlement adjustment.

Schedule Page: 310.8 Line No.: 9 Column: j
Settlement adjustment.

Schedule Page: 310.8 Line No.: 10 Column: b
Transmission loss sales revenues collected from PacifiCorp's third party transmission
service customers.

Schedule Page: 310.8 Line No.: 10 Column: j
Transmission loss sales revenues collected from PacifiCorp's third party transmission
service customers.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 310.8 Line No.: 11 Column: j
The negative revenue reported on this line reflects test energy generated that was
transferred to Account 107, Construction work in progress for the following wind-powered
generating facilities: Glenrock; Glenrock III; Goodnoe Hills; High Plains; Leaning Juniper
1; Marengo; McFadden Ridge I; Rolling Hills; Seven Mile Hill; and Seven Mile Hill II.
Energy generated during testing was delivered to PacifiCorp's electric system for sale as
accounted for under the guidance in 18 C.F.R., Part 101, Electric Plant Instructions
Electric Plant Instructions 3, 18(a). Test energy is a component of construction work in
progress and is reported at the fair value of the energy delivered.
Schedule Page: 310.8 Line No.: 12 Column: j
Reflects transactions that did not physically settle.

Schedule Page: 310.8 Line No.: 13 Column: j
Reflects transactions that were categorized as trading activities.
Schedule Page: 310.8 Line No.: 14 Column: j
Represents the difference between actual non-requirement sales revenues for the period as
reflected on the individual line items within this schedule and the accruals charged to
Account 447, Sales for resale, during the period.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
1. POWER PRODUCTION EXPENSES 1
A. Steam Power Generation 2
Operation 3
(500) Operation Supervision and Engineering 4 17,846,918 17,825,121
(501) Fuel 5 815,215,918 757,097,162
(502) Steam Expenses 6 80,653,310 80,249,325
(503) Steam from Other Sources 7 4,714,446 4,836,772
(Less) (504) Steam Transferred-Cr. 8
(505) Electric Expenses 9 1,538,384 1,532,522
(506) Miscellaneous Steam Power Expenses 10 24,373,827 27,042,769
(507) Rents 11 488,625 492,466
(509) Allowances 12
TOTAL Operation (Enter Total of Lines 4 thru 12) 13 944,831,428 889,076,137
Maintenance 14
(510) Maintenance Supervision and Engineering 15 7,987,432 7,293,482
(511) Maintenance of Structures 16 26,949,381 27,614,737
(512) Maintenance of Boiler Plant 17 94,244,196 89,039,742
(513) Maintenance of Electric Plant 18 40,477,428 39,509,020
(514) Maintenance of Miscellaneous Steam Plant 19 9,735,906 10,456,723
TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 179,394,343 173,913,704
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 1,124,225,771 1,062,989,841
B. Nuclear Power Generation 22
Operation 23
(517) Operation Supervision and Engineering 24
(518) Fuel 25
(519) Coolants and Water 26
(520) Steam Expenses 27
(521) Steam from Other Sources 28
(Less) (522) Steam Transferred-Cr. 29
(523) Electric Expenses 30
(524) Miscellaneous Nuclear Power Expenses 31
(525) Rents 32
TOTAL Operation (Enter Total of lines 24 thru 32) 33
Maintenance 34
(528) Maintenance Supervision and Engineering 35
(529) Maintenance of Structures 36
(530) Maintenance of Reactor Plant Equipment 37
(531) Maintenance of Electric Plant 38
(532) Maintenance of Miscellaneous Nuclear Plant 39
TOTAL Maintenance (Enter Total of lines 35 thru 39) 40
TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 41
C. Hydraulic Power Generation 42
Operation 43
(535) Operation Supervision and Engineering 44 8,478,869 9,462,766
(536) Water for Power 45 38,379 36,194
(537) Hydraulic Expenses 46 4,538,642 4,073,308
(538) Electric Expenses 47
(539) Miscellaneous Hydraulic Power Generation Expenses 48 17,012,228 18,007,655
(540) Rents 49 1,222,268 1,696,372
TOTAL Operation (Enter Total of Lines 44 thru 49) 50 31,290,386 33,276,295
C. Hydraulic Power Generation (Continued) 51
Maintenance 52
(541) Mainentance Supervision and Engineering 53 470 381
(542) Maintenance of Structures 54 717,063 646,717
(543) Maintenance of Reservoirs, Dams, and Waterways 55 1,426,368 1,770,311
(544) Maintenance of Electric Plant 56 1,683,128 2,013,122
(545) Maintenance of Miscellaneous Hydraulic Plant 57 3,880,263 4,378,310
TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 7,707,292 8,808,841
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 38,997,678 42,085,136
FERC FORM NO. 1 (ED. 12-93) Page 320
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
D. Other Power Generation 60
Operation 61
(546) Operation Supervision and Engineering 62 285,602 355,808
(547) Fuel 63 239,131,815 280,208,082
(548) Generation Expenses 64 17,616,683 17,253,968
(549) Miscellaneous Other Power Generation Expenses 65 5,107,905 7,815,446
(550) Rents 66 4,360,755 3,234,050
TOTAL Operation (Enter Total of lines 62 thru 66) 67 266,502,760 308,867,354
Maintenance 68
(551) Maintenance Supervision and Engineering 69
(552) Maintenance of Structures 70 4,396,956 2,374,413
(553) Maintenance of Generating and Electric Plant 71 17,759,259 12,239,103
(554) Maintenance of Miscellaneous Other Power Generation Plant 72 3,138,006 2,982,747
TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 25,294,221 17,596,263
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 291,796,981 326,463,617
E. Other Power Supply Expenses 75
(555) Purchased Power 76 667,434,104 633,195,384
(556) System Control and Load Dispatching 77 1,211,514 770,619
(557) Other Expenses 78 41,691,162 44,593,260
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 710,336,780 678,559,263
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 2,165,357,210 2,110,097,857
2. TRANSMISSION EXPENSES 81
Operation 82
(560) Operation Supervision and Engineering 83 6,772,651 7,360,740
84
(561.1) Load Dispatch-Reliability 85
(561.2) Load Dispatch-Monitor and Operate Transmission System 86 7,234,514 7,813,567
(561.3) Load Dispatch-Transmission Service and Scheduling 87
(561.4) Scheduling, System Control and Dispatch Services 88 1,384,344 1,250,888
(561.5) Reliability, Planning and Standards Development 89 1,968,543 1,962,101
(561.6) Transmission Service Studies 90 102,948 82,323
(561.7) Generation Interconnection Studies 91 1,755,384 504,815
(561.8) Reliability, Planning and Standards Development Services 92 7,447,677 8,800,994
(562) Station Expenses 93 2,901,944 3,124,100
(563) Overhead Lines Expenses 94 864,557 1,089,585
(564) Underground Lines Expenses 95
(565) Transmission of Electricity by Others 96 135,021,597 145,825,268
(566) Miscellaneous Transmission Expenses 97 2,859,169 3,006,329
(567) Rents 98 2,138,345 2,244,063
TOTAL Operation (Enter Total of lines 83 thru 98) 99 170,451,673 183,064,773
Maintenance 100
(568) Maintenance Supervision and Engineering 101 1,444,581 1,304,375
(569) Maintenance of Structures 102 41,891 105,140
(569.1) Maintenance of Computer Hardware 103 67,060
(569.2) Maintenance of Computer Software 104 825,322 951,021
(569.3) Maintenance of Communication Equipment 105 5,238,837 4,732,027
(569.4) Maintenance of Miscellaneous Regional Transmission Plant 106
(570) Maintenance of Station Equipment 107 11,984,857 11,796,851
(571) Maintenance of Overhead Lines 108 16,147,738 16,201,425
(572) Maintenance of Underground Lines 109 81,815 57,535
(573) Maintenance of Miscellaneous Transmission Plant 110 222,170 153,479
TOTAL Maintenance (Total of lines 101 thru 110) 111 36,054,271 35,301,853
TOTAL Transmission Expenses (Total of lines 99 and 111) 112 206,505,944 218,366,626
FERC FORM NO. 1 (ED. 12-93) Page 321
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
3. REGIONAL MARKET EXPENSES 113
Operation 114
(575.1) Operation Supervision 115
(575.2) Day-Ahead and Real-Time Market Facilitation 116
(575.3) Transmission Rights Market Facilitation 117
(575.4) Capacity Market Facilitation 118
(575.5) Ancillary Services Market Facilitation 119
(575.6) Market Monitoring and Compliance 120
(575.7) Market Facilitation, Monitoring and Compliance Services 121
(575.8) Rents 122
Total Operation (Lines 115 thru 122) 123
Maintenance 124
(576.1) Maintenance of Structures and Improvements 125
(576.2) Maintenance of Computer Hardware 126
(576.3) Maintenance of Computer Software 127
(576.4) Maintenance of Communication Equipment 128
(576.5) Maintenance of Miscellaneous Market Operation Plant 129
Total Maintenance (Lines 125 thru 129) 130
TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 131
4. DISTRIBUTION EXPENSES 132
Operation 133
(580) Operation Supervision and Engineering 134 8,848,063 9,520,507
(581) Load Dispatching 135 11,541,737 12,160,239
(582) Station Expenses 136 4,076,355 4,707,948
(583) Overhead Line Expenses 137 9,211,450 9,956,347
(584) Underground Line Expenses 138 2,063 621
(585) Street Lighting and Signal System Expenses 139 247,796 224,138
(586) Meter Expenses 140 2,790,673 2,526,289
(587) Customer Installations Expenses 141 14,205,310 15,268,629
(588) Miscellaneous Expenses 142 1,196,149 649,377
(589) Rents 143 3,182,216 2,874,305
TOTAL Operation (Enter Total of lines 134 thru 143) 144 55,301,812 57,888,400
Maintenance 145
(590) Maintenance Supervision and Engineering 146 5,835,359 6,381,190
(591) Maintenance of Structures 147 2,142,078 2,358,542
(592) Maintenance of Station Equipment 148 9,062,978 9,665,348
(593) Maintenance of Overhead Lines 149 89,351,304 88,649,749
(594) Maintenance of Underground Lines 150 24,670,628 27,326,536
(595) Maintenance of Line Transformers 151 974,547 1,003,084
(596) Maintenance of Street Lighting and Signal Systems 152 2,965,826 2,503,642
(597) Maintenance of Meters 153 225,334 529,287
(598) Maintenance of Miscellaneous Distribution Plant 154 6,728,870 6,497,561
TOTAL Maintenance (Total of lines 146 thru 154) 155 141,956,924 144,914,939
TOTAL Distribution Expenses (Total of lines 144 and 155) 156 197,258,736 202,803,339
5. CUSTOMER ACCOUNTS EXPENSES 157
Operation 158
(901) Supervision 159 2,477,399 2,282,185
(902) Meter Reading Expenses 160 19,056,668 14,595,821
(903) Customer Records and Collection Expenses 161 50,336,486 46,565,556
(904) Uncollectible Accounts 162 11,655,692 13,068,251
(905) Miscellaneous Customer Accounts Expenses 163 135,391 347,870
TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 83,661,636 76,859,683
FERC FORM NO. 1 (ED. 12-93) Page 322
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 165
Operation 166
(907) Supervision 167 117,633 6,737
(908) Customer Assistance Expenses 168 90,120,906 95,221,065
(909) Informational and Instructional Expenses 169 5,820,368 6,310,516
(910) Miscellaneous Customer Service and Informational Expenses 170 41,342 4,533
TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 96,100,249 101,542,851
7. SALES EXPENSES 172
Operation 173
(911) Supervision 174
(912) Demonstrating and Selling Expenses 175
(913) Advertising Expenses 176
(916) Miscellaneous Sales Expenses 177
TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 178
8. ADMINISTRATIVE AND GENERAL EXPENSES 179
Operation 180
(920) Administrative and General Salaries 181 72,265,963 76,578,659
(921) Office Supplies and Expenses 182 9,971,031 9,594,354
(Less) (922) Administrative Expenses Transferred-Credit 183 31,909,798 34,578,091
(923) Outside Services Employed 184 19,890,624 22,040,045
(924) Property Insurance 185 12,338,561 14,929,761
(925) Injuries and Damages 186 16,740,134 8,096,669
(926) Employee Pensions and Benefits 187 113,736,594 102,224,372
(927) Franchise Requirements 188
(928) Regulatory Commission Expenses 189 22,484,361 25,605,836
(929) (Less) Duplicate Charges-Cr. 190 128,629,971 130,646,461
(930.1) General Advertising Expenses 191 580 55,028
(930.2) Miscellaneous General Expenses 192 2,225,689 2,244,072
(931) Rents 193 2,723,369 2,541,299
TOTAL Operation (Enter Total of lines 181 thru 193) 194 111,837,137 98,685,543
Maintenance 195
(935) Maintenance of General Plant 196 23,525,832 24,451,060
TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 135,362,969 123,136,603
TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 2,884,246,744 2,832,806,959
FERC FORM NO. 1 (ED. 12-93) Page 323
Schedule Page: 320 Line No.: 185 Column: b
Adjustment to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, is as follows:
Account
(a)
Ref.
Line No.
(Column)
Amount for
Current Year
(b)
(924) Property Insurance 185(b) $ 14,929,761
Less: Situs property loss reserves, net of reimbursements(1) 10,192,677
Revised (924) Property Insurance $ 4,737,084
(1) To adjust PacifiCorp's formula rate, per FERC Docket No. FA16-4-000 for situs property
loss reserves, net of reimbursements.
Schedule Page: 320 Line No.: 187 Column: b
As required by Commission regulations, the cost of pensions, postretirement other than
pensions and other employee benefits are reported in Account 926, Employee pensions and
benefits. Pensions and benefits expense is associated with labor and generally charged to
operations and maintenance expense and construction work in progress, therefore, pursuant
to FERC Docket No. FA16-4-000, these pensions and benefits are offset in Account 929,
Duplicate charges-credit.
In accordance with PacifiCorp's formula rate settlement agreement in FERC Docket No.
ER11-3643-000, Section 3.4.2.9 states, in part, all regulatory asset amortizations should
be excluded from the calculation of the wholesale transmission revenue requirement and
charges under the wholesale formula rates, unless approved by the Commission. During the
year ended December 31, 2019, pension and postretirement regulatory asset amortization was
$(2,684,722).
Schedule Page: 320 Line No.: 190 Column: b
Includes the offset of pensions and benefits in Account 926, Employee pensions and
benefits, pursuant to FERC Docket No. FA16-4-000.
Schedule Page: 320 Line No.: 197 Column: b
Adjustments to PacifiCorp's formula rate under FERC Docket No. ER11-3643-000, Attachment
H-1, are as follows:
Account
(a)
Ref.
Line No.
(Column)
Amount for
Current Year
(b)
TOTAL Administrative & General Expenses 197(b) $ 123,136,603
Less: Situs property loss reserves, net of reimbursements(1) 10,192,677
Less: Pension and postretirement regulatory asset amort. (2) (2,684,722)
Revised TOTAL Administrative & General Expenses $ 115,628,648
(1) To adjust Account 924, Property insurance. Refer to footnote on page 320,
line no. 185, column (b)
(2) To adjust Account 926, Employee pensions and benefits. Refer to footnote on page 320,
line no. 187, column (b)
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Power Purchases: 1
NANANAAdams Solar Center LLC AD 2
NANANAAdams Solar Center LLC LU 3
NANANAAmor IX LLC LU 4
NANANAApple, Inc. LU 5
NANANAArizona Electric Power Cooperative SF 6
NANANAArizona Electric Power Cooperative AD 7
NANANAArizona Public Service Company LF 8
NANANAArizona Public Service Company SF 9
NANANAArizona Public Service Company AD 10
NANANAAvangrid Renewables, LLC SF 11
NANANAAvangrid Renewables, LLC AD 12
NANANAAvista Corporation SF 13
000Ballard Hog Farms Inc. LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
1
-1,987 -1,987 2
1,367,981 18,117 1,386,098 3 20,767
1,328,994 -15,000 1,313,994 4 24,611
409,072 409,072 5 5,193
1,102,286 1,102,286 6 30,353
3,750 3,750 7
2,183,574 2,183,574 8 98,778
5,515,159 5,515,159 9 287,871
-1,083 -1,083 10
33,602,095 1,167 33,603,262 11 785,902
104 104 12 1
5,284,535 6,724 5,291,259 13 138,294
5,070 12,145 17,215 14 228
FERC FORM NO. 1 (ED. 12-90) Page 327
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANABarclays Bank PLC AD 1
NANANABasin Electric Power Cooperative SF 2
NANANABC Solar, LLC LU 3
NANANABear Creek Solar Center, LLC LU 4
NANANABear Creek Solar Center, LLC LU 5
NANANABeaver City Corporation LF 6
NANANABell Mountain Hydro, LLC LU 7
133Beryl Solar, LLC LU 8
NANANABig Top, LLC LU 9
NANANABiomass One, L.P. LU 10
NANANABirch Power Company, Inc. LU 11
NANANABlack Cap Solar, LLC LU 12
NANANABlack Hills Power, Inc. SF 13
NANANABly Solar Center, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.1
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
-5,696,981 -5,696,981 1
3,577,578 3,577,578 2 106,829
1,223,880 1,223,880 3 18,570
19,785 19,785 4
1,492,873 1,492,873 5 22,665
2,801 2,801 6 27
71,601 71,601 7 806
416,812 300,113 716,925 8 5,641
254,626 254,626 9 3,276
12,594,337 2,809,629 15,403,966 10 162,616
833,996 833,996 11 13,011
21,825 21,825 12 678
426,207 426,207 13 10,084
11,976 11,976 14
FERC FORM NO. 1 (ED. 12-90) Page 327.1
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANABly Solar Center, LLC LU 1
NANANABly Solar Center, LLC AD 2
NANANABonneville Power Administration LF 3
NANANABonneville Power Administration SF 4
NANANABourdet, Peter M LU 5
243Box Canyon Limited Partnership LU 6
NANANABP Energy Company SF 7
NANANABP Energy Company AD 8
NANANABrigham Young University - Idaho IU 9
NANANABrigham Young University - Idaho AD 10
NANANABrookfield Energy Marketing LP SF 11
NANANABrookfield Renewable Trading SF 12
033Buckhorn Solar, LLC LU 13
NANANAButter Creek Power, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.2
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
1,188,171 1,188,171 1 18,040
836 836 2 20
146,932 146,932 3
12,040,753 37,565 12,078,318 4 316,449
9,228 9,228 5 269
271,262 3,143,412 3,414,674 6 20,928
45,251,221 45,251,221 7 1,419,068
84,861 84,861 8 1,853
2,117,518 2,117,518 9 38,557
-23,899 -23,899 10
2,810,720 2,810,720 11 54,200
1,651,022 1,651,022 12 49,625
431,159 267,580 698,739 13 5,030
872,869 872,869 14 11,294
FERC FORM NO. 1 (ED. 12-90) Page 327.2
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAC Drop Hydro, LLC LU 1
NANANACalifornia Independent System Operator SF 2
NANANACalpine Energy Services, L.P. SF 3
133Cedar Valley Solar, LLC LU 4
NANANACedar Valley Solar, LLC AD 5
343Central Oregon Irrigation District LU 6
NANANAChiloquin Solar LLC LU 7
NANANAChopin Wind, LLC LU 8
NANANACitigroup Energy, Inc. SF 9
NANANACity of Albany LU 10
NANANACity of Anaheim SF 11
NANANACity of Astoria LU 12
NANANACity of Burbank SF 13
NANANACity of Hurricane LF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.3
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
173,778 173,778 1 2,207
2,663,242 2,663,242 2 29,270
15,834,310 15,834,310 3 260,614
428,169 309,057 737,226 4 5,809
7,619 7,619 5 149
305,173 3,141,363 3,446,536 6 28,927
850,629 850,629 7 19,452
1,446,997 1,446,997 8 25,283
38,122,633 38,122,633 9 1,335,219
61,982 61,982 10 780
8,681 8,681 11 840
621 621 12 15
427,790 427,790 13 13,040
163,006 163,006 14 2,368
FERC FORM NO. 1 (ED. 12-90) Page 327.3
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANACity of Idaho Falls LU 1
NANANACity of Pasadena SF 2
NANANACity of Portland, Water Bureau LU 3
NANANACity of Preston Idaho LU 4
NANANACity of Roseville SF 5
NANANAClatskanie People's Utility District SF 6
NANANACommercial Energy Management Inc. LU 7
NANANAConfederate Tribes of Warm Springs LU 8
NANANAConocoPhillips Company SF 9
NANANAConsolidated Irrigation Company LU 10
NANANACottonwood Hydro, LLC IU 11
NANANACrook County Solar 1, LLC LU 12
345Deschutes Valley Water District LU 13
88100100Deseret Generation and Transmission LF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.4
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
1,744,932 1,744,932 1 48,730
3,927 3,927 2 161
13,131 13,131 3 166
162,071 162,071 4 2,633
1,270,674 1,270,674 5 6,548
18,486 18,486 6 769
126,903 126,903 7 2,221
10,178 10,178 8 312
18,558,664 18,558,664 9 585,885
124,862 124,862 10 2,085
160,345 160,345 11 3,327
36,238 36,238 12 1,096
513,536 3,959,903 4,473,439 13 28,184
18,175,560 12,558,772 4,679,760 35,414,092 14 541,968
FERC FORM NO. 1 (ED. 12-90) Page 327.4
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANADirect Energy Business Marketing, LLC SF 1
NANANADorena Hydro, LLC LU 2
NANANADouglas County, Inc. LU 3
110Douglas County LU 4
NANANADraper Irrigation Company IU 5
NANANADry Creek LLC LU 6
NANANADry Creek LLC AD 7
NANANADTE Energy Trading, Inc. SF 8
NANANAeBay Inc. LU 9
NANANAEDF Trading North America, LLC SF 10
NANANAEDF Trading North America, LLC AD 11
NANANAEl Paso Electric Company SF 12
NANANAElbe Solar Center, LLC LU 13
NANANAElbe Solar Center, LLC AD 14
FERC FORM NO. 1 (ED. 12-90) Page 326.5
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
525,998 525,998 1 5,654
848,230 848,230 2 10,754
22,632 22,632 3 995
98,739 648,091 746,830 4 4,470
52,146 52,146 5 731
623,246 623,246 6 10,376
-3,560 -3,560 7 -56
6,027,767 6,027,767 8 190,445
37,647 37,647 9 466
13,683,736 13,683,736 10 434,583
-166 -166 11 182
3,381,930 3,381,930 12 142,188
18,448 18,448 13
-457 -457 14
FERC FORM NO. 1 (ED. 12-90) Page 327.5
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAElbe Solar Center, LLC LU 1
NANANAEnterprise Solar, LLC LU 2
NANANAEnterprise Solar, LLC LU 3
NANANAEscalante Solar I, LLC LU 4
NANANAEscalante Solar II, LLC LU 5
NANANAEscalante Solar III, LLC LU 6
NANANAEugene Water & Electric Board SF 7
NANANAEurus Combine Hills I, LLC LU 8
NANANAExelon Generation Company, LLC SF 9
NANANAExelon Generation Company, LLC AD 10
NANANAExxonMobil Production Company LU 11
NANANAFall River Rural Electric Cooperative LU 12
132Falls Creek H.P. Limited Partnership LU 13
NANANAFarm Power Misty Meadow, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.6
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
1,363,154 1,363,154 1 20,745
406,684 406,684 2
12,066,974 12,066,974 3 220,046
11,032,982 11,032,982 4 205,146
10,424,754 10,424,754 5 203,681
10,087,420 10,087,420 6 204,442
94,471 94,471 7 4,311
4,399,842 4,399,842 8 89,111
10,604,595 10,604,595 9 297,327
1,294 1,294 10 25
7,239 7,239 11 263
1,866,357 1,866,357 12 29,171
121,744 1,458,119 1,579,863 13 10,112
295,386 295,386 14 3,731
FERC FORM NO. 1 (ED. 12-90) Page 327.6
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAFarmers Irrigation District LU 1
NANANAFillmore City Corporation LF 2
NANANAFinley BioEnergy, LLC LU 3
NANANAFlathead Electric Cooperative, Inc. LF 4
NANANAFoote Creek II, LLC LU 5
NANANAFoote Creek III, LLC LU 6
NANANAFour Corners Windfarm, LLC LU 7
NANANAFour Mile Canyon Windfarm, LLC LU 8
NANANAGeorgetown Irrigation Company LU 9
NANANAGrand Valley Power LF 10
NANANAGranite Mountain Solar East, LLC LU 11
NANANAGranite Mountain Solar West, LLC LU 12
033Granite Peak Solar, LLC LU 13
022Greenville Solar, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.7
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
1,636,710 1,636,710 1 20,509
17,394 17,394 2 145
2,432,064 2,432,064 3 30,642
11,853 11,853 4 385
99,550 99,550 5 5,327
871,196 871,196 6 38,576
1,844,901 1,844,901 7 23,868
1,691,287 1,691,287 8 21,832
127,440 127,440 9 2,023
10,167 10,167 10 49
10,610,270 10,610,270 11 204,075
6,859,673 6,859,673 12 125,440
244,700 210,743 455,443 13 5,665
322,016 206,206 528,222 14 3,876
FERC FORM NO. 1 (ED. 12-90) Page 327.7
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAGridforce Energy Management, LLC SF 1
NANANAGuzman Renewable Energy Partners LLC SF 2
NANANAHammerich 1 & 2 LU 3
NANANAHarold Foster & Robert Walker LU 4
NANANAHayward Paul Luckey and Joanne Luckey LU 5
NANANAIdaho Power Company OS 6
NANANAIdaho Power Company SF 7
NANANAIron Springs Solar, LLC LU 8
NANANAJ Bar 9 Ranch, Inc. LU 9
NANANAJake Amy LU 10
NANANAJoseph Community Solar, LLC LU 11
NANANAKeeton 1 & 2 LU 12
NANANAKettle Butte Digester LLC LU 13
NANANAKlamath Falls Solar 1, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.8
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
3,984 3,984 1 116
1,884 1,884 2 48
34,890 34,890 3 1,107
3,903 3,903 4 118
9,638 9,638 5 231
3,500 3,500 6 250
7,835,225 3,024 7,838,249 7 291,671
11,213,138 11,213,138 8 208,224
680 680 9 52
123,218 123,218 10 1,994
20,298 20,298 11 594
12,196 12,196 12 366
373,053 373,053 13 6,867
91,896 91,896 14 1,391
FERC FORM NO. 1 (ED. 12-90) Page 327.8
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAKlamath Falls Solar 2, LLC IU 1
NANANALacomb Irrigation District LU 2
133Laho Solar, LLC LU 3
NANANALatigo Wind Park, LLC LU 4
NANANALos Angeles Dept. of Water and Power SF 5
NANANALoyd Fery LU 6
NANANAMacquarie Energy LLC SF 7
NANANAMarsh Valley Hydro Electric Company LU 8
NANANAMeadow Creek Project Company LLC LU 9
NANANAMiddle Fork Irrigation District LU 10
133Milford Flat Solar, LLC LU 11
NANANAMink Creek Hydro LLC LU 12
NANANAMonsanto Company IU 13
NANANAMorgan City Corporation LF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.9
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
286,559 286,559 1 6,564
179,060 46,461 225,521 2 4,367
245,680 231,018 476,698 3 6,210
10,035,710 10,035,710 4 165,577
5,158,135 5,158,135 5 98,713
6,515 6,515 6 286
11,716,954 11,716,954 7 259,354
492,471 492,471 8 7,671
26,175,615 26,175,615 9 333,988
1,683,048 1,683,048 10 22,695
245,253 226,133 471,386 11 6,079
642,176 642,176 12 10,281
19,455,618 19,455,618 13
628 628 14 7
FERC FORM NO. 1 (ED. 12-90) Page 327.9
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAMorgan Stanley Capital Group, Inc. SF 1
NANANAMorgan Stanley Capital Group, Inc. AD 2
NANANAMountain Wind Power, LLC LU 3
NANANAMountain Wind Power II, LLC LU 4
NANANAMyron Jones LU 5
NANANANaturEner Power Watch, LLC AD 6
NANANANevada Power Company SF 7
NANANANextEra Energy Marketing, LLC SF 8
001Nichols Gap Limited Partnership LU 9
NANANANorthWestern Corporation SF 10
NANANANorWest Energy 2, LLC IU 11
NANANANorWest Energy 4, LLC IU 12
NANANANorWest Energy 7, LLC IU 13
NANANANorWest Energy 9, LLC IU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.10
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
30,500,035 30,500,035 1 751,562
27,738 27,738 2 1,303
8,512,829 8,512,829 3 153,281
13,304,971 13,304,971 4 206,041
46,727 46,727 5 784
-34 -34 6 1
1,132,876 1,132,876 7 31,623
160,629 160,629 8 2,955
40,565 475,111 515,676 9 3,189
134,934 6,358 141,292 10 6,380
1,363,784 1,363,784 11 20,696
696,918 696,918 12 10,714
1,285,525 1,285,525 13 19,520
503,971 503,971 14 11,511
FERC FORM NO. 1 (ED. 12-90) Page 327.10
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANANorWest Energy 9, LLC AD 1
NANANANucor Corporation IU 2
NANANAOak Lea Digester LLC LU 3
NANANAOak Lea Digester LLC AD 4
NANANAObsidian Finance Group, LLC LU 5
NANANAOld Mill Solar, LLC LU 6
NANANAOR Solar 3, LLC LU 7
NANANAOR Solar 5, LLC LU 8
NANANAOR Solar 6, LLC LU 9
NANANAOR Solar 8, LLC LU 10
NANANAOregon Environmental Industries, LLC LU 11
NANANAOregon Institute of Technology LU 12
NANANAOregon Institute of Technology AD 13
NANANAOregon Solar Incentive LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.11
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
5,069 5,069 1 192
7,201,200 7,201,200 2
59,163 59,163 3 751
50 50 4
30,082 30,082 5 930
837,215 837,215 6 11,163
1,087,550 1,087,550 7 24,887
854,819 854,819 8 19,565
1,068,963 1,068,963 9 24,451
1,076,978 1,076,978 10 24,677
1,035,162 1,035,162 11 13,989
9,890 9,890 12 174
821 821 13
350,926 350,926 14 10,608
FERC FORM NO. 1 (ED. 12-90) Page 327.11
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAOregon Trail Windfarm, LLC LU 1
NANANAOSLH, LLC IU 2
NANANAPacific Canyon Windfarm, LLC LU 3
NANANAPavant Solar LLC LU 4
NANANAPavant Solar II LLC LU 5
NANANAPavant Solar III LLC LU 6
NANANAPioneer Wind Park I, LLC LU 7
NANANAPlatte River Power Authority SF 8
NANANAPortland General Electric Company LF 9
NANANAPortland General Electric Company AD 10
NANANAPortland General Electric Company SF 11
NANANAPower County Wind Park North, LLC LU 12
NANANAPower County Wind Park South, LLC LU 13
NANANAPowerex Corporation SF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.12
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
1,635,833 1,635,833 1 21,184
945,939 945,939 2 21,654
1,276,839 1,276,839 3 16,444
4,487,103 166,425 4,653,528 4 110,950
3,510,009 3,510,009 5 115,089
2,541,438 2,541,438 6 48,133
11,278,486 11,278,486 7 282,578
100,885 100,885 8 19,629
104,129 104,129 9 12,241
-89,325 -89,325 10
6,264,389 10,860 6,275,249 11 204,348
4,925,197 4,925,197 12 65,015
4,360,555 4,360,555 13 57,102
21,688,308 21,688,308 14 370,487
FERC FORM NO. 1 (ED. 12-90) Page 327.12
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAProvo City Corporation LF 1
NANANAPublic Service Company of Colorado SF 2
NANANAPublic Service Company of Colorado AD 3
NANANAPublic Service Company of New Mexico SF 4
NANANAPublic Service Company of New Mexico AD 5
NANANAPUD No. 1 of Chelan County SF 6
NANANAPUD No. 1 of Douglas County SF 7
NANANAPUD No. 1 of Snohomish County SF 8
NANANAPUD No. 2 of Grant County LU 9
NANANAPUD No. 2 of Grant County AD 10
NANANAPUD No. 2 of Grant County SF 11
NANANAPuget Sound Energy, Inc. SF 12
133Quichapa 1, LLC LU 13
133Quichapa 2, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.13
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
4,122 4,122 1 46
56,828,092 2,933 56,831,025 2 1,890,453
4,749 4,749 3 87
2,434,433 2,434,433 4 77,945
-1,409 -1,409 5 -24
2,160,526 1,748 2,162,274 6 59,568
358,660 1,047 359,707 7 11,431
339,070 339,070 8 13,135
122,358 122,358 9 79,581
272,989 272,989 10
3,181 3,181 11 98
3,288,448 11,518 3,299,966 12 102,727
244,369 295,980 540,349 13 7,956
243,543 293,838 537,381 14 7,899
FERC FORM NO. 1 (ED. 12-90) Page 327.13
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
133Quichapa 3, LLC LU 1
NANANARainbow Energy Marketing Corporation SF 2
NANANARock River I, LLC LU 3
NANANARoseburg Forest Products Company LU 4
NANANARoseburg LFG Energy, LLC LU 5
NANANASacramento Municipal Utility District SF 6
NANANASage Solar I LLC LU 7
NANANASage Solar II LLC LU 8
NANANASage Solar III LLC LU 9
NANANASalt River Project SF 10
NANANASalt River Project AD 11
NANANASand Ranch Windfarm, LLC LU 12
000Santiam Water Control District LU 13
NANANASeattle City Light SF 14
FERC FORM NO. 1 (ED. 12-90) Page 326.14
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
243,407 290,873 534,280 1 7,819
110,406 110,406 2 4,248
4,833,945 4,833,945 3 136,244
1,028,431 1,028,431 4 47,698
480,825 480,825 5 6,125
332,100 332,100 6 15,300
499,768 499,768 7 12,780
710,378 710,378 8 18,531
656,254 656,254 9 17,060
13,998,318 13,998,318 10 378,287
11,075 11,075 11 264
1,601,501 1,601,501 12 20,643
13,156 176,855 190,011 13 1,324
1,363,980 3,952 1,367,932 14 36,577
FERC FORM NO. 1 (ED. 12-90) Page 327.14
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANASempra Gas & Power Marketing, LLC SF 1
NANANASempra Gas & Power Marketing, LLC AD 2
NANANAShell Energy North America (US), L.P. SF 3
NANANAShiloh Warm Springs Ranch, LLC LU 4
NANANASierra Pacific Power Company SF 5
NANANASimplot Phosphates, LLC LU 6
NANANASolwatt, LLC LU 7
NANANASouthern California Edison Company SF 8
NANANASpanish Fork Wind Park 2, LLC LU 9
000Sprague Hydro LLC LU 10
NANANASt. Anthony Hydro, LLC LU 11
NANANAStahlbush Island Farms, Inc. IU 12
113SunE DB18, LLC LU 13
133SunE DB24, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.15
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
4,975,367 4,975,367 1 162,918
61,187 61,187 2 1,289
21,391,142 21,391,142 3 520,603
45,356 45,356 4 706
42,051 4,807 46,858 5 1,123
1,257 1,257 6 56
25,800 25,800 7 803
500 500 8 24
2,849,569 2,849,569 9 49,131
49,988 406,377 456,365 10 2,778
385,843 385,843 11 5,796
38,025 38,025 12 1,196
417,280 380,529 797,809 13 7,153
196,240 226,305 422,545 14 6,083
FERC FORM NO. 1 (ED. 12-90) Page 327.15
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
483SunE Solar XVII Project 1, LLC LU 1
133SunE Solar XVII Project 2, LLC LU 2
123SunE Solar XVII Project 3, LLC LU 3
NANANASunny Bar Ranch LP LU 4
NANANASunny Bar Ranch LP AD 5
425353Sunnyside Cogeneration Associates LU 6
NANANASwalley Irrigation District LU 7
NANANASweetwater Solar LLC LU 8
NANANASweetwater Solar LLC AD 9
NANANATacoma Power SF 10
NANANATata Chemicals (Soda Ash) Partners LU 11
NANANATenaska Power Services Co. SF 12
NANANATesoro Refining & Marketing Co LLC LU 13
NANANAThayn Hydro LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.16
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
405,124 379,298 784,422 1 7,130
354,505 323,546 678,051 2 6,082
218,611 244,309 462,920 3 6,567
131,442 131,442 4 2,066
-51,956 -51,956 5 -812
29,537,917 29,537,917 6 401,228
171,078 171,078 7 2,154
7,816,242 7,816,242 8 181,501
-6,138 -6,138 9
666,990 1,823 668,813 10 18,116
52,493 52,493 11 3,125
2,742,909 2,742,909 12 101,998
109,332 109,332 13 6,015
117,879 117,879 14 2,633
FERC FORM NO. 1 (ED. 12-90) Page 327.16
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAThe Energy Authority, Inc. SF 1
NANANAThree Buttes Windpower, LLC LU 2
NANANAThree Peaks Power, LLC LU 3
NANANAThree Sisters Irrigation District LU 4
NANANAThreemile Canyon Wind I, LLC LU 5
NANANATMF Biofuels, LLC LU 6
NANANATooele Army Depot LU 7
NANANATop of the World Wind Energy LLC LU 8
NANANATransAlta Energy Marketing (U.S.) Inc. SF 9
NANANATransCanada Energy Sales Ltd. SF 10
132526Tri-State Generation and Transmission LF 11
NANANATri-State Generation and Transmission SF 12
NANANATucson Electric Power Company SF 13
NANANATumbleweed Solar LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.17
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
1,239,024 1,239,024 1 54,426
20,681,645 20,681,645 2 324,598
9,273,600 9,273,600 3 217,174
140,179 140,179 4 2,591
1,516,075 1,516,075 5 19,143
2,499,100 2,499,100 6 33,547
22,254 22,254 7 745
37,587,023 1,901,599 39,488,622 8 555,018
6,966,600 6,966,600 9 161,530
753,000 753,000 10 9,600
6,219,000 3,503,764 9,722,764 11 108,308
3,258,239 3,258,239 12 55,119
5,056,658 5,056,658 13 180,374
841,643 841,643 14 19,266
FERC FORM NO. 1 (ED. 12-90) Page 327.17
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANATurlock Irrigation District SF 1
NANANAU.S. Dept of the Interior LU 2
NANANAU.S. Air Force at Hill Air Force Base LU 3
NANANAUNS Electric, Inc. SF 4
NANANAUS Magnesium LLC LU 5
NANANAUtah Associated Municipal Power System LF 6
NANANAUtah Associated Municipal Power System SF 7
NANANAUtah Municipal Power Agency SF 8
NANANAUtah Red Hills Renewable Park, LLC LU 9
NANANAUtah Retail Solar Customers LU 10
NANANAUtah Retail Solar Customers AD 11
NANANAVitol Inc. SF 12
NANANAWagon Trail, LLC LU 13
NANANAWard Butte Windfarm, LLC LU 14
FERC FORM NO. 1 (ED. 12-90) Page 326.18
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
2,670,752 2,670,752 1 43,758
2,158 2,158 2 32
507,182 507,182 3 8,908
487,405 487,405 4 16,499
5,412,135 5,412,135 5
3,094,924 3,094,924 6 60,752
192 192 7 8
160,456 160,456 8 3,432
12,119,273 12,119,273 9 205,468
2,390,583 2,390,583 10 26,900
-133 -133 11
515,188 515,188 12 17,600
494,950 494,950 13 6,379
1,127,493 1,127,493 14 14,604
FERC FORM NO. 1 (ED. 12-90) Page 327.18
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAWeber County LU 1
NANANAWeber County AD 2
NANANAWestar Energy, Inc SF 3
NANANAWestern Area Power Administration LF 4
NANANAWestern Area Power Administration SF 5
NANANAWestern Area Power Administration AD 6
NANANAWolverine Creek Energy, LLC LU 7
NANANAWolverine Creek Energy, LLC AD 8
NANANAWoodline Solar, LLC IU 9
001Yakima-Tieton Irrigation District LU 10
UT STEP Gadsby Curtailment 11
CA Greenhouse Gas Allowance Purchases 12
Net Power Cost Deferrals 13
Netting - Bookouts 14
FERC FORM NO. 1 (ED. 12-90) Page 326.19
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
29,621 29,621 1 530
-263 -263 2
224,620 224,620 3 2,800
333,364 333,364 4 7,871
665,432 1,672 667,104 5 24,001
8,395 8,395 6
9,932,094 9,932,094 7 163,896
3 3 8
816,176 816,176 9 18,705
63,250 146,066 209,316 10 5,437
-7,067 -7,067 11
4,420,402 4,420,402 12
-52,470,478 -52,470,478 13
-212,766,314 -212,766,314 14 -8,044,855
FERC FORM NO. 1 (ED. 12-90) Page 327.19
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Netting - Trading 1
System Deviation 2
Accrual 3
4
Power Exchanges: 5
NANANAArizona Public Service Company 307EX 6
NANANAAvista Corporation 382EX 7
NANANABonneville Power Administration 237EX 8
NANANABonneville Power Administration 237AD 9
NANANABonneville Power Administration 519EX 10
NANANABonneville Power Administration T-BPAEX 11
NANANABonneville Power Administration T-BPAAD 12
NANANACalifornia Independent System Operator T-12EX 13
NANANACalifornia Independent System Operator T-12AD 14
FERC FORM NO. 1 (ED. 12-90) Page 326.20
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
-3,167,676 -3,167,676 1
2 838
-13,688,948 -13,688,948 3
4
5
566,506 570,517 5,149,751 5,149,751 6
1,765 7
404 12,507 39,204 39,204 8
14,586 14,586 9
72,746 71,999 10
5,368 256,761 624,778 624,778 11
7,255 7,255 12
4,136,075 4,467,627 -48,264,721 -48,264,721 13
59,479 59,479 14
FERC FORM NO. 1 (ED. 12-90) Page 327.20
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANACalifornia Independent System Operator T-11EX 1
NANANACalifornia Independent System Operator T-11AD 2
NANANACity of Roseville T-11AD 3
NANANAEmerald People's Utility District 351EX 4
NANANAEugene Water & Electric Board T-12EX 5
NANANAIdaho Power Company 708EX 6
NANANAIdaho Power Company T-6EX 7
NANANALos Angeles Dept. of Water and Power OV-1EX 8
NANANALos Angeles Dept. of Water and Power OV-1AD 9
NANANAMilford Wind Corridor Phase I, LLC OV-1EX 10
NANANAMilford Wind Corridor Phase I, LLC OV-1AD 11
NANANAMilford Wind Corridor Phase II, LLC OV-1EX 12
NANANAMilford Wind Corridor Phase II, LLC OV-1AD 13
NANANANorthWestern Corporation 160EX 14
FERC FORM NO. 1 (ED. 12-90) Page 326.21
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
5,654,152 5,654,152 1
3,949,612 3,949,612 2
164,072 164,072 3
747 -18,664 -18,664 4
10,037 9,732 5
89,566 91,519 6
2,036 2,064 7
3,833 327,900 327,900 8
29,643 29,643 9
2,771 -191,630 -191,630 10
-8,777 -8,777 11
806 -140,406 -140,406 12
1,940 1,940 13
380 14
FERC FORM NO. 1 (ED. 12-90) Page 327.21
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
PacifiCorp X / /2019/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including 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. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NANANAPortland General Electric Company T-8EX 1
NANANAPublic Service Company of Colorado 334EX 2
NANANAPUD No. 1 of Cowlitz County 442EX 3
NANANASeattle City Light 554EX 4
NANANAWestern Area Power Administration LAS-4EX 5
NANANAWestern Area Power Administration LAS-4AD 6
NANANAImbalance Energy Accrual T-11EX 7
NANANAImbalance Energy Accrual T-11AD 8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 326.22
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (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. If more energy was delivered than received, enter a negative amount. If 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.
4,353 1
1,313,207 1,314,000 5,400,000 5,400,000 2
139,812 137,741 3
338,452 303,461 -2,055,198 -2,055,198 4
143,543 2,375 -567,750 -567,750 5
3,000 -100,733 -100,733 6
441,617 16,417,948 16,417,948 7
17,309 -772,844 -772,844 8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 327.22
12,097,791 7,707,795 6,826,841 30,533,911 855,648,190 -252,986,717 633,195,384
Schedule Page: 326 Line No.: 2 Column: b
Settlement adjustment.

Schedule Page: 326 Line No.: 2 Column: l
Settlement adjustment.

Schedule Page: 326 Line No.: 3 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.
Schedule Page: 326 Line No.: 4 Column: l
Liquidated damages.
Schedule Page: 326 Line No.: 6 Column: a
Complete name is Arizona Electric Power Cooperative, Inc.
Schedule Page: 326 Line No.: 7 Column: b
Settlement adjustment.
Schedule Page: 326 Line No.: 7 Column: l
Settlement adjustment.

Schedule Page: 326 Line No.: 8 Column: b
Arizona Public Service Company - contract termination date: October 31, 2020.
Schedule Page: 326 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 326 Line No.: 10 Column: l
Settlement adjustment.

Schedule Page: 326 Line No.: 11 Column: l
Reserve share.

Schedule Page: 326 Line No.: 12 Column: b
Settlement adjustment.

Schedule Page: 326 Line No.: 12 Column: l
Settlement adjustment.

Schedule Page: 326 Line No.: 13 Column: l
Reserve share.

Schedule Page: 326.1 Line No.: 1 Column: b
Litigation settlement adjustment.

Schedule Page: 326.1 Line No.: 1 Column: l
Litigation settlement adjustment.

Schedule Page: 326.1 Line No.: 4 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 326.1 Line No.: 6 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
Schedule Page: 326.1 Line No.: 10 Column: l
Non-generation agreement.

Schedule Page: 326.1 Line No.: 12 Column: a
PacifiCorp has an agreement with Citizens Asset Finance, Inc. to lease the Black Cap Solar
generating facility. The lease has a 16-year term from October 2012 to October 2028 and is
accounted for as an operating lease.
Schedule Page: 326.1 Line No.: 14 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.

Schedule Page: 326.2 Line No.: 2 Column: b
Settlement adjustment.

Schedule Page: 326.2 Line No.: 2 Column: l
Settlement adjustment.

Schedule Page: 326.2 Line No.: 3 Column: b
Bonneville Power Administration - contract termination date: Upon 30 days written notice.

Schedule Page: 326.2 Line No.: 3 Column: l
Ancillary services.

Schedule Page: 326.2 Line No.: 4 Column: l
Reserve share.

Schedule Page: 326.2 Line No.: 8 Column: b
Settlement adjustment.

Schedule Page: 326.2 Line No.: 8 Column: l
Settlement adjustment.

Schedule Page: 326.2 Line No.: 10 Column: b
Settlement adjustment.

Schedule Page: 326.2 Line No.: 10 Column: l
Settlement adjustment.

Schedule Page: 326.2 Line No.: 12 Column: a
Complete name is Brookfield Renewable Trading and Marketing LP.
Schedule Page: 326.3 Line No.: 2 Column: a
This footnote applies to all occurrences of "California Independent System Operator" on
pages 326-327. Complete name is California Independent System Operator Corporation.
Schedule Page: 326.3 Line No.: 5 Column: b
Settlement adjustment.

Schedule Page: 326.3 Line No.: 5 Column: l
Settlement adjustment.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 326.3 Line No.: 14 Column: b
City of Hurricane - contract termination date: August 31, 2022.

Schedule Page: 326.4 Line No.: 1 Column: l
Labor, equipment and administration fees associated with hydro project in Idaho Falls,
Idaho.

Schedule Page: 326.4 Line No.: 3 Column: a
Complete name is City of Portland, Portland Water Bureau.

Schedule Page: 326.4 Line No.: 14 Column: a
Complete name is Deseret Generation and Transmission Co-operative.
Schedule Page: 326.4 Line No.: 14 Column: b
Deseret Generation and Transmission Co-operative - contract termination date: September
30, 2024.

Schedule Page: 326.4 Line No.: 14 Column: l
Reimbursement to counterparty for operation and maintenance costs at coal fired generating
facility located in Vernal, Utah.

Schedule Page: 326.5 Line No.: 7 Column: b
Settlement adjustment.

Schedule Page: 326.5 Line No.: 7 Column: l
Settlement adjustment.

Schedule Page: 326.5 Line No.: 11 Column: b
Settlement adjustment.

Schedule Page: 326.5 Line No.: 11 Column: l
Settlement adjustment.

Schedule Page: 326.5 Line No.: 13 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.

Schedule Page: 326.5 Line No.: 14 Column: b
Settlement adjustment.

Schedule Page: 326.5 Line No.: 14 Column: l
Settlement adjustment.

Schedule Page: 326.6 Line No.: 2 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.

Schedule Page: 326.6 Line No.: 10 Column: b
Settlement adjustment.

Schedule Page: 326.6 Line No.: 10 Column: l
Settlement adjustment.

Schedule Page: 326.6 Line No.: 12 Column: a
Complete name is Fall River Rural Electric Cooperative, Inc.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 326.7 Line No.: 2 Column: b
Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.7 Line No.: 4 Column: b
Flathead Electric Cooperative, Inc. - contract termination date: September 30, 2021.

Schedule Page: 326.7 Line No.: 10 Column: b
Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.8 Line No.: 1 Column: l
Reserve share.

Schedule Page: 326.8 Line No.: 5 Column: a
Complete name is Hayward Paul Luckey and Joanne Luckey Revocable Trust of 2005.
Schedule Page: 326.8 Line No.: 6 Column: b
Secondary, economy, renewable attributes and/or non-firm.

Schedule Page: 326.8 Line No.: 7 Column: l
Reserve share.

Schedule Page: 326.9 Line No.: 2 Column: l
Fixed annual payment.

Schedule Page: 326.9 Line No.: 5 Column: a
This footnote applies to all occurrences of "Los Angeles Dept. of Water and Power" on
pages 326-327. Complete name is Los Angeles Department of Water and Power.

Schedule Page: 326.9 Line No.: 13 Column: l
Compensation for interruptible service and operating reserves.
Schedule Page: 326.9 Line No.: 14 Column: b
Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.10 Line No.: 2 Column: b
Settlement adjustment.

Schedule Page: 326.10 Line No.: 2 Column: l
Settlement adjustment.

Schedule Page: 326.10 Line No.: 5 Column: a
Complete name is Myron Jones, Nola Jones, Larry Oja and Christie Oja.
Schedule Page: 326.10 Line No.: 6 Column: b
Settlement adjustment.

Schedule Page: 326.10 Line No.: 6 Column: l
Reserve share.

Schedule Page: 326.10 Line No.: 7 Column: a
Nevada Power Company is a wholly owned subsidiary of NV Energy, Inc., which is an indirect
wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
company.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 326.10 Line No.: 10 Column: l
Reserve share.

Schedule Page: 326.11 Line No.: 1 Column: b
Settlement adjustment.

Schedule Page: 326.11 Line No.: 1 Column: l
Settlement adjustment.

Schedule Page: 326.11 Line No.: 2 Column: b
Nucor Corporation - contract termination date: December 31, 2019.
Schedule Page: 326.11 Line No.: 2 Column: l
Ancillary services.

Schedule Page: 326.11 Line No.: 4 Column: b
Settlement adjustment.

Schedule Page: 326.11 Line No.: 4 Column: l
Settlement adjustment.

Schedule Page: 326.11 Line No.: 13 Column: b
Settlement adjustment.

Schedule Page: 326.11 Line No.: 13 Column: l
Settlement adjustment.

Schedule Page: 326.12 Line No.: 4 Column: l
Purchase of renewable energy credit certificates for renewable portfolio standard
requirements.

Schedule Page: 326.12 Line No.: 9 Column: b
Portland General Electric Company - contract termination date: When the Round Butte
project no longer operates for power production purposes.

Schedule Page: 326.12 Line No.: 9 Column: l
Operation expense plus amortization of unrecovered costs of Cove Project.

Schedule Page: 326.12 Line No.: 10 Column: b
Settlement adjustment.

Schedule Page: 326.12 Line No.: 10 Column: l
Settlement adjustment.

Schedule Page: 326.12 Line No.: 11 Column: l
Reserve share.

Schedule Page: 326.13 Line No.: 1 Column: b
Under Electric Service Agreement subject to termination upon timely notification.

Schedule Page: 326.13 Line No.: 2 Column: l
Reserve share.

Schedule Page: 326.13 Line No.: 3 Column: b
Settlement adjustment.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5

Schedule Page: 326.13 Line No.: 3 Column: l
Settlement adjustment.

Schedule Page: 326.13 Line No.: 5 Column: b
Settlement adjustment.

Schedule Page: 326.13 Line No.: 5 Column: l
Settlement adjustment.

Schedule Page: 326.13 Line No.: 6 Column: a
Complete name is Public Utility District No. 1 of Chelan County.
Schedule Page: 326.13 Line No.: 6 Column: l
Reserve share.

Schedule Page: 326.13 Line No.: 7 Column: a
Complete name is Public Utility District No. 1 of Douglas County.

Schedule Page: 326.13 Line No.: 7 Column: l
Reserve share.

Schedule Page: 326.13 Line No.: 8 Column: a
Complete name is Public Utility District No. 1 of Snohomish County.
Schedule Page: 326.13 Line No.: 9 Column: a
This footnote applies to all occurrences of "PUD No. 2 of Grant County" on pages 326-327.
Complete name is Public Utility District No. 2 of Grant County.
Schedule Page: 326.13 Line No.: 9 Column: l
Operating expense, bond interest, amortization and taxes.

Schedule Page: 326.13 Line No.: 10 Column: b
Settlement adjustment.

Schedule Page: 326.13 Line No.: 10 Column: l
Settlement adjustment.

Schedule Page: 326.13 Line No.: 11 Column: l
Reserve share.

Schedule Page: 326.13 Line No.: 12 Column: l
Reserve share.

Schedule Page: 326.14 Line No.: 11 Column: b
Settlement adjustment.

Schedule Page: 326.14 Line No.: 11 Column: l
Settlement adjustment.

Schedule Page: 326.14 Line No.: 14 Column: l
Reserve share.

Schedule Page: 326.15 Line No.: 2 Column: b
Settlement adjustment.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6

Schedule Page: 326.15 Line No.: 2 Column: l
Settlement adjustment.

Schedule Page: 326.15 Line No.: 5 Column: a
Sierra Pacific Power Company is a wholly owned subsidiary of NV Energy, Inc., which is an
indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's
indirect parent company.
Schedule Page: 326.15 Line No.: 5 Column: l
Reserve share.

Schedule Page: 326.16 Line No.: 5 Column: b
Settlement adjustment.

Schedule Page: 326.16 Line No.: 5 Column: l
Settlement adjustment.

Schedule Page: 326.16 Line No.: 9 Column: b
Settlement adjustment.

Schedule Page: 326.16 Line No.: 9 Column: l
Settlement adjustment.

Schedule Page: 326.16 Line No.: 10 Column: l
Reserve share.

Schedule Page: 326.16 Line No.: 13 Column: a
Complete name is Tesoro Refining & Marketing Company LLC.
Schedule Page: 326.17 Line No.: 8 Column: l
Non-generation agreement.

Schedule Page: 326.17 Line No.: 11 Column: a
This footnote applies to all occurrences of "Tri-State Generation and Transmission" on
pages 326-327. Complete name is Tri-State Generation and Transmission Association, Inc.
Schedule Page: 326.17 Line No.: 11 Column: b
Tri-State Generation and Transmission Association, Inc. - contract termination date:
December 31, 2020.

Schedule Page: 326.18 Line No.: 2 Column: a
Complete name is U.S. Department of the Interior - Bureau of Land Management.
Schedule Page: 326.18 Line No.: 5 Column: b
US Magnesium LLC - contract termination date: December 31, 2019.

Schedule Page: 326.18 Line No.: 5 Column: l
Ancillary services.

Schedule Page: 326.18 Line No.: 6 Column: b
Utah Associated Municipal Power System - contract termination date: March 31, 2022.

Schedule Page: 326.18 Line No.: 11 Column: b
Settlement adjustment.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7

Schedule Page: 326.18 Line No.: 11 Column: l
Settlement adjustment.

Schedule Page: 326.19 Line No.: 2 Column: b
Settlement adjustment.

Schedule Page: 326.19 Line No.: 2 Column: l
Settlement adjustment.

Schedule Page: 326.19 Line No.: 4 Column: b
Western Area Power Administration - contract termination date: May 31, 2022.

Schedule Page: 326.19 Line No.: 5 Column: l
Reserve share.

Schedule Page: 326.19 Line No.: 6 Column: b
Settlement adjustment.

Schedule Page: 326.19 Line No.: 6 Column: l
Settlement adjustment.

Schedule Page: 326.19 Line No.: 8 Column: b
Settlement adjustment.

Schedule Page: 326.19 Line No.: 8 Column: l
Settlement adjustment.

Schedule Page: 326.19 Line No.: 11 Column: a
Complete name is Utah Sustainable Transportation and Energy Plan, Gadsby plant
curtailment.
Schedule Page: 326.19 Line No.: 12 Column: l
Purchases of greenhouse gas allowances for compliance with the California Air Resources
Board greenhouse gas cap-and-trade program.

Schedule Page: 326.19 Line No.: 13 Column: l
Deferrals and associated amortization under various energy cost adjustment mechanisms.

Schedule Page: 326.19 Line No.: 14 Column: l
Reflects transactions that did not physically settle.

Schedule Page: 326.20 Line No.: 1 Column: l
Reflects transactions that were categorized as trading activities.
Schedule Page: 326.20 Line No.: 2 Column: g
Adjustment for inadvertent intercharge.

Schedule Page: 326.20 Line No.: 3 Column: l
Represents the difference between actual purchase expenses for the period as reflected on
the individual line items within this schedule and the accruals charged to Account 555,
Purchased power, during this period.

Schedule Page: 326.20 Line No.: 6 Column: l
Exchange energy charge/(credit).
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8

Schedule Page: 326.20 Line No.: 8 Column: l
Storage and exchange charges.
Schedule Page: 326.20 Line No.: 9 Column: b
Settlement adjustment.

Schedule Page: 326.20 Line No.: 9 Column: l
Settlement adjustment.

Schedule Page: 326.20 Line No.: 11 Column: l
Storage and exchange charges.

Schedule Page: 326.20 Line No.: 12 Column: b
Settlement adjustment.

Schedule Page: 326.20 Line No.: 12 Column: l
Settlement adjustment.

Schedule Page: 326.20 Line No.: 13 Column: l
Energy Imbalance Market ("EIM") participating resource settlements in EIM.

Schedule Page: 326.20 Line No.: 14 Column: b
Settlement adjustment.

Schedule Page: 326.20 Line No.: 14 Column: l
Settlement adjustment.
Schedule Page: 326.21 Line No.: 1 Column: l
Energy Imbalance Market ("EIM") entity settlements in EIM.

Schedule Page: 326.21 Line No.: 2 Column: b
Settlement adjustment.

Schedule Page: 326.21 Line No.: 2 Column: l
Settlement adjustment.

Schedule Page: 326.21 Line No.: 3 Column: b
Settlement adjustment.

Schedule Page: 326.21 Line No.: 3 Column: l
Imbalance energy.

Schedule Page: 326.21 Line No.: 4 Column: l
Exchange energy charge/(credit).

Schedule Page: 326.21 Line No.: 8 Column: l
Station service for third-party wind project.
Schedule Page: 326.21 Line No.: 9 Column: b
Settlement adjustment.

Schedule Page: 326.21 Line No.: 9 Column: l
Settlement adjustment.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
Schedule Page: 326.21 Line No.: 10 Column: l
Reimbursement for providing station service to third-party wind project.

Schedule Page: 326.21 Line No.: 11 Column: b
Settlement adjustment.

Schedule Page: 326.21 Line No.: 11 Column: l
Settlement adjustment.

Schedule Page: 326.21 Line No.: 12 Column: l
Reimbursement for providing station service to third-party wind project.

Schedule Page: 326.21 Line No.: 13 Column: b
Settlement adjustment.

Schedule Page: 326.21 Line No.: 13 Column: l
Settlement adjustment.

Schedule Page: 326.22 Line No.: 2 Column: l
Exchange energy charge/(credit).

Schedule Page: 326.22 Line No.: 3 Column: a
Complete name is Public Utility District No. 1 of Cowlitz County.
Schedule Page: 326.22 Line No.: 4 Column: l
Exchange energy charge/(credit).
Schedule Page: 326.22 Line No.: 5 Column: l
Imbalance energy settlements between PacifiCorp, the transmission provider and third party
transmission customers.

Schedule Page: 326.22 Line No.: 6 Column: b
Settlement adjustment.

Schedule Page: 326.22 Line No.: 6 Column: l
Settlement adjustment.

Schedule Page: 326.22 Line No.: 7 Column: l
Imbalance energy settlements between PacifiCorp, the transmission provider and third party
transmission customers.

Schedule Page: 326.22 Line No.: 8 Column: b
Settlement adjustment.

Schedule Page: 326.22 Line No.: 8 Column: l
Settlement adjustment.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX / /2019/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
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. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
3 Phase Renewables, LLC Bonneville Power Administration Oregon Direct Access FNO 1
3 Phase Renewables, LLC Bonneville Power Administration Oregon Direct Access AD 2
Arizona Public Service Company Arizona Public Service Company various signatories OS 3
Arizona Public Service Company Arizona Public Service Company various signatories NF 4
Avangrid Renewables, LLC various signatories various signatories NF 5
Avangrid Renewables, LLC various signatories various signatories AD 6
Avangrid Renewables, LLC various signatories various signatories SFP 7
Avangrid Renewables, LLC various signatories various signatories AD 8
Avangrid Renewables, LLC Avangrid Renewables, LLC various signatories OS 9
Avangrid Renewables, LLC Avangrid Renewables, LLC various signatories AD 10
Avangrid Renewables, LLC Exxon Mobil Nevada Power Company LFP 11
Avangrid Renewables, LLC Exxon Mobil Nevada Power Company AD 12
Avangrid Renewables, LLC Bonneville Power Administration Oregon Direct Access FNO 13
Avangrid Renewables, LLC Avangrid Renewables, LLC various signatories AD 14
Avista Corporation various signatories various signatories NF 15
Basin Electric Power Cooperative, Inc. Western Area Power Administration Powder River Energy Corporation FNO 16
Basin Electric Power Cooperative, Inc. Western Area Power Administration Powder River Energy Corporation AD 17
Basin Electric Power Cooperative, Inc. Western Area Power Administration Powder River Energy Corporation NF 18
Basin Electric Power Cooperative, Inc. Western Area Power Administration Powder River Energy Corporation AD 19
Basin Electric Power Cooperative, Inc. Western Area Power Administration Powder River Energy Corporation SFP 20
Basin Electric Power Cooperative, Inc. Western Area Power Administration Powder River Energy Corporation AD 21
Black Hills/Colorado Electric Utility Company various signatories various signatories NF 22
Black Hills/Colorado Electric Utility Company various signatories various signatories SFP 23
Black Hills Corporation PacifiCorp Montana-Dakota Utilities FNO 24
Black Hills Corporation PacifiCorp Montana-Dakota Utilities AD 25
Black Hills Corporation PacifiCorp Black Hills Corporation LFP 26
Black Hills Corporation PacifiCorp Black Hills Corporation AD 27
Black Hills Corporation various signatories various signatories NF 28
Black Hills Corporation various signatories various signatories AD 29
Black Hills Corporation various signatories various signatories SFP 30
Black Hills Corporation various signatories various signatories AD 31
Black Hills Power Marketing various signatories various signatories NF 32
Black Hills Power Marketing various signatories various signatories AD 33
Black Hills Power Marketing various signatories various signatories SFP 34
FERC FORM NO. 1 (ED. 12-90) Page 328
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2019/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
Bonneville Power AdmSA 876 Various 1 577 577 1
Bonneville Power AdmSA 876 Various 8 8 2
RS 436 Borah/Brady Sub 3
VariousSA 42 Various 672 672 4
VariousSA 121 Various 206,799 206,799 5
VariousSA 121 Various 16,603 16,603 6
VariousSA 122 Various 67,324 67,324 7
VariousSA 122 Various 3,218 3,218 8
SA 476 9
SA 476 10
Trona SubstationSA 895 Red Butte/Mona Sub 31 64,410 64,410 11
Trona SubstationSA 895 Red Butte/Mona Sub 6,407 6,407 12
Ponderosa SubstationSA 742 Various 32 251,535 251,535 13
Ponderosa SubstationSA 742 Various 31 22,862 22,862 14
VariousSA 886 Various 2,621 2,621 15
Yellowtail SubSA 505 Sheridan Substation 10 71,013 71,013 16
Yellowtail SubSA 505 Sheridan Substation 10 6,938 6,938 17
VariousSA 607 Various 46,761 46,761 18
VariousSA 607 Various 30,053 30,053 19
VariousSA 606 Various 13,835 13,835 20
VariousSA 606 Various 21
VariousSA 563 Various 692 692 22
VariousSA 562 Various 60 60 23
VariousSA 347 Sheridan Substation 47 269,606 269,606 24
VariousSA 347 Sheridan Substation 47 28,460 28,460 25
VariousSA 67 Wyodak Substation 52 118,362 118,362 26
VariousSA 67 Wyodak Substation 52 27
VariousSA 768 Various 13,782 13,782 28
VariousSA 768 Various 29
VariousSA 767 Various 5,460 5,460 30
VariousSA 767 Various 31
VariousSA 43 Various 1,969 1,969 32
VariousSA 43 Various 33
VariousSA 714 Various 192 192 34
FERC FORM NO. 1 (ED. 12-90) Page 329
5,281 15,241,847 15,129,193
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
2,540 3,013 473 1
339 339 2
3
2,739 107 2,632 4
2,264,523 385,320 1,879,203 5
185,594 185,594 6
757,146 29,344 727,802 7
44,259 44,259 8
210,063 210,063 9
20,437 20,437 10
845,473 968,631 123,158 11
56,764 56,764 12
877,348 1,205,974 328,626 13
834,762 834,762 14
21,511 838 20,673 15
308,436 361,646 53,210 16
18,071 18,071 17
360,941 14,146 346,795 18
215,937 215,937 19
96,773 3,752 93,021 20
2,038 2,038 21
4,124 162 3,962 22
598 23 575 23
1,374,745 1,430,367 55,622 24
84,767 84,767 25
1,551,588 1,614,385 62,797 26
94,606 94,606 27
64,315 2,523 61,792 28
24,345 24,345 29
43,362 1,684 41,678 30
659 659 31
13,435 523 12,912 32
108 108 33
1,595 62 1,533 34
FERC FORM NO. 1 (ED. 12-90) Page 330
71,429,114 111,912,996 23,992,613 16,491,269
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX / /2019/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
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. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Black Hills Power Marketing various signatories various signatories AD 1
Bonneville Power Administration OS 2
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 3
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 4
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration LFP 5
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 6
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative FNO 7
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative AD 8
Bonneville Power Administration Bonneville Power Administration Benton REA FNO 9
Bonneville Power Administration Bonneville Power Administration Benton REA AD 10
Bonneville Power Administration Bonneville Power Administration Umatilla Electric and Columbia FNO 11
Bonneville Power Administration Bonneville Power Administration Umatilla Electric and Columbia AD 12
Bonneville Power Administration U.S. Bureau of Reclamation Bonneville Power Administration LFP 13
Bonneville Power Administration U.S. Bureau of Reclamation Bonneville Power Administration AD 14
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 15
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 16
Bonneville Power Administration Bonneville Power Administration Yakama Power FNO 17
Bonneville Power Administration Bonneville Power Administration Yakama Power AD 18
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO 19
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 20
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO 21
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 22
Bonneville Power Administration various signatories various signatories NF 23
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration AD 24
Bonneville Power Administration various signatories various signatories FNO 25
Bonneville Power Administration various signatories various signatories AD 26
Bonneville Power Administration Bonneville Power Administration PUD No. 1 of Clark County FNO 27
Bonneville Power Administration Bonneville Power Administration PUD No. 1 of Clark County AD 28
Brookfield Energy Marketing, Inc. various signatories various signatories NF 29
Calpine Energy Solutions, LLC Bonneville Power Administration Oregon Direct Access FNO 30
Calpine Energy Solutions, LLC Bonneville Power Administration Oregon Direct Access AD 31
City of Roseville City of Roseville City of Roseville LFP 32
City of Roseville City of Roseville City of Roseville AD 33
Clatskanie People's Utility District Clatskanie People's Utility Dist Clatskanie People's Utility Dist LFP 34
FERC FORM NO. 1 (ED. 12-90) Page 328.1
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2019/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
VariousSA 714 Various 1
Midpoint SubstationRS 369 Summer Lake Sub 2
VariousRS 237 Various 352 1,048,115 1,048,115 3
VariousRS 237 Various 300 101,667 101,667 4
Lost Creek Hydro PltSA 656 Alvey Substation 58 253,190 253,190 5
Lost Creek Hydro PltSA 656 Alvey Substation 58 14,017 14,017 6
Bonneville Power AdmSA 229 Gazley Substation 3 24,203 24,203 7
Bonneville Power AdmSA 229 Gazley Substation 3 2,435 2,435 8
Bonneville Power AdmSA 539 Tieton Substation 1 5,498 5,498 9
Bonneville Power AdmSA 539 Tieton Substation 1 853 853 10
McNary SubstationSA 538 Hinkle Substation 1 956 956 11
McNary SubstationSA 538 Hinkle Substation 1 118 118 12
USBR Green SpringsSA 179 Bonneville Power Adm 19 52,611 52,611 13
USBR Green SpringsSA 179 Bonneville Power Adm 3,391 3,391 14
Malin SubstationRS 368 Malin Substation 516,151 516,151 15
Malin SubstationRS 368 Malin Substation 24,118 24,118 16
Bonneville Power AdmSA 328 6 37,147 37,147 17
Bonneville Power AdmSA 328 5 3,533 3,533 18
Bonneville Power AdmSA 827 Neff Substation 2 709 709 19
Bonneville Power AdmSA 827 Neff Substation 93 93 20
Goshen SubstationSA 746 Various 216 1,321,976 1,321,976 21
Goshen SubstationSA 746 Various 276 170,911 170,911 22
VariousSA 44 Various 172,143 172,143 23
VariousSA 44 Various 24
Goshen SubstationSA 747 Various 89 612,581 612,581 25
Goshen SubstationSA 747 Various 82 52,811 52,811 26
Cardwell-MerwinSA 735 21 115,463 115,463 27
Cardwell-MerwinSA 735 27 14,769 14,769 28
VariousSA 757 Various 52,775 52,775 29
Bonneville Power AdmSA 299 Various 16 108,967 108,967 30
Bonneville Power AdmSA 299 Various 17 11,537 11,537 31
Malin 500 SubstationSA 881 Round Mountain Sub 52 32
Malin 500 SubstationSA 881 Round Mountain Sub 52 33
Troutdale SubstationSA 899 Troutdale Substation 19 98,402 98,402 34
FERC FORM NO. 1 (ED. 12-90) Page 329.1
5,281 15,241,847 15,129,193
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
528 528 1
2
3,985,821 4,053,768 67,947 3
376,999 376,999 4
1,737,779 1,751,364 13,585 5
101,367 101,367 6
100,603 257,511 156,908 7
20,385 20,385 8
23,926 27,749 3,823 9
4,539 4,539 10
3,401 4,001 600 11
-2,085 -2,085 12
558,572 564,261 5,689 13
32,925 32,925 14
232,452 232,452 15
21,132 21,132 16
169,407 293,302 123,895 17
29,220 29,220 18
1,389 1,729 340 19
388 388 20
6,424,187 7,949,451 1,525,264 21
694,384 694,384 22
1,212,350 47,112 1,165,238 23
67 67 24
2,862,327 3,355,362 493,035 25
204,559 204,559 26
623,286 714,359 91,073 27
59,372 59,372 28
277,876 10,705 267,171 29
455,266 615,575 160,309 30
661,418 661,418 31
1,485,485 1,520,398 34,913 32
126,970 126,970 33
541,479 563,402 21,923 34
FERC FORM NO. 1 (ED. 12-90) Page 330.1
71,429,114 111,912,996 23,992,613 16,491,269
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX / /2019/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
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. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Clatskanie People's Utility District Clatskanie People's Utility Dist Clatskanie People's Utility Dist AD 1
Deseret Gen and Trans Deseret Gen and Trans Deseret Gen and Trans OS 2
Deseret Gen and Trans Deseret Gen and Trans Deseret Gen and Trans AD 3
Deseret Gen and Trans various signatories various signatories NF 4
Deseret Gen and Trans various signatories various signatories AD 5
Eagle Energy Partners I LP various signatories various signatories NF 6
Energy Keepers, Inc. various signatories various signatories NF 7
Eugene Water & Electric Board NextEra Energy Resources, LLC various signatories LFP 8
Eugene Water & Electric Board NextEra Energy Resources, LLC PUD No. 2 of Grant County AD 9
Eugene Water & Electric Board various signatories various signatories NF 10
Evergreen Biopower LLC NextEra Energy Resources, LLC various signatories LFP 11
Evergreen Biopower LLC NextEra Energy Resources, LLC PUD No. 2 of Grant County AD 12
Exelon Generation Company, LLC Bonneville Power Administration Oregon Direct Access FNO 13
Exelon Generation Company, LLC Bonneville Power Administration Oregon Direct Access AD 14
Exelon Generation Company, LLC various signatories various signatories NF 15
Exelon Generation Company, LLC various signatories various signatories AD 16
Exelon Generation Company, LLC various signatories various signatories SFP 17
Fall River Rural Electric Cooperative, Inc. Marysville Hydro Partners Idaho Power Company OS 18
Fall River Rural Electric Cooperative, Inc. Marysville Hydro Partners Idaho Power Company AD 19
Foote Creek III, LLC Foote Creek III, LLC PacifiCorp OS 20
Foote Creek III, LLC Foote Creek III, LLC PacifiCorp AD 21
Idaho Power Company Exxon Mobil Nevada Power Company LFP 22
Idaho Power Company Exxon Mobil Nevada Power Company AD 23
Idaho Power Company various signatories various signatories NF 24
Idaho Power Company various signatories various signatories SFP 25
Idaho Power Company various signatories various signatories AD 26
Los Angeles Department of Water & Power various signatories various signatories NF 27
Los Angeles Department of Water & Power various signatories various signatories SFP 28
Macquarie Energy LLC various signatories various signatories NF 29
Macquarie Energy LLC various signatories various signatories AD 30
Macquarie Energy LLC various signatories various signatories SFP 31
MAG Energy Solutions, Inc. various signatories various signatories NF 32
MAG Energy Solutions, Inc. various signatories various signatories AD 33
Moon Lake Electric Association Inc. Moon Lake Electric Association Moon Lake Electric Association OS 34
FERC FORM NO. 1 (ED. 12-90) Page 328.2
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2019/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
Troutdale SubstationSA 899 Troutdale Substation 19 8,535 8,535 1
VariousRS 280 Various 96 859,615 859,615 2
VariousRS 280 Various 75 73,850 73,850 3
VariousSA 156 Various 3,800 3,800 4
VariousSA 156 Various 636 636 5
VariousSA 569 Various 1,692 1,692 6
VariousSA 815 Various 70 70 7
VariousSA 780 Various 8
VariousSA 780 Various 9
VariousSA 13 Various 10
VariousSA 874 Various 53,538 53,538 11
VariousSA 874 Various 4,903 4,903 12
Bonneville Power AdmSA 847 Various 1 5,552 5,552 13
Bonneville Power AdmSA 847 Various 1 578 578 14
VariousSA 759 Various 16,524 16,524 15
VariousSA 759 Various 760 760 16
VariousSA 760 Various 17
Targhee SubstationRS 322 Goshen Substation 18
Targhee SubstationRS 322 Goshen Substation 19
Foote Creek SubSA 761 Various 20
Foote Creek SubSA 761 Various 21
Trona SubstationSA 212 Red Butte/Mona Sub 78 8,778 8,778 22
Trona SubstationSA 212 Red Butte/Mona Sub 23
Antelope SubstationSA 725 Various 3 3 24
VariousSA 726 Various 1,647 1,647 25
VariousSA 726 Various 26
VariousSA 142 Various 206,295 206,295 27
VariousSA 143 Various 5,020 5,020 28
VariousSA 755 Various 25,273 25,273 29
VariousSA 755 Various 4,061 4,061 30
VariousSA 754 Various 191 191 31
VariousSA 903 Various 13,323 13,323 32
VariousSA 903 Various 1,004 1,004 33
DuchesneRS 302 Duchesne 18,568 18,568 34
FERC FORM NO. 1 (ED. 12-90) Page 329.2
5,281 15,241,847 15,129,193
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
9,136 9,136 1
3,406,634 5,103,403 1,696,769 2
471,601 471,601 3
37,015 1,425 35,590 4
4,836 4,836 5
20,282 782 19,500 6
598 23 575 7
72,538 72,538 8
47,304 47,304 9
8 8 10
310,318 355,181 44,863 11
28,496 28,496 12
20,972 26,123 5,151 13
14,366 14,366 14
1,766,085 1,683,703 82,382 15
138,106 138,106 16
4,104 161 3,943 17
138,699 138,699 18
12,609 12,609 19
37,629 37,629 20
8,881 8,881 21
712,333 740,846 28,513 22
-20,654 -20,654 23
128,494 4,925 123,569 24
16,026 630 15,396 25
3,660 3,660 26
1,196,350 47,070 1,149,280 27
42,059 1,657 40,402 28
215,299 8,371 206,928 29
34,674 34,674 30
1,810 69 1,741 31
103,782 4,084 99,698 32
8,134 8,134 33
17,655 17,655 34
FERC FORM NO. 1 (ED. 12-90) Page 330.2
71,429,114 111,912,996 23,992,613 16,491,269
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX / /2019/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
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. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Moon Lake Electric Association Inc. Moon Lake Electric Association Moon Lake Electric Association AD 1
Morgan Stanley Capital Group, Inc. various signatories various signatories NF 2
Morgan Stanley Capital Group, Inc. various signatories various signatories AD 3
Morgan Stanley Capital Group, Inc. various signatories various signatories SFP 4
Municipal Energy Agency of Nebraska various signatories various signatories AD 5
Municipal Energy Agency of Nebraska various signatories various signatories AD 6
Navajo Tribal Utility Authority Navajo Tribal Utility Authority Navajo Tribal Utility Authority FNO 7
Navajo Tribal Utility Authority Navajo Tribal Utility Authority Navajo Tribal Utility Authority AD 8
Nevada Power Company various signatories various signatories NF 9
Nevada Power Company various signatories various signatories SFP 10
NextEra Energy Resources, LLC NextEra Energy Resources, LLC PUD No. 2 of Grant County LFP 11
NextEra Energy Resources, LLC NextEra Energy Resources, LLC PUD No. 2 of Grant County AD 12
NextEra Energy Resources, LLC various signatories various signatories NF 13
NextEra Energy Resources, LLC various signatories various signatories AD 14
Obsidian Renewables Lakeview Airport 10 Portland General Electric LFP 15
Pacific Gas & Electric Company OS 16
Pacific Gas & Electric Company various signatories various signatories NF 17
Portland General Electric Company OS 18
Portland General Electric Company various signatories various signatories NF 19
Portland General Electric Company various signatories various signatories AD 20
Portland General Electric Company various signatories various signatories SFP 21
Powerex Corporation Bonneville Power Administration CAISO LFP 22
Powerex Corporation Bonneville Power Administration CAISO AD 23
Powerex Corporation Powerex Corporation CAISO LFP 24
Powerex Corporation Powerex Corporation CAISO AD 25
Powerex Corporation Powerex Corporation CAISO LFP 26
Powerex Corporation Powerex Corporation CAISO AD 27
Powerex Corporation Powerex Corporation CAISO LFP 28
Powerex Corporation Powerex Corporation CAISO AD 29
Powerex Corporation Powerex Corporation CAISO LFP 30
Powerex Corporation Powerex Corporation CAISO AD 31
Powerex Corporation Powerex Corporation CAISO LFP 32
Powerex Corporation Powerex Corporation CAISO AD 33
Powerex Corporation various signatories various signatories NF 34
FERC FORM NO. 1 (ED. 12-90) Page 328.3
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2019/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
DuchesneRS 302 Duchesne 1,515 1,515 1
VariousSA 157 Various 316,878 316,878 2
VariousSA 157 Various 15,757 15,757 3
VariousSA 160 Various 6,321 6,321 4
VariousSA 307 Various 120 120 5
VariousSA 308 Various 6
Four CornersSA 894 Pinto-Four Corners 1 14,941 14,941 7
Four CornersSA 894 Pinto-Four Corners 1 1,639 1,639 8
VariousSA 455 Various 16,311 16,311 9
VariousSA 454 Various 34,179 34,179 10
Wallula SubstationSA 733 Wala-MIDC path 103 53,577 53,577 11
Wallula SubstationSA 733 Wala-MIDC path 103 14,226 14,226 12
VariousSA 236 Various 1,497 1,497 13
VariousSA 236 Various 59 59 14
VariousSA 880 Various 10 15
Sigurd-Glen CanyonRS 298 Pinto-Four Corners 16
VariousSA 338 Various 1,170 1,170 17
VariousRS 137 Various 18
VariousSA 8 Various 1,390 1,390 19
VariousSA 8 Various 7 7 20
VariousSA 8 Various 76,320 76,320 21
Bonneville Power AdmSA 169 CRAG View Substation 83 321,300 321,300 22
Bonneville Power AdmSA 169 CRAG View Substation 83 15,679 15,679 23
Malin 500 SubstationSA 700 Round Mountain Sub 67 24
Malin 500 SubstationSA 700 Round Mountain Sub 67 25
Malin 500 SubstationSA 701 Round Mountain Sub 67 26
Malin 500 SubstationSA 701 Round Mountain Sub 67 27
Malin 500 SubstationSA 702 Round Mountain Sub 66 28
Malin 500 SubstationSA 702 Round Mountain Sub 66 29
Malin 500 SubstationSA 748 Round Mountain Sub 50 30
Malin 500 SubstationSA 748 Round Mountain Sub 50 31
Malin 500 SubstationSA 749 Round Mountain Sub 150 32
Malin 500 SubstationSA 749 Round Mountain Sub 50 33
VariousSA 47 Various 174,881 174,881 34
FERC FORM NO. 1 (ED. 12-90) Page 329.3
5,281 15,241,847 15,129,193
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
1,605 1,605 1
2,377,580 92,694 2,284,886 2
235,674 235,674 3
43,442 1,695 41,747 4
8 8 5
1,004 1,004 6
67,179 78,811 11,632 7
6,102 6,102 8
2,095 443 1,652 9
207,102 7,967 199,135 10
2,095,338 2,943,886 848,548 11
224,588 224,588 12
183,651 7,106 176,545 13
28,943 28,943 14
28,493 29,634 1,141 15
135,015 135,015 16
11,084 429 10,655 17
3,314 3,314 18
8,546 326 8,220 19
253 253 20
300,862 11,855 289,007 21
2,482,542 2,583,018 100,476 22
151,144 151,144 23
2,970,969 3,040,795 69,826 24
179,039 179,039 25
2,970,969 3,040,795 69,826 26
179,042 179,042 27
2,970,969 3,040,795 69,826 28
180,051 180,051 29
3,122,249 3,195,178 72,929 30
25,344 25,344 31
2,819,690 2,886,413 66,723 32
327,792 327,792 33
646,227 25,246 620,981 34
FERC FORM NO. 1 (ED. 12-90) Page 330.3
71,429,114 111,912,996 23,992,613 16,491,269
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX / /2019/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
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. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Powerex Corporation various signatories various signatories AD 1
Powerex Corporation various signatories various signatories SFP 2
Powerex Corporation various signatories various signatories AD 3
PUD No. 1 of Cowlitz County PUD No. 1 of Cowlitz County Bonneville Power Administration OS 4
PUD No. 1 of Cowlitz County PUD No. 1 of Cowlitz County Bonneville Power Administration AD 5
Rainbow Energy Marketing Corporation various signatories various signatories NF 6
Rainbow Energy Marketing Corporation various signatories various signatories AD 7
Rainbow Energy Marketing Corporation various signatories various signatories SFP 8
Sacramento Municipal Utility District Sacramento Municipal Utility Dist Sacramento Municipal Utility Dist LFP 9
Sacramento Municipal Utility District Sacramento Municipal Utility Dist Sacramento Municipal Utility Dist AD 10
Salt River Project Salt River Project Salt River Project LFP 11
Salt River Project Salt River Project Salt River Project AD 12
Salt River Project various signatories various signatories NF 13
Salt River Project various signatories various signatories SFP 14
Shell Energy North America (US), L.P. NextEra Energy Resources, LLC PUD No. 2 of Grant County LFP 15
Shell Energy North America (US), L.P. various signatories various signatories NF 16
Shell Energy North America (US), L.P. various signatories various signatories AD 17
Shell Energy North America (US), L.P. various signatories various signatories SFP 18
Shell Energy North America (US), L.P. various signatories various signatories AD 19
Sierra Pacific Power Company OS 20
Sierra Pacific Power Company AD 21
Southern California Edison Company OS 22
Southern California Edison Company various signatories various signatories NF 23
Southern California Edison Company various signatories various signatories AD 24
Southern California Public Power Powerex Corporation Southern California Public Power NF 25
State of South Dakota Western Area Power Administration Black Hills Corporation LFP 26
State of South Dakota Western Area Power Administration Black Hills Corporation AD 27
Tenaska Power Services Co. various signatories various signatories NF 28
Tenaska Power Services Co. various signatories various signatories AD 29
Tenaska Power Services Co. various signatories various signatories SFP 30
Tenaska Power Services Co. various signatories various signatories AD 31
The Energy Authority, Inc. various signatories various signatories NF 32
The Energy Authority, Inc. various signatories various signatories AD 33
Thermo No. 1 BE-01, LLC Thermo Geothermal Project various signatories LFP 34
FERC FORM NO. 1 (ED. 12-90) Page 328.4
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2019/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
VariousSA 47 Various 11,722 11,722 1
VariousSA 151 Various 5,003 5,003 2
VariousSA 151 Various 655 655 3
Swift Unit No. 2RS 234 Woodland Substation 4
Swift Unit No. 2RS 234 Woodland Substation 5
VariousSA 316 Various 7,448 7,448 6
VariousSA 316 Various 259 259 7
VariousSA 261 Various 8
Malin SubstationSA 863 Malin Substation 31 125,066 125,066 9
Malin SubstationSA 863 Malin Substation 31 12,560 12,560 10
Enel Cove FortSA 809 Red Butte Substation 26 141,357 141,357 11
Enel Cove FortSA 809 Red Butte Substation 26 15,408 15,408 12
VariousSA 557 Various 120 120 13
VariousSA 557 Various 510 510 14
Wallula SubstationSA 791 Wala-MIDC path 59,659 59,659 15
VariousSA 23 Various 390,545 390,545 16
VariousSA 23 Various 14,271 14,271 17
VariousSA 162 Various 25,237 25,237 18
VariousSA 162 Various 6,337 6,337 19
Sigurd SubstationRS 674 Utah-Nevada Border 20
Sigurd SubstationRS 674 Utah-Nevada Border 21
Sigurd-Glen CanyonRS 298 Pinto-Four Corners 22
VariousSA 642 Various 37,781 37,781 23
VariousSA 642 Various 51 51 24
Tieton SubstationSA 629 Various 38 38 25
Yellowtail SubSA 779 Wyodak Substation 4 19,220 19,220 26
Yellowtail SubSA 779 Wyodak Substation 4 1,675 1,675 27
VariousSA 125 Various 23,580 23,580 28
VariousSA 125 Various 70 70 29
VariousSA 126 Various 3,342 3,342 30
VariousSA 126 Various 31
VariousSA 310 Various 14,471 14,471 32
VariousSA 310 Various 300 300 33
South Milford SubSA 568 Mona Substation 11 59,638 59,638 34
FERC FORM NO. 1 (ED. 12-90) Page 329.4
5,281 15,241,847 15,129,193
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
30,231 30,231 1
1,194,592 46,252 1,148,340 2
378 378 3
123,059 123,059 4
15,346 15,346 5
50,151 1,959 48,192 6
9,162 9,162 7
15,936 628 15,308 8
589,619 613,482 23,863 9
32,318 32,318 10
775,809 807,207 31,398 11
47,304 47,304 12
1,260 49 1,211 13
4,146 162 3,984 14
1,133,537 1,311,197 177,660 15
1,887,025 138,141 1,748,884 16
85,567 85,567 17
293,662 11,517 282,145 18
1,334 1,334 19
33,147 33,147 20
3,013 3,013 21
135,015 135,015 22
3,355,216 904,697 2,450,519 23
295,919 295,919 24
32,287 32,287 25
124,127 129,152 5,025 26
7,568 7,568 27
352,143 125,131 227,012 28
9,085 9,085 29
25,331 976 24,355 30
280 280 31
110,533 4,268 106,265 32
2,511 2,511 33
341,364 391,312 49,948 34
FERC FORM NO. 1 (ED. 12-90) Page 330.4
71,429,114 111,912,996 23,992,613 16,491,269
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX / /2019/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
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. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Thermo No. 1 BE-01, LLC Thermo Geothermal Project various signatories AD 1
TransAlta Energy Marketing (U.S.) Inc. various signatories various signatories NF 2
TransAlta Energy Marketing (U.S.) Inc. various signatories various signatories AD 3
TransAlta Energy Marketing (U.S.) Inc. various signatories various signatories SFP 4
Tri-State Gen and Trans various signatories Tri-State Gen and Trans FNO 5
Tri-State Gen and Trans various signatories Tri-State Gen and Trans AD 6
Tri-State Gen and Trans various signatories various signatories NF 7
Tucson Power Company various signatories various signatories NF 8
U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation FNO 9
U.S. Bureau of Reclamation Bonneville Power Administration U.S. Bureau of Reclamation AD 10
U.S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.OS 11
U.S. Bureau of Reclamation Western Area Power Administration Weber Basin Water Conserv.AD 12
U.S. Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District OS 13
Utah Associated Municipal Power Utah Associated Municipal Power Utah Associated Municipal Power OS 14
Utah Associated Municipal Power Utah Associated Municipal Power Utah Associated Municipal Power AD 15
Utah Associated Municipal Power various signatories various signatories NF 16
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency OS 17
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency AD 18
Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric OS 19
Warm Springs Power Enterprises Warm Springs Power Enterprises Portland General Electric AD 20
Westar Energy, Inc. various signatories various signatories NF 21
Westar Energy, Inc. various signatories various signatories AD 22
Western Area Power Administration Western Area Power Administration OS 23
Western Area Power Administration Western Area Power Administration AD 24
Western Area Power Administration Western Area Power Administration OS 25
Western Area Power Administration Western Area Power Administration AD 26
Western Area Power Administration Western Area Power Administration various signatories OS 27
Western Area Power Administration Western Area Power Administration Western Area Power Administration FNO 28
Western Area Power Administration Western Area Power Adm CO River Western Area Power Administration AD 29
Western Area Power Adm CO River Western Area Power Adm CO River various signatories NF 30
Western Area Power Adm CO MO Western Area Power Adm CO River various signatories NF 31
Western Area Power Adm CO MO Western Area Power Adm CO River various signatories AD 32
Accrual 33
34
FERC FORM NO. 1 (ED. 12-90) Page 328.5
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
PacifiCorp X / /2019/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
South Milford SubSA 568 Mona Substation 11 6,444 6,444 1
VariousSA 127 Various 37,090 37,090 2
VariousSA 127 Various 2,757 2,757 3
VariousSA 127 Various 453 453 4
Dave Johnston SubSA 628 Thermopolis Sub 17 108,632 108,632 5
Dave Johnston SubSA 628 Thermopolis Sub 16 10,693 10,693 6
VariousSA 33 Various 476 476 7
VariousSA 180 Various 2,010 2,010 8
Walla Walla SubSA 506 Burbank Pumps 1 2,236 2,236 9
Walla Walla SubSA 506 Burbank Pumps 1 4 4 10
VariousRS 286 Various 21,010 21,010 11
VariousRS 286 Various 1,019 1,019 12
Redmond SubstationRS 67 Crooked River Pumps 10,047 10,047 13
VariousRS 297 Various 501 2,695,851 2,695,851 14
VariousRS 297 Various 440 271,099 271,099 15
VariousSA 9 Various 100 100 16
VariousRS 637 Various 78 553,783 553,783 17
VariousRS 637 Various 77 62,023 62,023 18
Pelton ReregulatingRS 591 Round Butte Sub 55,750 55,750 19
Pelton ReregulatingRS 591 Round Butte Sub 6,814 6,814 20
VariousSA 813 Various 21
VariousSA 813 Various 273 273 22
VariousRS 262 Various 330 1,666,231 1,566,257 23
VariousRS 262 Various 330 168,185 158,094 24
VariousRS 263 Various 44,040 41,397 25
VariousRS 263 Various 4,111 3,858 26
Dave Johnston SubRS 684 Various 27
Wyoming DistributionSA 175 Wyoming Distribution 1 9,187 9,187 28
VariousSA 175 Wyoming Distribution 1 5 5 29
VariousSA 132 Various 30
VariousSA 724 Various 188 188 31
VariousSA 724 Various 527 527 32
71,144 71,451 33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.5
5,281 15,241,847 15,129,193
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
PacifiCorp X / /2019/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
24,404 24,404 1
387,911 15,043 372,868 2
17,214 17,214 3
3,358 128 3,230 4
480,206 563,944 83,738 5
34,880 34,880 6
3,544 136 3,408 7
14,634 563 14,071 8
8,380 19,051 10,671 9
402 402 10
21,009 21,009 11
1,019 1,019 12
11,223 11,223 13
15,304,609 17,873,827 2,569,218 14
961,964 961,964 15
1,718 66 1,652 16
2,386,727 2,778,303 391,576 17
249,401 249,401 18
109,725 109,725 19
9,975 9,975 20
418 16 402 21
2,285 2,285 22
2,322,553 2,885,741 563,188 23
264,317 264,317 24
36,405 36,405 25
4,047 4,047 26
27
39,247 81,641 42,394 28
-1,276 -1,276 29
1,197 46 1,151 30
1,502 57 1,445 31
4,151 4,151 32
320,321 320,321 33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.5
71,429,114 111,912,996 23,992,613 16,491,269
Schedule Page: 328 Line No.: 1 Column: d
Transmission service under the Open Access Transmission Tariff (1st Revised Service
Agreement 876). Service provided pursuant to rules and regulations of Oregon Direct
Access. Agreement terminates upon notification pursuant to Oregon Direct Access and Open
Access Transmission Tariff.

Schedule Page: 328 Line No.: 1 Column: f
This footnote applies to all occurrences of "Bonneville Power Adm" on pages 328-330.
Complete name is Bonneville Power Administration.

Schedule Page: 328 Line No.: 1 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328 Line No.: 2 Column: d
Transmission service under the Open Access Transmission Tariff (1st Revised Service
Agreement 876). Service provided pursuant to rules and regulations of Oregon Direct
Access. Agreement terminates upon notification pursuant to Oregon Direct Access and Open
Access Transmission Tariff.

Schedule Page: 328 Line No.: 2 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328 Line No.: 3 Column: c
This footnote applies to all occurrences of "various signatories" on pages 328-330.
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 3 Column: d
Legacy contract executed between PacifiCorp and Arizona Public Service Company concerning
the exchange of transmission services over agreed-upon facilities (Restated Transmission
Service Agreement between PacifiCorp and Arizona Public Service Company, Rate Schedule
436). The contract terminates when the Cholla Plant, Unit 4 has been retired from service
and all costs of terminating Unit 4 have been paid. See also page 332, Transmission of
electricity by others, in this Form No. 1.
Schedule Page: 328 Line No.: 3 Column: f
Glenn Canyon/Four Corners substation

Schedule Page: 328 Line No.: 4 Column: b
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.: 4 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 4 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 5 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 328 Line No.: 5 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service. Refunds for transmission
services pursuant to FERC Docket No. ER17-219-002.

Schedule Page: 328 Line No.: 6 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 6 Column: m
2018 transmission and ancillary services.
Schedule Page: 328 Line No.: 7 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 8 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 8 Column: m
2018 transmission and ancillary services.

Schedule Page: 328 Line No.: 9 Column: d
Ancillary services under the Open Access Transmission Tariff (1st Revised Service
Agreement 476) in effect until superseded.

Schedule Page: 328 Line No.: 9 Column: f
Long Hollow, WY switching station

Schedule Page: 328 Line No.: 9 Column: g
Long Hollow, WY switching station

Schedule Page: 328 Line No.: 9 Column: m
Operating reserve - spinning reserve service. Operating reserve - supplemental reserve
service.

Schedule Page: 328 Line No.: 10 Column: d
Ancillary services under the Open Access Transmission Tariff (1st Revised Service
Agreement 476) in effect until superseded.

Schedule Page: 328 Line No.: 10 Column: f
Long Hollow, WY switching station

Schedule Page: 328 Line No.: 10 Column: g
Long Hollow, WY switching station

Schedule Page: 328 Line No.: 10 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 328 Line No.: 11 Column: c
This footnote applies to all occurrences of "Nevada Power Company" on pages 328-330.
Nevada Power Company is a wholly owned subsidiary of NV Energy, Inc., which is an indirect
wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
company.
Schedule Page: 328 Line No.: 11 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 895) terminating on April 30, 2024.

Schedule Page: 328 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 12 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 895) terminating on April 30, 2024.

Schedule Page: 328 Line No.: 12 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328 Line No.: 13 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 742) terminating no earlier than 12-months from notice by the customer.

Schedule Page: 328 Line No.: 13 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328 Line No.: 14 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 742) terminating no earlier than 12-months from notice by the customer.

Schedule Page: 328 Line No.: 14 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328 Line No.: 15 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 15 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 16 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 505) terminating no earlier than 12-months from notice by the customer.

Schedule Page: 328 Line No.: 16 Column: m
Distribution voltage service charge. Primary delivery service. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Regulation and
frequency response service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 328 Line No.: 17 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 505) terminating no earlier than 12-months from notice by the customer.

Schedule Page: 328 Line No.: 17 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328 Line No.: 18 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 18 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 18 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 19 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 19 Column: m
2018 transmission and ancillary services.

Schedule Page: 328 Line No.: 20 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 20 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 20 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 21 Column: c
Various signatories to the Volume 11 Point-to-Point Transmission Tariff.

Schedule Page: 328 Line No.: 21 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 21 Column: m
2018 transmission and ancillary services.

Schedule Page: 328 Line No.: 22 Column: a
This footnote applies to all occurrences of "Black Hills/Colorado Electric Utility
Company" on pages 328-330. Complete name is Black Hills/Colorado Electric Utility Company,
L.P.
Schedule Page: 328 Line No.: 22 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 328 Line No.: 22 Column: m
Transmission resale - purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service.

Schedule Page: 328 Line No.: 23 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 23 Column: m
Transmission resale - purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service.

Schedule Page: 328 Line No.: 24 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 347) terminating on December 31, 2023.

Schedule Page: 328 Line No.: 24 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 25 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 347) terminating on December 31, 2023.

Schedule Page: 328 Line No.: 25 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328 Line No.: 26 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 67) terminating on December 31, 2023.

Schedule Page: 328 Line No.: 26 Column: m
Transmission resale - purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service.

Schedule Page: 328 Line No.: 27 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 67) terminating on December 31, 2023.

Schedule Page: 328 Line No.: 27 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328 Line No.: 28 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 28 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 29 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Schedule Page: 328 Line No.: 29 Column: m
2018 transmission and ancillary services.

Schedule Page: 328 Line No.: 30 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 31 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 31 Column: m
2018 transmission and ancillary services.

Schedule Page: 328 Line No.: 32 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 32 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328 Line No.: 33 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 33 Column: m
2018 transmission and ancillary services.

Schedule Page: 328 Line No.: 34 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328 Line No.: 34 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.1 Line No.: 1 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.1 Line No.: 1 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.1 Line No.: 2 Column: b
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.

Schedule Page: 328.1 Line No.: 2 Column: c
Capacity exchanged and operated by each transmission provider with no receipt or delivery
of energy.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
Schedule Page: 328.1 Line No.: 2 Column: d
Legacy contract executed between PacifiCorp and Bonneville Power Administration concerning
the exchange of transmission services over agreed-upon facilities ("Midpoint-Meridian
Transmission Agreement", Rate Schedule 369). This agreement runs concurrently with the AC
Intertie Agreement (Rate Schedule 368), which terminates when the facilities subject to
that agreement are taken out of service. See also page 332, Transmission of electricity by
others, in this Form No. 1.

Schedule Page: 328.1 Line No.: 3 Column: d
Legacy contract (3rd Revised Rate Schedule 237) executed between PacifiCorp and Bonneville
Power Administration ("BPA") for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Contract subject to terminate upon the earlier
of the termination of the "Exchange Agreement" between PacifiCorp and BPA or the time of
the termination of all deliveries as defined in the agreement.

Schedule Page: 328.1 Line No.: 3 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.

Schedule Page: 328.1 Line No.: 4 Column: d
Legacy contract (3rd Revised Rate Schedule 237) executed between PacifiCorp and Bonneville
Power Administration ("BPA") for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Contract subject to terminate upon the earlier
of the termination of the "Exchange Agreement" between PacifiCorp and BPA or the time of
the termination of all deliveries as defined in the agreement.

Schedule Page: 328.1 Line No.: 4 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.1 Line No.: 5 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised
Service Agreement 656) terminating on August 31, 2030.

Schedule Page: 328.1 Line No.: 5 Column: m
Reactive supply and voltage control service.

Schedule Page: 328.1 Line No.: 6 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (4th Revised
Service Agreement 656) terminating on August 31, 2030.

Schedule Page: 328.1 Line No.: 6 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.1 Line No.: 7 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (9th Revised Service Agreement 229) terminating on September 30, 2028.

Schedule Page: 328.1 Line No.: 7 Column: m
Distribution voltage service charge. Primary delivery service. Regulation and frequency
response service. Reactive supply and voltage control service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
Schedule Page: 328.1 Line No.: 8 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (9th Revised Service Agreement 229) terminating on September 30, 2028.
Schedule Page: 328.1 Line No.: 8 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.1 Line No.: 9 Column: c
This footnote applies to all occurrences of "Benton REA" on pages 328-330. Complete name
is Benton Rural Electric Association.

Schedule Page: 328.1 Line No.: 9 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (3rd Revised Service Agreement 539) terminating on September 30, 2028.

Schedule Page: 328.1 Line No.: 9 Column: m
Scheduling, system control and dispatch service. Regulation and frequency response
service. Operating reserve - spinning reserve service. Operating reserve - supplemental
reserve service.

Schedule Page: 328.1 Line No.: 10 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (3rd Revised Service Agreement 539) terminating on September 30, 2028.

Schedule Page: 328.1 Line No.: 10 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.1 Line No.: 11 Column: c
This footnote applies to all occurrences of "Umatilla Electric and Columbia" on pages
328-330. Complete name is Umatilla Electric Cooperative Association and Columbia Basin
Electric Cooperative, Inc.

Schedule Page: 328.1 Line No.: 11 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 538) terminating on September 30, 2028.

Schedule Page: 328.1 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Regulation and frequency response
service. Operating reserve - spinning reserve service. Operating reserve - supplemental
reserve service.

Schedule Page: 328.1 Line No.: 12 Column: d
Network transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 538) terminating on September 30, 2028.

Schedule Page: 328.1 Line No.: 12 Column: m
Refunds for transmission services pursuant to FERC Docket No. ER17-219-002.

Schedule Page: 328.1 Line No.: 13 Column: b
This footnote applies to all occurrences of "U.S. Bureau of Reclamation" on pages 328-330.
Complete name is United States Department of Interior, Bureau of Reclamation.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.8
Schedule Page: 328.1 Line No.: 13 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (5th Revised
Service Agreement 179) terminating on September 30, 2025.

Schedule Page: 328.1 Line No.: 13 Column: m
Reactive supply and voltage control service.

Schedule Page: 328.1 Line No.: 14 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (5th Revised
Service Agreement 179) terminating on September 30, 2025.

Schedule Page: 328.1 Line No.: 14 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.1 Line No.: 15 Column: d
Legacy contract (5th Revised Rate Schedule 368) executed between PacifiCorp and Bonneville
Power Administration for transmission service over agreed-upon facilities and/or subject
to a sole-use or facilities charge. Subject to termination upon mutual agreement.

Schedule Page: 328.1 Line No.: 15 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.

Schedule Page: 328.1 Line No.: 16 Column: d
Legacy contract (5th Revised Rate Schedule 368) executed between PacifiCorp and Bonneville
Power Administration for transmission service over agreed-upon facilities and/or subject
to a sole-use or facilities charge. Subject to termination upon mutual agreement.

Schedule Page: 328.1 Line No.: 16 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.1 Line No.: 17 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (7th Revised Service Agreement 328) terminating on September 30, 2028.

Schedule Page: 328.1 Line No.: 17 Column: g
White Swan/Toppenish Substations

Schedule Page: 328.1 Line No.: 17 Column: m
Distribution voltage service charge. Primary delivery service. Regulation and frequency
response service. Reactive supply and voltage control service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.
Schedule Page: 328.1 Line No.: 18 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (6th Revised Service Agreement 328) terminating on July 31, 2028.

Schedule Page: 328.1 Line No.: 18 Column: g
White Swan/Toppenish Substations

Schedule Page: 328.1 Line No.: 18 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.9
Schedule Page: 328.1 Line No.: 19 Column: d
Network transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 827) terminating on September 30, 2028.

Schedule Page: 328.1 Line No.: 19 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328.1 Line No.: 20 Column: d
Network transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 827) terminating on September 30, 2028.

Schedule Page: 328.1 Line No.: 20 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.1 Line No.: 21 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (3rd Revised Service Agreement 746) terminating on June 30, 2028.

Schedule Page: 328.1 Line No.: 21 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328.1 Line No.: 22 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (3rd Revised Service Agreement 746) terminating on June 30, 2028.

Schedule Page: 328.1 Line No.: 22 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.1 Line No.: 23 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.1 Line No.: 23 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.1 Line No.: 24 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.1 Line No.: 24 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.1 Line No.: 25 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (2nd Revised Service Agreement 747) terminating on June 30, 2028.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.10
Schedule Page: 328.1 Line No.: 25 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328.1 Line No.: 26 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (2nd Revised Service Agreement 747) terminating on June 30, 2028.

Schedule Page: 328.1 Line No.: 26 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.1 Line No.: 27 Column: c
This footnote applies to all occurrences of “PUD No. 1 of Clark County” on pages 328-330.
Complete name is Public Utility District No. 1 of Clark County.

Schedule Page: 328.1 Line No.: 27 Column: d
Network transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 735) terminating on September 30, 2028.

Schedule Page: 328.1 Line No.: 27 Column: g
Chelatchie/View 115kV

Schedule Page: 328.1 Line No.: 27 Column: m
Scheduling, system control and dispatch service. Regulation and frequency response
service. Operating reserve - spinning reserve service. Operating reserve - supplemental
reserve service.

Schedule Page: 328.1 Line No.: 28 Column: d
Network transmission service under the Open Access Transmission Tariff (2nd Revised
Service Agreement 735) terminating on September 30, 2028.

Schedule Page: 328.1 Line No.: 28 Column: g
Chelatchie/View 115kV

Schedule Page: 328.1 Line No.: 28 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.1 Line No.: 29 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.1 Line No.: 29 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.1 Line No.: 30 Column: d
Transmission service under the Open Access Transmission Tariff (12th 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 Tariff.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.11
Schedule Page: 328.1 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328.1 Line No.: 31 Column: d
Transmission service under the Open Access Transmission Tariff (12th 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 Tariff.

Schedule Page: 328.1 Line No.: 31 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.1 Line No.: 32 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 881) terminating on February 28, 2023.

Schedule Page: 328.1 Line No.: 32 Column: m
Scheduling, system control and dispatch service.

Schedule Page: 328.1 Line No.: 33 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 881) terminating on February 28, 2023.

Schedule Page: 328.1 Line No.: 33 Column: m
Scheduling, system control and dispatch service.

Schedule Page: 328.1 Line No.: 34 Column: b
This footnote applies to all occurrences of “Clatskanie People's Utility Dist” on pages
328-330. Complete name is Clatskanie People's Utility District.

Schedule Page: 328.1 Line No.: 34 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 899) terminating on December 31, 2020.

Schedule Page: 328.1 Line No.: 34 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 1 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 899) terminating on December 31, 2020.

Schedule Page: 328.2 Line No.: 1 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.2 Line No.: 2 Column: a
This footnote applies to all occurrences of "Deseret Gen and Trans" on pages 328-330.
Complete name is Deseret Generation and Transmission Co-operative.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.12
Schedule Page: 328.2 Line No.: 2 Column: d
Legacy contract executed between PacifiCorp and Deseret Generation and Transmission
Co-operative for transmission service over agreed-upon facilities (6th Amended and
Restated Transmission Service and Operating Agreement, Rate Schedule 280). Agreement
subject to termination upon mutual agreement.

Schedule Page: 328.2 Line No.: 2 Column: m
Distribution voltage service charge. Meter interrogation services. Scheduling, system
control and dispatch service. Reactive supply and voltage control service. Regulation and
frequency response service. Operating reserve - spinning reserve service. Operating
reserve - supplemental reserve service.

Schedule Page: 328.2 Line No.: 3 Column: d
Legacy contract executed between PacifiCorp and Deseret Generation and Transmission
Co-operative for transmission service over agreed-upon facilities (6th Amended and
Restated Transmission Service and Operating Agreement, Rate Schedule 280). Agreement
subject to termination upon mutual agreement.

Schedule Page: 328.2 Line No.: 3 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.2 Line No.: 4 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 4 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 5 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 5 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.2 Line No.: 6 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 6 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 7 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 8 Column: d
Transmission resale service under the Open Access Transmission Tariff (Service Agreement
780). Termination upon mutual consent.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.13

Schedule Page: 328.2 Line No.: 8 Column: m
Transmission resale - purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Generation regulation
and frequency response service.

Schedule Page: 328.2 Line No.: 9 Column: c
This footnote applies to all occurrences of "PUD No. 2 of Grant County" on pages 328-330.
Complete name is Public Utility District No. 2 of Grant County.

Schedule Page: 328.2 Line No.: 9 Column: d
Transmission resale service under the Open Access Transmission Tariff (Service Agreement
780). Termination upon mutual consent.

Schedule Page: 328.2 Line No.: 9 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.2 Line No.: 10 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 11 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 874) terminating on December 31, 2032.

Schedule Page: 328.2 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.

Schedule Page: 328.2 Line No.: 12 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 874) terminating on December 31, 2032.

Schedule Page: 328.2 Line No.: 12 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.2 Line No.: 13 Column: d
Transmission service under the Open Access Transmission Tariff (2nd Revised Service
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 Tariff.

Schedule Page: 328.2 Line No.: 13 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328.2 Line No.: 14 Column: d
Transmission service under the Open Access Transmission Tariff (2nd Revised Service
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 Tariff.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.14
Schedule Page: 328.2 Line No.: 14 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.2 Line No.: 15 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 15 Column: m
Unauthorized use of transmission service. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Generation regulation and frequency response
service. Operating reserve - spinning reserve service. Operating reserve - supplemental
reserve service.

Schedule Page: 328.2 Line No.: 16 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 16 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.2 Line No.: 17 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 17 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 18 Column: d
Legacy contract (Rate Schedule 322) executed between PacifiCorp and Fall River Rural
Electric Cooperative, Inc. for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Terminating on July 31, 2027.

Schedule Page: 328.2 Line No.: 18 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.

Schedule Page: 328.2 Line No.: 19 Column: d
Legacy contract (Rate Schedule 322) executed between PacifiCorp and Fall River Rural
Electric Cooperative, Inc. for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Terminating on July 31, 2027.

Schedule Page: 328.2 Line No.: 19 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.2 Line No.: 20 Column: d
Service Agreement 761 executed between PacifiCorp and Foote Creek III, LLC (d/b/a
Terra-Gen Operating, LLC) for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Terminating on March 1, 2024.

Schedule Page: 328.2 Line No.: 20 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. Distribution voltage service charge.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.15

Schedule Page: 328.2 Line No.: 21 Column: d
Service Agreement 761 executed between PacifiCorp and Foote Creek III, LLC (d/b/a
Terra-Gen Operating, LLC) for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Terminating on March 1, 2024.

Schedule Page: 328.2 Line No.: 21 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.2 Line No.: 22 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised
Service Agreement 212) terminating on May 31, 2024.

Schedule Page: 328.2 Line No.: 22 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 23 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised
Service Agreement 212) terminating on May 31, 2024.

Schedule Page: 328.2 Line No.: 23 Column: m
Refunds for transmission services pursuant to FERC Docket No. ER17-219-002.

Schedule Page: 328.2 Line No.: 24 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 24 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 25 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 25 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 26 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 26 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.2 Line No.: 27 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 27 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.16
Schedule Page: 328.2 Line No.: 28 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 28 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 29 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 29 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 30 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 31 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 31 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 32 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 32 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.2 Line No.: 33 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.2 Line No.: 33 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.2 Line No.: 34 Column: d
Legacy contract (3rd Revised Rate Schedule 302) executed between PacifiCorp and Moon Lake
Electric Association Inc. for transmission and interconnection service over agreed-upon
facilities and/or subject to a sole-use or facilities charge. Either party may terminate
the agreement at any time after October 14, 2016, by providing two years written notice.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.17

Schedule Page: 328.2 Line No.: 34 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.

Schedule Page: 328.3 Line No.: 1 Column: d
Legacy contract (3rd Revised Rate Schedule 302) executed between PacifiCorp and Moon Lake
Electric Association Inc. for transmission and interconnection service over agreed-upon
facilities and/or subject to a sole-use or facilities charge. Either party may terminate
the agreement at any time after October 14, 2016, by providing two years written notice.

Schedule Page: 328.3 Line No.: 1 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.3 Line No.: 2 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 2 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 3 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 3 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.3 Line No.: 4 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 4 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 5 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 5 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.3 Line No.: 6 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 6 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.3 Line No.: 7 Column: d
Network transmission service under the Open Access Transmission Tariff (Service Agreement
894) terminating on December 31, 2057.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.18
Schedule Page: 328.3 Line No.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328.3 Line No.: 8 Column: d
Network transmission service under the Open Access Transmission Tariff (Service Agreement
894) terminating on December 31, 2057.

Schedule Page: 328.3 Line No.: 8 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.3 Line No.: 9 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 9 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 10 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 10 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 11 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 733) terminating on November 30, 2023.

Schedule Page: 328.3 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.

Schedule Page: 328.3 Line No.: 12 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 733) terminating on November 30, 2023.

Schedule Page: 328.3 Line No.: 12 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.3 Line No.: 13 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 13 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 14 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.19

Schedule Page: 328.3 Line No.: 14 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.3 Line No.: 15 Column: c
This footnote applies to all occurrences of “Portland General Electric” on pages 328-330.
Complete name is Portland General Electric Company.

Schedule Page: 328.3 Line No.: 15 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 880) terminating on September 29, 2024.

Schedule Page: 328.3 Line No.: 15 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 16 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.3 Line No.: 16 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.3 Line No.: 16 Column: d
Legacy contract (Rate Schedule 298) executed between PacifiCorp and Pacific Gas & Electric
Company for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge and phase shifting transformers at Sigurd-Glen Canyon 230kV
transmission line and Pinto-Four Corners 345kV transmission line terminating on February
12, 2020.

Schedule Page: 328.3 Line No.: 16 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.

Schedule Page: 328.3 Line No.: 17 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 17 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.

Schedule Page: 328.3 Line No.: 18 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.3 Line No.: 18 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.3 Line No.: 18 Column: d
Legacy contract (1st Revised Rate Schedule 137) executed between PacifiCorp and Portland
General Electric Company for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge for the Dalreed Substation, which allows for
automatic one-year renewals after initial one-year term.

Schedule Page: 328.3 Line No.: 18 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.20

Schedule Page: 328.3 Line No.: 19 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 19 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 20 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 20 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.3 Line No.: 21 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 21 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.

Schedule Page: 328.3 Line No.: 22 Column: c
This footnote applies to all occurrences of "CAISO" on pages 328-330. Complete name is
California Independent System Operator Corporation.

Schedule Page: 328.3 Line No.: 22 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 169) terminating on October 31, 2020.

Schedule Page: 328.3 Line No.: 22 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.3 Line No.: 23 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (8th Revised
Service Agreement 169) terminating on October 31, 2020.

Schedule Page: 328.3 Line No.: 23 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.3 Line No.: 24 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 700) terminating on March 31, 2022.

Schedule Page: 328.3 Line No.: 24 Column: m
Scheduling, system control and dispatch service.

Schedule Page: 328.3 Line No.: 25 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 700) terminating on March 31, 2022.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.21
Schedule Page: 328.3 Line No.: 25 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.3 Line No.: 26 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 701) terminating on March 31, 2022.

Schedule Page: 328.3 Line No.: 26 Column: m
Scheduling, system control and dispatch service.

Schedule Page: 328.3 Line No.: 27 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 701) terminating on March 31, 2022.

Schedule Page: 328.3 Line No.: 27 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.3 Line No.: 28 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 702) terminating on March 31, 2022.

Schedule Page: 328.3 Line No.: 28 Column: m
Scheduling, system control and dispatch service.

Schedule Page: 328.3 Line No.: 29 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 702) terminating on March 31, 2022.

Schedule Page: 328.3 Line No.: 29 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.3 Line No.: 30 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 748) terminating on December 31, 2023.

Schedule Page: 328.3 Line No.: 30 Column: m
Scheduling, system control and dispatch service.

Schedule Page: 328.3 Line No.: 31 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 748) terminating on December 31, 2023.

Schedule Page: 328.3 Line No.: 31 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.3 Line No.: 32 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 749) terminating on December 31, 2023.

Schedule Page: 328.3 Line No.: 32 Column: m
Scheduling, system control and dispatch service.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.22
Schedule Page: 328.3 Line No.: 33 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 749) terminating on December 31, 2023.

Schedule Page: 328.3 Line No.: 33 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.3 Line No.: 34 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.3 Line No.: 34 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 1 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 1 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.4 Line No.: 2 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 2 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 3 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 3 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.4 Line No.: 4 Column: a
This footnote applies to all occurrences of “PUD No. 1 of Cowlitz County” on pages
328-330. Complete name is Public Utility District No. 1 of Cowlitz County.

Schedule Page: 328.4 Line No.: 4 Column: d
Legacy contract (Rate Schedule 234) providing for transmission and operation of Swift
Hydroelectric plant No. 2 and for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Agreement may be terminated subsequent to the
termination of the Power contract as defined in the agreement by the customer providing at
least six-months written notice and specifying the date on which the customer will assume
responsibility of operations and maintenance of Swift Hydroelectric plant No. 2.

Schedule Page: 328.4 Line No.: 4 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.23
Schedule Page: 328.4 Line No.: 5 Column: d
Legacy contract (Rate Schedule 234) providing for transmission and operation of Swift
Hydroelectric plant No. 2 and for transmission service over agreed-upon facilities and/or
subject to a sole-use or facilities charge. Agreement may be terminated subsequent to the
termination of the Power contract as defined in the agreement by the customer providing at
least six-months written notice and specifying the date on which the customer will assume
responsibility of operations and maintenance of Swift Hydroelectric plant No. 2.

Schedule Page: 328.4 Line No.: 5 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.4 Line No.: 6 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 6 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 7 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 8 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 8 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 9 Column: b
This footnote applies to all occurrences of "Sacramento Municipal Utility Dist" on pages
328-330. Complete name is Sacramento Municipal Utility District.

Schedule Page: 328.4 Line No.: 9 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 863) terminating on June 30, 2022.

Schedule Page: 328.4 Line No.: 9 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 10 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 863) terminating on June 30, 2022.

Schedule Page: 328.4 Line No.: 10 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.24
Schedule Page: 328.4 Line No.: 11 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 809) terminating on October 31, 2020.

Schedule Page: 328.4 Line No.: 11 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 12 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (Service
Agreement 809) terminating on October 31, 2020.

Schedule Page: 328.4 Line No.: 12 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.4 Line No.: 13 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 13 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 14 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 14 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 15 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (9th Revised
Service Agreement 791) terminating upon written notification.

Schedule Page: 328.4 Line No.: 15 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 16 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 16 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.

Schedule Page: 328.4 Line No.: 17 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 17 Column: m
2018 transmission and ancillary services.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.25
Schedule Page: 328.4 Line No.: 18 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 18 Column: m
Transmission resale - purchase of point-to-point transmission. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Generation regulation
and frequency response service.

Schedule Page: 328.4 Line No.: 19 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 19 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.4 Line No.: 20 Column: a
This footnote applies to all occurrences of Sierra Pacific Power Company on page 328-330.
Sierra Pacific Power Company is a wholly owned subsidiary of NV Energy, Inc., which is an
indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's
indirect parent company.

Schedule Page: 328.4 Line No.: 20 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.4 Line No.: 20 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.4 Line No.: 20 Column: d
Legacy contract (Rate Schedule 674) executed between PacifiCorp and Sierra Pacific Power
Company for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. Terminating in September 2022.

Schedule Page: 328.4 Line No.: 20 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.

Schedule Page: 328.4 Line No.: 21 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.4 Line No.: 21 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.

Schedule Page: 328.4 Line No.: 21 Column: d
Legacy contract (Rate Schedule 674) executed between PacifiCorp and Sierra Pacific Power
Company for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge. Terminating in September 2022.

Schedule Page: 328.4 Line No.: 21 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.4 Line No.: 22 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Schedule Page: 328.4 Line No.: 22 Column: c
Operation, maintenance or facility lease services with no receipt or delivery of energy.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.26
Schedule Page: 328.4 Line No.: 22 Column: d
Use of Facilities Agreement pertaining to the legacy contract (Rate Schedule 298) for
phase shifting transformers at Sigurd-Glen Canyon 230kV transmission line and Pinto-Four
Corners 345kV transmission line, terminating on February 12, 2020.

Schedule Page: 328.4 Line No.: 22 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge.

Schedule Page: 328.4 Line No.: 23 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 23 Column: m
Unauthorized use of transmission service. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Generation regulation and frequency response
service. Operating reserve - spinning reserve service. Operating reserve - supplemental
reserve service.

Schedule Page: 328.4 Line No.: 24 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 24 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.4 Line No.: 25 Column: a
This footnote applies to all occurrences of "Southern California Public Power" on pages
328-330. Complete name is Southern California Public Power Authority.

Schedule Page: 328.4 Line No.: 25 Column: d
Small Generator Interconnection Agreement (Service Agreement 629) executed between
PacifiCorp and Southern California Public Power Authority which terminated on November 30,
2019.
Schedule Page: 328.4 Line No.: 25 Column: m
Unauthorized use of transmission service. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Generation regulation and frequency response
service. Operating reserve - spinning reserve service. Operating reserve - supplemental
reserve service.

Schedule Page: 328.4 Line No.: 26 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 779) which terminated on August 31, 2024.

Schedule Page: 328.4 Line No.: 26 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 27 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (1st Revised
Service Agreement 779) which terminated on August 31, 2024.

Schedule Page: 328.4 Line No.: 27 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.27

Schedule Page: 328.4 Line No.: 28 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 28 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 29 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 29 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.4 Line No.: 30 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 31 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 31 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 32 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 32 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.4 Line No.: 33 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.4 Line No.: 33 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.4 Line No.: 34 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 568) terminating on April 30, 2029.

Schedule Page: 328.4 Line No.: 34 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service. Operating reserve -
spinning reserve service. Operating reserve - supplemental reserve service.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.28
Schedule Page: 328.5 Line No.: 1 Column: d
Point-to-point transmission service under the Open Access Transmission Tariff (3rd Revised
Service Agreement 568) terminating on April 30, 2029.

Schedule Page: 328.5 Line No.: 1 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.5 Line No.: 2 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.5 Line No.: 2 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 3 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.5 Line No.: 3 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.5 Line No.: 4 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.5 Line No.: 4 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 5 Column: a
This footnote applies to all occurrences of "Tri-State Gen and Trans" on pages 328-330.
Complete name is Tri-State Generation and Transmission Association, Inc.
Schedule Page: 328.5 Line No.: 5 Column: d
Network transmission service under the Open Access Transmission Tariff (7th Revised
Service Agreement 628) terminating on June 30, 2021.

Schedule Page: 328.5 Line No.: 5 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328.5 Line No.: 6 Column: d
Network transmission service under the Open Access Transmission Tariff (7th Revised
Service Agreement 628) terminating on June 30, 2021.

Schedule Page: 328.5 Line No.: 6 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.5 Line No.: 7 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.29
Schedule Page: 328.5 Line No.: 7 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 8 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.5 Line No.: 8 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 9 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (2nd Revised Service Agreement 506) terminating upon written
notification.

Schedule Page: 328.5 Line No.: 9 Column: m
Distribution voltage service charge. Primary delivery service. Scheduling, system control
and dispatch service. Reactive supply and voltage control service. Regulation and
frequency response service. Operating reserve - spinning reserve service. Operating
reserve - supplemental reserve service.

Schedule Page: 328.5 Line No.: 10 Column: d
Network transmission service and distribution delivery service under the Open Access
Transmission Tariff (2nd Revised Service Agreement 506) terminating upon written
notification.

Schedule Page: 328.5 Line No.: 10 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.5 Line No.: 11 Column: c
This footnote applies to all occurrences of "Weber Basin Water Conserv." on pages 328-330.
Complete name is Weber Basin Water Conservancy District.

Schedule Page: 328.5 Line No.: 11 Column: d
Legacy contract (3rd Revised Rate Schedule 286) executed between PacifiCorp and United
States Department of the Interior, Bureau of Reclamation Weber Basin Water Conservancy
District for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge for energy deliveries at and below 138kV. Agreement terminates any
time after April 1, 2040, with four years written notification.

Schedule Page: 328.5 Line No.: 11 Column: m
Energy consumption for charge for deliveries at and below 138kV.
Schedule Page: 328.5 Line No.: 12 Column: d
Legacy contract (3rd Revised Rate Schedule 286) executed between PacifiCorp and United
States Department of the Interior, Bureau of Reclamation Weber Basin Water Conservancy
District for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge for energy deliveries at and below 138kV. Agreement terminates any
time after April 1, 2040, with four years written notification.

Schedule Page: 328.5 Line No.: 12 Column: m
2018 transmission and ancillary services.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.30
Schedule Page: 328.5 Line No.: 13 Column: d
Legacy contract (3rd Amended Rate Schedule 67) executed between PacifiCorp and United
States Department of the Interior, Bureau of Reclamation Crooked River Irrigation District
for transmission service over agreed-upon facilities and/or subject to a sole-use or
facilities charge. Agreement terminates with one year written notice.

Schedule Page: 328.5 Line No.: 14 Column: a
This footnote applies to all occurrences of "Utah Associated Municipal Power" on pages
328-330. Complete name is Utah Associated Municipal Power Systems.

Schedule Page: 328.5 Line No.: 14 Column: d
Legacy contract executed between PacifiCorp and Utah Associated Municipal Power Systems
for transmission service over agreed-upon facilities (4th Amended and Restated
Transmission Service and Operating Agreement, 4th Revised Rate Schedule 297). Agreement
subject to termination upon mutual agreement and replacement agreements are in effect.

Schedule Page: 328.5 Line No.: 14 Column: m
Distribution voltage service charge. Scheduling, system control and dispatch service.
Reactive supply and voltage control service. Generation regulation and frequency response
service. Operating reserve - spinning reserve service. Operating reserve - supplemental
reserve service.

Schedule Page: 328.5 Line No.: 15 Column: d
Legacy contract executed between PacifiCorp and Utah Associated Municipal Power Systems
for transmission service over agreed-upon facilities (4th Amended and Restated
Transmission Service and Operating Agreement, 4th Revised Rate Schedule 297). Agreement
subject to termination upon mutual agreement and replacement agreements are in effect.

Schedule Page: 328.5 Line No.: 15 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.5 Line No.: 16 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.5 Line No.: 16 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Generation regulation and frequency response service.

Schedule Page: 328.5 Line No.: 17 Column: d
Legacy contract (5th Revised Rate Schedule 637) executed between PacifiCorp and Utah
Municipal Power Agency for transmission service over agreed-upon facilities (Amended and
Restated Transmission Service and Operating Agreement). Subject to termination upon mutual
agreement and replacement agreements are in effect.

Schedule Page: 328.5 Line No.: 17 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service. Regulation and frequency response service. Operating reserve - spinning reserve
service. Operating reserve - supplemental reserve service.

Schedule Page: 328.5 Line No.: 18 Column: d
Legacy contract (5th Revised Rate Schedule 637) executed between PacifiCorp and Utah
Municipal Power Agency for transmission service over agreed-upon facilities (Amended and
Restated Transmission Service and Operating Agreement). Subject to termination upon mutual
agreement and replacement agreements are in effect.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.31

Schedule Page: 328.5 Line No.: 18 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.5 Line No.: 19 Column: d
Legacy contract (Rate Schedule 591) executed between PacifiCorp and Warm Springs Power
Enterprises for transmission service over agreed-upon facilities and/or subject to
sole-use or facilities charge. Terminating on January 31, 2032.

Schedule Page: 328.5 Line No.: 19 Column: m
Charge for transmission service over agreed-upon facilities and/or subject to a sole-use
or facilities charge based on a capacity factor and/or proportional use as defined in the
contract.

Schedule Page: 328.5 Line No.: 20 Column: d
Legacy contract (Rate Schedule 591) executed between PacifiCorp and Warm Springs Power
Enterprises for transmission service over agreed-upon facilities and/or subject to
sole-use or facilities charge. Terminating on January 31, 2032.

Schedule Page: 328.5 Line No.: 20 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.5 Line No.: 21 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.5 Line No.: 21 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 22 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.5 Line No.: 22 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 23 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.

Schedule Page: 328.5 Line No.: 23 Column: d
Legacy contract (Rate Schedule 262) executed between PacifiCorp and Western Area Power
Administration for transmission and interconnection service over agreed-upon facilities
and/or subject to a sole-use or facilities charge for load service to preferential
customers for deliveries of Colorado River Storage Project power and energy. Agreement
terminates upon three years after written notice and mutual consent.

Schedule Page: 328.5 Line No.: 23 Column: m
Fixed termination fee associated with a contract cancellation applied for the duration of
this agreement.

Schedule Page: 328.5 Line No.: 24 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.32
Schedule Page: 328.5 Line No.: 24 Column: d
Legacy contract (Rate Schedule 262) executed between PacifiCorp and Western Area Power
Administration for transmission and interconnection service over agreed-upon facilities
and/or subject to a sole-use or facilities charge for load service to preferential
customers for deliveries of Colorado River Storage Project power and energy. Agreement
terminates upon three years after written notice and mutual consent.

Schedule Page: 328.5 Line No.: 24 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.5 Line No.: 25 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.

Schedule Page: 328.5 Line No.: 25 Column: d
Legacy contract (Rate Schedule 263) executed between PacifiCorp and Western Area Power
Administration for transmission and interconnection service over agreed-upon facilities
and/or subject to a sole-use or facilities charge for load service to low voltage
customers for deliveries of power and energy from Salt Lake City Area Integrated Projects,
including the Colorado River Storage Projects, to certain municipalities at service below
138kV. Agreement terminates upon three years after written notice and mutual consent.

Schedule Page: 328.5 Line No.: 25 Column: m
Charges for low-voltage transmission of power and energy.
Schedule Page: 328.5 Line No.: 26 Column: c
Various Western Area Power Administration customers in PacifiCorp's control area.

Schedule Page: 328.5 Line No.: 26 Column: d
Legacy contract (Rate Schedule 263) executed between PacifiCorp and Western Area Power
Administration for transmission and interconnection service over agreed-upon facilities
and/or subject to a sole-use or facilities charge for load service to low voltage
customers for deliveries of power and energy from Salt Lake City Area Integrated Projects,
including the Colorado River Storage Projects, to certain municipalities at service below
138kV. Agreement terminates upon three years after written notice and mutual consent.

Schedule Page: 328.5 Line No.: 26 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.5 Line No.: 27 Column: d
Legacy contract (Rate Schedule 684) executed between PacifiCorp and Western Area Power
Administration concerning the exchange of transmission services over agreed-upon
facilities. The contract terminates 50 years from execution. See also page 332,
Transmission of electricity by others, in this Form No. 1.

Schedule Page: 328.5 Line No.: 28 Column: d
Evergreen network transmission service under the Open Access Transmission Tariff (4th
Revised Service Agreement 175).

Schedule Page: 328.5 Line No.: 28 Column: m
Distribution voltage service charge. Primary delivery service. Scheduling, system control
and dispatch service. Reactive supply and voltage control service.
Schedule Page: 328.5 Line No.: 29 Column: b
This footnote applies to all occurrences of "Western Area Power Adm CO River" on pages
328-330. Complete name is Western Area Power Administration Colorado River Storage
Project.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.33

Schedule Page: 328.5 Line No.: 29 Column: d
Evergreen network transmission service under the Open Access Transmission Tariff (4th
Revised Service Agreement 175).

Schedule Page: 328.5 Line No.: 29 Column: m
2018 transmission and ancillary services. Refunds for transmission services pursuant to
FERC Docket No. ER17-219-002.

Schedule Page: 328.5 Line No.: 30 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.5 Line No.: 30 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 31 Column: a
This footnote applies to all occurrences of "Western Area Power Adm CO MO" on pages
328-330. Complete name is Western Area Power Administration Colorado Missouri.

Schedule Page: 328.5 Line No.: 31 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.5 Line No.: 31 Column: m
Scheduling, system control and dispatch service. Reactive supply and voltage control
service.

Schedule Page: 328.5 Line No.: 32 Column: d
Non-firm or short-term firm transmission service under the Open Access Transmission Tariff
between various parties and points.

Schedule Page: 328.5 Line No.: 32 Column: m
2018 transmission and ancillary services.

Schedule Page: 328.5 Line No.: 33 Column: m
Represents the difference between actual wheeling revenues for the period as reflected on
the individual line items within this schedule and the accruals credited to Account 456.1,
Revenues from transmission of electricity for others, during the period.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.34
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
PacifiCorp X
/ /2019/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including 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. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification(b)
LFP -35,661 -35,661Adams Solar Center LLC 1
OS -9,082 -9,082Adams Solar Center LLC 2
AD -27,542 -27,542Arizona Public Service 3
NF 387,199 387,199 55,061 55,061Arizona Public Service 4
LFP 586,611 586,611 1,314,000 1,314,000Arizona Public Service 5
OS 52,683 52,683Arizona Public Service 6
SFP 728,316 728,316 96,561 96,561Arizona Public Service 7
FNS 23,755 23,755 2,467 2,467Ashland, City of 8
AD -1,906 -1,906Avista Corporation 9
FNS 277,574 277,574 58,803 58,789Avista Corporation 10
NF 467,063 467,063 41,002 40,004Avista Corporation 11
SFP 1,971,429 1,971,429 685,577 673,284Avista Corporation 12
NF 5,637 5,637 3,783 3,783Basin Elect. Power Coop 13
OLF 162,290 162,290 36,065 36,065Big Horn Rural Electric 14
AD -2,850 -2,850Black Hills Power, Inc. 15
NF 40 40 40 40Black Hills Power, Inc. 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332
22,624,955 22,879,489 123,126,897 410,546 22,287,825 145,825,268TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
PacifiCorp X
/ /2019/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including 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. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification(b)
OS 14,436 14,436Black Hills Power, Inc. 1
SFP 92,415 92,415 33,621 33,621Black Hills Power, Inc. 2
AD 5,651,535 5,651,535Bonneville Power Admin 3
FNS 5,970,389 5,970,389 3,489 3,412Bonneville Power Admin 4
LFP 52,997,354 52,997,354 5,137,779 5,026,307Bonneville Power Admin 5
NF 3,472,693 3,472,693 1,084,314 1,062,208Bonneville Power Admin 6
OLF 19,829,076 19,829,076 4,334,671 4,239,591Bonneville Power Admin 7
OS 17,109,578 17,109,578Bonneville Power Admin 8
SFP 1,176,411 1,176,411 340,854 333,453Bonneville Power Admin 9
AD 19,365 19,365CA Ind Sys Operator 10
OS 2,158,634 2,158,634CA Ind Sys Operator 11
SFP 385,372 385,372CA Ind Sys Operator 12
LFP 3,304,078 3,304,078 853,847 853,847Deseret Gen and Trans 13
NF 51,272 51,272 8,337 8,337Deseret Gen and Trans 14
LFP -169,828 -169,828Elbe Solar Center, LLC 15
OS -44,598 -44,598Elbe Solar Center, LLC 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.1
22,624,955 22,879,489 123,126,897 410,546 22,287,825 145,825,268TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
PacifiCorp X
/ /2019/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including 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. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification(b)
OS 99,437 99,437Flathead Elect Coop Inc 1
OS 205,960 205,960Hermiston Gen Co L.P. 2
AD -72,096 -72,096Idaho Power Company 3
FNS 12,228 12,228Idaho Power Company 4
LFP 15,436,629 15,436,629 4,961,516 4,961,516Idaho Power Company 5
NF 305,837 305,837 51,381 51,381Idaho Power Company 6
OLF 7,440 7,440Idaho Power Company 7
OS -1,532,485 -1,532,485Idaho Power Company 8
SFP 2,443,215 2,443,215 84,280 84,280Idaho Power Company 9
OS 360 360LA Dept. of Water & Pwr 10
SFP 3,492 3,492 864 864LA Dept. of Water & Pwr 11
FNS 260,104 260,104 19 19Moon Lake Elect. Assoc. 12
LFP 1,419 1,419Morgan City Corporation 13
AD -40,124 -40,124Nevada Power Company 14
NF 370,821 370,821 85,556 85,556Nevada Power Company 15
OS 214,607 214,607Nevada Power Company 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.2
22,624,955 22,879,489 123,126,897 410,546 22,287,825 145,825,268TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
PacifiCorp X
/ /2019/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including 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. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification(b)
SFP 82,085 82,085 18,432 18,432Nevada Power Company 1
NF 99,408 99,408 26,087 25,707NorthWestern Corp. 2
OS 4,961 4,961NorthWestern Corp. 3
SFP 43,846 43,846NorthWestern Corp. 4
LFP 849,352 849,352 219,375 219,375Platte River Pwr Auth 5
OS 19,353 19,353Platte River Pwr Auth 6
LFP 75,360 75,360 105,024 105,024Portland Gen. Electric 7
NF 2,402 2,402 2,435 2,435Portland Gen. Electric 8
OLF 1,000 1,000Portland Gen. Electric 9
OS 7,481 7,481 4,713Portland Gen. Electric 10
LFP 1,062,752 1,062,752 438,800 438,800Public Service Co of CO 11
AD -17 -17Public Service CO of NM 12
NF 281 281Public Service CO of NM 13
OS 27 27Public Service CO of NM 14
NF 8,638 8,638 1,400 1,400Salt River Project 15
OS 1,246 1,246Salt River Project 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.3
22,624,955 22,879,489 123,126,897 410,546 22,287,825 145,825,268TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
PacifiCorp X
/ /2019/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including 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. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification(b)
NF 6,742 6,742 1,201 1,201Sierra Pacific Power Co 1
OS 39,838 39,838Sierra Pacific Power Co 2
SFP 274,372 274,372 80,256 80,256Sierra Pacific Power Co 3
AD 693 693Surprise Valley Electr. 4
OLF 6,523 6,523Surprise Valley Electr. 5
LFP 1,062,752 1,062,752 438,800 438,800Tri-State Gen and Trans 6
NF 74,770 74,770 14,954 14,954Tri-State Gen and Trans 7
OS 11,968 11,968Tri-State Gen and Trans 8
AD -755 -755Tucson Electric Pwr Co. 9
AD -240 -240Western Area Power Admn 10
FNS 6,555,320 6,555,320 901,615 901,615Western Area Power Admn 11
LFP 2,403,334 2,403,334 899,250 899,250Western Area Power Admn 12
NF 624,329 624,329 267,375 267,375Western Area Power Admn 13
OS 788,095 788,095Western Area Power Admn 14
SFP 11,375 11,375 185,885 185,885Western Area Power Admn 15
AD -128,664 -128,664Westport Field Srv LLC 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.4
22,624,955 22,879,489 123,126,897 410,546 22,287,825 145,825,268TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
PacifiCorp X
/ /2019/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including 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. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification(b)
LFP -2,403,434 -2,403,434Westport Field Srv LLC 1
-80,507 -80,507Accrual 2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332.5
22,624,955 22,879,489 123,126,897 410,546 22,287,825 145,825,268TOTAL
Schedule Page: 332 Line No.: 1 Column: b
Adams Solar Center LLC - contract termination date: October 30, 2036.
Schedule Page: 332 Line No.: 1 Column: g
Reimbursement for third party services.
Schedule Page: 332 Line No.: 2 Column: b
Ancillary services.
Schedule Page: 332 Line No.: 2 Column: g
Ancillary services.
Schedule Page: 332 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 3 Column: g
Settlement adjustment.
Schedule Page: 332 Line No.: 5 Column: b
Arizona Public Service Company - Legacy contract executed between PacifiCorp and Arizona
Public Service Company concerning the exchange of transmission services over agreed-upon
facilities (Restated Transmission Service Agreement between PacifiCorp and Arizona Public
Service Company, Rate Schedule 436). The contract terminates when the Cholla Plant, Unit 4
has been retired from service and all costs of terminating Unit 4 have been paid. See also
page 328-330, Transmission of electricity for others in this Form No. 1.

Schedule Page: 332 Line No.: 6 Column: b
Ancillary services.
Schedule Page: 332 Line No.: 6 Column: g
Ancillary services.
Schedule Page: 332 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 9 Column: g
Settlement adjustment.
Schedule Page: 332 Line No.: 13 Column: a
Complete name is Basin Electric Power Cooperative, Inc.
Schedule Page: 332 Line No.: 14 Column: b
Big Horn Rural Electric Company - contract termination date: March 10, 2021.
Schedule Page: 332 Line No.: 14 Column: g
Use of facilities.
Schedule Page: 332 Line No.: 15 Column: b
Settlement adjustment.
Schedule Page: 332 Line No.: 15 Column: g
Settlement adjustment.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 332.1 Line No.: 1 Column: b
Ancillary services.
Schedule Page: 332.1 Line No.: 1 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 332.1 Line No.: 3 Column: g
Settlement adjustment.
Schedule Page: 332.1 Line No.: 5 Column: b
Bonneville Power Administration - contract termination dates: October 1, 2019; November 1,
2019; November 1, 2020; January 1, 2021; July 1, 2021; September 1, 2021; November 1,
2021; December 1, 2021; January 1, 2022; March 1, 2022; April 1, 2022; July 1, 2022;
November 1, 2022; March 1, 2023; July 1, 2023; October 1, 2023; December 1, 2023; January
1, 2024; July 1, 2024; September 1, 2024; October 1, 2024; November 1, 2024; October 1,
2027; November 1, 2033 and evergreen.
Schedule Page: 332.1 Line No.: 7 Column: b
Bonneville Power Administration - contract termination dates: September 30, 2023;
September 30, 2027 and evergreen.
Schedule Page: 332.1 Line No.: 8 Column: b
Bonneville Power Administration - Legacy contract executed between PacifiCorp and
Bonneville Power Administration concerning the exchange of transmission services over
agreed-upon facilities ("Midpoint-Meridian Transmission Agreement", Rate Schedule 369).
This agreement runs concurrently with the AC Intertie Agreement (Rate Schedule 368), which
terminates when the facilities subject to that agreement are taken out of service. See
also page 328-330, Transmission of electricity for others in this Form No. 1.
Schedule Page: 332.1 Line No.: 8 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.1 Line No.: 10 Column: a
This footnote applies to all occurrences of "CA Ind Sys Operator" on page 332. Complete
name is California Independent System Operator Corporation.
Schedule Page: 332.1 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 332.1 Line No.: 10 Column: g
Settlement adjustment.
Schedule Page: 332.1 Line No.: 11 Column: b
Ancillary services.
Schedule Page: 332.1 Line No.: 11 Column: g
Ancillary services.
Schedule Page: 332.1 Line No.: 13 Column: a
This footnote applies to all occurrences of "Deseret Gen and Trans" on page 332. Complete
name is Deseret Generation and Transmission Co-operative.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 332.1 Line No.: 13 Column: b
Deseret Generation and Transmission Co-operative - contract termination date: November 1,
2022.
Schedule Page: 332.1 Line No.: 15 Column: b
Elbe Solar Center, LLC - contract termination date: October 30, 2036.
Schedule Page: 332.1 Line No.: 15 Column: g
Reimbursement for third party services.
Schedule Page: 332.1 Line No.: 16 Column: b
Ancillary services.
Schedule Page: 332.1 Line No.: 16 Column: g
Ancillary services.
Schedule Page: 332.2 Line No.: 1 Column: a
Complete name is Flathead Electric Cooperative, Inc.
Schedule Page: 332.2 Line No.: 1 Column: b
Use of facilities.
Schedule Page: 332.2 Line No.: 1 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 2 Column: a
Complete name is Hermiston Generating Company, L.P. who operates the Hermiston Plant and
is jointly owned. PacifiCorp owns 50% of the Hermiston plant.
Schedule Page: 332.2 Line No.: 2 Column: b
Use of facilities.
Schedule Page: 332.2 Line No.: 2 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 3 Column: b
Settlement adjustment.
Schedule Page: 332.2 Line No.: 3 Column: g
Settlement adjustment.
Schedule Page: 332.2 Line No.: 5 Column: b
Idaho Power Company - contract termination dates: April 1, 2025 and July 1, 2025.
Schedule Page: 332.2 Line No.: 7 Column: b
Idaho Power Company - The contract termination date of August 31, 2022, shall
automatically renew for each successive one year period thereafter unless or until the
earlier of (i) one year following Department of Energy’s receipt of written notice by
PacifiCorp, if due to a re-configuration of its transmission system PacifiCorp no longer
needs use of the Department of Energy, Scoville Facilities; or (ii) upon mutual agreement
of the parties.
Schedule Page: 332.2 Line No.: 7 Column: g
Use of facilities.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 332.2 Line No.: 8 Column: b
Ancillary services.
Schedule Page: 332.2 Line No.: 8 Column: g
Ancillary services.
Schedule Page: 332.2 Line No.: 10 Column: a
This footnote applies to all occurrences of "LA Dept. of Water & Pwr" on page 332.
Complete name is Los Angeles Department of Water and Power.
Schedule Page: 332.2 Line No.: 10 Column: b
Ancillary services.
Schedule Page: 332.2 Line No.: 10 Column: g
Ancillary services.
Schedule Page: 332.2 Line No.: 12 Column: a
Complete name is Moon Lake Electric Association Inc.
Schedule Page: 332.2 Line No.: 12 Column: g
Use of facilities.
Schedule Page: 332.2 Line No.: 13 Column: b
Morgan City Corporation - contract termination date: Evergreen.
Schedule Page: 332.2 Line No.: 14 Column: a
This footnote applies to all occurrences of "Nevada Power Company" on page 332. Nevada
Power Company is a wholly owned subsidiary of NV Energy, Inc., which is an indirect wholly
owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's indirect parent
company.
Schedule Page: 332.2 Line No.: 14 Column: b
Settlement adjustment.
Schedule Page: 332.2 Line No.: 14 Column: g
Settlement adjustment.
Schedule Page: 332.2 Line No.: 16 Column: b
Ancillary services.
Schedule Page: 332.2 Line No.: 16 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 3 Column: b
Ancillary services.
Schedule Page: 332.3 Line No.: 3 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 5 Column: a
This footnote applies to all occurrences of "Platte River Pwr Auth" on page 332. Complete
name is Platte River Power Authority.
Schedule Page: 332.3 Line No.: 5 Column: b
Platte River Power Authority - contract termination date: October 31, 2022.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 332.3 Line No.: 6 Column: b
Ancillary services.
Schedule Page: 332.3 Line No.: 6 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 7 Column: a
This footnote applies to all occurrences of "Portland Gen. Electric" on page 332. Complete
name is Portland General Electric Company.
Schedule Page: 332.3 Line No.: 7 Column: b
Portland General Electric Company - contract termination date: April 1, 2022.
Schedule Page: 332.3 Line No.: 9 Column: b
Portland General Electric Company - contract termination date: Upon two years written
notice.
Schedule Page: 332.3 Line No.: 9 Column: g
Use of facilities.
Schedule Page: 332.3 Line No.: 10 Column: b
Ancillary services.
Schedule Page: 332.3 Line No.: 10 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 11 Column: a
Complete name is Public Service Company of Colorado.
Schedule Page: 332.3 Line No.: 11 Column: b
Public Service Company of Colorado - contract termination date: The date that all
generating plants comprising PacifiCorp resources associated with this agreement have been
retired from service or interests transferred.
Schedule Page: 332.3 Line No.: 12 Column: a
This footnote applies to all occurrences of "Public Service Co of NM" on page 332.
Complete name is Public Service Company of New Mexico.
Schedule Page: 332.3 Line No.: 12 Column: b
Settlement adjustment.
Schedule Page: 332.3 Line No.: 12 Column: g
Settlement adjustment.
Schedule Page: 332.3 Line No.: 14 Column: b
Ancillary services.

Schedule Page: 332.3 Line No.: 14 Column: g
Ancillary services.
Schedule Page: 332.3 Line No.: 16 Column: b
Ancillary services.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Schedule Page: 332.3 Line No.: 16 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 1 Column: a
This footnote applies to all occurrences of "Sierra Pacific Power Co" on page 332. Sierra
Pacific Power Company is a wholly owned subsidiary of NV Energy, Inc., which is an
indirect wholly owned subsidiary of Berkshire Hathaway Energy Company, PacifiCorp's
indirect parent company.
Schedule Page: 332.4 Line No.: 2 Column: b
Ancillary services.
Schedule Page: 332.4 Line No.: 2 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 4 Column: a
This footnote applies to all occurrences of "Surprise Valley Electr." on page 332.
Complete name is Surprise Valley Electrification Corp.
Schedule Page: 332.4 Line No.: 4 Column: b
Settlement adjustment.
Schedule Page: 332.4 Line No.: 4 Column: g
Settlement adjustment.
Schedule Page: 332.4 Line No.: 5 Column: b
Surprise Valley Electrification Corp. - contract termination date: Evergreen.
Schedule Page: 332.4 Line No.: 5 Column: g
Use of facilities.
Schedule Page: 332.4 Line No.: 6 Column: a
This footnote applies to all occurrences of "Tri-State Gen and Trans" on page 332. The
complete name is Tri-State Generation and Transmission Association, Inc.
Schedule Page: 332.4 Line No.: 6 Column: b
Tri-State Generation and Transmission Association, Inc. - contract termination date: The
date that all generating plants comprising PacifiCorp resources associated with this
agreement have been retired from service or interests transferred.
Schedule Page: 332.4 Line No.: 8 Column: b
Ancillary services.
Schedule Page: 332.4 Line No.: 8 Column: g
Ancillary services.
Schedule Page: 332.4 Line No.: 9 Column: a
The complete name is Tucson Electric Power Company.
Schedule Page: 332.4 Line No.: 9 Column: b
Settlement adjustment.
Schedule Page: 332.4 Line No.: 9 Column: g
Settlement adjustment.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.6
Schedule Page: 332.4 Line No.: 10 Column: b
Settlement adjustment.
Schedule Page: 332.4 Line No.: 10 Column: g
Settlement adjustment.
Schedule Page: 332.4 Line No.: 12 Column: b
Western Area Power Administration - contract termination date: May 31, 2022.
Schedule Page: 332.4 Line No.: 14 Column: b
Western Area Power Administration - Legacy contract (Rate Schedule 684) executed between
PacifiCorp and Western Area Power Administration concerning the exchange of transmission
services over agreed-upon facilities. The contract terminates 50 years from execution. See
also page 328-330, Transmission of electricity for others in this Form No. 1.
Schedule Page: 332.4 Line No.: 14 Column: g
Ancillary services. Use of facilities.
Schedule Page: 332.4 Line No.: 16 Column: b
Settlement adjustment.
Schedule Page: 332.4 Line No.: 16 Column: g
Settlement adjustment.
Schedule Page: 332.5 Line No.: 1 Column: b
Westport Field Services, LLC - contract termination date: Evergreen.
Schedule Page: 332.5 Line No.: 1 Column: g
Reimbursement for third party services.
Schedule Page: 332.5 Line No.: 2 Column: g
Represents the difference between actual wheeling expenses for the period as reflected on
the individual line items within this schedule and the accruals charged to Account 565,
Transmission of electricity by others, during this period.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
PacifiCorp X / /2019/Q4
Line Description Amount
(b)(a)No.
1,376,461Industry Association Dues 1
Nuclear Power Research Expenses 2
Other Experimental and General Research Expenses 3
Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 4
Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 5
6
Business & Economic Development and 7
Corporate Memberships & Subscriptions: 8
5,000 Carbon County Economic Development Corporation 9
5,000 Clatsop Economic Development Resources 10
7,500 Economic Development for Central Oregon 11
12,500 Forth (Drive Oregon) 12
5,000 Greater Yakima Chamber of Commerce 13
5,000 Klamath County Economic Development Association 14
5,000 Laramie Chamber of Business Alliance 15
6,000 Ogden-Weber Chamber of Commerce 16
33,447 Oregon Business Council 17
13,500 Oregon Economic Development Association 18
5,000 Oregon Sports Authority 19
7,000 Redmond Economic Development, Inc. 20
30,000 Salt Lake Chamber 21
5,000 South Coast Development Council, Inc. 22
5,000 South Valley Chamber 23
7,500 Southern Oregon Regional Economic Development, Inc 24
10,471 Utah Manufacturers Association 25
18,700 Utah Taxpayers Association 26
8,750 Utah Technology Council 27
6,500 Utah Valley Chamber of Commerce 28
15,000 Walla Walla Valley Chamber of Commerce 29
5,000 Wyoming Business Alliance 30
7,980 Yakima County Development Association 31
137,596 Other (Individually < $5,000) 32
33
Rating Agency and Trustee Fees: 34
127,965 The Bank of New York Mellon 35
17,857 Computershare Shareowner Services, LLC 36
121,854 Moody's Investors Service 37
198,940 Standard and Poor's Financial Services, LLC 38
13,624 U.S. Bank National Association 39
1,035 Other (Individually < $5,000) 40
41
18,872Directors' Fees - Regional Advisory Board 42
43
20General - Other 44
45
2,244,072
FERC FORM NO. 1 (ED. 12-94) Page 335
46 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
PacifiCorp X
/ /2019/Q4
Line
No.Functional Classification Depreciation
(d)(b)(a)
Amortization of
Total
(Except amortization of aquisition adjustments)
A. Summary of Depreciation and Amortization Charges
Expense(Account 403)
Limited TermElectric Plant Amortization ofOther ElectricPlant (Acc 405)(e) (f)
1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included
in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the
bottom of section C the amounts and nature of the provisions and the plant items to which related.
(Account 404)(c)
DepreciationExpense for AssetRetirement Costs(Account 403.1)
48,671,914 48,671,914 1 Intangible Plant
277,542,946 277,542,946 2 Steam Production Plant
3 Nuclear Production Plant
38,630,838 38,319,142 311,696 4 Hydraulic Production Plant-Conventional
5 Hydraulic Production Plant-Pumped Storage
247,234,128 247,234,128 6 Other Production Plant
112,507,659 112,507,659 7 Transmission Plant
161,981,289 161,981,289 8 Distribution Plant
9 Regional Transmission and Market Operation
43,110,635 42,404,362 706,273 10 General Plant
11 Common Plant-Electric
929,679,409 879,989,526 49,689,883 12 TOTAL
The Amortization of Limited-Term Electric Plant is based on straight-line amortization over the life of the asset.
FERC FORM NO. 1 (REV. 12-03) Page 336
B. Basis for Amortization Charges
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.Account No.
(c)(b)(a)(d) (e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f) (g)(Percent)
HYDRAULIC PROD. 12
WIND GENERATION 13
Foote Creek 14
3.20340.20 All States 5,526 15
16
17
Acct 403 - Provisions 18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337
Schedule Page: 336 Line No.: 12 Column: b
Depreciation expense associated with transportation equipment is generally charged to
operations and maintenance expense and construction work in progress. During the year
ended December 31, 2019, depreciation expense associated with transportation equipment was
$16,386,376.
Schedule Page: 336 Line No.: 12 Column: e
Generally, PacifiCorp records the depreciation expense of asset retirement obligations as
either a regulatory asset or liability.

Schedule Page: 336 Line No.: 12 Column: a
The depreciation rate changes are for the Klamath hydroelectric system’s four mainstem
dams (JC Boyle, Iron Gate, Copco No. 1 and Copco No. 2). For further discussion, refer to
Note 14 of Notes to Financial Statements in this Form No. 1.
Account
No.
(a)
Depreciable
Plant Base
($000s)
(b)
Estimated
Avg.
Service
Life
(c)
Net
Salvage
(Percent)
(d)
Applied
Depr.
Rates
(Percent)
(e)
Mortality
Curve
Type
(f)
Average
Remaining
Life
(g)
HYDRAULIC PRODUCTION
Klamath River Accelerated
330.20 CA/OR $ 41 -
330.40 CA/OR 1 -
331.00 CA/OR 16,990 -
332.00 CA/OR 39,624 -
333.00 CA/OR 18,254 -
334.00 CA/OR 16,630 -
335.00 CA/OR 182 -
336.00 CA/OR 2,753 -
Total $ 94,475 12.77
Schedule Page: 336 Line No.: 18 Column: a
For a discussion on provisions for depreciation that were made during the year, refer to
Note 3 of Notes to the Financial Statements in this Form No. 1.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES
PacifiCorp X
/ /2019/Q4
Line
No.
Description Assessed by
(c)(b)(a)
Total Expense forExpenses
of
(d)
(Furnish name of regulatory commission or body the Regulatory
docket or case number and a description of the case)Commission Utility Current Year(b) + (c)
Deferredin Account182.3 at Beginning of Year(e)
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.
Utah Public Service Commission: 1
Annual Fee 6,244,201 6,244,201 2
Rate Cases and Proceedings 267,955 267,955 3
4
Oregon Public Utility Commission: 5
Annual Fee 3,374,491 3,374,491 6
Rate Cases and Proceedings 782,606 782,606 7
926,951 Deferred Intervenor Funding Grants 8
9
Wyoming Public Service Commission: 10
Annual Fee 1,752,156 1,752,156 11
Rate Cases and Proceedings 144,671 144,671 12
13
Washington Utilities and Transportation 14
Commission: 15
Annual Fee 627,091 627,091 16
Rate Cases and Proceedings 410,854 410,854 17
18
Idaho Public Utilities Commission: 19
Annual Fee 683,750 683,750 20
Rate Cases and Proceedings 90,230 90,230 21
66,865 Deferred Intervenor Funding Grants 22
23
California Public Utilities Commission: 24
Annual Fee 1,439 1,439 25
Rate Cases and Proceedings 650,752 650,752 26
41,995 Deferred Intervenor Funding Grants 27
28
California Environmental Protection Agency: 29
Industry Compliance Fee 70,935 8,012 78,947 30
31
Multi-State: 32
Rate Cases and Proceedings 315,890 315,890 33
Other Regulatory 1,571,261 1,571,261 34
35
Federal Energy Regulatory Commission: 36
Annual Fee 2,468,009 2,468,009 37
Annual Fee - Hydroelectric Plants 2,658,529 2,658,529 38
Transmission Rate Cases 245,707 245,707 39
Other Regulatory 3,237,297 3,237,297 40
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96) Page 350
46 TOTAL 17,880,601 7,725,235 25,605,836 1,035,811
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
(j)(i)(f)(k) (l)
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO
Department AccountNo.(g)
Amount
(h)
Deferred to
Account 182.3
Contra
Account Amount Deferred in Account 182.3End of Year
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.
1
Electric 2 6,244,201928
Electric 3 267,955928
4
5
Electric 6 3,374,491928
Electric 7 782,606928
1,496,800 569,849 8
9
10
Electric 11 1,752,156928
Electric 12 144,671928
13
14
15
Electric 16 627,091928
Electric 17 410,854928
18
19
Electric 20 683,750928
Electric 21 90,230928
66,865 22
23
24
Electric 25 1,439928
Electric 26 650,752928
43,749 1,754 27
28
29
Electric 30 78,947928
31
32
Electric 33 315,890928
Electric 34 1,571,261928
35
36
Electric 37 2,468,009928
Electric 38 2,658,529928
Electric 39 245,707928
Electric 40 3,237,297928
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96) Page 351
46 25,605,836 571,603 1,607,414
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
PacifiCorp X
/ /2019/Q4
Line
No.
Description
(b)(a)
Classification
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.(Identify
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, development, and demonstration in Uniform System of Accounts).
2. Indicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, D & D Performed Internally: a. Overhead
(1) Generation b. Underground
a. hydroelectric (3) Distribution
i. Recreation fish and wildlife (4) Regional Transmission and Market Operation
ii Other hydroelectric (5) Environment (other than equipment)
b. Fossil-fuel steam (6) Other (Classify and include items in excess of $50,000.)
c. Internal combustion or gas turbine (7) Total Cost Incurred
d. Nuclear B. Electric, R, D & D Performed Externally:
e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric
f. Siting and heat rejection Power Research Institute
(2) Transmission
A. Electric R, D & D Performed Internally: 1
WestSmart Electric Vehicle Project (6) Other 2
Utah Sustainable Transportation and Energy Plan (6) Other 3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87) Page 352
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
AMOUNTS CHARGED IN CURRENT YEAR
(e)(c)
Costs Incurred Internally
Current Year Costs Incurred Externally
Current Year
(d)Account Amount(f)
Unamortized
Accumulation
(g)
(2) Research Support to Edison Electric Institute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classify)
(5) Total Cost Incurred
3. Include 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)) classify 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 Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account 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 at the end of the year.
6. If costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by "Est."
7. Report separately research and related testing facilities operated by the respondent.
1
80,399 2 80,399
305,348 3 2,688,430 107,908 2,993,778
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87) Page 353
Schedule Page: 352 Line No.: 2 Column: b
In December 2016, PacifiCorp was selected for a $4 million grant from the U.S. Department
of Energy to install, operate and collect data on plug-in electric vehicle charging
stations located on 1,500 miles of interstate across Utah, Idaho and Wyoming. A component
of this program related to research, development and demonstration activities is to manage
and design an electric grid to handle widespread electric vehicle charging requirements in
collaboration with the University of Utah.
Schedule Page: 352 Line No.: 2 Column: e
Account 557, Other expenses
Account 560, Operation supervision and engineering
Account 908, Customer assistance expenses
Schedule Page: 352 Line No.: 3 Column: b
The Utah Sustainable Transportation and Energy Plan was signed into law in March 2016. The
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-scale battery storage and other innovative technology, economic
development and air quality initiatives.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DISTRIBUTION OF SALARIES AND WAGES
PacifiCorp X
/ /2019/Q4
Line
No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)
Distribution Payroll charged forClearing Accounts
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Electric 1
Operation 2
98,500,178Production 3
15,242,556Transmission 4
Regional Market 5
36,832,966Distribution 6
32,939,624Customer Accounts 7
7,320,919Customer Service and Informational 8
Sales 9
41,187,581Administrative and General 10
232,023,824TOTAL Operation (Enter Total of lines 3 thru 10) 11
Maintenance 12
45,001,166Production 13
11,616,988Transmission 14
Regional Market 15
71,750,912Distribution 16
1,608,102Administrative and General 17
129,977,168TOTAL Maintenance (Total of lines 13 thru 17) 18
Total Operation and Maintenance 19
143,501,344Production (Enter Total of lines 3 and 13) 20
26,859,544Transmission (Enter Total of lines 4 and 14) 21
Regional Market (Enter Total of Lines 5 and 15) 22
108,583,878Distribution (Enter Total of lines 6 and 16) 23
32,939,624Customer Accounts (Transcribe from line 7) 24
7,320,919Customer Service and Informational (Transcribe from line 8) 25
Sales (Transcribe from line 9) 26
42,795,683Administrative and General (Enter Total of lines 10 and 17) 27
362,000,992 362,000,992TOTAL Oper. and Maint. (Total of lines 20 thru 27) 28
Gas 29
Operation 30
Production-Manufactured Gas 31
Production-Nat. Gas (Including Expl. and Dev.) 32
Other Gas Supply 33
Storage, LNG Terminaling and Processing 34
Transmission 35
Distribution 36
Customer Accounts 37
Customer Service and Informational 38
Sales 39
Administrative and General 40
TOTAL Operation (Enter Total of lines 31 thru 40) 41
Maintenance 42
Production-Manufactured Gas 43
Production-Natural Gas (Including Exploration and Development) 44
Other Gas Supply 45
Storage, LNG Terminaling and Processing 46
Transmission 47
FERC FORM NO. 1 (ED. 12-88) Page 354
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)
Distribution Payroll charged forClearing Accounts
DISTRIBUTION OF SALARIES AND WAGES (Continued)
Distribution 48
Administrative and General 49
TOTAL Maint. (Enter Total of lines 43 thru 49) 50
Total Operation and Maintenance 51
Production-Manufactured Gas (Enter Total of lines 31 and 43) 52
Production-Natural Gas (Including Expl. and Dev.) (Total lines 32, 53
Other Gas Supply (Enter Total of lines 33 and 45) 54
Storage, LNG Terminaling and Processing (Total of lines 31 thru 47) 55
Transmission (Lines 35 and 47) 56
Distribution (Lines 36 and 48) 57
Customer Accounts (Line 37) 58
Customer Service and Informational (Line 38) 59
Sales (Line 39) 60
Administrative and General (Lines 40 and 49) 61
TOTAL Operation and Maint. (Total of lines 52 thru 61) 62
Other Utility Departments 63
Operation and Maintenance 64
362,000,992 362,000,992TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65
Utility Plant 66
Construction (By Utility Departments) 67
163,070,510 163,070,510Electric Plant 68
Gas Plant 69
Other (provide details in footnote): 70
163,070,510 163,070,510TOTAL Construction (Total of lines 68 thru 70) 71
Plant Removal (By Utility Departments) 72
9,955,796 9,955,796Electric Plant 73
Gas Plant 74
Other (provide details in footnote): 75
9,955,796 9,955,796TOTAL Plant Removal (Total of lines 73 thru 75) 76
Other Accounts (Specify, provide details in footnote): 77
5,959,817 5,959,817Fuel Stock 78
514,397 514,397Miscellaneous Other Income Deductions 79
912,471 912,471Miscellaneous Non-Operating and Non-Utility 80
698,114 698,114Charges to Affiliates 81
82
83
84
85
86
87
88
89
90
91
92
93
94
8,084,799 8,084,799TOTAL Other Accounts 95
543,112,097 543,112,097TOTAL SALARIES AND WAGES 96
FERC FORM NO. 1 (ED. 12-88) Page 355
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.
Description of Item(s) Balance at End of
(c)(b)(a)
Balance at End of
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
Quarter 1 Quarter 2
Balance at End of
Quarter 3
(d) (e)
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 items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for
purposes of determining 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
whether a net purchase or sale has occurred. In 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.
Balance at End of
Year
Energy 1
Net Purchases (Account 555) 2 2,663,242 347,365 362,023 2,553,768
Net Sales (Account 447) 3 ( 131,343)( 74,013) ( 103,837) ( 131,342)
Transmission Rights 4
Ancillary Services 5
Other Items (list separately) 6
Energy Imbalance Market (Account 555) 7 ( 38,601,478)( 32,890,418) ( 6,951,983) ( 14,615,028)
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
( 36,069,579)( 32,617,066) ( 6,693,797) ( 12,192,602)
FERC FORM NO. 1/3-Q (NEW. 12-05) Page 397
46 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASES AND SALES OF ANCILLARY SERVICES
PacifiCorp X
/ /2019/Q4
Line
No.
Type of Ancillary Service
(a)
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during the
year. Include in a footnote and specify the amount for each type of other ancillary service provided.
Number of Units
Unit of
Measure Dollars
(b) (c) (d)
Number of Units
Unit of
Measure Dollars
(e) (f) (g)
Usage - Related Billing Determinant Usage - Related Billing Determinant
Amount Purchased for the Year Amount Sold for the Year
12,048,930MWh135,632,339Scheduling, System Control and Dispatch 1
8,271,361MWh129,422,935 7,287,885MWh114,577,957Reactive Supply and Voltage 2
41,056,109MWh 74,862,218 33,972,358MWh 54,981,585Regulation and Frequency Response 3
18,597,634MWh -1,025,172Energy Imbalance 4
19,781,151MWh131,202,978 17,927,465MWh118,724,932Operating Reserve - Spinning 5
19,854,873MWh131,691,201 17,927,465MWh118,724,932Operating Reserve - Supplement 6
Other 7
119,610,058601,786,499 77,115,173407,009,406Total (Lines 1 thru 7) 8
FERC FORM NO. 1 (New 2-04) Page 398
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
PacifiCorp X / /2019/Q4
Line
No.
Monthly Peak
MW - Total
(c)(b)(a)
Month
NAME OF SYSTEM:
Day of
Monthly
Peak
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, furnish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the
definition of each statistical classification.
(d)
Hour of
Monthly
Peak
(e)
Firm Network
Service for Self
(f)
Firm Network
Service for
Others
(g)
Long-Term Firm
Point-to-point
Reservations
(h)
Other Long-
Term Firm
Service
(i)
Short-Term Firm
Point-to-point
Reservation
(j)
Other
Service
1,816 1,342 3,544 594 8,470 900 2 15,766January 1
1,760 1,319 3,544 562 8,790 800 7 15,975February 2
1,828 1,135 3,544 562 8,410 800 4 15,479March 3
5,404 3,796 10,632 1,718 25,670Total for Quarter 1 4
921 1,070 3,570 384 7,363 80010 13,308April 5
1,287 1,171 3,570 338 7,496180013 13,862May 6
1,705 1,546 3,701 407 8,878180028 16,237June 7
3,913 3,787 10,841 1,129 23,737Total for Quarter 2 8
1,849 1,813 3,701 471 10,436170022 18,270July 9
2,024 1,808 3,701 431 10,3141700 5 18,278August 10
1,759 1,728 3,701 409 9,9011700 5 17,498September 11
5,632 5,349 11,103 1,311 30,651Total for Quarter 3 12
1,556 1,266 3,709 557 8,465 80030 15,553October 13
1,885 1,270 3,629 481 8,316180026 15,581November 14
1,311 1,351 3,629 511 8,734180017 15,536December 15
4,752 3,887 10,967 1,549 25,515Total for Quarter 4 16
19,701 16,819 43,543 5,707 105,573
Total Year to
Date/Year
17
FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400
Schedule Page: 400 Line No.: 1 Column: d
Pacific Standard Time
Schedule Page: 400 Line No.: 2 Column: d
Pacific Standard Time
Schedule Page: 400 Line No.: 3 Column: d
Pacific Standard Time
Schedule Page: 400 Line No.: 5 Column: d
Pacific Daylight Time
Schedule Page: 400 Line No.: 6 Column: d
Pacific Daylight Time
Schedule Page: 400 Line No.: 7 Column: d
Pacific Daylight Time
Schedule Page: 400 Line No.: 9 Column: d
Pacific Daylight Time

Schedule Page: 400 Line No.: 10 Column: d
Pacific Daylight Time
Schedule Page: 400 Line No.: 11 Column: d
Pacific Daylight Time
Schedule Page: 400 Line No.: 13 Column: d
Pacific Daylight Time
Schedule Page: 400 Line No.: 14 Column: d
Pacific Standard Time
Schedule Page: 400 Line No.: 15 Column: d
Pacific Standard Time
Schedule Page: 400 Line No.: 17 Column: e
Year-to-date 2019 Net System Load information was compiled using metering and/or
scheduling data. Reflects actual peak net system load for self at time of Transmission
System Peak. Peak load includes behind-the-meter generation.
Schedule Page: 400 Line No.: 17 Column: f
Year-to-date 2019 Net System Load information was compiled using metering and/or
scheduling data. Reflects actual peak of customers' load at time of Transmission System
Peak.
Schedule Page: 400 Line No.: 17 Column: g
Year-to-date 2019 Net System Load information was compiled using reservations in 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
measured by the transmission system loss factor. This adjustment has been made to ensure
that transmission rates are designed fairly and in a non-discriminatory manner and is
consistent with the system input measurement utilized for other long-term firm users of
PacifiCorp’s transmission system, including network service.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 400 Line No.: 17 Column: i
Year-to-date 2019 Net System Load information was compiled using reservations in OASIS at
time of Transmission System Peak.
Schedule Page: 400 Line No.: 17 Column: j
Year-to-date 2019 Net System Load information was compiled using metering, scheduling
and/or contractual data. Reflects actual peak and/or contractual demands of customers'
load at time of Transmission System Peak.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC ENERGY ACCOUNT
PacifiCorp X
/ /2019/Q4
Line
No.
Item
(a)(b)(a)(b)
Line
No.MegaWatt Hours Item MegaWatt Hours
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
SOURCES OF ENERGY1
Generation (Excluding Station Use):2
38,283,488Steam3
Nuclear4
2,839,382Hydro-Conventional5
Hydro-Pumped Storage6
10,626,462Other7
2,155Less Energy for Pumping8
51,747,177Net Generation (Enter Total of lines 3
through 8)
9
12,097,791Purchases10
Power Exchanges:11
7,707,795Received12
6,826,841Delivered13
880,954Net Exchanges (Line 12 minus line 13)14
Transmission For Other (Wheeling)15
15,241,847Received16
15,129,193Delivered17
112,654Net Transmission for Other (Line 16 minus
line 17)
18
-254,534Transmission By Others Losses19
64,584,042TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
20
DISPOSITION OF ENERGY21
55,342,607Sales to Ultimate Consumers (Including
Interdepartmental Sales)
22
302,600Requirements Sales for Resale (See
instruction 4, page 311.)
23
5,177,028Non-Requirements Sales for Resale (See
instruction 4, page 311.)
24
Energy Furnished Without Charge25
125,044Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
26
3,636,763Total Energy Losses27
64,584,042TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
28
FERC FORM NO. 1 (ED. 12-90)Page 401a
(d)
Day of Month
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MONTHLY PEAKS AND OUTPUT
PacifiCorp X / /2019/Q4
Line
No.Total Monthly Energy Megawatts
(c)(b)(a)
Hour
(e)
MONTHLY PEAK
Month
NAME OF SYSTEM:
Monthly Non-RequirmentsSales for Resale &Associated Losses (See Instr. 4)
1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
2. Report in column (b) by month the system’s output in Megawatt hours for each month.
3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
4. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system.
5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
(f)
January 29 2 8,269 839,278 1800 PST 6,116,979
February 30 7 8,604 538,253 0800 PST 5,452,600
March 31 4 8,218 435,285 0800 PST 5,303,501
April 32 10 7,167 397,398 0800 PDT 4,734,818
May 33 13 7,311 253,950 1800 PDT 4,786,585
June 34 12 8,747 255,956 1700 PDT 5,062,773
July 35 22 10,334 218,029 1700 PDT 5,883,677
August 36 5 10,220 177,393 1700 PDT 5,797,896
September 37 5 9,722 397,374 1700 PDT 5,165,778
October 38 30 8,274 525,643 0800 PDT 5,230,095
November 39 26 8,081 613,690 1800 PST 5,297,562
December 40 17 8,498 524,779 1800 PST 5,751,778
FERC FORM NO. 1 (ED. 12-90) Page 401b
41 TOTAL 64,584,042 5,177,028
Schedule Page: 401 Line No.: 26 Column: b
For metered locations only.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
ColstripCholla
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
SteamSteam 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
ConventionalFull Outdoor 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
19841981 3 Year Originally Constructed
19861981 4 Year Last Unit was Installed
155.61414.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
162374 6 Net Peak Demand on Plant - MW (60 minutes)
86035312 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
148395 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
00 11 Average Number of Employees
10828200001482932000 12 Net Generation, Exclusive of Plant Use - KWh
17886442635317 13 Cost of Plant: Land and Land Rights
6767639765595551 14 Structures and Improvements
171025121484419888 15 Equipment Costs
827764122278622 16 Asset Retirement Costs
248767803574929378 17 Total Cost
1598.66211388.7183 18 Cost per KW of Installed Capacity (line 17/5) Including
304682307136 19 Production Expenses: Oper, Supv, & Engr
1709164741486521 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
9866606114697 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
51410309411 25 Electric Expenses
19068652052900 26 Misc Steam (or Nuclear) Power Expenses
100420 27 Rents
00 28 Allowances
2531172359677 29 Maintenance Supervision and Engineering
3893934086250 30 Maintenance of Structures
25646394854765 31 Maintenance of Boiler (or reactor) Plant
81271055833 32 Maintenance of Electric Plant
3441401277890 33 Maintenance of Misc Steam (or Nuclear) Plant
2363650865905080 34 Total Production Expenses
0.02180.0444 35 Expenses per Net KWh
Coal Oil Composite Coal Oil Composite 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
Tons Barrels Tons Barrels 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
874610 5588 0 665474 1383 0 38 Quantity (Units) of Fuel Burned
9189 129293 0 8385 140000 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
44.008 96.105 0.000 23.976 96.428 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
46.820 96.105 0.000 25.483 96.428 0.000 41 Average Cost of Fuel per Unit Burned
2.548 17.698 2.576 1.519 16.399 1.530 42 Average Cost of Fuel Burned per Million BTU
0.028 0.000 0.028 0.016 0.000 0.016 43 Average Cost of Fuel Burned per KWh Net Gen
10839.206 20.463 10859.669 10306.855 7.511 10314.366 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03) Page 402
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
HaydenDave JohnstonCraig
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2019/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
SteamSteam Steam 1
Outdoor BoilerOutdoor Boiler Semi-Outdoor 2
19651979 1959 3
19761980 1972 4
81.37172.13 816.77 5
78161 752 6
87608727 8760 7
00 0 8
77161 745 9
00 0 10
00 195 11
4864690001166870000 4686381000 12
683069137086 10448598 13
1779721738554855 166341191 14
96325444185278568 887464165 15
212248735149 29368123 16
116928217224005658 1093622077 17
1436.99421301.3749 1338.9597 18
145370422593 15843 19
1205184123520484 49807479 20
00 0 21
11794202037591 2024824 22
00 0 23
00 0 24
393609808542 0 25
4927711112827 16810355 26
00 86157 27
00 0 28
210597792998 0 29
319054564248 4307318 30
6892913715128 14838235 31
208446604437 11731602 32
216206884870 1386180 33
1590660534463718 101007993 34
0.03270.0295 0.0216 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
609767 105 0 239090 145 03184801 13963 0 38
9689 133056 0 11294 136306 08212 138000 0 39
32.017 101.821 0.000 46.271 99.983 0.00015.171 94.695 0.000 40
38.445 101.821 0.000 50.277 99.983 0.00015.224 94.695 0.000 41
1.984 18.223 1.990 2.226 17.467 2.2310.927 16.338 0.951 42
0.020 0.000 0.020 0.025 0.000 0.0250.010 0.000 0.010 43
10126.513 0.504 10127.017 11101.555 1.702 11103.25711161.565 17.269 11178.834 44
FERC FORM NO. 1 (REV. 12-03) Page 403
Hunter Unit No. 2Hunter Unit No. 1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
SteamSteam 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
Outdoor BoilerOutdoor Boiler 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
19801978 3 Year Originally Constructed
19801978 4 Year Last Unit was Installed
294.46457.73 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
270416 6 Net Peak Demand on Plant - MW (60 minutes)
87608756 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
269418 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
00 11 Average Number of Employees
18025190002754327000 12 Net Generation, Exclusive of Plant Use - KWh
96882619688261 13 Cost of Plant: Land and Land Rights
5448230865040176 14 Structures and Improvements
250955259388792796 15 Equipment Costs
42783094278309 16 Asset Retirement Costs
319404137467799542 17 Total Cost
1084.71151021.9989 18 Cost per KW of Installed Capacity (line 17/5) Including
00 19 Production Expenses: Oper, Supv, & Engr
3250855250679932 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
62568778268308 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
85963-60931 25 Electric Expenses
-63518232914656 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
1413135889773 30 Maintenance of Structures
96331612540716 31 Maintenance of Boiler (or reactor) Plant
3595083749579 32 Maintenance of Electric Plant
385252332077 33 Maintenance of Misc Steam (or Nuclear) Plant
4752620066314110 34 Total Production Expenses
0.02640.0241 35 Expenses per Net KWh
Coal Oil Composite Coal Oil Composite 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
Tons Barrels Tons Barrels 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
1269491 2259 0 813081 1720 0 38 Quantity (Units) of Fuel Burned
11390 138000 0 11589 138000 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
0.000 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
39.742 0.000 0.000 39.766 0.000 0.000 41 Average Cost of Fuel per Unit Burned
1.745 17.415 1.752 1.716 17.648 1.724 42 Average Cost of Fuel Burned per Million BTU
0.018 0.000 0.018 0.018 0.000 0.018 43 Average Cost of Fuel Burned per KWh Net Gen
10499.604 4.753 10504.357 10455.414 5.531 10460.945 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03) Page 402.1
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
HuntingtonHunter - Total PlantHunter Unit No. 3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2019/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
SteamSteam Steam 1
Outdoor BoilerOutdoor Boiler Outdoor Boiler 2
19741983 1978 3
19771983 1983 4
996.00495.59 1247.78 5
910474 1356 6
83288481 7840 7
00 0 8
909471 1158 9
00 0 10
1600 208 11
48975410002883126000 7439972000 12
237756410274569 29651091 13
12754419193063053 212585537 14
762757587447664189 1087412244 15
100228864278309 12834927 16
902702228555280120 1342483799 17
906.32751120.4425 1075.8978 18
150870 0 19
10457149552826299 136014783 20
00 0 21
132057698989022 23514207 22
00 0 23
00 0 24
0-57347 -32315 25
98483213807812 370645 26
259640 0 27
00 0 28
15989110 0 29
24779611109881 3412789 30
135950554556362 16730239 31
7992089685322 5029984 32
822980532779 1250108 33
15415363272450130 186290440 34
0.03150.0251 0.0250 35
Coal Oil Composite Coal Oil CompositeCoal Oil Composite 36
Tons Barrels Tons BarrelsTons Barrels 37
1299243 10943 0 2219115 6142 03381815 14922 0 38
11230 138000 0 11482 138000 011376 138000 0 39
0.000 0.000 0.000 45.293 97.754 0.00039.356 99.812 0.000 40
39.824 0.000 0.000 46.852 97.754 0.00039.779 99.812 0.000 41
1.773 17.114 1.806 2.040 16.866 2.0511.748 17.221 1.766 42
0.018 0.000 0.018 0.021 0.000 0.0210.018 0.000 0.018 43
10121.250 21.999 10143.249 10404.729 7.269 10411.99810342.279 11.625 10353.904 44
FERC FORM NO. 1 (REV. 12-03) Page 403.1
NaughtonJim Bridger
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
SteamSteam 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
Outdoor BoilerOutdoor Boiler 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
19631974 3 Year Originally Constructed
19711979 4 Year Last Unit was Installed
707.201550.65 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
6491417 6 Net Peak Demand on Plant - MW (60 minutes)
87608760 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
3841415 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
112329 11 Average Number of Employees
28403740009012300000 12 Net Generation, Exclusive of Plant Use - KWh
13210311193761 13 Cost of Plant: Land and Land Rights
127175501148774873 14 Structures and Improvements
6175207291274734660 15 Equipment Costs
5091476519566856 16 Asset Retirement Costs
7969320261444270150 17 Total Cost
1126.8835931.3966 18 Cost per KW of Installed Capacity (line 17/5) Including
29935614234340 19 Production Expenses: Oper, Supv, & Engr
86682877252682285 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
791336019568003 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
18650 25 Electric Expenses
6252984-21036522 26 Misc Steam (or Nuclear) Power Expenses
14350331946 27 Rents
00 28 Allowances
1498176580006 29 Maintenance Supervision and Engineering
103153010304164 30 Maintenance of Structures
483485623037622 31 Maintenance of Boiler (or reactor) Plant
29527617389583 32 Maintenance of Electric Plant
8265832295209 33 Maintenance of Misc Steam (or Nuclear) Plant
112308698309386636 34 Total Production Expenses
0.03950.0343 35 Expenses per Net KWh
Coal Oil Composite Coal Gas Composite 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
Tons Barrels Tons MCF 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
5088688 10059 0 1540808 294181 0 38 Quantity (Units) of Fuel Burned
9336 138000 0 9965 1056 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
45.191 95.461 0.000 54.265 3.495 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
49.467 95.461 0.000 55.591 3.495 0.000 41 Average Cost of Fuel per Unit Burned
2.649 16.470 2.658 2.789 3.310 2.795 42 Average Cost of Fuel Burned per Million BTU
0.028 0.000 0.028 0.030 0.000 0.030 43 Average Cost of Fuel Burned per KWh Net Gen
10543.205 6.469 10549.674 10811.227 109.357 10920.584 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03) Page 402.2
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
HermistonGadsby SteamWyodak
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2019/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
Combined CycleSteam Steam 1
OutdoorConventional Outdoor 2
19961978 1951 3
19961978 1955 4
279.56289.66 251.64 5
251270 177 6
76177610 2294 7
00 0 8
231266 238 9
00 0 10
062 32 11
15115320001417217000 114952000 12
796929210526 1252090 13
1284058152526739 15311112 14
165639028411039819 68474405 15
407646279518 1132809 16
179684184464056602 86170416 17
642.73921602.0735 342.4353 18
09495 34410 19
2928558222490477 6669026 20
00 0 21
03295495 144257 22
00 0 23
00 0 24
71378880 0 25
03800445 3691399 26
015043 0 27
00 0 28
00 0 29
0240210 128946 30
02978981 906130 31
01175767 1166287 32
0134621 445065 33
3642347034140534 13185520 34
0.02410.0241 0.1147 35
Coal Oil Composite GasGas 36
Tons Barrels MCFMCF 37
1150788 4566 0 10809997 0 01913753 0 0 38
8096 138000 0 1046 0 01053 0 0 39
18.976 88.926 0.000 2.709 0.000 0.0003.485 0.000 0.000 40
19.191 88.926 0.000 2.709 0.000 0.0003.485 0.000 0.000 41
1.185 15.343 1.205 2.590 0.000 0.0003.309 0.000 0.000 42
0.016 0.000 0.016 0.019 0.000 0.0000.058 0.000 0.000 43
13147.486 18.675 13166.161 7481.695 0.000 0.00017530.143 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403.2
ChehalisBlundell
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Combined CycleSteam - Geothermal 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
OutdoorIndoor 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
20031984 3 Year Originally Constructed
20032007 4 Year Last Unit was Installed
593.3038.10 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
50720 6 Net Peak Demand on Plant - MW (60 minutes)
66948588 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
47732 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
1820 11 Average Number of Employees
2431536000115179000 12 Net Generation, Exclusive of Plant Use - KWh
373052741195596 13 Cost of Plant: Land and Land Rights
244609048435435 14 Structures and Improvements
328898079103009122 15 Equipment Costs
10307772272415 16 Asset Retirement Costs
358120287154912568 17 Total Cost
603.60744065.9467 18 Cost per KW of Installed Capacity (line 17/5) Including
19291243503 19 Production Expenses: Oper, Supv, & Engr
649828810 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
0265042 22 Steam Expenses
04836772 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
19346640 25 Electric Expenses
8786611739757 26 Misc Steam (or Nuclear) Power Expenses
08964 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
28915352874 30 Maintenance of Structures
0294801 31 Maintenance of Boiler (or reactor) Plant
1693967194104 32 Maintenance of Electric Plant
047548 33 Maintenance of Misc Steam (or Nuclear) Plant
697120007783365 34 Total Production Expenses
0.02870.0676 35 Expenses per Net KWh
Gas 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
MCF 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
0 0 0 16292784 0 0 38 Quantity (Units) of Fuel Burned
0 0 0 1102 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
0.000 0.000 0.000 3.988 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
0.000 0.000 0.000 3.988 0.000 0.000 41 Average Cost of Fuel per Unit Burned
0.000 0.000 0.000 3.621 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.000 0.000 0.000 0.027 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
0.000 0.000 0.000 7380.752 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03) Page 402.3
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Lake SideCurrant CreekGadsby Peakers
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2019/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
Combined CycleGas Turbine Combined Cycle 1
OutdoorOutdoor Outdoor 2
20072002 2005 3
20072002 2006 4
591.30181.05 566.90 5
518120 561 6
8193571 8654 7
00 0 8
546119 524 9
00 0 10
310 20 11
278191400019230000 2917279000 12
145322750 3403277 13
355092204263755 44247448 14
33905559981328508 307259168 15
00 134848 16
38909709485592263 355044741 17
658.0367472.7548 626.2917 18
473280 60872 19
647382431160580 64056541 20
00 0 21
00 0 22
00 0 23
00 0 24
2341763734954 1747075 25
4965090 1021373 26
00 0 27
00 0 28
00 0 29
90931058078 420484 30
00 0 31
1256397307244 920033 32
14715123631 68252 33
698042652384487 68294630 34
0.02510.1240 0.0234 35
Gas GasGas 36
MCF MCFMCF 37
244619 0 0 20079834 0 020700822 0 0 38
1057 0 0 1045 0 01042 0 0 39
4.744 0.000 0.000 3.224 0.000 0.0003.094 0.000 0.000 40
4.744 0.000 0.000 3.224 0.000 0.0003.094 0.000 0.000 41
4.489 0.000 0.000 3.085 0.000 0.0002.969 0.000 0.000 42
0.060 0.000 0.000 0.023 0.000 0.0000.022 0.000 0.000 43
13443.474 0.000 0.000 7542.521 0.000 0.0007395.894 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403.3
Lake Side 2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofPacifiCorpX
/ /2019/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Combined Cycle 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
Outdoor 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
2014 3 Year Originally Constructed
2014 4 Year Last Unit was Installed
0.00655.20 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
0626 6 Net Peak Demand on Plant - MW (60 minutes)
06230 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
0631 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
00 11 Average Number of Employees
02281902000 12 Net Generation, Exclusive of Plant Use - KWh
016794626 13 Cost of Plant: Land and Land Rights
053128704 14 Structures and Improvements
0569331831 15 Equipment Costs
00 16 Asset Retirement Costs
0639255161 17 Total Cost
0975.6642 18 Cost per KW of Installed Capacity (line 17/5) Including
054696 19 Production Expenses: Oper, Supv, & Engr
055984255 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
00 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
03127779 25 Electric Expenses
0574681 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
0957626 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
0378560 32 Maintenance of Electric Plant
015451 33 Maintenance of Misc Steam (or Nuclear) Plant
061093048 34 Total Production Expenses
0.00000.0268 35 Expenses per Net KWh
Gas 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
MCF 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
16958632 0 0 0 0 0 38 Quantity (Units) of Fuel Burned
1044 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
3.301 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
3.301 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
3.162 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.025 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
7758.462 0.000 0.000 0.000 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03) Page 402.4
Schedule Page: 402 Line No.: -1 Column: b
The Cholla Plant is operated by Arizona Public Service Company and is jointly owned.
PacifiCorp owns 100% of Unit No. 4 and 49.53% of common facilities. Data reported
represents PacifiCorp's share.
In December 2019, PacifiCorp initiated steps toward retiring Cholla Unit No. 4 by December
31, 2020.
Schedule Page: 402 Line No.: -1 Column: c
The Colstrip Plant is operated by Talen Montana, LLC and is jointly owned. PacifiCorp owns
a 10.0% share of Colstrip Plant Unit Nos. 3 and 4. Data reported represents PacifiCorp's
share.
Schedule Page: 403 Line No.: -1 Column: d
The Craig Plant is operated by Tri-State Generation and Transmission Association, Inc. and
is jointly owned. PacifiCorp owns a 19.28% share of Craig Plant Unit Nos. 1 and 2 and
12.86% of common facilities. Data reported represents PacifiCorp's share.
Schedule Page: 403 Line No.: -1 Column: f
The Hayden Plant is operated by Public Service Company of Colorado and is jointly owned.
PacifiCorp owns a 24.5% (45 MW) share of Hayden Unit No. 1, a 12.6% (33 MW) share of
Hayden Unit No. 2 and 17.5% of common facilities. Data reported represents PacifiCorp's
share.
Schedule Page: 402 Line No.: 11 Column: b
PacifiCorp does not have employees at the Cholla Plant.
Schedule Page: 402 Line No.: 11 Column: c
PacifiCorp does not have employees at the Colstrip Plant.
Schedule Page: 403 Line No.: 11 Column: d
PacifiCorp does not have employees at the Craig Plant.
Schedule Page: 403 Line No.: 11 Column: f
PacifiCorp does not have employees at the Hayden Plant.
Schedule Page: 403 Line No.: 20 Column: d
Amount includes intercompany profits.
Schedule Page: 402.1 Line No.: -1 Column: b
Hunter Unit No. 1 is operated by PacifiCorp and is jointly owned by PacifiCorp and Utah
Municipal Power Agency with an undivided interest of 93.75% and 6.25%, respectively. Data
reported represents PacifiCorp's share. Costs that were billed to minority owners for the
operation and maintenance (excluding fuel) of this unit for calendar year 2019 were $1.2
million and were primarily credited to Account 506, Miscellaneous steam power expenses.
Schedule Page: 402.1 Line No.: -1 Column: c
Hunter Unit No. 2 is operated by PacifiCorp and is jointly owned by PacifiCorp, Deseret
Power Electric Cooperative and Utah Associated Municipal Power Systems, each with an
undivided interest of 60.31%, 25.108% and 14.582%, respectively. Data reported represents
PacifiCorp's share. Costs that were billed to minority owners for the operation and
maintenance (excluding fuel) of this unit for calendar year 2019 were $11.8 million and
were primarily credited to Account 506, Miscellaneous steam power expenses.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 403.1 Line No.: -1 Column: e
Refer to Hunter Unit Nos. 1, 2 and 3 for each unit's plant statistics.
Schedule Page: 402.1 Line No.: 11 Column: b
Refer to Hunter - Total Plant for the average number of employees.
Schedule Page: 402.1 Line No.: 11 Column: c
Refer to Hunter - Total Plant for the average number of employees.
Schedule Page: 403.1 Line No.: 11 Column: d
Refer to Hunter - Total Plant for the average number of employees.
Schedule Page: 402.2 Line No.: -1 Column: b
The Jim Bridger Plant is operated by PacifiCorp and is jointly owned by PacifiCorp and
Idaho Power Company with an undivided interest of 66.67% and 33.33%, respectively. Data
reported represents PacifiCorp's share. Costs that were billed to minority owners for the
operation and maintenance (excluding fuel) of this plant for calendar year 2019 were $30.9
million and were primarily credited to Account 506, Miscellaneous steam power expenses.
Schedule Page: 402.2 Line No.: -1 Column: c
On January 30, 2019, Naughton Unit No. 3 (280 MW) was removed from service as a
coal-fueled generating unit and will be converted to a natural gas-fueled generation
resource that is expected to be completed, including all required regulatory notices and
filings, by the end of 2020.
Schedule Page: 403.2 Line No.: -1 Column: d
The Wyodak Plant is operated by PacifiCorp and is jointly owned by PacifiCorp and Black
Hills Corporation with an undivided interest of 80% and 20%, respectively. Data reported
represents PacifiCorp's share. Costs that were billed to minority owners for the operation
and maintenance (excluding fuel) of this plant for calendar year 2019 were $3.9 million
and were primarily credited to Account 506, Miscellaneous steam power expenses.
Schedule Page: 403.2 Line No.: -1 Column: f
The Hermiston Plant is operated by Hermiston Generating Company, L.P. and is jointly
owned. PacifiCorp owns a 50.0% share of the Hermiston Plant. Data reported represents
PacifiCorp's share.
Schedule Page: 403.2 Line No.: 11 Column: f
PacifiCorp does not have employees at the Hermiston Plant.
Schedule Page: 402.2 Line No.: 20 Column: b
Amount includes intercompany profits.
Schedule Page: 402.3 Line No.: -1 Column: b
All or some of the renewable energy attributes associated with generation from the
Blundell generating facility 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 energy credits or other environmental commodities.
Schedule Page: 403.3 Line No.: 11 Column: d
Refer to the Gadsby Steam Plant for the average number of employees.
Schedule Page: 402.4 Line No.: 11 Column: b
Refer to the Lake Side Plant for the average number of employees.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 402 Line No.: 36 Column: b2
Cholla Plant - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 36 Column: c2
Colstrip Plant - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 36 Column: d2
Craig Plant - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 36 Column: e2
Dave Johnston Plant - Fuel oil is used for start-up purposes.
Schedule Page: 402 Line No.: 36 Column: f2
Hayden Plant - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: b2
Hunter Plant, Unit No. 1 - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: c2
Hunter Plant, Unit No. 2 - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: d2
Hunter Plant, Unit No. 3 - Fuel oil is used for start-up purposes.
Schedule Page: 402.1 Line No.: 36 Column: e2
Hunter - Total Plant - Fuel oil is used for start-up purposes.

Schedule Page: 402.1 Line No.: 36 Column: f2
Huntington Plant - Fuel oil is used for start-up purposes.
Schedule Page: 402.2 Line No.: 36 Column: b2
Jim Bridger Plant - Fuel oil is used for start-up purposes.
Schedule Page: 402.2 Line No.: 36 Column: d2
Wyodak Plant - Fuel oil is used for start-up purposes.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
14803
Copco No. 2
14803
Copco No. 1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2019/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Kind of Plant (Run-of-River or Storage) 1 Storage Run-of-River
Plant Construction type (Conventional or Outdoor) 2 Conventional Conventional
Year Originally Constructed 3 1918 1925
Year Last Unit was Installed 4 1922 1925
Total installed cap (Gen name plate Rating in MW) 5 20.00 27.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 26 33
Plant Hours Connect to Load 7 5,648 5,677
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 28 34
(b) Under the Most Adverse Oper Conditions 10 28 34
Average Number of Employees 11 1 2
Net Generation, Exclusive of Plant Use - Kwh 12 85,841,000 108,585,000
Cost of Plant 13
Land and Land Rights 14 107,019 20,914
Structures and Improvements 15 2,106,958 2,556,192
Reservoirs, Dams, and Waterways 16 3,374,971 3,134,323
Equipment Costs 17 5,713,067 10,514,919
Roads, Railroads, and Bridges 18 133,348 551,687
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 11,435,363 16,778,035
Cost per KW of Installed Capacity (line 20 / 5) 21 571.7682 621.4087
Production Expenses 22
Operation Supervision and Engineering 23 21,216 28,641
Water for Power 24 0 0
Hydraulic Expenses 25 1,048 1,414
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 1,077,576 1,243,258
Rents 28 120,695 162,938
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 2,787 3,395
Maintenance of Reservoirs, Dams, and Waterways 31 12,324 898
Maintenance of Electric Plant 32 101,694 6,866
Maintenance of Misc Hydraulic Plant 33 15,425 20,823
Total Production Expenses (total 23 thru 33) 34 1,352,765 1,468,233
Expenses per net KWh 35 0.0158 0.0135
FERC FORM NO. 1 (REV. 12-03) Page 406
1927
Clearwater No. 1 Cutler
2420
Clearwater No. 2
1927
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
PacifiCorp X
/ /2019/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Run-of-River StorageRun-of-River 1
Outdoor ConventionalOutdoor 2
1953 19271953 3
1953 19271953 4
26.00 30.0015.00 5
16 299 6
8,548 7,2936,725 7
8
31 2918 9
31 2918 10
1 31 11
35,821,000 90,186,00026,356,000 12
13
0 3,511,1050 14
2,442,850 4,712,7891,500,707 15
14,820,860 10,043,5115,185,834 16
2,198,202 15,038,9611,407,764 17
250,151 590,23250,817 18
0 00 19
19,712,063 33,896,5988,145,122 20
758.1563 1,129.8866543.0081 21
22
29,046 129,37621,753 23
586 0338 24
59,916 114,72834,567 25
0 00 26
456,212 1,428,546326,338 27
107,628 18,01162,093 28
0 00 29
37,586 021,528 30
10,946 5,6827,297 31
7,042 16,40754,360 32
125,599 334,10472,409 33
834,561 2,046,854600,683 34
0.0233 0.02270.0228 35
FERC FORM NO. 1 (REV. 12-03) Page 407
20
Grace
1927
Fish Creek
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2019/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River Storage
Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional
Year Originally Constructed 3 1952 1908
Year Last Unit was Installed 4 1952 1923
Total installed cap (Gen name plate Rating in MW) 5 11.00 33.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 10 28
Plant Hours Connect to Load 7 2,657 8,471
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 10 33
(b) Under the Most Adverse Oper Conditions 10 10 33
Average Number of Employees 11 1 5
Net Generation, Exclusive of Plant Use - Kwh 12 20,911,000 80,378,000
Cost of Plant 13
Land and Land Rights 14 0 62,169
Structures and Improvements 15 1,764,935 2,959,781
Reservoirs, Dams, and Waterways 16 12,462,362 13,006,415
Equipment Costs 17 2,993,343 5,845,562
Roads, Railroads, and Bridges 18 533,015 546,915
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 17,753,655 22,420,842
Cost per KW of Installed Capacity (line 20 / 5) 21 1,613.9686 679.4195
Production Expenses 22
Operation Supervision and Engineering 23 12,289 125,312
Water for Power 24 248 0
Hydraulic Expenses 25 25,349 37,655
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 261,016 1,567,742
Rents 28 45,535 12,477
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 16,389 17,856
Maintenance of Reservoirs, Dams, and Waterways 31 5,999 91,128
Maintenance of Electric Plant 32 4,474 124,958
Maintenance of Misc Hydraulic Plant 33 53,100 86,818
Total Production Expenses (total 23 thru 33) 34 424,399 2,063,946
Expenses per net KWh 35 0.0203 0.0257
FERC FORM NO. 1 (REV. 12-03) Page 406.1
14803
Iron Gate Lemolo No. 1
1927
JC Boyle
14803
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
PacifiCorp X
/ /2019/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Storage StorageStorage 1
Outdoor OutdoorOutdoor 2
1958 19551962 3
1958 19551962 4
97.98 31.9918.00 5
76 3019 6
6,294 8,2988,471 7
8
83 3219 9
83 3219 10
2 11 11
228,036,000 114,477,000101,368,000 12
13
25,845 0341,617 14
3,807,630 2,940,3918,516,810 15
15,898,657 15,807,13917,215,786 16
15,631,472 6,726,7913,206,406 17
972,360 484,0461,095,742 18
0 00 19
36,335,964 25,958,36730,376,361 20
370.8508 811.45251,687.5756 21
22
166,463 35,7381,310,374 23
0 7210 24
4,979 73,720943 25
0 00 26
1,023,745 710,1901,072,544 27
2,305 132,424108,626 28
0 00 29
88,225 77,4123,282 30
23,609 6,8408,566 31
214,540 70,001120,412 32
131,211 155,18813,882 33
1,655,077 1,262,2342,638,629 34
0.0073 0.01100.0260 35
FERC FORM NO. 1 (REV. 12-03) Page 407.1
935
Merwin
1927
Lemolo No. 2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2019/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River Storage (Re-Reg)
Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional
Year Originally Constructed 3 1956 1931
Year Last Unit was Installed 4 1956 1958
Total installed cap (Gen name plate Rating in MW) 5 38.50 136.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 33 140
Plant Hours Connect to Load 7 8,711 8,760
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 39 151
(b) Under the Most Adverse Oper Conditions 10 39 151
Average Number of Employees 11 1 1
Net Generation, Exclusive of Plant Use - Kwh 12 143,451,000 337,034,000
Cost of Plant 13
Land and Land Rights 14 0 1,735,054
Structures and Improvements 15 6,296,317 111,143,662
Reservoirs, Dams, and Waterways 16 32,880,312 31,885,493
Equipment Costs 17 11,847,627 18,947,937
Roads, Railroads, and Bridges 18 1,820,580 4,135,655
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 52,844,836 167,847,801
Cost per KW of Installed Capacity (line 20 / 5) 21 1,372.5931 1,234.1750
Production Expenses 22
Operation Supervision and Engineering 23 43,011 1,689,541
Water for Power 24 868 3,618
Hydraulic Expenses 25 88,722 788,143
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 643,546 562,242
Rents 28 159,372 96,619
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 56,821 36,479
Maintenance of Reservoirs, Dams, and Waterways 31 152,722 32,091
Maintenance of Electric Plant 32 15,261 137,630
Maintenance of Misc Hydraulic Plant 33 185,851 500,907
Total Production Expenses (total 23 thru 33) 34 1,346,174 3,847,270
Expenses per net KWh 35 0.0094 0.0114
FERC FORM NO. 1 (REV. 12-03) Page 406.2
1927
Toketee Prospect No. 2
2630
Oneida
20
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
PacifiCorp X
/ /2019/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Storage Run-of-RiverStorage 1
Conventional ConventionalConventional 2
1915 19281949 3
1920 19281950 4
30.00 32.0042.50 5
17 3643 6
8,759 8,6568,555 7
8
28 3645 9
28 3645 10
2 11 11
51,274,000 190,315,000193,356,000 12
13
283,870 105,1680 14
2,319,787 4,238,4994,381,649 15
8,536,133 35,368,39012,846,444 16
15,673,315 7,376,9606,271,807 17
662,757 533,423502,952 18
0 00 19
27,475,862 47,622,44024,002,852 20
915.8621 1,488.2013564.7730 21
22
90,472 394,40271,088 23
0 12,490958 24
34,232 1,62697,942 25
0 00 26
849,267 712,142736,778 27
10,751 40,113175,933 28
0 2600 29
0 64,84267,843 30
7,436 200,59112,989 31
77,027 99,617117,837 32
57,958 438,020205,165 33
1,127,143 1,964,1031,486,533 34
0.0220 0.01030.0077 35
FERC FORM NO. 1 (REV. 12-03) Page 407.2
20
Soda
1927
Slide Creek
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
PacifiCorp X
/ /2019/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River Storage
Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional
Year Originally Constructed 3 1951 1924
Year Last Unit was Installed 4 1951 1924
Total installed cap (Gen name plate Rating in MW) 5 18.00 14.45
Net Peak Demand on Plant-Megawatts (60 minutes) 6 15 7
Plant Hours Connect to Load 7 7,857 7,697
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 18 14
(b) Under the Most Adverse Oper Conditions 10 18 14
Average Number of Employees 11 1 2
Net Generation, Exclusive of Plant Use - Kwh 12 46,271,000 20,509,000
Cost of Plant 13
Land and Land Rights 14 0 511,083
Structures and Improvements 15 2,205,575 1,325,982
Reservoirs, Dams, and Waterways 16 14,883,968 11,107,798
Equipment Costs 17 8,978,518 5,446,933
Roads, Railroads, and Bridges 18 582,653 0
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 26,650,714 18,391,796
Cost per KW of Installed Capacity (line 20 / 5) 21 1,480.5952 1,272.7887
Production Expenses 22
Operation Supervision and Engineering 23 24,905 42,220
Water for Power 24 406 0
Hydraulic Expenses 25 41,480 15,975
Electric Expenses 26 0 0
Misc Hydraulic Power Generation Expenses 27 351,691 466,712
Rents 28 74,512 5,077
Maintenance Supervision and Engineering 29 0 0
Maintenance of Structures 30 28,288 60
Maintenance of Reservoirs, Dams, and Waterways 31 20,519 3,591
Maintenance of Electric Plant 32 89,618 30,637
Maintenance of Misc Hydraulic Plant 33 86,891 27,047
Total Production Expenses (total 23 thru 33) 34 718,310 591,319
Expenses per net KWh 35 0.0155 0.0288
FERC FORM NO. 1 (REV. 12-03) Page 406.3
1927
Soda Springs Yale
2071
Swift No. 1
2111
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
PacifiCorp X
/ /2019/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
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.
Storage StorageStorage (Re-Reg) 1
Conventional ConventionalOutdoor 2
1958 19531952 3
1958 19531952 4
240.00 134.0011.00 5
243 16412 6
4,399 5,2917,863 7
8
264 16412 9
264 16412 10
1 12 11
369,084,000 370,023,00038,101,000 12
13
17,912,070 8,363,0130 14
71,477,347 17,641,3944,306,658 15
48,366,872 35,024,80790,257,199 16
25,269,498 18,290,6722,624,544 17
1,319,865 2,045,6312,089,012 18
0 00 19
164,345,652 81,365,51799,277,413 20
684.7736 607.20549,025.2194 21
22
2,948,946 1,576,35412,289 23
6,384 3,564248 24
1,636,070 776,553112,090 25
0 00 26
404,476 486,488435,622 27
170,475 95,18245,535 28
0 00 29
32,253 24,88816,506 30
114,965 75,68787,988 31
175,100 84,677105,167 32
854,965 478,73061,413 33
6,343,634 3,602,123876,858 34
0.0172 0.00970.0230 35
FERC FORM NO. 1 (REV. 12-03) Page 407.3
Schedule Page: 406 Line No.: -1 Column: b
This footnote applies to all hydroelectric generating facilities with current generation.
All or some of the renewable energy attributes associated with generation from these
generating 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 energy credits or other environmental commodities.
Schedule Page: 406 Line No.: 1 Column: b
Copco No. 1 - Pondage for peaking - storage, Upper Klamath Lake
Schedule Page: 406 Line No.: 1 Column: d
Clearwater No. 1 - Forebay for peaking
Schedule Page: 406 Line No.: 1 Column: e
Clearwater No. 2 - Forebay for peaking
Schedule Page: 406.1 Line No.: 1 Column: b
Fish Creek - Forebay for peaking
Schedule Page: 406.1 Line No.: 1 Column: d
Iron Gate - Storage for regulation
Schedule Page: 406.1 Line No.: 1 Column: e
JC Boyle - Pondage for peaking - storage, Upper Klamath Lake
Schedule Page: 406.1 Line No.: 1 Column: f
Lemolo No. 1 - Storage, Lemolo Lake
Schedule Page: 406.2 Line No.: 1 Column: b
Lemolo No. 2 - Storage, Lemolo Lake
Schedule Page: 406.2 Line No.: 1 Column: d
Toketee - Pondage for peaking - storage, Lemolo Lake
Schedule Page: 406.2 Line No.: 1 Column: f
Prospect No. 2 - Forebay for peaking
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants)
PacifiCorp X / /2019/Q4
Line
No.Name of Plant
Installed Capacity
(c)(b)(a)
Cost of PlantNet PeakDemand
(d)
YearOrig.Const.Name Plate Rating
(In MW)MW(60 min.)
Net GenerationExcludingPlant Use
(e) (f)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give
project number in footnote.
Hydroelectric: Licensed Proj. No. 1
6.85 7.0 39,649,000 34,004,8011917Ashton 2381 2
1.11 1.0 1,559,000 2,515,7711913Bend 3
4.15 4.6 27,204,000 9,678,8291910Big Fork 2652 4
2.81 2.8 16,812,000 2,011,6171957Eagle Point 5
3.20 1,991,6951924East Side 2082 6
2.20 2.0 6,046,000 2,138,4741903Fall Creek 2082 7
2.00 1.2 6,719,000 5,261,2691896Granite 8
0.75 0.5 1,782,000 683,0451917Gunlock 9
1.73 1.4 4,695,000 3,176,8471983Last Chance 10
0.72 0.7 2,489,000 459,9781910Paris 703 11
5.00 4.0 21,353,000 11,654,6741897Pioneer 2722 12
3.76 4.6 8,511,000 5,344,4521912Prospect No. 1 2630 13
7.20 7.0 23,624,000 9,256,4861932Prospect No. 3 2337 14
1.00 0.9 1,817,000 2,518,1271944Prospect No. 4 2630 15
0.80 0.5 1,820,000 1,139,7891926Sand Cove 16
1.00 1.2 5,771,000 1,952,8781895Stairs 597 17
0.50 0.3 774,000 898,4641920Veyo 18
0.74 0.1 590,000 1,232,1151986Viva Naughton 19
1.10 1.1 2,745,000 3,796,6481921Wallowa Falls 308 20
3.85 2.0 14,064,000 3,892,8171911Weber 1744 21
0.60 1.0 -19,000 478,9461908West Side 2082 22
7,684,061Keno Regulating Dam 2082 23
3,849,552Upper Klamath Lake 2082 24
17,125,400North Umpqua 1927 25
26
Pumping Plant: 27
-2.80 -2.0 -2,155,000 19,551,0561917Lifton 28
29
Wind: 30
111.00 111.0 384,833,000 243,396,3682010Dunlap Ranch 1 31
41.40 35.0 107,369,000 48,338,9251999Foote Creek 32
99.00 100.0 276,714,000 190,998,3272008Glenrock 33
39.00 39.0 106,250,000 80,657,7572009Glenrock III 34
99.00 100.0 267,528,000 195,865,1092009Rolling Hills 35
94.00 90.0 47,965,000 157,081,1522008Goodnoe Hills 36
100.50 100.0 98,159,000 176,413,2732006Leaning Juniper 1 37
140.40 120.0 143,441,000 246,917,9492007Marengo 38
70.20 66.0 91,293,000 131,515,0922008Marengo II 39
99.00 99.0 320,975,000 187,112,3962008Seven Mile Hill 40
19.50 19.5 64,968,000 38,261,3892008Seven Mile Hill II 41
99.00 99.0 235,562,000 190,134,4382009High Plains 42
28.50 28.5 75,204,000 52,540,1312009McFadden Ridge I 43
44
Solar: 45
2.00 2.0 3,289,000 74,9862012Black Cap 46
FERC FORM NO. 1 (REV. 12-03) Page 410
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants) (Continued)
PacifiCorp X / /2019/Q4
Line
No.(i)(h)(g)(j) (k) (l)
Operation
Exc'l. Fuel
Production Expenses
Fuel Maintenance Kind of Fuel Fuel Costs (in cents
(per Million Btu)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl AssetRetire. Costs) Per MW
1
149,232 5,075,343 2Water 454,176
3,403 2,266,460 3Water 90,798
113,408 2,332,248 4Water 323,530
103,622 715,878 5Water 305,682
66,449 622,405 6Water 33,683
29,749 972,034 7Water 173,202
11,865 2,630,635 8Water 197,363
51,952 910,727 9Water 37,008
13,325 1,836,328 10Water 113,004
10,677 638,858 11Water 74,596
81,454 2,330,935 12Water 411,057
121,261 1,421,397 13Water 138,550
171,900 1,285,623 14Water 334,353
29,665 2,518,127 15Water 39,552
83,633 1,424,736 16Water 46,935
5,703 1,952,878 17Water 223,418
332,212 1,796,928 18Water 39,917
63,984 1,665,020 19Water 9,671
41,479 3,451,498 20Water 315,587
53,199 1,011,121 21Water 162,881
70,879 798,243 22Water 8,372
8,223 23 14,160
110,123 24 288,327
25
26
27
29,733 -6,982,520 28Water 227,024
29
30
1,190,706 2,192,760 31Wind 367,926
1,250,631 1,167,607 32Wind 1,192,666
740,767 1,929,276 33Wind 191,664
382,682 2,068,148 34Wind 78,135
1,247,565 1,978,435 35Wind 192,248
484,223 1,671,076 36Wind 958,589
272,243 1,755,356 37Wind 1,133,720
893,869 1,758,675 38Wind 737,176
445,604 1,873,434 39Wind 465,922
551,715 1,890,024 40Wind 791,847
105,554 1,962,123 41Wind 54,683
814,274 1,920,550 42Wind 1,014,346
289,526 1,843,513 43Wind 290,190
44
45
37,493 46Solar 487,066
FERC FORM NO. 1 (REV. 12-03) Page 411
Schedule Page: 410 Line No.: 1 Column: a
Common river system costs for the operation of these facilities are allocated to each
plant based upon the unit’s name plate rating.
This footnote applies to all hydroelectric generating facilities with current generation.
All or some of the renewable energy attributes associated with generation from these
generating 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 energy credits or other environmental commodities.
Schedule Page: 410 Line No.: 6 Column: a
The East Side plant was significantly curtailed pursuant to Section 6.2 of the Klamath
Hydroelectric Settlement Agreement in FERC Docket No. P-2082-000.
Schedule Page: 410 Line No.: 22 Column: a
The West Side plant generation supplies station use and was significantly curtailed
pursuant to Section 6.2 of the Klamath Hydroelectric Settlement Agreement in FERC Docket
No. P-2082-000.
Schedule Page: 410 Line No.: 23 Column: a
Used in regulating the release of water from Klamath Lake and in maintaining proper water
surface level in the Klamath River between Klamath Falls and Keno, Oregon.
Schedule Page: 410 Line No.: 24 Column: a
Storage reservoir for six plants on the Klamath River (Copco No. 1, Copco No. 2, East
Side, West Side, JC Boyle and Iron Gate).
Schedule Page: 410 Line No.: 25 Column: a
Represents facilities that support the North Umpqua River system projects. All common
roads, employee houses, control equipment, etc. are included in this account.
Schedule Page: 410 Line No.: 28 Column: a
Used in regulating the release of water from Bear Lake and in maintaining proper water
surface level in the Bear River near St. Charles, Idaho.
Schedule Page: 410 Line No.: 30 Column: a
Common costs for the operation of these facilities are allocated to each plant based upon
the unit’s name plate rating.
This footnote applies to all wind-powered generating facilities with current generation.
All or some of the renewable energy attributes associated with generation from these
generating 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 energy credits or other environmental commodities.

Schedule Page: 410 Line No.: 32 Column: a
In July 2019, PacifiCorp completed a transaction with Eugene Water & Electric Board to
acquire the remaining undivided interest in the Foote Creek I joint-owned wind generating
facility. For further discussion, refer to Item 12 in Important Changes During the Year in
this Form No. 1.
Schedule Page: 410 Line No.: 46 Column: a
PacifiCorp has an agreement with Citizens Asset Finance, Inc. to lease the Black Cap Solar
generating facility. The lease has a 16-year term from October 2012 to October 2028 and is
accounted for as an operating lease.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2019/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
1
Steel Tower 500.00 500.00 58.00 1 2 ALVEY, OR DIXONVILLE 500kV, OR
Steel Tower 500.00 500.00 7.00 1 3 CAPTAIN JACK, OR MALIN, OR
Steel Tower 500.00 500.00 74.00 1 4 DIXONVILLE, OR MERIDIAN, OR
Steel Tower 500.00 500.00 26.00 1 5 KLAMATH CO-GEN, OR CAPTAIN JACK, OR
Steel Tower 500.00 500.00 47.00 1 6 MALIN, OR PG&E ROUND MTN, CA
Steel Tower 500.00 500.00 58.00 1 7 MERIDIAN, OR KLAMATH CO-GEN, OR
Steel Tower 500.00 500.00 447.00 1 8 MIDPOINT, ID MALIN, OR
Steel Tower 500.00 500.00 1.00 1 9 COLSTRIP 4, MT SWITCHYARD, MT
Steel Tower 500.00 500.00 112.00 1 10 COLSTRIP, MT BROADVIEW A, MT
Steel Tower 500.00 500.00 116.00 1 11 COLSTRIP, MT BROADVIEW B, MT
Steel Tower 500.00 500.00 133.00 1 12 BROADVIEW, MT TOWNSEND A, MT
Steel Tower 500.00 500.00 133.00 1 13 BROADVIEW, MT TOWNSEND B, MT
14 500kV costs and expenses
1,212.00 12 15 Subtotal 500kV
16
Steel - SP 345.00 345.00 11.00 1 17 90TH SOUTH, UT CAMP WILLIAMS #3, UT
Steel - SP 345.00 345.00 11.00 1 18 90TH SOUTH, UT CAMP WILLIAMS #4, UT
Steel - SP 345.00 345.00 11.00 1 19 90TH SOUTH, UT CAMP WILLIAMS #1, UT
Steel - SP 345.00 345.00 16.00 1 20 90TH SOUTH, UT TERMINAL, UT
Steel - SP 345.00 345.00 82.00 1 21 BEN LOMOND, UT POPULUS #1, ID
Steel - SP 345.00 345.00 86.00 1 22 BEN LOMOND, UT POPULUS #2, ID
Steel - SP 345.00 345.00 69.00 1 23 BEN LOMOND, UT CAMP WILLIAMS, UT
Steel - SP 345.00 345.00 47.00 1 24 BEN LOMOND, UT TERMINAL #2, UT
Steel - SP 345.00 345.00 47.00 1 25 BEN LOMOND, UT TERMINAL #1, UT
Wood - H 345.00 345.00 83.00 1 26 BORAH, ID MIDPOINT #1, ID
Wood - H 345.00 345.00 78.00 1 27 BORAH, ID MIDPOINT #2, ID
Wood - H 345.00 345.00 47.00 1 28 CAMP WILLIAMS, UT MONA #3, UT
Wood - H 345.00 345.00 47.00 1 29 CAMP WILLIAMS, UT MONA #1, UT
Steel Tower 345.00 345.00 47.00 1 30 CAMP WILLIAMS, UT MONA #2, UT
Steel Tower 345.00 345.00 42.00 5.00 1 31 CAMP WILLIAMS, UT MONA #4 UT
Steel Tower 345.00 345.00 100.00 1 32 CLOVER, UT OQUIRRH, UT
Steel - SP 345.00 345.00 1.00 1 33 CURRANT CREEK, UT MONA, UT
Steel Tower 345.00 345.00 121.00 1 34 EMERY, UT CAMP WILLIAMS, UT
Wood - H 345.00 345.00 20.00 1 35 EMERY, UT HUNTINGTON, UT
FERC FORM NO. 1 (ED. 12-87) Page 422
36 TOTAL 16,965.00 651.00 288
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
1
3-2250 AAC /91 2
3-1272 ACSR 36/1 3
3-1272 ACSR 36/1 4
3-1272 ACSR 54/19 5
3-1852 ACSR 51/27 6
3-1272 ACSR 54/19 7
3-1272 ACSR 36/1 8
795 KCM ACSR 9
795 ACSR 26/7 10
795 ACSR 26/7 11
795 ACSR 26/7 12
795 ACSR 26/7 13
250,276,543 236,936,844 13,339,699 1,921,671 316,379 1,601,934 3,358 14
250,276,543 236,936,844 13,339,699 1,921,671 316,379 1,601,934 3,358 15
16
17
18
1272 ACSR 45/7 19
1272 ACSR 45/7 20
1272 ACSR 45/7 21
1272 ACSR 45/7 22
1272 ACSR 45/7 23
1272 ACSR 45/7 24
1272 ACSR 45/7 25
1272 ACSR 45/7 26
1272 ACSR 45/7 27
954 ACSR 45/7 28
1272 ACSR 45/7 29
954 ACSR 45/7 30
954 ACSR 45/7 31
1949 ACSR 45/7 32
954 ACSR 54/7 33
1272 ACSR 45/7 34
954 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423
36 253,528,964 3,620,408,197 3,873,937,161 1,089,585 16,258,960 2,244,063 19,592,608
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2019/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Steel - H 345.00 345.00 74.00 1 1 EMERY, UT SIGURD #1, UT
Steel - H 345.00 345.00 75.00 1 2 EMERY, UT SIGURD #2, UT
Wood - H 345.00 345.00 101.00 1 3 FOUR CORNERS, NM PINTO, UT
Wood - H 345.00 345.00 41.00 1 4 GOSHEN, ID KINPORT, ID
Steel Tower 345.00 345.00 1.00 1 5 HUNTINGTON, UT HUNT PLANT 1, UT
Steel Tower 345.00 345.00 1.00 1 6 HUNTINGTON, UT HUNT PLANT 2, UT
Steel - SP 345.00 345.00 158.00 1 7 HUNTINGTON, UT PINTO, UT
Steel Tower 345.00 345.00 78.00 1 8 HUNTINGTON, UT SPANISH FORK, UT
Steel Tower 345.00 345.00 220.00 1 9 JIM BRIDGER, WY GOSHEN, ID
Steel Tower 345.00 345.00 240.00 1 10 JIM BRIDGER, WY BORAH, ID
Steel - SP 345.00 345.00 234.00 1 11 JIM BRIDGER, WY KINPORT, ID
Steel - SP 345.00 345.00 113.00 1 12 KINPORT, ID MIDPOINT, ID
Wood - H 345.00 345.00 69.00 1 13 MONA, UT SIGURD #1, UT
Steel - SP 345.00 345.00 69.00 1 14 MONA, UT SIGURD #2, UT
Steel - SP 345.00 345.00 60.00 1 15 MONA, UT HUNTINGTON, UT
Steel - H 345.00 345.00 170.00 1 16 RED BUTTE, UT SIGURD, UT
Steel Tower 345.00 345.00 190.00 1 17 SIGURD, UT UT-NV STATE LINE
Steel - SP 345.00 345.00 35.00 1 18 SPANISH FORK, UT CAMP WILLIAMS, UT
Wood - H 345.00 345.00 138.00 1 19 TERMINAL, UT BORAH, ID
Steel - SP 345.00 345.00 47.00 1 20 TERMINAL, UT BORAH, ID
Steel - SP 345.00 345.00 10.00 16.00 1 21 TERMINAL, UT CAMP WILLIAMS #2, UT
Steel Tower 345.00 345.00 23.00 1 22 TERMINAL, UT CAMP WILLIAMS, UT
23 345kV costs and expenses
382.00 2,752.00 41 24 Subtotal 345kV
25
Wood - H 230.00 230.00 59.00 1 26 ALVEY, OR DIXONVILLE, OR
Wood - H 230.00 230.00 76.00 1 27 ANTELOPE, ID ANACONDA, MT
Wood - H 230.00 230.00 20.00 1 28 ANTELOPE, ID LOST RIVER, ID
Wood - H 230.00 230.00 9.00 1 29 ARROWHEAD, WY FIREHOLE, WY
Wood - H 230.00 230.00 1.00 1 30 ATLANTIC CITY, WY COLUMBIA GENEVA, WY
Wood - H 230.00 230.00 88.00 1 31 BEN LOMOND, UT NAUGHTON #1, WY
Wood - H 230.00 230.00 88.00 1 32 BEN LOMOND, UT NAUGHTON #2, WY
Wood - H 230.00 230.00 19.00 1 33 BIRCH CREEK, UT RAILROAD, WY
Wood - H 230.00 230.00 3.00 1 34 BITTER CREEK, WY MONELL, WY
Wood - H 230.00 230.00 1.00 1 35 BRIDGER PUMP, WY MANS FACE, WY
FERC FORM NO. 1 (ED. 12-87) Page 422.1
36 TOTAL 16,965.00 651.00 288
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
954 ACSR 45/7 1
954 ACSR 54/7 2
795 ACSR 45/7 3
795 ACSR 26/7 4
2156 ACSR 8419 5
2156 ACSR 8419 6
795 ACSR 45/7 7
1272 ACSR 45/7 8
1272 ACSR 36/1 9
1272 ACSR 36/1 10
1272 ACSR 36/1 11
1272 ACSR 45/7 12
795 ACSR 45/7 13
954 ACSR 45/7 14
954 ACSR 54/7 15
2-954 ACSR 45/7 16
954 ACSR 54/7 17
1272 ACSR 45/7 18
2-954 ACSR 45/7 19
2-1272 ACSR 45/7 20
1272 ACSR 45/7 21
1272 ACSR 45/7 22
1,815,493,906 1,660,982,229 154,511,677 2,055,220 589,703 1,261,113 204,404 23
1,815,493,906 1,660,982,229 154,511,677 2,055,220 589,703 1,261,113 204,404 24
25
1272 ACSR 36/1 26
1272 ACSR 45/7 27
795 ACSR 45/7 28
795 ACSR 26/7 29
1272 ACSR 36/1 30
795 ACSR 26/7 31
795 ACSR 26/7 32
954 ACSR 54/7 33
795 ACSR 26/7 34
1272 ACSR 36/1 35
FERC FORM NO. 1 (ED. 12-87) Page 423.1
36 253,528,964 3,620,408,197 3,873,937,161 1,089,585 16,258,960 2,244,063 19,592,608
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2019/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Wood - H 230.00 230.00 107.00 1 1 BUFFALO, WY CASPER, WY
Wood - H 230.00 230.00 36.00 1 2 CASPER, WY DAVE JOHNSTON, WY
Wood - H 230.00 230.00 110.00 1 3 CASPER, WY RIVERTON, WY
Steel - SP 230.00 230.00 30.00 1 4 CHAPPEL CREEK, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 32.00 1 5 CHAPPEL CREEK, WY JONAH GAS, WY
Wood - H 230.00 230.00 6.00 29.00 1 6 CHAPPEL CREEK, WY RILEY RIDGE, WY
Wood - H 230.00 230.00 9.00 1 7 CORRAL, OR OCHOCO #1, OR
Wood - H 230.00 230.00 2.00 1 8 CRAVEN CREEK, WY PIONEER, WY
Wood - H 230.00 230.00 31.00 1 9 DAVE JOHNSTON, WY SPENCE, WY
Wood - H 230.00 230.00 69.00 1 10 DAVE JOHNSTON, WY WYODAK, WY
Wood - H 230.00 230.00 1.00 1 11 DIXONVILLE 500kV, OR DIXONVILLE 230kV, OR
Wood - H 230.00 230.00 17.00 1 12 DIXONVILLE, OR RESTON (BPA), OR
Wood - H 230.00 230.00 12.00 1 13 FAIRVIEW (BPA), OR ISTHMUS, OR
Wood - H 230.00 230.00 49.00 1 14 FIREHOLE, WY MONUMENT, WY
Wood - H 230.00 230.00 26.00 1 15 FRY, OR BETHEL, OR
Wood - H 230.00 230.00 45.00 1 16 FRY, OR ALVEY, OR
Wood - H 230.00 230.00 159.00 1 17 GLEN CANYON, AZ SIGURD, UT
Wood - H 230.00 230.00 98.00 1 18 GONDER, UT-NV STATE PAVANT, UT
Wood - H 230.00 230.00 62.00 1 19 DIXONVILLE, OR GRANTS PASS, OR
Wood - H 230.00 230.00 38.00 1 20 HIGH PLAINS, WY STANDPIPE, WY
Wood - H 230.00 230.00 78.00 1 21 HURRICANE, OR WALLA WALLA, WA
Wood - H 230.00 230.00 35.00 1 22 JIM BRIDGER, WY ROCK SPRINGS, WY
Wood - H 230.00 230.00 149.00 1 23 JIM BRIDGER, WY SPENCE, WY
Wood - H 230.00 230.00 36.00 1 24 KLAMATH FALLS, OR MALIN, OR
Wood - H 230.00 230.00 2.00 1 25 LIMA, WY ROBERSON, WY
Wood - H 230.00 230.00 76.00 1 26 LONE PINE, OR KLAMATH FALLS, OR
Steel - SP 230.00 230.00 5.00 1 27 LONE PINE, OR MERIDIAN #1, OR
Steel - SP 230.00 230.00 5.00 1 28 LONE PINE, OR MERIDIAN #2, OR
Wood - H 230.00 230.00 56.00 1 29 MCNARY (BPA), OR WALLA WALLA, WA
Wood - H 230.00 230.00 29.00 1 30 MCNARY (BPA), OR WALLULA, WA
Wood - H 230.00 230.00 35.00 1 31 MERIDIAN, OR GRANTS PASS, OR
Wood - H 230.00 230.00 13.00 1 32 MONUMENT, WY EXXON, WY
Wood - H 230.00 230.00 20.00 1 33 MONUMENT, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 80.00 1 34 NAUGHTON, WY TREASURETON, ID
Wood - H 230.00 230.00 30.00 1 35 NAUGHTON, WY MONUMENT, WY
FERC FORM NO. 1 (ED. 12-87) Page 422.2
36 TOTAL 16,965.00 651.00 288
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
1272 ACSR 36/1 1
2
1272 ACSR 36/1 3
954 ACSR 54/7 4
1272 ACSR 45/7 5
1272 ACSR 45/7 6
7
1272 ACSR 45/7 8
1272 ACSR 45/7 9
1272 ACSR 36/1 10
1272 ACSR 36/1 11
795 ACSR 26/7 12
1272 ACSR 36/1 13
1272 ACSR 45/7 14
1272 ACSR 36/1 15
1272 ACSR 36/1 16
954 ACSR 45/7 17
795 ACSR 45/7 18
1272 ACSR 36/1 19
1272 ACSR 45/7 20
1272 ACSR 36/1 21
1272 ACSR 45/7 22
1272 ACSR 36/1 23
1272 ACSR 36/1 24
1272 ACSR 45/7 25
795 ACSR 26/7 26
1272 ACSR 54/19 27
1272 ACSR 36/1 28
1272 ACSR 36/1 29
30
1272 ACSR 36/1 31
1272 ACSR 36/1 32
1272 ACSR 45/7 33
1272 ACSR 45/7 34
1272 ACSR 36/1 35
FERC FORM NO. 1 (ED. 12-87) Page 423.2
36 253,528,964 3,620,408,197 3,873,937,161 1,089,585 16,258,960 2,244,063 19,592,608
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2019/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Wood - H 230.00 230.00 16.00 1 1 NAUGHTON, WY CRAVEN CREEK, WY
Wood - H 230.00 230.00 4.00 1 2 PALISADES SS, WY BLUE RIM, WY
Wood - H 230.00 230.00 94.00 1 3 PAROWAN VALLEY, UT SIGURD, UT
Wood - H 230.00 230.00 26.00 1 4 PAROWAN VALLEY, UT WEST CEDAR, UT
Wood - H 230.00 230.00 43.00 1 5 PAVANT, UT SIGURD, UT
Wood - H 230.00 230.00 209.00 1 6 POINT OF ROCKS, WY DAVE JOHNSTON, WY
Wood - H 230.00 230.00 7.00 1 7 POMONA, WA UNION GAP, WA
Wood - H 230.00 230.00 118.00 1 8 RIVERTON, WY ROCK SPRINGS, WY
Wood - H 230.00 230.00 51.00 1 9 RIVERTON, WY THERMOPOLIS, WY
Wood - H 230.00 230.00 55.00 1 10 ROCK SPRINGS, WY FLAMING GORGE, UT
Wood - H 230.00 230.00 35.00 1 11 ROCK SPRINGS, WY JIM BRIDGER, WY
Wood - H 230.00 230.00 41.00 1 12 ROCK SPRINGS, WY MONUMENT, WY
Wood - H 230.00 230.00 40.00 1 13 SHERIDAN (MDU), WY BUFFALO, WY
Wood - H 230.00 230.00 62.00 1 14 SHERIDAN (MDU), WY YELLOWTAIL, MT
Wood - H 230.00 230.00 12.00 1 15 SHIRLEY BASIN, WY DUNLAP RANCH, WY
Wood - H 230.00 230.00 2.00 1 16 SWIFT NO. 1, WA SWIFT NO. 2, WA
Wood - H 230.00 230.00 23.00 1 17 SWIFT NO. 2, WA WOODLAND (BPA) SS, WA
Wood - H 230.00 230.00 7.00 1 18 TALBOT, WA MARENGO II, WA
Wood - H 230.00 230.00 9.00 1 19 TAP TO HANNA, OR NICKEL MOUNTAIN, OR
Wood - H 230.00 230.00 176.00 1 20 THERMOPOLIS, WY YELLOWTAIL, MT
Wood - H 230.00 230.00 66.00 1 21 TREASURETON, ID BRADY, ID
Steel Tower 230.00 230.00 6.00 1 22 TROUTDALE (BPA), OR GRESHAM (PGE), OR
Steel Tower 230.00 230.00 7.00 1 23 TROUTDALE (BPA), OR LINNEMAN (PGE), OR
Wood - H 230.00 230.00 39.00 1 24 UNION GAP, WA MIDWAY (BPA), WA
Wood - H 230.00 230.00 45.00 1 25 WALLA WALLA, WA LEWISTON (AVISTA), ID
Wood - H 230.00 230.00 33.00 1 26 WALLA WALLA, WA WANAPUM (GPUD), WA
Wood - H 230.00 230.00 37.00 1 27 WANAPUM (GPUD), WA POMONA, WA
Wood - H 230.00 230.00 13.00 1 28 WINDSTAR, WY GLENROCK, WY
Wood - H 230.00 230.00 69.00 1 29 WYODAK, WY BUFFALO, WY
Wood - H 230.00 230.00 63.00 1 30 YAMSAY (BPA), OR KLAMATH FALLS, OR
31 230kV costs and expenses
13.00 3,376.00 75 32 Subtotal 230kV
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 422.3
36 TOTAL 16,965.00 651.00 288
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
954 ACSR 54/7 1
1272 ACSR 36/1 2
795 ACSR 45/7 3
795 ACSR 45/7 4
795 ACSR 45/7 5
1272 ACSR 36/1 6
1272 ACSR 36/1 7
1272 ACSR 36/1 8
1272 ACSR 36/1 9
1272 ACSR 36/1 10
1272 ACSR 36/1 11
1272 ACSR 36/1 12
795 ACSR 26/7 13
795 ACSR 26/7 14
795 ACSR 26/7 15
954 ACSR 45/7 16
954 ACSR 45/7 17
795 ACSR 26/7 18
795 ACSR 26/7 19
1272 ACSR 36/1 20
795 ACSR 26/7 21
954 ACSR 45/7 22
900 ACSR 54/7 23
954 ACSR 45/7 24
1272 ACSR 36/1 25
1272 ACSR 36/1 26
1272 ACSR 36/1 27
1272 ACSR 45/7 28
1272 ACSR 36/1 29
795 ACSR 26/7 30
459,383,280 434,223,527 25,159,753 3,402,223 424,374 2,896,518 81,331 31
459,383,280 434,223,527 25,159,753 3,402,223 424,374 2,896,518 81,331 32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 423.3
36 253,528,964 3,620,408,197 3,873,937,161 1,089,585 16,258,960 2,244,063 19,592,608
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2019/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Wood - H 161.00 161.00 45.00 1 1 ANTELOPE, ID GOSHEN, ID
Wood - H 161.00 161.00 21.00 1 2 BIG GRASSY, ID JEFFERSON, ID
Wood - SP 161.00 161.00 9.00 1 3 BONNEVILLE, ID EAGLEROCK, ID
Wood - H 161.00 161.00 15.00 1 4 EAGLEROCK, ID GOSHEN, ID
Wood - H 161.00 161.00 57.00 1 5 GOSHEN, ID GRACE, ID
Wood - H 161.00 161.00 30.00 1 6 GOSHEN, ID JEFFERSON, ID
Wood - H 161.00 161.00 31.00 1 7 GOSHEN, ID RIGBY, ID
Wood - SP 161.00 161.00 17.00 1 8 GOSHEN, ID SUGAR MILL, ID
Wood - SP 161.00 161.00 18.00 1 9 RIGBY, ID JEFFERSON, ID
Wood - SP 161.00 161.00 17.00 1 10 SUGARMILL, ID RIGBY, ID
Wood - H 161.00 161.00 46.00 1 11 YELLOWTAIL, MT RIMROCK, MT
12 161kV costs and expenses
51.00 255.00 11 13 Subtotal 161kV
14
Wood - H 138.00 138.00 12.00 1 15 90TH SOUTH, UT DUMAS #1, UT
Wood - H 138.00 138.00 6.00 1 16 90TH SOUTH, UT DUMAS #2, UT
Wood - SP 138.00 138.00 10.00 1 17 90TH SOUTH, UT OQUIRRH, UT
Steel - SP 138.00 138.00 1.00 1 18 90TH SOUTH, UT SANDY, UT
Wood - H 138.00 138.00 44.00 1 19 ABAJO, UT PINTO, UT
Wood - SP 138.00 138.00 10.00 1 20 ABAJO, UT SAN JUAN, UT
Wood - H 138.00 138.00 4.00 1 21 AGRIUM, UT THREEMILE KNOLL, ID
Wood - H 138.00 138.00 22.00 1 22 ANSCHTZ CO-GEN, WY EVANSTON, WY
Wood - H 138.00 138.00 1.00 1 23 ANTELOPE, ID SCOVILLE #1, ID
Wood - H 138.00 138.00 1.00 1 24 ANTELOPE, ID SCOVILLE #2, ID
Wood - H 138.00 138.00 26.00 1 25 ASHGROVE, UT CLOVER, UT
Wood - H 138.00 138.00 102.00 1 26 ASHLEY, UT CARBON, UT
Wood - H 138.00 138.00 12.00 1 27 ASHLEY, UT VERNAL, UT
Wood - H 138.00 138.00 6.00 1 28 BANGERTER, UT OQUIRRH, UT
Wood - SP 138.00 138.00 1.00 1 29 BARNEYS, UT GRINDING, UT
Wood - SP 138.00 138.00 1.00 1 30 BDO, UT BDO TAP, UT
Steel - SP 138.00 138.00 27.00 1 31 BEN LOMOND, UT ANGEL, UT
Wood - H 138.00 138.00 14.00 1 32 BEN LOMOND, UT BRIGHAM CITY, UT
Steel - SP 138.00 138.00 14.00 1 33 BEN LOMOND #1, UT EL MONTE, UT
Wood - H 138.00 138.00 13.00 1 34 BEN LOMOND #2, UT EL MONTE, UT
Steel Tower 138.00 138.00 22.00 1 35 BEN LOMOND, UT HONEYVILLE, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.4
36 TOTAL 16,965.00 651.00 288
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
397.5 ACSR 26/7 1
250HH CU /7 2
954 ACSR 45/7 3
1272 ACSR 45/7 4
250HH CU /7 5
250HH CU /7 6
397.5 ACSR 26/7 7
795 AAC /37 8
397.5 ACSR 26/7 9
397.5 ACSR 26/7 10
556.5 ACSR 26/7 11
41,421,078 40,759,855 661,223 294,781 13,522 262,267 18,992 12
41,421,078 40,759,855 661,223 294,781 13,522 262,267 18,992 13
14
795 AAC /37 15
795 AAC /37 16
795 ACSR 26/7 17
795 AAC /37 18
397.5 ACSR 26/7 19
795 ACSR 26/7 20
397.5 ACSR 26/7 21
795 ACSR 26/7 22
397.5 ACSR 26/7 23
397.5 ACSR 26/7 24
397.5 ACSR 26/7 25
397.5 ACSR 26/7 26
397.5 ACSR 26/7 27
28
1272 AAC /61 29
397.5 ACSR 26/7 30
397.5 ACSR 26/7 31
1272 ACSR 45/7 32
795 ACSR 45/7 33
795 ACSR 45/7 34
250 CUHD /12 35
FERC FORM NO. 1 (ED. 12-87) Page 423.4
36 253,528,964 3,620,408,197 3,873,937,161 1,089,585 16,258,960 2,244,063 19,592,608
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2019/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Steel Tower 230.00 138.00 13.00 7.00 1 1 BEN LOMOND, UT SYRACUSE #1, UT
Steel Tower 138.00 138.00 58.00 1 2 BEN LOMOND, UT SYRACUSE, UT
Wood - SP 138.00 138.00 14.00 1 3 BEN LOMOND, UT W ZIRCONIUM, UT
Steel Tower 138.00 138.00 42.00 1 4 BEN LOMOND, UT WHEELON, UT
Wood - H 138.00 138.00 9.00 1 5 BONANZA, UT CHAPITA, UT
Wood - SP 138.00 138.00 16.00 1 6 BRIDGERLAND, UT GREEN CANYON, UT
Wood - H 138.00 138.00 24.00 1 7 BRIGHAM CITY, UT WHEELON, UT
Steel - SP 138.00 138.00 9.00 1 8 BUTLERVILLE, UT 90TH SOUTH, UT
Wood - SP 138.00 138.00 25.00 1 9 CAMERON, UT MILFORD, UT
Wood - H 138.00 138.00 35.00 1 10 CAMERON, UT PAROWAN, UT
Wood - H 138.00 138.00 65.00 1 11 CAMERON, UT SIGURD, UT
Wood - H 138.00 138.00 12.00 1 12 CANYON COMP, WY STR 204, WY
Wood - H 138.00 138.00 2.00 1 13 CARBON, UT HELPER #2, UT
Wood - H 138.00 138.00 120.00 1 14 CARBON, UT MOAB, UT
Steel Tower 138.00 138.00 54.00 1 15 CARBON, UT SPANISH FORK #1, UT
Steel Tower 138.00 138.00 52.00 1 16 CARBON, UT SPANISH FORK #2, UT
Steel - SP 138.00 138.00 20.00 1 17 CENTRAL (UAMPS) #2, UT SAINT GEORGE, UT
Steel - SP 138.00 138.00 20.00 1 18 CENTRAL (UAMPS) #3, UT SAINT GEORGE, UT
Wood - SP 138.00 138.00 5.00 1 19 CLEAR CREEK, WY PAINTER, UT
Wood - SP 138.00 138.00 2.00 1 20 CLOVER, UT BURRASTON PONDS
Wood - SP 138.00 138.00 8.00 1 21 CLOVER, UT NEBO, UT
Wood - H 138.00 138.00 2.00 1 22 COLUMBIA, UT SUNNYSIDE, UT
Wood - SP 138.00 138.00 5.00 1 23 COTTONWOOD, UT HAMMER, UT
Steel - SP 138.00 138.00 6.00 1 24 COTTONWOOD, UT MCCLELLAND, UT
Wood - SP 138.00 138.00 30.00 1 25 COTTONWOOD, UT SILVER CREEK, UT
Wood - SP 138.00 138.00 1 26 CUTLER, UT WHEELON, UT
Steel - SP 138.00 138.00 5.00 1 27 DRY CREEK, UT SPANISH FORK, UT
Wood - SP 138.00 138.00 19.00 1 28 DUMAS, UT WESTFIELD, UT
Steel - SP 138.00 138.00 2.00 1 29 DYNAMO, UT TRI-CITY #1, UT
Steel - SP 138.00 138.00 3.00 1 30 DYNAMO, UT TRI-CITY #2, UT
Wood - SP 138.00 138.00 10.00 1 31 EAGLE MOUNTAIN, UT PONY EXPRESS, UT
Steel - SP 138.00 138.00 15.00 1 32 EAST LAYTON, UT 105 TAP, UT
Wood - SP 138.00 138.00 1.00 1 33 EBAY TAP, UT OQUIRRH, UT
Steel - SP 138.00 138.00 1.00 1 34 EL MONTE, UT PIONEER, UT
Steel - SP 138.00 138.00 4.00 1 35 EL MONTE, UT EAST BANK, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.5
36 TOTAL 16,965.00 651.00 288
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
795 AAC /37 1
1272 ACSR 45/7 2
795 AAC /37 3
250 CUHD /12 4
795 ACSR 26/7 5
1272 ACSR 45/7 6
795 ACSR 26/7 7
795 AAC /37 8
397.5 ACSR 26/7 9
397.5 ACSR 26/7 10
397.5 ACSR 26/7 11
795 ACSR 26/7 12
556.5 ACSR 26/7 13
954 ACSR 54/7 14
795 ACSR 26/7 15
1272 ACSR 45/7 16
1272 ACSR 45/7 17
1272 ACSR 45/7 18
795 ACSR 26/7 19
397.5 ACSR 26/7 20
1272 ACSR 45/7 21
397.5 ACSR 26/7 22
795 AAC /37 23
795 AAC /37 24
397.5 ACSR 26/7 25
250 CUHD /12 26
1272 ACSR 45/7 27
795 ACSR 26/7 28
795 ACSR 26/7 29
795 ACSR 26/7 30
795 ACSR 26/7 31
795 ACSR 26/7 32
795 ACSR 26/7 33
1272 ACSR 45/7 34
1272 ACSR 45/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.5
36 253,528,964 3,620,408,197 3,873,937,161 1,089,585 16,258,960 2,244,063 19,592,608
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2019/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Wood - SP 138.00 138.00 3.00 1 1 EVANSTON, WY RAILROAD, UT
Wood - SP 138.00 138.00 3.00 1 2 FORT DOUGLAS, UT MCCLELLAND, UT
Wood - SP 138.00 138.00 25.00 1 3 FRANKLIN, ID GREEN CANYON, UT
Wood - SP 138.00 138.00 10.00 1 4 FRANKLIN, ID TREASURETON, ID
Wood - SP 138.00 138.00 1 5 GADSBY, UT JORDAN, UT
Wood - SP 138.00 138.00 6.00 1 6 GADSBY, UT TERMINAL, UT
Wood - SP 138.00 138.00 1.00 1 7 GADSBY, UT THIRD WEST, UT
Wood - SP 138.00 138.00 1.00 1 8 GRAPHITE, UT MOUNTAIN VIEW, UT
Wood - SP 138.00 138.00 7.00 1 9 GREEN CANYON, UT NIBLEY, UT
Wood - SP 138.00 138.00 19.00 1 10 GREEN CANYON, UT WHEELON, UT
Wood - SP 138.00 138.00 3.00 1 11 GRINDING, UT OQUIRRH, UT
Wood - SP 138.00 138.00 14.00 1 12 GRINDING, UT TOOELE, UT
Wood - H 138.00 138.00 19.00 1 13 HALE, UT MIDWAY, UT
Wood - H 138.00 138.00 18.00 1 14 HALE, UT SPANISH FORK, UT
Wood - H 138.00 138.00 7.00 1 15 HALE, UT TANNER, UT
Wood - SP 138.00 138.00 2.00 1 16 HAMMER, UT BUTLERVILLE, UT
Wood - SP 138.00 138.00 5.00 1 17 HIGHLAND, UT BULL RIVER (LEHI #5), UT
Wood - H 138.00 138.00 25.00 1 18 HONEYVILLE, UT LAMPO, UT
Steel Tower 138.00 138.00 14.00 1 19 HONEYVILLE, UT WHEELON, UT
Wood - H 138.00 138.00 7.00 1 20 HUNTINGTON, UT MCFADDEN, UT
Wood - H 138.00 138.00 26.00 1 21 JERUSALEM, UT NEBO, UT
Wood - SP 138.00 138.00 5.00 1 22 JORDAN, UT MCCLELLAND, UT
Wood - SP 138.00 138.00 6.00 1 23 JORDAN, UT TERMINAL, UT
Wood - SP 138.00 138.00 1.00 1 24 JORDAN, UT THIRD WEST, UT
Wood - SP 138.00 138.00 3.00 1 25 KEARNS, UT TAYLORSVILLE, UT
Wood - SP 138.00 138.00 2.00 1 26 KEARNS, UT WEST VALLEY, UT
Steel - SP 138.00 138.00 8.00 1 27 LONE PEAK, UT CAMP WILLIAMS, UT
Wood - SP 138.00 138.00 6.00 1 28 MCCLELLAND, UT MIDVALLEY, UT
Wood - H 138.00 138.00 11.00 1 29 MCFADDEN, UT BLACKHAWK, UT
Wood - H 138.00 138.00 9.00 1 30 MID VALLEY, UT 90TH SOUTH, UT
Wood - SP 138.00 138.00 3.00 1 31 MID VALLEY #2, UT COTTONWOOD, UT
Wood - SP 138.00 138.00 5.00 1 32 MID VALLEY #1, UT COTTONWOOD, UT
Wood - SP 138.00 138.00 2.00 4.00 1 33 MID VALLEY, UT TAYLORSVILLE, UT
Wood - H 138.00 138.00 1.00 1 34 MIDDLETON, UT ST. GEORGE, UT
Wood - H 138.00 138.00 68.00 1 35 MOAB, UT PINTO, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.6
36 TOTAL 16,965.00 651.00 288
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
795 ACSR 26/7 1
2
397.5 ACSR 26/7 3
795 ACSR 26/7 4
1272 ACSR 45/7 5
1272 ACSR 45/7 6
1272 AAC /61 7
397.5 ACSR 26/7 8
1272 ACSR 45/7 9
397.5 ACSR 26/7 10
795 ACSR 45/7 11
795 ACSR 45/7 12
397.5 ACSR 26/7 13
1272 ACSR 45/7 14
1272 ACSR 45/7 15
795 ACSR 26/7 16
1272 ACSR 45/7 17
397.5 ACSR 26/7 18
250 CUHD /12 19
397.5 ACSR 26/7 20
397.5 ACSR 26/7 21
795 AAC /37 22
1272 AAC/91 23
1272 AAC /61 24
795 ACSR 26/7 25
26
1272 ACSR 45/7 27
795 AAC 26/7 28
795 AAC 26/7 29
1272 ACSR 45/7 30
31
32
1272 ACSR /61 33
397.5 ACSR 26/7 34
397.5 ACSR 26/7 35
FERC FORM NO. 1 (ED. 12-87) Page 423.6
36 253,528,964 3,620,408,197 3,873,937,161 1,089,585 16,258,960 2,244,063 19,592,608
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2019/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Wood - H 138.00 138.00 35.00 1 1 NAUGHTON, WY CANYON COMP, WY
Wood - H 138.00 138.00 44.00 1 2 NAUGHTON, WY PAINTER, WY
Wood - H 138.00 138.00 33.00 1 3 NEBO, UT DRY CREEK, UT
Wood - H 138.00 138.00 10.00 1 4 NUCOR STEEL, UT WHEELON, UT
Wood - H 138.00 138.00 23.00 1 5 ONEIDA, ID OVID, UT
Wood - H 138.00 138.00 19.00 1 6 ONIEDA, ID GRACE, ID
Wood - H 138.00 138.00 5.00 1 7 OQUIRRH, UT BARNEY, UT
Wood - H 138.00 138.00 8.00 1 8 OQUIRRH, UT BINGHAM CANYON, UT
Steel - SP 138.00 138.00 23.00 1 9 OQUIRRH, UT TOOELE, UT
Wood - H 138.00 138.00 7.00 1 10 PAINTER, UT RAILROAD, UT
Steel - SP 138.00 138.00 14.00 1 11 PARRISH #105, UT TERMINAL, UT
Wood - H 138.00 138.00 21.00 1 12 PAROWAN, UT WEST CEDAR, UT
Steel - SP 138.00 138.00 8.00 1 13 PARRISH, UT TAP TO N. SALT LAKE, UT
Steel - SP 138.00 138.00 16.00 1 14 PARRISH, UT TERMINAL #1, UT
Steel - SP 138.00 138.00 14.00 1 15 PARRISH, UT TERMINAL #2, UT
Wood - H 138.00 138.00 17.00 1 16 RAILROAD, UT CANYON COMP, WY
Wood - H 138.00 138.00 49.00 1 17 RED BUTTE, UT WEST CEDAR, UT
Steel - SP 138.00 138.00 7.00 1 18 RIVERDALE, UT EAST LAYTON, UT
Wood - H 138.00 138.00 10.00 1 19 SHICK, UT PARRISH, UT
Wood - SP 138.00 138.00 10.00 1 20 SILVER CREEK, UT JORDANELLE, UT
Wood - SP 138.00 138.00 72.00 1 21 SILVER CREEK, UT RAILROAD, UT
Wood - H 138.00 138.00 10.00 1 22 SPANISH FORK, UT TANNER, UT
Wood - SP 138.00 138.00 10.00 2 23 ST. GEORGE, UT PURGATORY FLAT, UT
Wood - SP 138.00 138.00 2.00 1 24 SUNRISE, UT OQUIRRH, UT
Wood - SP 138.00 138.00 7.00 1 25 SYRACUSE, UT ANGEL #1, UT
Steel - SP 138.00 138.00 5.00 1 26 SYRACUSE, UT CLEARFIELD SOUTH, UT
Steel Tower 138.00 138.00 15.00 1 27 SYRACUSE, UT PARRISH, UT
Wood - H 138.00 138.00 4.00 1 28 TAP TO ANGEL NORTH, UT TAP TO PARRISH, UT
Wood - SP 138.00 138.00 2.00 6.00 1 29 TAYLORSVILLE, UT 90TH SOUTH, UT
Steel - SP 138.00 138.00 9.00 1 30 TERMINAL, UT KENNECOTT, UT
Wood - H 138.00 138.00 7.00 1 31 TERMINAL, UT MIDVALLEY #1, UT
Wood - H 138.00 138.00 7.00 1 32 TERMINAL, UT MIDVALLEY #2, UT
Wood - H 138.00 138.00 53.00 1 33 TERMINAL, UT ROWLEY, UT
Wood - H 138.00 138.00 6.00 24.00 1 34 TERMINAL, UT TOOELE, UT
Wood - SP 138.00 138.00 7.00 1 35 TERMINAL, UT WEST VALLEY, UT
FERC FORM NO. 1 (ED. 12-87) Page 422.7
36 TOTAL 16,965.00 651.00 288
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
795 AAC 26/7 1
795 AAC 26/7 2
795 AAC 26/7 3
397.5 ACSR 26/7 4
336.4 ACSR 26/7 5
250 CUHD /12 6
795 AAC 26/7 7
1557.4 ACSR/TW 8
1272 ACSR 45/7 9
1272 ACSR 45/7 10
795 AAC 45/7 11
397.5 ACSR 26/7 12
795 AAC 26/7 13
795 AAC 45/7 14
795 AAC 26/7 15
795 ACSR 26/7 16
397.5 ACSR 26/7 17
795 AAC 26/7 18
250 CUHD /12 19
795 AAC 26/7 20
1272 ACSR 45/7 21
1272 ACSR 45/7 22
1272 ACSR 45/7 23
24
250 CUHD /12 25
1272 ACSR 45/7 26
1272 ACSR 45/7 27
795 AAC /37 28
795 AAC /37 29
795 AAC 26/7 30
1272 ACSR 45/7 31
1272 AAC /61 32
795 AAC /37 33
397.5 ACSR 26/7 34
35
FERC FORM NO. 1 (ED. 12-87) Page 423.7
36 253,528,964 3,620,408,197 3,873,937,161 1,089,585 16,258,960 2,244,063 19,592,608
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
PacifiCorp X
/ /2019/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
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. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Wood - H 138.00 138.00 17.00 1 1 THREEMILE KNOLL, ID GRACE #1, ID
Wood - H 138.00 138.00 17.00 1 2 THREEMILE KNOLL, ID GRACE #2, ID
Wood - H 138.00 138.00 2.00 1 3 THREEMILE KNOLL, ID MONSANTO #1, ID
Steel - SP 138.00 138.00 2.00 1 4 THREEMILE KNOLL, ID MONSANTO #2, ID
Steel - SP 138.00 138.00 2.00 1 5 TIMP #1, UT DYNAMO, UT
Steel - SP 138.00 138.00 2.00 1 6 TIMP #2, UT DYNAMO, UT
Steel - SP 138.00 138.00 4.00 1 7 TIMP, UT HALE, UT
Wood - H 138.00 138.00 20.00 1 8 TIMP, UT SPANISH FORK, UT
Wood - SP 138.00 138.00 2.00 1 9 TIMP, UT VINEYARD, UT
Steel Tower 138.00 138.00 25.00 1 10 TREASURETON, ID GRACE, ID
Steel Tower 138.00 138.00 25.00 1 11 TREASURETON, ID GRACE #2, ID
Wood - H 138.00 138.00 6.00 1 12 TREASURETON, ID ONEIDA, ID
Wood - SP 138.00 138.00 12.00 6.00 1 13 TRI-CITY, UT BANGERTER, UT
Wood - SP 138.00 138.00 22.00 1 14 TRI-CITY, UT SUNRISE, ID
Wood - H 138.00 138.00 15.00 1 15 TRI-CITY, UT WESTFIELD, UT
Wood - SP 138.00 138.00 20.00 1 16 WEST CEDAR, UT THREE PEAKS, UT
Wood - H 138.00 138.00 9.00 1 17 WEST VALLEY, UT OQUIRRH, UT
Wood - H 138.00 138.00 13.00 1 18 WESTFIELD, UT HALE, UT
Wood - H 138.00 138.00 87.00 1 19 WHEELON, UT AMERICAN FALLS, ID
Steel Tower 138.00 138.00 29.00 1 20 WHEELON #1, UT TREASURETON, ID
Steel Tower 138.00 138.00 29.00 1 21 WHEELON #2, UT TREASURETON, ID
Wood - H 138.00 138.00 29.00 1 22 WHEELON #3, UT TREASURETON, ID
23 138kV costs and expenses
205.00 2,222.00 149 24 Subtotal 138kV
25
1,655.00 26 All 115kV Lines
27
2,913.00 28 All 69kV Lines
29
107.00 30 All 57kV Lines
31
2,473.00 32 All 46kV Lines
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 422.8
36 TOTAL 16,965.00 651.00 288
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i) (j) (k) (l)(m) (n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
250 CUHD /12 1
1272 ACSR 45/7 2
1272 AAC /61 3
1272 ACSR 45/7 4
5
6
7
8
1272 ACSR 45/7 9
250 CUHD /12 10
250 CUHD /12 11
250 CUHD /12 12
13
14
1272 ACSR 45/7 15
795 AAC 26/7 16
17
795 AAC 26/7 18
250 CUHD /12 19
250 CUHD /12 20
250 CUHD /12 21
250 CUHD /12 22
444,459,347 410,150,732 34,308,615 2,705,012 152,371 2,209,841 342,800 23
444,459,347 410,150,732 34,308,615 2,705,012 152,371 2,209,841 342,800 24
25
231,646,391 226,218,441 5,427,950 2,544,267 472,318 2,029,723 42,226 26
27
321,182,486 312,795,076 8,387,410 4,643,768 220,843 4,233,722 189,203 28
29
12,861,558 12,720,090 141,468 23,917 5,392 14,575 3,950 30
31
297,212,572 285,621,403 11,591,169 2,001,749 49,161 1,749,267 203,321 32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 423.8
36 253,528,964 3,620,408,197 3,873,937,161 1,089,585 16,258,960 2,244,063 19,592,608
Schedule Page: 422 Line No.: 1 Column: a
Certain transmission lines reported on pages 422-423 are part of exchange agreements with
various third parties. For further discussion, see also page 328-330, Transmission of
electricity for others in this Form No. 1.
Schedule Page: 422 Line No.: 2 Column: a
The Alvey - Dixonville 500kV line is jointly owned by PacifiCorp and Bonneville Power
Administration ("BPA"), each with an undivided 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 and responsibility is as follows: PacifiCorp 58.0% and the BPA
42.0%.
Schedule Page: 422 Line No.: 4 Column: a
The Dixonville - Meridian 500kV line is jointly owned by PacifiCorp and BPA, each with an
undivided 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 and
responsibility is as follows: PacifiCorp 58.0% and the BPA 42.0%.
Schedule Page: 422 Line No.: 8 Column: a
The Midpoint - Malin 500kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line designation is as follows:
Designation PacifiCorp Idaho Power Company
Hemingway – Summer Lake 78.0% 22.0%
Midpoint – Hemingway 63.0% 37.0%
Plant cost and operation and maintenance costs reported for this line represents
PacifiCorp’s share.
Schedule Page: 422 Line No.: 9 Column: a
The Colstrip 4 - Switchyard 500kV line is jointly owned by PacifiCorp, NorthWestern
Corporation, Puget Sound Energy, Avista Corporation and Portland General Electric Company,
in which PacifiCorp owns 6.8% of the line. Plant cost and operation and maintenance costs
reported for this line represents PacifiCorp’s share.
Schedule Page: 422 Line No.: 10 Column: a
The Colstrip - Broadview A 500kV line is jointly owned by PacifiCorp, NorthWestern
Corporation, Puget Sound Energy, Avista Corporation and Portland General Electric Company,
in which PacifiCorp owns 6.8% of the line. Plant cost and operation and maintenance costs
reported for this line represents PacifiCorp's share.
Schedule Page: 422 Line No.: 11 Column: a
The Colstrip - Broadview B 500kV line is jointly owned by PacifiCorp, NorthWestern
Corporation, Puget Sound Energy, Avista Corporation and Portland General Electric Company,
in which PacifiCorp owns 6.8% of the line. Plant cost and operation and maintenance costs
reported for this line represents PacifiCorp's share.
Schedule Page: 422 Line No.: 12 Column: a
The Broadview - Townsend A 500kV line is jointly owned by PacifiCorp, NorthWestern
Corporation, Puget Sound Energy, Avista Corporation and Portland General Electric Company,
in which PacifiCorp owns 8.1% of the line. Plant cost and operation and maintenance costs
reported for this line represents PacifiCorp's share.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 422 Line No.: 13 Column: a
The Broadview - Townsend B 500kV line is jointly owned by PacifiCorp, NorthWestern
Corporation, Puget Sound Energy, Avista Corporation and Portland General Electric Company,
in which PacifiCorp owns 8.1% of the line. Plant cost and operation and maintenance costs
reported for this line represents PacifiCorp's share.
Schedule Page: 422 Line No.: 17 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422 Line No.: 18 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422 Line No.: 26 Column: a
The Borah - Midpoint #1 345kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line designation Borah - Adelaide - Midpoint #1 is as follows: PacifiCorp
35.6%, Idaho Power Company 64.4%. Plant cost and operation and maintenance costs reported
for this line represents PacifiCorp’s share.
Schedule Page: 422 Line No.: 27 Column: a
The Borah - Midpoint #2 345kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line designation Borah - Adelaide - Midpoint #2 is as follows: PacifiCorp
35.6%, Idaho Power Company 64.4%. Plant cost and operation and maintenance costs reported
for this line represents PacifiCorp’s share.
Schedule Page: 422.1 Line No.: 4 Column: a
The Goshen - Kinport 345kV line is jointly owned by PacifiCorp and Idaho Power Company
with an undivided interest of 81.7% and 18.3%, respectively. Plant cost and operation and
maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.1 Line No.: 9 Column: a
The Jim Bridger - Goshen 345kV line is jointly owned by PacifiCorp and Idaho Power Company
with an undivided interest of 70.8% and 29.2%, respectively. Plant cost and operation and
maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.1 Line No.: 10 Column: a
The Jim Bridger - Borah 345kV line is jointly owned by PacifiCorp and Idaho Power Company.
Ownership of the line designation is as follows:
Designation PacifiCorp Idaho Power Company
Jim Bridger – Populus #1 70.8% 29.2%
Populus – Borah #1 70.8% 29.2%
Plant cost and operation and maintenance costs reported for this line represents
PacifiCorp’s share.
Schedule Page: 422.1 Line No.: 11 Column: a
The Jim Bridger - Kinport 345kV line is jointly owned by PacifiCorp and Idaho Power
Company. Ownership of the line designation is as follows:
Designation PacifiCorp Idaho Power Company
Jim Bridger – Populus #2 70.8% 29.2%
Populus – Kinport 70.8% 29.2%
Plant cost and operation and maintenance costs reported for this line represents
PacifiCorp’s share.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 422.1 Line No.: 12 Column: a
The Kinport - Midpoint 345kV line is jointly owned by PacifiCorp and Idaho Power Company
with an undivided interest of 26.8% and 73.2%, respectively. Plant cost and operation and
maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.2 Line No.: 2 Column: a
A 1.5 mile segment of the Casper - Dave Johnston 230kV line is jointly owned by PacifiCorp
and Black Hills Power with an undivided interest of 43.75% and 56.25%, respectively. Plant
cost and operation and maintenance costs reported for this line represents PacifiCorp's
share.
Schedule Page: 422.2 Line No.: 2 Column: i
1557 ACSS/TW 45/7
Schedule Page: 422.2 Line No.: 7 Column: i
1557 ACSR/TW 36/7

Schedule Page: 422.2 Line No.: 18 Column: a
Complete name is Gonder (NV Energy), Utah-Nevada State
Schedule Page: 422.2 Line No.: 21 Column: a
The Hurricane - Walla Walla 230kV line is jointly owned by PacifiCorp and Idaho Power
Company with an undivided interest of 59.2% and 40.8%, respectively. Plant cost and
operation and maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.2 Line No.: 30 Column: i
1158.4 ACSS/TW 25/7
Schedule Page: 422.4 Line No.: 1 Column: a
The Antelope - Goshen 161kV line is jointly owned by PacifiCorp and Idaho Power Company
with an undivided interest of 78.1% and 21.9%, respectively. Plant cost and operation and
maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.4 Line No.: 2 Column: a
The Big Grassy - Jefferson 161kV line is jointly owned by PacifiCorp and Idaho Power
company with an undivided interest of 62.2% and 37.8%, respectively. Plant costs and
operation and maintenance costs reported for this line represents PacifiCorp's share.
Schedule Page: 422.4 Line No.: 6 Column: a
The Goshen - Jefferson 161kV line is jointly owned by PacifiCorp and Idaho Power Company
with an undivided interest of 77.0% and 23.0%, respectively. Plant cost and operation and
maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.4 Line No.: 23 Column: a
The Antelope - Scoville #1 138kV line is jointly owned by PacifiCorp and Idaho Power
Company with an undivided interest of 33.3% and 66.7%, respectively. Plant cost and
operation and maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.4 Line No.: 24 Column: a
The Antelope - Scoville #2 138kV line is jointly owned by PacifiCorp and Idaho Power
Company with an undivided interest of 33.3% and 66.7%, respectively. Plant cost and
operation and maintenance costs reported for this line represents PacifiCorp’s share.
Schedule Page: 422.4 Line No.: 28 Column: i
1557.4 ACSR/TW 36/7
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Schedule Page: 422.5 Line No.: 17 Column: a
The Central #2 - Saint George 138kV line is jointly owned by PacifiCorp and Utah
Associated Municipal Power Systems with an undivided interest of 43.26% and 56.74%,
respectively. Plant cost and operation and maintenance costs reported for this line
represents PacifiCorp's share.
Schedule Page: 422.5 Line No.: 18 Column: a
The Central #3 - Saint George 138kV line is jointly owned by PacifiCorp and Utah
Associated Municipal Power Systems with an undivided interest of 43.26% and 56.74%,
respectively. Plant cost and operation and maintenance costs reported for this line
represents PacifiCorp's share.
Schedule Page: 422.5 Line No.: 20 Column: b
Complete name is Burraston Ponds Metering, UT
Schedule Page: 422.6 Line No.: 2 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 26 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 31 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.6 Line No.: 32 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.7 Line No.: 8 Column: b
Complete name is Bingham Canyon (KCC), UT
Schedule Page: 422.7 Line No.: 24 Column: i
1557.4 ACSR/TW 36/7

Schedule Page: 422.7 Line No.: 35 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 5 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 6 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 7 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 8 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 13 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 14 Column: i
1557.4 ACSR/TW 36/7
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.4
Schedule Page: 422.8 Line No.: 17 Column: i
1557.4 ACSR/TW 36/7
Schedule Page: 422.8 Line No.: 19 Column: a
The Wheelon - American Falls 138kV line is jointly owned by PacifiCorp and Idaho Power
Company with an undivided interest of 96.4% and 3.6%, respectively. Plant cost and
operation and maintenance costs reported for this line represents PacifiCorp’s share.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINES ADDED DURING YEAR
PacifiCorp X
/ /2019/Q4
Line
No.
(c)(b)(a) (d) (e)
LINE DESIGNATION
From To
LineLengthinMiles
SUPPORTING STRUCTURE
Type AverageNumber perMiles
CIRCUITS PER STRUCTURE
Present Ultimate
(f) (g)
1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the
8.00Wood - H 1 1 1 CORRAL, OR OCHOCO #1, OR 9.00
8.00Wood - H 1 1 2 MCNARY (BPA), OR WALLULA, WA 29.00
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
38.00 16.00 2 2
FERC FORM NO. 1 (REV. 12-03) Page 424
44 TOTAL
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINES ADDED DURING YEAR (Continued)
PacifiCorp X
/ /2019/Q4
Line
No.
(k)(j)(h) (l) (m)
CONDUCTORS
Size Configuration
Voltage
KV
LINE COST
Land and Poles, Towers
and Fixtures Conductors
(n) (p)
Specification and Spacing (Operating)Land Rights and Devices(i)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate
such other characteristic.
Asset
(o)Retire. Costs
Horiz. 20'ACSR1557 3,713,593 9,334,649 5,549,547 71,509 230 1
Horiz. 20'ACSS1158.4 13,513,307 30,018,285 11,344,287 5,160,691 230 2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
17,226,900 16,893,834
FERC FORM NO. 1 (REV. 12-03) Page 425
44 5,232,200 39,352,934
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
CALIFORNIA 1
BELMONT SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
BIG SPRINGS SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
CASTELLA SUB 2.40 69.00DISTRIBUTION-UNATTEN 4
CLEAR LAKE SUB 12.47 69.00DISTRIBUTION-UNATTEN 5
DOG CREEK SUB 2.40 69.00DISTRIBUTION-UNATTEN 6
DORRIS SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
FORT JONES SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
GASQUET SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
GREENHORN SUB 12.47 69.00DISTRIBUTION-UNATTEN 10
HAMBURG SUB 2.40 69.00DISTRIBUTION-UNATTEN 11
HAPPY CAMP SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
HORNBROOK SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
INTERNATIONAL PAPER SUB 2.40 69.00DISTRIBUTION-UNATTEN 14
LAKE EARL SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
LITTLE SHASTA SUB 7.20 69.00DISTRIBUTION-UNATTEN 16
LUCERNE SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
MACDOEL SUB 20.80 69.00DISTRIBUTION-UNATTEN 18
MCCLOUD SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
MILLER REDWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
MONTAGUE SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
MORRISON CREEK SUB 12.50 69.00DISTRIBUTION-UNATTEN 22
MOUNT SHASTA SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
NEWELL SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
NORTH DUNSMUIR SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
NORTHCREST SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
NUTGLADE SUB 2.40 69.00DISTRIBUTION-UNATTEN 27
PATRICKS CREEK SUB 7.20 115.00DISTRIBUTION-UNATTEN 28
PEREZ SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
REDWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
SCOTT BAR SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
SEIAD SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
SHASTINA SUB 20.80 69.00DISTRIBUTION-UNATTEN 33
SHOTGUN CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
SMITH RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
SNOW BRUSH SUB 7.20 69.00DISTRIBUTION-UNATTEN 36
SOUTH DUNSMUIR SUB 4.16 69.00DISTRIBUTION-UNATTEN 37
TULELAKE SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
TUNNEL SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
WALKER BRYAN SUB 12.47 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
1
25 1 2
6 1 3
1 3 4
4 3 5
1 6
7 3 7
6 1 8
9 1 9
12 1 10
1 1 11
7 3 12
4 3 13
9 3 14
12 1 15
2 3 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
1 3 27
1 1 28
1 3 29
9 3 30
2 3 31
2 3 32
6 3 33
1 1 34
6 3 35
1 3 36
2 3 37
20 1 38
6 6 39
9 3 40
FERC FORM NO. 1 (ED. 12-96) Page 427
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
WEED SUB 12.47 115.00DISTRIBUTION-UNATTEN 1
YUBA SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
YUROK SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
TOTAL (Number of Substations-42) 465.96 3082.00 4
5
ALTURAS SUB 69.00 115.00T/D-UNATTENDED 6
YREKA SUB 12.47 115.00 69.00T/D-UNATTENDED 7
TOTAL (Number of Substations-2) 81.47 230.00 69.00 8
9
COPCO #2 230 SUB 115.00 230.00TRANSMISSION-ATTENDE 10
COPCO #2 SUB 69.00 115.00 12.47TRANSMISSION-ATTENDE 11
AGER SUB 69.00 115.00TRANSMISSION-UNATTEN 12
CRAG VIEW SUB 69.00 115.00TRANSMISSION-UNATTEN 13
DEL NORTE SUB 69.00 115.00TRANSMISSION-UNATTEN 14
TOTAL (Number of Substations-5) 391.00 690.00 12.47 15
16
IDAHO 17
ALEXANDER 12.47 46.00DISTRIBUTION-UNATTEN 18
AMMON 12.47 69.00DISTRIBUTION-UNATTEN 19
ANDERSON 12.47 69.00DISTRIBUTION-UNATTEN 20
ARCO 12.47 69.00DISTRIBUTION-UNATTEN 21
ARIMO 12.47 46.00DISTRIBUTION-UNATTEN 22
BANCROFT SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
BELSON SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
BERENICE SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
CAMAS SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
CANYON CREEK SUB 24.90 69.00DISTRIBUTION-UNATTEN 27
CHESTERFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
CLEMENTS SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
CLIFTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
COVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
DOWNEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
DUBOIS SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
EAST AMMON 12.47 69.00DISTRIBUTION-UNATTEN 34
EASTMONT SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
EGIN SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
EIGHT MILE SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
GEORGETOWN SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
GRACE CITY SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
HAMER SUB 12.47 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
25 1 1
4 3 2
4 3 3
323 99 4
5
35 4 6
95 2 7
130 6 8
9
500 2 10
51 4 11
5 3 12
19 3 13
150 2 14
725 14 15
16
17
4 1 18
14 1 19
20 1 20
6 1 21
7 1 22
4 1 23
12 1 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 1 33
9 1 34
14 1 35
14 1 36
4 1 37
6 1 38
5 1 39
14 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
HAYES SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
HENRY SUB 7.20 46.00DISTRIBUTION-UNATTEN 2
HOLBROOK SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
HOOPES SUB 12.47 69.00DISTRIBUTION-UNATTEN 4
HORSLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
IDAHO FALLS SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
INDIAN CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
JEFFCO SUB 24.90 69.00DISTRIBUTION-UNATTEN 8
KETTLE SUB 24.90 69.00DISTRIBUTION-UNATTEN 9
LAVA SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
LUND SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
MCCAMMON SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
MENAN SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
MERRILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 14
MILLER SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
MONTPELIER SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
MOODY SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
NEWDALE SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
OSGOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
PRESTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
RAYMOND SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
RENO SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
REXBURG SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
ROBERTS SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
RUBY SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
SAND CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
SANDUNE SUB 24.90 67.00DISTRIBUTION-UNATTEN 27
SHELLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
SMITH SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
SOUTH FORK SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
SPUD SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
ST. CHARLES SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
SUGAR CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
SUNNYDELL SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
TANNER SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
TARGHEE SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
THORNTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
UCON SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
WATKINS SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
WEBSTER SUB 12.47 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
9 1 1
1 1 2
6 1 3
9 1 4
4 1 5
20 1 6
3 1 7
22 1 8
14 1 9
6 1 10
5 1 11
3 1 12
10 1 13
20 1 14
5 1 15
8 1 16
14 1 17
20 1 18
20 1 19
12 1 20
2 1 21
20 1 22
32 2 23
8 1 24
7 1 25
40 2 26
30 1 27
20 1 28
20 1 29
14 1 30
8 1 31
5 1 32
12 1 33
13 1 34
4 1 35
4 1 36
7 1 37
7 1 38
14 1 39
20 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
WESTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
WINDSPER SUB 24.90 69.00DISTRIBUTION-UNATTEN 2
TOTAL (Number of Substations-65) 867.43 4000.00 3
4
CINDER BUTTE SUB 12.47 161.00T/D-UNATTENDED 5
MALAD SUB 69.00 138.00 12.47T/D-UNATTENDED 6
MUD LAKE SUB 12.47 69.00T/D-UNATTENDED 7
RIGBY SUB 12.47 161.00 69.00T/D-UNATTENDED 8
SAINT ANTHONY SUB 46.00 69.00 12.47T/D-UNATTENDED 9
TOTAL (Number of Substations-5) 152.41 598.00 93.94 10
11
AMPS SUB 69.00 230.00 12.47TRANSMISSION-UNATTEN 12
ANTELOPE SUB 161.00 230.00 13.80TRANSMISSION-UNATTEN 13
ASHTON PLANT 12.47 46.00 2.40TRANSMISSION-UNATTEN 14
BIG GRASSY SUB 69.00 161.00TRANSMISSION-UNATTEN 15
BONNEVILLE SUB 69.00 161.00TRANSMISSION-UNATTEN 16
CONDA SUB 46.00 138.00TRANSMISSION-UNATTEN 17
FISH CREEK SUB 46.00 161.00TRANSMISSION-UNATTEN 18
FRANKLIN SUB 46.00 138.00TRANSMISSION-UNATTEN 19
GOSHEN SUB 161.00 345.00 69.00TRANSMISSION-UNATTEN 20
GRACE SUB 138.00 161.00 12.50TRANSMISSION-UNATTEN 21
JEFFERSON SUB 69.00 161.00TRANSMISSION-UNATTEN 22
MIDPOINT SUB 345.00 500.00TRANSMISSION-UNATTEN 23
OVID SUB 69.00 138.00TRANSMISSION-UNATTEN 24
SCOVILLE SUB 69.00 138.00TRANSMISSION-UNATTEN 25
SUGARMILL SUB 46.00 161.00 69.00TRANSMISSION-UNATTEN 26
THREEMILE KNOLL SUB 138.00 345.00 46.00TRANSMISSION-UNATTEN 27
TREASURETON SUB 138.00 230.00TRANSMISSION-UNATTEN 28
WESTWOOD SUB 13.20 161.00TRANSMISSION-UNATTEN 29
TOTAL (Number of Substations-18) 1704.67 3605.00 225.17 30
31
MONTANA 32
BROADVIEW SUB 230.00 500.00TRANSMISSION-UNATTEN 33
COLSTRIP SUB 230.00 500.00TRANSMISSION-UNATTEN 34
YELLOWTAIL SUB 161.00 230.00TRANSMISSION-UNATTEN 35
TOTAL (Number of Substations-3) 621.00 1230.00 36
37
OREGON 38
26TH STREET 4.16 20.80DISTRIBUTION-UNATTEN 39
35TH STREET 2.40 20.80DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
4 1 1
20 1 2
736 67 3
4
30 1 5
39 4 1 6
14 1 7
189 4 8
40 2 9
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 1 19
908 4 1 20
217 2 21
233 3 22
1500 1 1 23
105 2 24
76 2 25
168 3 26
775 2 27
533 2 28
30 1 29
5186 32 2 30
31
32
32 2 33
68 2 34
100 1 35
200 5 36
37
38
5 1 39
30 6 40
FERC FORM NO. 1 (ED. 12-96) Page 427.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
AGNESS AVE 12.47 115.00DISTRIBUTION-UNATTEN 1
ALDERWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
ARLINGTON 12.47 69.00DISTRIBUTION-UNATTEN 3
ATHENA 12.47 69.00DISTRIBUTION-UNATTEN 4
BANDON TIE SUB 12.47 20.80DISTRIBUTION-UNATTEN 5
BEACON SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
BEALL LANE SUB 12.47 115.00DISTRIBUTION-UNATTEN 7
BEATTY SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
BELKNAP SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
BLALOCK SUB 12.47 69.00DISTRIBUTION-UNATTEN 10
BLOSS SUB 12.47 115.00DISTRIBUTION-UNATTEN 11
BLY SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
BOISE CASCADE SUB 11.00 69.00DISTRIBUTION-UNATTEN 13
BONANZA SUB 12.47 69.00DISTRIBUTION-UNATTEN 14
BOND STREET SUB 12.50 69.00DISTRIBUTION-UNATTEN 15
BROOKHURST SUB 12.47 115.00DISTRIBUTION-UNATTEN 16
BROWNSVILLE SUB 20.80 69.00DISTRIBUTION-UNATTEN 17
BRYANT SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
BUCHANAN SUB 20.80 115.00DISTRIBUTION-UNATTEN 19
BUCKAROO SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
CAMPBELL SUB 12.47 115.00DISTRIBUTION-UNATTEN 21
CANNON BEACH SUB 12.47 115.00DISTRIBUTION-UNATTEN 22
CANYONVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 23
CARNES SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
CASEBEER SUB 20.80 69.00DISTRIBUTION-UNATTEN 25
CAVEMAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 26
CHERRY LANE SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
CHILOQUIN MARKET SUB 12.47 69.00DISTRIBUTION-UNATTEN 28
CHINA HAT SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
CIRCLE BLVD SUB 20.80 115.00DISTRIBUTION-UNATTEN 30
CLEVELAND AVE SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
CLOAKE SUB 20.80 69.00DISTRIBUTION-UNATTEN 32
COBURG SUB 20.80 69.00DISTRIBUTION-UNATTEN 33
COLISEUM SUB 4.16 20.80DISTRIBUTION-UNATTEN 34
COLUMBIA SUB 69.00 115.00 12.47DISTRIBUTION-UNATTEN 35
COOS RIVER SUB 20.80 115.00DISTRIBUTION-UNATTEN 36
COQUILLE SUB 20.80 115.00DISTRIBUTION-UNATTEN 37
CREEK SUB 34.50 69.00DISTRIBUTION-UNATTEN 38
CROOKED RIVER RANCH SUB 20.80 69.00DISTRIBUTION-UNATTEN 39
CROWFOOT SUB 12.47 115.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
25 1 1
45 2 2
5 1 3
9 1 4
8 3 1 5
11 3 6
25 1 7
6 1 8
40 2 9
2 3 10
32 2 11
8 3 12
3 1 13
8 3 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
9 3 24
20 1 25
45 2 26
25 1 27
9 3 28
25 1 29
80 2 30
45 2 31
20 1 32
10 3 33
9 2 34
128 4 1 35
20 1 36
40 2 37
5 1 38
25 2 39
20 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
CULLY SUB 12.47 115.00DISTRIBUTION-UNATTEN 1
CULVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
DAIRY SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
DALLAS SUB 20.80 115.00DISTRIBUTION-UNATTEN 4
DALREED SUB 34.40 230.00DISTRIBUTION-UNATTEN 5
DEVILS LAKE SUB 20.80 115.00DISTRIBUTION-UNATTEN 6
DIXON SUB 4.16 115.00DISTRIBUTION-UNATTEN 7
DODGE BRIDGE SUB 20.80 70.60DISTRIBUTION-UNATTEN 8
DOWELL SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
EASY VALLEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 10
EMPIRE SUB 20.80 115.00DISTRIBUTION-UNATTEN 11
ENTERPRISE SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
FERN HILL SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
FIELDER CREEK SUB 20.80 115.00DISTRIBUTION-UNATTEN 14
FOOTHILLS SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
FRALEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
GARDEN VALLEY SUB 20.80 69.00DISTRIBUTION-UNATTEN 17
GLENDALE SUB 12.47 230.00DISTRIBUTION-UNATTEN 18
GLENEDEN SUB 4.16 20.80DISTRIBUTION-UNATTEN 19
GLIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 20
GOLD HILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 21
GORDON HOLLOW SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
GOSHEN SUB 20.80 115.00DISTRIBUTION-UNATTEN 23
GRANT STREET SUB 20.80 115.00DISTRIBUTION-UNATTEN 24
GREEN SUB 12.47 69.00DISTRIBUTION-UNATTEN 25
GRIFFIN CREEK SUB 12.47 115.00DISTRIBUTION-UNATTEN 26
HAMAKER SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
HARRISBURG SUB 20.80 69.00DISTRIBUTION-UNATTEN 28
HENLEY SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
HERMISTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 30
HILLVIEW SUB 20.80 115.00DISTRIBUTION-UNATTEN 31
HINKLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
HOLLADAY SUB 12.47 115.00DISTRIBUTION-UNATTEN 33
HOLLYWOOD SUB 12.47 115.00DISTRIBUTION-UNATTEN 34
HOOD RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
HORNET SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
HUMBUG CREEK SUB 12.50 67.00DISTRIBUTION-UNATTEN 37
HUNTERS CIRCLE TEMP SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
ILLAHEE FLATS SUB 12.47 115.00DISTRIBUTION-UNATTEN 39
INDEPENDENCE SUB 20.80 69.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
25 1 1
13 1 2
25 1 3
50 2 4
95 4 5
50 2 6
7 1 7
25 2 8
20 1 9
45 2 10
20 1 11
19 2 12
12 1 13
25 1 14
21 4 15
5 3 16
20 1 17
25 2 18
6 1 19
12 1 20
11 3 21
6 1 22
20 1 23
45 2 24
25 1 25
20 1 26
8 3 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
9 1 37
12 1 38
2 1 39
20 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.5
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
JACKSONVILLE SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 1
JEFFERSON SUB 20.80 69.00DISTRIBUTION-UNATTEN 2
JEROME PRAIRIE SUB 12.47 115.00DISTRIBUTION-UNATTEN 3
JORDAN POINT SUB 12.47 115.00DISTRIBUTION-UNATTEN 4
JOSEPH SUB 12.47 20.80DISTRIBUTION-UNATTEN 5
JUNCTION CITY SUB 20.80 69.00DISTRIBUTION-UNATTEN 6
KENWOOD SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
KILLINGWORTH SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
KNAPPA SVENSEN SUB 12.47 115.00DISTRIBUTION-UNATTEN 9
LAKEPORT SUB 12.47 69.00DISTRIBUTION-UNATTEN 10
LANCASTER SUB 20.80 69.00DISTRIBUTION-UNATTEN 11
LEBANON SUB 20.80 115.00DISTRIBUTION-UNATTEN 12
LINCOLN SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
LOCKHART SUB 20.80 115.00DISTRIBUTION-UNATTEN 14
LYONS SUB 20.80 69.00DISTRIBUTION-UNATTEN 15
MADRAS SUB 12.47 69.00DISTRIBUTION-UNATTEN 16
MALLORY SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
MARYS RIVER SUB 20.80 115.00DISTRIBUTION-UNATTEN 18
MEDCO SUB 12.47 115.00DISTRIBUTION-UNATTEN 19
MEDFORD SUB 12.47 115.00DISTRIBUTION-UNATTEN 20
MERLIN SUB 12.47 115.00DISTRIBUTION-UNATTEN 21
MERRILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
MINAM SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
MODOC SUB 12.47 69.00DISTRIBUTION-UNATTEN 24
MURDER CREEK SUB 20.80 115.00DISTRIBUTION-UNATTEN 25
MYRTLE CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
MYRTLE POINT SUB 20.80 115.00DISTRIBUTION-UNATTEN 27
NELSCOTT SUB 4.16 20.80DISTRIBUTION-UNATTEN 28
NEW DESCHUTES SUB 13.09 70.44DISTRIBUTION-UNATTEN 29
NEW O'BRIEN SUB 12.47 115.00DISTRIBUTION-UNATTEN 30
OAK KNOLL SUB 12.47 115.00DISTRIBUTION-UNATTEN 31
OAKLAND SUB 12.47 115.00DISTRIBUTION-UNATTEN 32
OREMET SUB 12.47 115.00DISTRIBUTION-UNATTEN 33
OVERPASS SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
PALLETTE SUB 20.80 69.00DISTRIBUTION-UNATTEN 35
PARK STREET SUB 12.47 115.00DISTRIBUTION-UNATTEN 36
PARKROSE SUB 13.20 120.00DISTRIBUTION-UNATTEN 37
PENDLETON SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
PILOT ROCK SUB 12.47 69.00DISTRIBUTION-UNATTEN 39
POWELL BUTTE SUB 12.47 115.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.6
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
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 9
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
9 1 27
4 1 28
25 1 29
9 1 30
45 2 31
8 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 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.6
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
PRINEVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 1
PROVOLT SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
QUEEN AVE SUB 20.80 69.00DISTRIBUTION-UNATTEN 3
RED BLANKET SUB 4.16 69.00DISTRIBUTION-UNATTEN 4
REDMOND SUB 12.47 115.00DISTRIBUTION-UNATTEN 5
RIDDLE VENEER SUB 12.47 115.00DISTRIBUTION-UNATTEN 6
ROGUE RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
ROSEBURG SUB 20.80 115.00DISTRIBUTION-UNATTEN 8
ROSS AVE SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
ROXY ANN SUB 12.47 115.00DISTRIBUTION-UNATTEN 10
RUCH SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
RUNNING Y SUB 20.80 69.00DISTRIBUTION-UNATTEN 12
RUSSELLVILLE SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
SCENIC SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 14
SCIO SUB 12.47 69.00DISTRIBUTION-UNATTEN 15
SEASIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 16
SELMA SUB 12.47 115.00DISTRIBUTION-UNATTEN 17
SHASTA WAY SUB 4.16 12.47DISTRIBUTION-UNATTEN 18
SHEVLIN PARK SUB 12.50 69.00DISTRIBUTION-UNATTEN 19
SIMTAG BOOSTER PUMP 4.16 34.50DISTRIBUTION-UNATTEN 20
SOUTH DUNES SUB 12.47 115.00DISTRIBUTION-UNATTEN 21
SOUTHGATE SUB 20.80 69.00DISTRIBUTION-UNATTEN 22
SPRAGUE RIVER SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
STATE STREET SUB 20.80 115.00DISTRIBUTION-UNATTEN 24
STAYTON SUB 20.80 69.00DISTRIBUTION-UNATTEN 25
STEAMBOAT SUB 7.20 115.00DISTRIBUTION-UNATTEN 26
STEVENS ROAD SUB 20.80 115.00DISTRIBUTION-UNATTEN 27
SUTHERLIN SUB 12.00 115.00DISTRIBUTION-UNATTEN 28
SWEET HOME SUB 20.80 115.00DISTRIBUTION-UNATTEN 29
TAKELMA SUB 20.80 115.00DISTRIBUTION-UNATTEN 30
TALENT SUB 12.47 115.00DISTRIBUTION-UNATTEN 31
TEXUM SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
TILLER SUB 12.47 115.00DISTRIBUTION-UNATTEN 33
TOLO SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
TURKEY HILL SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
UMAPINE SUB 12.47 69.00DISTRIBUTION-UNATTEN 36
UMATILLA SUB 12.47 69.00DISTRIBUTION-UNATTEN 37
VERNON SUB 12.47 115.00DISTRIBUTION-UNATTEN 38
VILAS SUB 12.47 115.00DISTRIBUTION-UNATTEN 39
VILLAGE GREEN SUB 20.80 115.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
50 2 1
11 3 2
50 2 3
2 3 4
50 2 5
25 1 6
25 2 7
50 2 8
9 3 9
25 1 10
9 1 11
9 1 12
45 2 13
70 3 14
8 1 15
40 2 16
9 1 17
2 3 18
25 1 19
19 2 20
9 1 21
20 1 22
7 3 23
40 2 24
55 2 25
1 26
50 2 27
25 1 28
42 2 29
12 1 30
50 2 31
25 1 32
1 1 33
11 1 34
13 3 35
20 1 36
25 2 37
50 2 38
25 1 39
40 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.7
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
VINE STREET SUB 21.80 67.00DISTRIBUTION-UNATTEN 1
WALLOWA SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
WARM SPRINGS SUB 20.80 69.00DISTRIBUTION-UNATTEN 3
WARRENTON SUB 12.47 115.00DISTRIBUTION-UNATTEN 4
WASCO SUB 4.16 20.80DISTRIBUTION-UNATTEN 5
WECOMA BEACH SUB 4.16 20.80DISTRIBUTION-UNATTEN 6
WESTON SUB 13.09 70.60DISTRIBUTION-UNATTEN 7
WESTSIDE HYDRO/SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
WEYERHAUSER SUB 12.47 69.00DISTRIBUTION-UNATTEN 9
WHITE CITY SUB 12.47 115.00DISTRIBUTION-UNATTEN 10
WILLOW COVE SUB 4.16 34.50DISTRIBUTION-UNATTEN 11
WINSTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
YEW AVENUE SUB 12.47 115.00DISTRIBUTION-UNATTEN 13
YOUNGS BAY SUB 12.47 115.00DISTRIBUTION-UNATTEN 14
TOTAL (Number of Substations-176) 2539.44 15500.31 150.47 15
16
ALBINA SUB 12.47 116.00T/D-UNATTENDED 17
APPLEGATE SUB 69.00 115.00 12.47T/D-UNATTENDED 18
ASHLAND SUB 12.47 115.00 7.20T/D-UNATTENDED 19
BEND PLANT SUB 13.09 69.00 12.47T/D-UNATTENDED 20
CAVE JUNCTION SUB 12.47 115.00 69.00T/D-UNATTENDED 21
HAZELWOOD SUB 69.00 115.00 12.47T/D-UNATTENDED 22
KNOTT SUB 12.47 115.00 57.00T/D-UNATTENDED 23
MILE HI SUB 69.00 115.00 12.47T/D-UNATTENDED 24
PILOT BUTTE SUB 69.00 230.00 12.47T/D-UNATTENDED 25
RIDDLE SUB 69.00 115.00T/D-UNATTENDED 26
SAGE ROAD SUB 12.47 115.00T/D-UNATTENDED 27
WINCHESTER SUB 12.47 115.00 69.00T/D-UNATTENDED 28
TOTAL (Number of Substations-12) 432.91 1450.00 264.55 29
30
LEMOLO #1 HYDRO 12.50 11.50TRANSMISSION-ATTENDE 31
CALAPOOYA SUB 69.00 230.00TRANSMISSION-UNATTEN 32
CHILOQUIN SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 33
COLD SPRINGS SUB 69.00 230.00 2.40TRANSMISSION-UNATTEN 34
COVE SUB 69.00 230.00TRANSMISSION-UNATTEN 35
DIAMOND HILL SUB 69.00 230.00TRANSMISSION-UNATTEN 36
DIXONVILLE 115/230 SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 37
DIXONVILLE 500 SUB 230.00 500.00TRANSMISSION-UNATTEN 38
FISH HOLE SUB 69.00 115.00TRANSMISSION-UNATTEN 39
FRIEND SUB 115.00 230.00TRANSMISSION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.8
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
30 1 1
7 1 2
12 3 3
25 2 4
2 3 5
3 1 6
25 1 7
22 9 8
40 2 9
60 3 10
28 3 11
22 3 12
25 1 13
37 2 14
4653 335 5 15
16
120 7 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 5 28
1203 40 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
1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.8
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
FRY SUB 115.00 230.00TRANSMISSION-UNATTEN 1
GRANTS PASS SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 2
HURRICANE SUB 69.00 230.00 2.40TRANSMISSION-UNATTEN 3
ISTHMUS SUB 115.00 230.00TRANSMISSION-UNATTEN 4
KLAMATH FALLS SUB 69.00 230.00TRANSMISSION-UNATTEN 5
LONE PINE SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 6
MALIN SUB 230.00 500.00 69.00TRANSMISSION-UNATTEN 7
MERIDIAN SUB 230.00 500.00TRANSMISSION-UNATTEN 8
MONPAC SUB 69.00 115.00TRANSMISSION-UNATTEN 9
NICKEL MOUNTAIN SUB 115.00 230.00TRANSMISSION-UNATTEN 10
PARRISH GAP SUB 69.00 230.00 12.47TRANSMISSION-UNATTEN 11
PONDEROSA SUB 115.00 230.00TRANSMISSION-UNATTEN 12
PROSPECT CENTRAL SUB 69.00 115.00TRANSMISSION-UNATTEN 13
ROBERTS CREEK SUB 69.00 115.00TRANSMISSION-UNATTEN 14
ROUNDUP SUB - BPA 69.00 230.00TRANSMISSION-UNATTEN 15
SANTIAM TIE - BPA 69.00 230.00TRANSMISSION-UNATTEN 16
SNOW GOOSE SUB 230.00 525.00 34.50TRANSMISSION-UNATTEN 17
TROUTDALE SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 18
TUCKER SUB 69.00 115.00TRANSMISSION-UNATTEN 19
WHETSTONE SUB 115.00 230.00 12.47TRANSMISSION-UNATTEN 20
TOTAL (Number of Substations-30) 3163.50 7211.50 478.24 21
22
UTAH 23
106TH SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 24
118TH SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 25
23RD ST SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
70TH SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 27
ALTAVIEW SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
AMALGA SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
AMERICAN FORK SUB 12.47 138.00DISTRIBUTION-UNATTEN 30
ARAGONITE 7.20 46.00DISTRIBUTION-UNATTEN 31
AURORA SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
BANGERTER SUB 12.47 138.00DISTRIBUTION-UNATTEN 33
BEAR RIVER SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
BENJAMIN SUB 12.47 46.20DISTRIBUTION-UNATTEN 35
BINGHAM SUB 7.62 46.00DISTRIBUTION-UNATTEN 36
BLUE CREEK 12.47 46.00DISTRIBUTION-UNATTEN 37
BLUFF SUB 12.47 69.00DISTRIBUTION-UNATTEN 38
BLUFFDALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
BOTHWELL SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.9
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
500 2 1
583 4 3 2
29 2 3
250 1 4
251 6 1 5
733 10 6
775 4 1 7
1300 6 1 8
50 1 9
114 1 10
150 1 11
500 2 12
30 3 13
50 1 14
67 2 15
75 1 16
650 1 1 17
500 3 18
100 2 19
250 1 20
8374 82 8 21
22
23
30 1 24
30 1 25
13 1 26
30 1 27
45 2 28
11 1 29
30 1 30
1 1 31
3 1 32
50 2 33
17 2 34
4 1 35
25 1 36
2 3 37
1 3 38
9 1 39
4 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.9
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
BRIAN HEAD SUB 12.47 34.50DISTRIBUTION-UNATTEN 1
BRIGHTON SUB 24.90 46.00DISTRIBUTION-UNATTEN 2
BROOKLAWN SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
BRUNSWICK SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
BURTON SUB 12.47 34.50DISTRIBUTION-UNATTEN 5
BUSH SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
CANNON SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
CANYONLANDS SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
CAPITOL SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
CARBIDE SUB 7.20 69.00DISTRIBUTION-UNATTEN 10
CARBONVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
CARLISLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 12
CASTO SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
CENTERVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
CENTRAL SUB 12.47 43.80DISTRIBUTION-UNATTEN 15
CHAPEL HILL SUB 12.47 138.00DISTRIBUTION-UNATTEN 16
CHERRYWOOD SUB 12.47 138.00DISTRIBUTION-UNATTEN 17
CIRCLEVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
CLEAR CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
CLEAR LAKE SUB 12.47 69.00DISTRIBUTION-UNATTEN 20
CLEARFIELD SOUTH SUB 12.47 138.00DISTRIBUTION-UNATTEN 21
CLINTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 22
CLIVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
COALVILLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 24
COLD WATER CANYON SUB 12.47 138.00DISTRIBUTION-UNATTEN 25
COLEMAN SUB 69.00 138.00 12.47DISTRIBUTION-UNATTEN 26
COLTON WELL SUB 2.40 46.00DISTRIBUTION-UNATTEN 27
COMMERCE SUB 12.47 138.00DISTRIBUTION-UNATTEN 28
COPPER HILLS SUB 12.47 138.00DISTRIBUTION-UNATTEN 29
CORINNE SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
COVE FORT SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
COZYDALE SUB 12.47 138.00DISTRIBUTION-UNATTEN 32
CROSS HOLLOW SUB 12.47 138.00DISTRIBUTION-UNATTEN 33
CUDAHY SUB 12.47 138.00DISTRIBUTION-UNATTEN 34
DAMMERON VALLEY SUB 12.47 34.50DISTRIBUTION-UNATTEN 35
DECKER LAKE SUB 12.47 138.00DISTRIBUTION-UNATTEN 36
DELLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
DELTA SUB 69.00 46.00DISTRIBUTION-UNATTEN 38
DEWEYVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
DIMPLE DELL SUB 12.47 138.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.10
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
14 1 1
29 2 2
6 1 3
60 3 4
11 3 5
9 1 6
12 1 7
1 1 8
20 1 9
3 1 10
6 1 11
30 1 12
25 1 13
22 1 14
9 1 15
30 1 16
50 2 17
3 1 18
4 1 19
3 20
60 2 21
50 2 22
4 1 23
22 1 24
30 1 25
106 4 26
1 3 27
30 1 28
30 1 29
3 1 30
2 3 31
30 1 32
22 1 33
30 1 34
42 1 35
55 2 36
6 1 37
48 3 38
4 1 39
60 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.10
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
DRAPER SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
EAST BENCH SUB 12.47 138.00DISTRIBUTION-UNATTEN 2
EAST HYRUM SUB 12.47 46.00DISTRIBUTION-UNATTEN 3
EAST LAYTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 4
EAST MILLCREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
EDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
ELBERTA SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
ELK MEADOWS SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
ELSINORE SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
EMERY CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 10
EMIGRATION SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
ENOCH SUB 12.47 138.00DISTRIBUTION-UNATTEN 12
ENTERPRISE VALLEY SUB 12.47 138.00DISTRIBUTION-UNATTEN 13
EUREKA SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
FARMINGTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 15
FAYETTE SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
FERRON SUB 12.47 69.00DISTRIBUTION-UNATTEN 17
FIELDING SUB 12.00 46.00DISTRIBUTION-UNATTEN 18
FIFTH WEST SUB 12.47 138.00DISTRIBUTION-UNATTEN 19
FLUX SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
FOOL CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
FORT DOUGLAS 13.20 138.00DISTRIBUTION-UNATTEN 22
FOUNTAIN GREEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
FREEDOM SUB 7.20 46.00DISTRIBUTION-UNATTEN 24
FRUIT HEIGHTS SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
GARDEN CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 26
GATEWAY SUB 12.47 69.00DISTRIBUTION-UNATTEN 27
GOLD RUSH SUB 12.47 138.00DISTRIBUTION-UNATTEN 28
GORDON AVENUE SUB 12.47 138.00DISTRIBUTION-UNATTEN 29
GOSHEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
GRANGER SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
GRANTSVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
GUNNISON SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
HAMMER SUB 12.47 138.00DISTRIBUTION-UNATTEN 34
HAVASU SUB 12.47 69.00DISTRIBUTION-UNATTEN 35
HELPER CITY SUB 4.16 46.00DISTRIBUTION-UNATTEN 36
HERRIMAN SUB 13.20 138.00DISTRIBUTION-UNATTEN 37
HIGHLAND DIST SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
HOGGARD SUB 12.47 138.00DISTRIBUTION-UNATTEN 39
HOLDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.11
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
23 2 1
30 1 2
6 1 3
60 2 4
20 1 5
19 2 6
5 1 7
3 1 8
2 1 9
3 3 10
25 1 11
14 1 12
10 1 13
3 1 14
30 1 15
1 2 16
5 1 17
6 1 18
50 2 19
4 1 20
2 1 21
40 1 22
7 1 23
1 24
22 1 25
12 1 26
14 1 2 27
30 1 28
30 1 29
2 1 30
50 2 31
23 1 32
20 2 33
60 2 34
3 1 35
3 3 36
60 2 37
25 1 38
50 2 39
4 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.11
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
HOLLADAY SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
HUNTER SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
HUNTINGTON CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
IRON MOUNTAIN SUB 7.20 34.50DISTRIBUTION-UNATTEN 4
IRONTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
IVINS SUB 12.47 67.00DISTRIBUTION-UNATTEN 6
JORDAN NARROWS SUB 2.40 46.00DISTRIBUTION-UNATTEN 7
JORDAN PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 8
JORDANELLE SUB 12.47 138.00DISTRIBUTION-UNATTEN 9
JUAB SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
JUNCTION SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
KAIBAB SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
KAMAS SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
KEARNS SUB 12.47 138.00DISTRIBUTION-UNATTEN 14
KENSINGTON SUB 4.16 46.00DISTRIBUTION-UNATTEN 15
KYUNE SUB 7.20 46.00DISTRIBUTION-UNATTEN 16
LAKE PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 17
LAYTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
LEGRANDE SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
LEWISTON SUB 7.20 46.00DISTRIBUTION-UNATTEN 20
LINCOLN SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
LINDON SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
LISBON SUB 12.47 70.60DISTRIBUTION-UNATTEN 23
LOAFER SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
LOGAN CANYON SUB 7.20 46.00DISTRIBUTION-UNATTEN 25
LONE TREE SUB 12.47 34.50DISTRIBUTION-UNATTEN 26
LOWER BEAVER SUB 6.60 46.00DISTRIBUTION-UNATTEN 27
LYNNDYL SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
MAESER SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
MAGNA SUB 12.47 138.00DISTRIBUTION-UNATTEN 30
MANILA SUB 12.47 138.00DISTRIBUTION-UNATTEN 31
MANTUA SUB 12.47 44.00DISTRIBUTION-UNATTEN 32
MAPLETON SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
MARRIOTT SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
MARYSVALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 35
MATHIS SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
MCCORNICK SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
MCKAY SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
MEADOWBROOK SUB 12.47 138.00 46.00DISTRIBUTION-UNATTEN 39
MEDICAL SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.12
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
32 2 1
22 1 2
12 2 3
1 1 4
2 1 5
30 1 6
13 2 7
30 1 8
30 1 9
4 1 10
3 1 11
5 1 12
7 1 13
60 2 14
7 1 15
1 16
53 2 17
40 2 18
2 1 19
22 1 20
20 1 21
20 1 22
3 1 23
1 24
1 1 25
20 1 26
1 1 27
4 1 28
12 1 29
30 1 30
22 1 31
2 1 32
14 1 33
20 1 34
3 1 35
9 1 36
6 1 37
20 1 38
42 2 39
57 4 40
FERC FORM NO. 1 (ED. 12-96) Page 427.12
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
MIDLAND SUB 12.47 138.00DISTRIBUTION-UNATTEN 1
MIDVALE SUB 12.47 46.00DISTRIBUTION-UNATTEN 2
MILFORD SUB 46.00 138.00DISTRIBUTION-UNATTEN 3
MILFORD TV SUB 13.20 46.00DISTRIBUTION-UNATTEN 4
MINERSVILLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
MOAB CITY SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
MOORE SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
MORGAN SUB 4.16 46.00DISTRIBUTION-UNATTEN 8
MORONI SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
MOUNTAIN DELL SUB 12.47 46.00DISTRIBUTION-UNATTEN 10
MOUNTAIN GREEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
MYTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 12
NEW HARMONY SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
NEWGATE SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
NEWTON SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
NIBLEY SUB 24.90 138.00DISTRIBUTION-UNATTEN 16
NORTH BENCH SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
NORTH FIELDS SUB 12.47 46.00DISTRIBUTION-UNATTEN 18
NORTH LOGAN SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
NORTH OGDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
NORTH SALT LAKE SUB 13.20 46.00DISTRIBUTION-UNATTEN 21
NORTHEAST SUB 12.50 46.00DISTRIBUTION-UNATTEN 22
NORTHRIDGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 23
OAKLAND AVE SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
OAKLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 25
OLYMPUS SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
OPHIR SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
ORANGE SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
ORANGEVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 29
OREM SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
PACK CREEK RESERVOIR 12.47 46.00DISTRIBUTION-UNATTEN 31
PANGUITCH SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
PARIETTE SUB 24.94 69.00DISTRIBUTION-UNATTEN 33
PARK CITY SUB 12.47 46.00DISTRIBUTION-UNATTEN 34
PARKSIDE SUB 12.47 138.00DISTRIBUTION-UNATTEN 35
PARKWAY SUB 12.47 138.00DISTRIBUTION-UNATTEN 36
PARLEYS SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
PELICAN POINT SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
PINE CANYON SUB 12.47 138.00DISTRIBUTION-UNATTEN 39
PINE CREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.13
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
30 1 1
25 1 2
89 2 3
1 4
2 1 5
19 2 6
3 1 7
7 2 8
6 1 9
5 1 10
6 1 11
6 1 12
7 1 13
20 1 14
5 1 15
14 1 16
25 1 17
2 1 18
25 1 19
22 1 20
25 1 21
45 2 22
14 1 23
24 2 24
6 1 25
22 1 26
3 1 27
20 1 28
14 1 29
48 2 30
4 1 31
5 1 32
14 1 33
42 2 34
60 2 35
50 2 36
16 2 37
6 1 38
55 2 39
2 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.13
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
PINNACLE SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
PLAIN CITY SUB 12.47 138.00DISTRIBUTION-UNATTEN 2
PLEASANT GROVE SUB 12.47 138.00DISTRIBUTION-UNATTEN 3
PLEASANT VIEW SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
PONY EXPRESS SUB 12.47 138.00DISTRIBUTION-UNATTEN 5
PORTER ROCKWELL SUB 13.20 138.00DISTRIBUTION-UNATTEN 6
PROMONTORY SUB 12.47 46.00DISTRIBUTION-UNATTEN 7
QUAIL CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 8
QUARRY SUB 12.47 138.00DISTRIBUTION-UNATTEN 9
QUICHAPA SUB 12.47 34.50DISTRIBUTION-UNATTEN 10
RAINS SUB 7.20 46.00DISTRIBUTION-UNATTEN 11
RANDOLPH SUB 12.47 46.00DISTRIBUTION-UNATTEN 12
RASMUSON SUB 12.47 46.00DISTRIBUTION-UNATTEN 13
RATTLESNAKE SUB 24.90 69.00DISTRIBUTION-UNATTEN 14
RED MOUNTAIN SUB 34.50 69.00DISTRIBUTION-UNATTEN 15
REDWOOD SUB 12.47 46.00DISTRIBUTION-UNATTEN 16
RESEARCH PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
RICH SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
RICHFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
RICHMOND SUB 12.47 46.00DISTRIBUTION-UNATTEN 20
RIDGELAND SUB 12.47 138.00DISTRIBUTION-UNATTEN 21
RITER SUB 12.47 46.00DISTRIBUTION-UNATTEN 22
ROCK CANYON SUB 12.47 69.00DISTRIBUTION-UNATTEN 23
ROCKVILLE SUB 12.47 34.50DISTRIBUTION-UNATTEN 24
ROCKY POINT 13.20 138.00DISTRIBUTION-UNATTEN 25
ROSE PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 26
ROYAL SUB 4.16 46.00DISTRIBUTION-UNATTEN 27
SALINA SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
SANDY SUB 12.47 138.00DISTRIBUTION-UNATTEN 29
SARATOGA SUB 12.47 138.00DISTRIBUTION-UNATTEN 30
SCIPIO SUB 12.47 46.00DISTRIBUTION-UNATTEN 31
SCOFIELD RESERVOIR SUB 7.20 46.00DISTRIBUTION-UNATTEN 32
SCOFIELD SUB 12.47 46.00DISTRIBUTION-UNATTEN 33
SEGO CANYON SUB 12.47 69.00DISTRIBUTION-UNATTEN 34
SEVEN MILE SUB 7.20 68.68DISTRIBUTION-UNATTEN 35
SHARON SUB 12.47 46.00DISTRIBUTION-UNATTEN 36
SHORELINE SUB 13.20 138.00DISTRIBUTION-UNATTEN 37
SIXTH SOUTH SUB 12.47 46.00DISTRIBUTION-UNATTEN 38
SKULL VALLEY SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
SKYPARK SUB 12.47 138.00 12.47DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.14
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
14 1 1
22 1 2
25 1 3
14 1 4
60 2 5
60 2 6
2 1 7
4 1 8
60 2 9
4 1 10
15 1 11
2 1 12
1 3 13
14 1 14
12 1 15
45 2 16
45 2 17
5 1 18
22 2 19
11 1 20
40 2 21
20 1 22
5 1 23
4 1 24
30 1 25
24 3 26
3 27
11 1 28
60 2 29
60 2 30
1 3 31
1 1 32
1 3 33
14 1 34
1 35
20 1 36
60 2 37
20 1 38
2 1 39
40 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.14
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
SNARR SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
SNOWVILLE SUB 12.47 69.00DISTRIBUTION-UNATTEN 2
SNYDERVILLE SUB 46.00 138.00DISTRIBUTION-UNATTEN 3
SOLDIER SUMMIT SUB 12.47 46.00DISTRIBUTION-UNATTEN 4
SOUTH JORDAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 5
SOUTH MILFORD SUB 12.47 46.00DISTRIBUTION-UNATTEN 6
SOUTH MOUNTAIN SUB 12.47 138.00DISTRIBUTION-UNATTEN 7
SOUTH OGDEN SUB 12.47 46.00DISTRIBUTION-UNATTEN 8
SOUTH PARK SUB 12.47 138.00DISTRIBUTION-UNATTEN 9
SOUTH WEBER SUB 12.47 138.00DISTRIBUTION-UNATTEN 10
SOUTHWEST SUB 12.47 46.00DISTRIBUTION-UNATTEN 11
SPANISH VALLEY SUB 12.47 67.00DISTRIBUTION-UNATTEN 12
SPRINGDALE SUB 12.47 34.50DISTRIBUTION-UNATTEN 13
ST. JOHNS SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
STANSBURY SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
SUMMIT CREEK SUB 12.47 138.00DISTRIBUTION-UNATTEN 16
SUMMIT PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 17
SUNRISE SUB 12.47 138.00DISTRIBUTION-UNATTEN 18
SUTHERLAND SUB 12.47 46.00DISTRIBUTION-UNATTEN 19
TAMARISK SUB 12.47 138.00DISTRIBUTION-UNATTEN 20
TAYLOR SUB 12.47 46.00DISTRIBUTION-UNATTEN 21
THIEF CREEK SUB 24.90 138.00DISTRIBUTION-UNATTEN 22
THIRD WEST SUB 13.20 138.00DISTRIBUTION-UNATTEN 23
THIRTEENTH SOUTH SUB 12.47 46.00DISTRIBUTION-UNATTEN 24
TOOELE DEPOT SUB 12.50 46.00DISTRIBUTION-UNATTEN 25
TOQUERVILLE SUB 12.47 69.00 34.50DISTRIBUTION-UNATTEN 26
UINTAH SUB 12.47 46.00DISTRIBUTION-UNATTEN 27
UNION SUB 12.47 46.00DISTRIBUTION-UNATTEN 28
VALLEY CENTER SUB 12.47 46.00DISTRIBUTION-UNATTEN 29
VERMILLION SUB 12.47 46.00DISTRIBUTION-UNATTEN 30
VERNAL SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
VICKERS SUB 12.47 46.00DISTRIBUTION-UNATTEN 32
VINEYARD SUB 13.20 138.00DISTRIBUTION-UNATTEN 33
WALLSBURG SUB 12.47 138.00DISTRIBUTION-UNATTEN 34
WALNUT GROVE SUB 12.47 138.00DISTRIBUTION-UNATTEN 35
WARREN SUB 12.47 138.00DISTRIBUTION-UNATTEN 36
WASATCH STATE PARK SUB 12.47 46.00DISTRIBUTION-UNATTEN 37
WASHAKIE SUB 4.16 138.00DISTRIBUTION-UNATTEN 38
WELBY SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
WELFARE SUB 12.47 46.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.15
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
40 2 1
5 1 2
127 3 3
12 1 4
60 2 5
28 2 6
60 2 7
25 1 8
30 1 9
22 1 10
22 2 11
14 1 12
14 1 13
4 1 14
20 1 15
14 1 16
7 1 17
60 2 18
6 1 19
20 1 20
14 1 21
14 1 22
100 2 23
22 1 24
25 1 25
34 2 26
39 2 27
50 2 28
22 1 29
3 1 30
33 2 31
2 1 32
30 1 33
13 1 34
30 1 35
30 1 36
2 3 37
14 1 38
42 2 39
10 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.15
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
WEST COMMERCIAL SUB 12.47 46.00DISTRIBUTION-UNATTEN 1
WEST JORDAN SUB 12.47 138.00DISTRIBUTION-UNATTEN 2
WEST OGDEN SUB 12.47 138.00DISTRIBUTION-UNATTEN 3
WEST POINT SUB 13.20 138.00DISTRIBUTION-UNATTEN 4
WEST ROY SUB 12.47 46.00DISTRIBUTION-UNATTEN 5
WEST TEMPLE SUB 4.16 46.00DISTRIBUTION-UNATTEN 6
WESTWATER SUB 12.47 69.00DISTRIBUTION-UNATTEN 7
WHITE ROCK SUB 12.47 138.00DISTRIBUTION-UNATTEN 8
WILLOWCREEK SUB 12.47 46.00DISTRIBUTION-UNATTEN 9
WILLOWRIDGE SUB 12.47 44.90DISTRIBUTION-UNATTEN 10
WINCHESTER HILLS SUB 12.47 34.50DISTRIBUTION-UNATTEN 11
WINKLEMAN SUB 7.20 46.00DISTRIBUTION-UNATTEN 12
WOLF CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
WOOD CROSS SUB 12.47 46.00DISTRIBUTION-UNATTEN 14
WOODRUFF SUB 12.47 46.00DISTRIBUTION-UNATTEN 15
TOTAL (Number of Substations-272) 3524.38 20128.68 105.44 16
17
90TH SOUTH SUB 138.00 345.00 12.47T/D-UNATTENDED 18
ANGEL SUB 12.47 138.00 46.00T/D-UNATTENDED 19
BDO SUB 12.47 138.00T/D-UNATTENDED 20
BUTLERVILLE SUB 46.00 138.00 12.47T/D-UNATTENDED 21
CENTENNIAL SUB 12.47 138.00T/D-UNATTENDED 22
COTTONWOOD SUB 12.47 138.00 46.00T/D-UNATTENDED 23
DECADE SUB 12.47 138.00T/D-UNATTENDED 24
DUMAS SUB 12.47 138.00T/D-UNATTENDED 25
EMMA PARK SUB 12.47 138.00T/D-UNATTENDED 26
GROW SUB 12.47 138.00 46.00T/D-UNATTENDED 27
HALE SUB 46.00 138.00 12.47T/D-UNATTENDED 28
HIGHLAND SUB 12.47 138.00 46.00T/D-UNATTENDED 29
JORDAN SUB 46.00 138.00 12.47T/D-UNATTENDED 30
JUDGE SUB 12.47 46.00T/D-UNATTENDED 31
MCCLELLAND SUB 46.00 138.00 12.47T/D-UNATTENDED 32
MORTON COURT SUB 12.47 138.00T/D-UNATTENDED 33
OQUIRRH SUB 46.00 345.00 138.00T/D-UNATTENDED 34
PARRISH SUB 12.47 138.00 46.00T/D-UNATTENDED 35
PIONEER PLANT 12.47 138.00T/D-UNATTENDED 36
RIVERDALE SUB 46.00 138.00 12.47T/D-UNATTENDED 37
SEVIER SUB 46.00 138.00 12.47T/D-UNATTENDED 38
SILVER CREEK SUB 12.47 138.00 46.00T/D-UNATTENDED 39
SOUTHEAST SUB 12.47 138.00 46.00T/D-UNATTENDED 40
FERC FORM NO. 1 (ED. 12-96) Page 426.16
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
22 1 1
28 1 2
60 2 3
40 1 4
25 1 5
60 3 6
5 1 7
30 1 8
1 1 9
24 1 10
4 1 11
1 12
6 1 13
20 1 14
2 1 15
5830 374 2 16
17
1572 5 18
135 3 19
30 1 20
205 4 21
40 2 22
289 7 23
60 2 24
60 2 25
8 1 26
72 3 27
114 2 28
97 2 29
164 2 30
22 1 31
340 3 32
65 2 33
835 4 1 34
97 2 35
30 1 36
180 3 37
34 4 38
100 2 39
50 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.16
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
SYRACUSE SUB 138.00 345.00 46.00T/D-UNATTENDED 1
TAYLORSVILLE SUB 46.00 138.00 12.47T/D-UNATTENDED 2
TERMINAL SUB 46.00 345.00 138.00T/D-UNATTENDED 3
TIMP SUB 46.00 138.00 12.47T/D-UNATTENDED 4
TOOELE SUB 46.00 138.00 12.47T/D-UNATTENDED 5
TRI CITY SUB 12.47 138.00T/D-UNATTENDED 6
WEST VALLEY SUB 12.47 138.00T/D-UNATTENDED 7
WESTFIELD SUB 12.47 138.00T/D-UNATTENDED 8
TOTAL (Number of Substations-31) 1006.46 5014.00 768.70 9
10
EMERY SUB 138.00 345.00 69.00TRANSMISSION-ATTENDE 11
GADSBY SUB 46.00 138.00TRANSMISSION-ATTENDE 12
ABAJO SUB 69.00 138.00TRANSMISSION-UNATTEN 13
ASHLEY SUB 46.00 138.00TRANSMISSION-UNATTEN 14
BARNEY SUB 46.00 138.00TRANSMISSION-UNATTEN 15
BEN LOMOND SUB 230.00 345.00 138.00TRANSMISSION-UNATTEN 16
BLACK ROCK SUB 69.00 230.00TRANSMISSION-UNATTEN 17
BLACKHAWK SUB 69.00 138.00 46.00TRANSMISSION-UNATTEN 18
CAMERON SUB 46.00 138.00TRANSMISSION-UNATTEN 19
CAMP WILLIAMS SUB 138.00 345.00 12.47TRANSMISSION-UNATTEN 20
CLOVER SUB 138.00 345.00 14.40TRANSMISSION-UNATTEN 21
COLUMBIA SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 22
CRANER FLAT SUB 12.47 138.00TRANSMISSION-UNATTEN 23
CROYDON SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 24
CUTLER SUB 46.00 138.00TRANSMISSION-UNATTEN 25
EL MONTE SUB 46.00 138.00TRANSMISSION-UNATTEN 26
GARKANE SUB 46.00 69.00TRANSMISSION-UNATTEN 27
GREEN CANYON SUB 46.00 138.00TRANSMISSION-UNATTEN 28
GRINDING SUB 13.80 138.00TRANSMISSION-UNATTEN 29
HELPER SUB 46.00 138.00TRANSMISSION-UNATTEN 30
HONEYVILLE SUB 46.00 138.00TRANSMISSION-UNATTEN 31
HORSESHOE SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 32
HUNTINGTON SUB 138.00 345.00 24.90TRANSMISSION-UNATTEN 33
JERUSALEM SUB 46.00 138.00TRANSMISSION-UNATTEN 34
LAMPO SUB 46.00 138.00TRANSMISSION-UNATTEN 35
MATHINGTON SUB 46.00 138.00 13.20TRANSMISSION-UNATTEN 36
MCFADDEN SUB 46.00 138.00TRANSMISSION-UNATTEN 37
MIDDLETON SUB 69.00 138.00 34.50TRANSMISSION-UNATTEN 38
MIDVALLEY SUB 138.00 345.00TRANSMISSION-UNATTEN 39
MIDWAY CITY SUB 46.00 138.00TRANSMISSION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.17
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
1300 6 1
358 4 2
1108 6 2 3
130 2 4
249 3 5
30 1 6
30 1 7
20 1 8
7824 84 3 9
10
783 13 11
318 2 12
67 1 13
133 2 14
100 1 15
1813 5 16
75 1 17
100 2 18
25 4 19
169 2 20
448 1 21
71 2 22
40 2 23
81 2 24
50 1 25
312 3 26
33 1 27
67 2 28
225 3 29
77 2 30
35 1 31
80 2 32
270 4 33
67 1 34
75 1 35
160 5 1 36
45 1 37
137 3 38
900 2 39
67 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.17
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
MINERAL PRODUCTS SUB 46.00 69.00TRANSMISSION-UNATTEN 1
MOAB SUB 69.00 138.00TRANSMISSION-UNATTEN 2
NEBO SUB 46.00 138.00TRANSMISSION-UNATTEN 3
PAROWAN VALLEY SUB 138.00 230.00 34.50TRANSMISSION-UNATTEN 4
PAVANT SUB 46.00 230.00TRANSMISSION-UNATTEN 5
PINTO SUB 138.00 345.00 69.00TRANSMISSION-UNATTEN 6
PURGATORY FLAT SUBSTATION 69.00 138.00 12.47TRANSMISSION-UNATTEN 7
RED BUTTE SUB 138.00 345.00TRANSMISSION-UNATTEN 8
SIGURD SUB 230.00 345.00 138.00TRANSMISSION-UNATTEN 9
SMITHFIELD SUB 46.00 138.00 12.47TRANSMISSION-UNATTEN 10
SPANISH FORK SUB 138.00 345.00 13.80TRANSMISSION-UNATTEN 11
ST GEORGE SUB 16.50 138.00TRANSMISSION-UNATTEN 12
THREE PEAKS SUB 138.00 345.00TRANSMISSION-UNATTEN 13
WEST CEDAR SUB 138.00 230.00 34.50TRANSMISSION-UNATTEN 14
TOTAL (Number of Substations-44) 3446.77 8579.00 704.62 15
16
WASHINGTON 17
ATTALIA SUB 12.47 69.00DISTRIBUTION-UNATTEN 18
BOWMAN SUB 12.47 69.00DISTRIBUTION-UNATTEN 19
CASCADE KRAFT SUB 12.47 69.00 4.16DISTRIBUTION-UNATTEN 20
CLINTON SUB 12.47 115.00DISTRIBUTION-UNATTEN 21
DAYTON SUB 12.47 69.00DISTRIBUTION-UNATTEN 22
DODD ROAD SUB 20.80 69.00DISTRIBUTION-UNATTEN 23
GRANDVIEW SUB 12.47 115.00 69.00DISTRIBUTION-UNATTEN 24
GROMORE SUB 13.20 116.00DISTRIBUTION-UNATTEN 25
HOPLAND SUB 12.47 115.00DISTRIBUTION-UNATTEN 26
NACHES SUB 12.00 115.00DISTRIBUTION-UNATTEN 27
NOB HILL SUB 12.47 115.00DISTRIBUTION-UNATTEN 28
NORTH PARK SUB 12.47 115.00DISTRIBUTION-UNATTEN 29
ORCHARD SUB 12.47 115.00DISTRIBUTION-UNATTEN 30
PACIFIC SUB 12.47 115.00DISTRIBUTION-UNATTEN 31
POMEROY SUB 12.47 69.00DISTRIBUTION-UNATTEN 32
PROSPECT POINT SUB 12.47 69.00DISTRIBUTION-UNATTEN 33
PUNKIN CENTER SUB 13.20 116.00DISTRIBUTION-UNATTEN 34
RIVER ROAD SUB 12.47 115.00DISTRIBUTION-UNATTEN 35
SELAH SUB 12.47 115.00DISTRIBUTION-UNATTEN 36
SULPHUR CREEK SUB 12.47 115.00DISTRIBUTION-UNATTEN 37
SUNNYSIDE SUB 12.47 115.00DISTRIBUTION-UNATTEN 38
TIETON SUB 12.47 115.00 34.50DISTRIBUTION-UNATTEN 39
TOPPENISH SUB 12.47 115.00DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.18
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
12 1 1
67 1 2
67 1 3
138 2 4
133 2 5
258 3 6
300 2 7
414 2 8
1124 6 9
63 2 10
1100 2 11
100 3 1 12
450 1 13
262 3 14
11311 104 2 15
16
17
25 1 18
45 2 19
118 6 20
25 1 21
23 2 22
25 4 23
42 2 24
25 1 25
50 2 26
25 1 27
42 2 28
45 2 29
50 2 30
28 3 31
9 1 32
40 2 33
44 3 34
76 5 35
45 2 36
25 1 37
45 2 38
29 2 39
50 2 40
FERC FORM NO. 1 (ED. 12-96) Page 427.18
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
TOUCHET SUB 12.47 69.00DISTRIBUTION-UNATTEN 1
VOELKER SUB 12.47 115.00DISTRIBUTION-UNATTEN 2
WAITSBURG SUB 12.47 69.00DISTRIBUTION-UNATTEN 3
WAPATO SUB 12.47 115.00DISTRIBUTION-UNATTEN 4
WENAS SUB 12.47 115.00DISTRIBUTION-UNATTEN 5
WHITE SWAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 6
WILEY SUB 12.47 115.00DISTRIBUTION-UNATTEN 7
TOTAL (Number of Substations-30) 383.42 3038.00 107.66 8
9
CENTRAL SUB 12.47 69.00T/D-UNATTENDED 10
MILL CREEK SUB 12.47 69.00T/D-UNATTENDED 11
UNION GAP SUB 115.00 230.00 12.47T/D-UNATTENDED 12
TOTAL (Number of Substations-3) 139.94 368.00 12.47 13
14
DRY GULCH SUB - AVISTA 69.00 115.00TRANSMISSION-UNATTEN 15
OUTLOOK SUB 115.00 230.00TRANSMISSION-UNATTEN 16
PASCO SUB 69.00 115.00 7.20TRANSMISSION-UNATTEN 17
POMONA HEIGHTS SUB 115.00 230.00 13.20TRANSMISSION-UNATTEN 18
WALLA WALLA 230KV SUB 69.00 230.00TRANSMISSION-UNATTEN 19
WALLULA SUB 69.00 230.00TRANSMISSION-UNATTEN 20
WINE COUNTRY SUB 115.00 230.00TRANSMISSION-UNATTEN 21
TOTAL (Number of Substations-7) 621.00 1380.00 20.40 22
23
WYOMING 24
ANTELOPE MINE SUB 34.50 230.00DISTRIBUTION-UNATTEN 25
ARROWHEAD SUB 34.50 230.00DISTRIBUTION-UNATTEN 26
ASTLE STREET 13.20 34.50DISTRIBUTION-UNATTEN 27
BAILEY DOME SUB 12.47 57.00DISTRIBUTION-UNATTEN 28
BAR NUNN 12.47 115.00DISTRIBUTION-UNATTEN 29
BAR X SUB 34.50 230.00DISTRIBUTION-UNATTEN 30
BIG MUDDY SUB 12.47 69.00DISTRIBUTION-UNATTEN 31
BIG PINEY SUB 24.90 69.00DISTRIBUTION-UNATTEN 32
BLACKS FORK SUB 34.50 230.00DISTRIBUTION-UNATTEN 33
BRIDGER PUMP SUB 34.50 230.00 13.20DISTRIBUTION-UNATTEN 34
BRYAN SUB 12.47 115.00DISTRIBUTION-UNATTEN 35
BYRON SUB 4.16 34.50DISTRIBUTION-UNATTEN 36
CASSA SUB 20.80 57.00 12.47DISTRIBUTION-UNATTEN 37
CENTER STREET SUB 12.47 115.00DISTRIBUTION-UNATTEN 38
CHAPMAN SUB 12.47 46.00DISTRIBUTION-UNATTEN 39
CHUKAR SUB 4.16 12.47DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.19
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
6 1 1
25 1 2
9 1 3
45 2 4
25 2 5
22 2 6
45 2 7
1108 62 8
9
14 1 10
45 2 11
595 5 12
654 8 13
14
20 1 15
125 1 16
39 9 17
325 3 18
300 2 19
120 2 20
250 1 21
1179 19 22
23
24
25 1 25
150 2 26
12 1 27
2 1 28
30 1 29
25 1 30
7 1 31
14 1 32
150 2 33
73 4 34
25 1 35
2 3 36
2 6 37
12 1 38
4 1 39
1 3 40
FERC FORM NO. 1 (ED. 12-96) Page 427.19
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
CHURCH AND DWIGHT SUB 0.48 34.50DISTRIBUTION-UNATTEN 1
COKEVILLE SUB 24.90 46.00DISTRIBUTION-UNATTEN 2
COLUMBIA-GENEVA SUB 13.80 230.00DISTRIBUTION-UNATTEN 3
COMMUNITY PARK SUB 12.47 115.00DISTRIBUTION-UNATTEN 4
CROOKS GAP SUB 12.47 34.50DISTRIBUTION-UNATTEN 5
DEER CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 6
DJ COAL MINE SUB 34.50 69.00DISTRIBUTION-UNATTEN 7
DRY FORK SUB 4.16 69.00DISTRIBUTION-UNATTEN 8
ELK BASIN SUB 7.20 34.50DISTRIBUTION-UNATTEN 9
EMIGRANT SUB 12.47 115.00DISTRIBUTION-UNATTEN 10
EVANS SUB 12.47 115.00DISTRIBUTION-UNATTEN 11
EVANSTON SUB 12.47 138.00DISTRIBUTION-UNATTEN 12
FORT CASPER SUB 12.47 69.00DISTRIBUTION-UNATTEN 13
FORT SANDERS SUB 13.20 115.00DISTRIBUTION-UNATTEN 14
FRANNIE SUB 34.50 230.00DISTRIBUTION-UNATTEN 15
FRONTIER SUB 4.16 69.00DISTRIBUTION-UNATTEN 16
GARLAND SUB 34.50 230.00DISTRIBUTION-UNATTEN 17
GLENDO SUB 4.16 57.00DISTRIBUTION-UNATTEN 18
GRASS CREEK SUB 34.50 230.00DISTRIBUTION-UNATTEN 19
GREAT DIVIDE SUB 34.50 115.00DISTRIBUTION-UNATTEN 20
GREYBULL SUB 4.16 34.50DISTRIBUTION-UNATTEN 21
HANNA SUB 12.47 34.50DISTRIBUTION-UNATTEN 22
JACKALOPE SUB 12.47 115.00DISTRIBUTION-UNATTEN 23
KEMMERER SUB 24.90 69.00DISTRIBUTION-UNATTEN 24
KIRBY CREEK PUMPING STATION 2.40 34.50DISTRIBUTION-UNATTEN 25
KIRBY CREEK SUB 4.16 34.50DISTRIBUTION-UNATTEN 26
LANDER SUB 12.47 34.50DISTRIBUTION-UNATTEN 27
LARAMIE SUB 13.20 115.00DISTRIBUTION-UNATTEN 28
LATHAM SUB 34.50 230.00DISTRIBUTION-UNATTEN 29
LINCH SUB 13.80 69.00DISTRIBUTION-UNATTEN 30
LITTLE MOUNTAIN SUB 34.50 230.00DISTRIBUTION-UNATTEN 31
LOVELL SUB 4.16 34.50DISTRIBUTION-UNATTEN 32
MILL IRON SUB 13.80 34.50DISTRIBUTION-UNATTEN 33
MILLS SUB 4.16 12.47DISTRIBUTION-UNATTEN 34
MURPHY DOME SUB 13.20 34.50DISTRIBUTION-UNATTEN 35
NUGGETT SUB 7.20 69.00DISTRIBUTION-UNATTEN 36
OPAL SUB 24.90 69.00DISTRIBUTION-UNATTEN 37
ORIN SUB 7.20 57.00DISTRIBUTION-UNATTEN 38
PARADISE SUB 25.00 69.00DISTRIBUTION-UNATTEN 39
PARCO SUB 12.47 34.50DISTRIBUTION-UNATTEN 40
FERC FORM NO. 1 (ED. 12-96) Page 426.20
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
1 1 1
4 1 2
45 2 3
50 2 4
5 3 5
9 1 6
12 1 7
9 1 8
5 1 9
12 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 1 22
55 2 23
14 1 24
3 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 3 34
5 1 35
1 36
8 1 37
1 1 38
30 1 39
5 1 40
FERC FORM NO. 1 (ED. 12-96) Page 427.20
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
PINEDALE SUB 24.90 69.00DISTRIBUTION-UNATTEN 1
PITCHFORK SUB 24.90 69.00DISTRIBUTION-UNATTEN 2
POISON SPIDER SUB 2.40 69.00DISTRIBUTION-UNATTEN 3
POLECAT SUB 12.47 34.50DISTRIBUTION-UNATTEN 4
RAINBOW SUB 13.20 34.50DISTRIBUTION-UNATTEN 5
RAVEN SUB 34.50 230.00DISTRIBUTION-UNATTEN 6
RED BUTTE SUB 13.20 115.00DISTRIBUTION-UNATTEN 7
REFINERY SUB 12.47 115.00DISTRIBUTION-UNATTEN 8
SAGE HILL SUB 13.20 34.50DISTRIBUTION-UNATTEN 9
SHOSHONI SUB 2.40 34.50DISTRIBUTION-UNATTEN 10
SLATE CREEK SUB 12.47 69.00DISTRIBUTION-UNATTEN 11
SOUTH CODY SUB 24.90 69.00DISTRIBUTION-UNATTEN 12
SOUTH ELK BASIN SUB 4.16 34.50DISTRIBUTION-UNATTEN 13
SOUTH TRONA SUB 34.50 230.00DISTRIBUTION-UNATTEN 14
SPRING CREEK SUB 13.20 115.00DISTRIBUTION-UNATTEN 15
SVILAR SUB 4.16 34.50DISTRIBUTION-UNATTEN 16
TEN MILE STEP DOWN SUB 12.50 34.50DISTRIBUTION-UNATTEN 17
TEN MILE SUB 34.50 69.00DISTRIBUTION-UNATTEN 18
THERMOPOLIS TOWN SUB 4.16 34.50DISTRIBUTION-UNATTEN 19
THUNDER CREEK SUB 12.47 57.00DISTRIBUTION-UNATTEN 20
VETERANS SUB 13.20 34.50DISTRIBUTION-UNATTEN 21
WAPA THERMOPOLIS 34.50 115.00DISTRIBUTION-UNATTEN 22
WERTZ-SINCLAIR SUB 4.16 57.00 12.50DISTRIBUTION-UNATTEN 23
WEST ADAMS SUB 4.16 34.50DISTRIBUTION-UNATTEN 24
WESTVACO SUB 34.50 230.00DISTRIBUTION-UNATTEN 25
WORLAND TOWN SUB 4.16 34.50DISTRIBUTION-UNATTEN 26
WYOPO SUB 34.50 230.00DISTRIBUTION-UNATTEN 27
TOTAL (Number of Substations-83) 1367.35 7761.44 38.17 28
29
BUFFALO SUB 20.80 230.00T/D-UNATTENDED 30
ELK HORN SUB 12.47 115.00T/D-UNATTENDED 31
FIREHOLE SUB 34.50 230.00T/D-UNATTENDED 32
HILLTOP SUB 34.50 115.00 20.80T/D-UNATTENDED 33
LABARGE SUB 24.90 69.00T/D-UNATTENDED 34
POINT OF ROCKS SUB 34.50 230.00T/D-UNATTENDED 35
RIVERTON 230 SUB 12.47 230.00 34.50T/D-UNATTENDED 36
YELLOWCAKE SUB 34.50 230.00T/D-UNATTENDED 37
TOTAL (Number of Substations-8) 208.64 1449.00 55.30 38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 426.21
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
20 1 1
16 9 2 2
3 1 3
2 3 4
12 1 5
200 2 6
30 1 7
45 2 8
6 1 9
2 3 10
1 1 11
14 3 1 12
2 6 13
150 2 14
28 1 15
2 3 16
5 1 17
12 1 18
5 1 19
9 1 20
25 2 21
25 1 22
2 6 23
3 1 24
25 1 25
5 1 26
20 1 1 27
1880 145 4 28
29
20 1 1 30
25 1 31
50 2 32
45 2 1 33
8 6 34
25 1 35
76 4 36
25 1 37
274 18 2 38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.21
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
DAVE JOHNSTON PLANT/SUB 115.00 230.00 69.00TRANSMISSION-ATTENDE 1
JIM BRIDGER 345KV SUB 230.00 345.00 34.50TRANSMISSION-ATTENDE 2
NAUGHTON SUB 138.00 230.00 69.00TRANSMISSION-ATTENDE 3
BAIROIL SUB 34.50 115.00 57.00TRANSMISSION-UNATTEN 4
CASPER SUB 115.00 230.00 69.00TRANSMISSION-UNATTEN 5
CHAPPEL CREEK SUB 69.00 230.00TRANSMISSION-UNATTEN 6
CHIMNEY BUTTE SUB 69.00 230.00TRANSMISSION-UNATTEN 7
FOOTE CREEK WIND FARM 34.50 230.00TRANSMISSION-UNATTEN 8
GLENDO AUTO SUB 57.00 69.00TRANSMISSION-UNATTEN 9
MANSFACE SUB 34.50 230.00TRANSMISSION-UNATTEN 10
MIDWEST SUB 69.00 230.00 34.50TRANSMISSION-UNATTEN 11
MINERS SUB 34.50 230.00 9.70TRANSMISSION-UNATTEN 12
MUSTANG SUB 115.00 230.00TRANSMISSION-UNATTEN 13
OREGON BASIN SUB 69.00 230.00 34.50TRANSMISSION-UNATTEN 14
PLATTE SUB 115.00 230.00 34.50TRANSMISSION-UNATTEN 15
RAILROAD SUB 138.00 230.00TRANSMISSION-UNATTEN 16
ROCK SPRINGS 230 SUB 34.50 230.00TRANSMISSION-UNATTEN 17
SAGE SUB 46.00 69.00TRANSMISSION-UNATTEN 18
STANDPIPE SUB 12.47 230.00TRANSMISSION-UNATTEN 19
THERMOPOLIS SUB 115.00 230.00TRANSMISSION-UNATTEN 20
TOTAL (Number of Substations-20) 1644.97 4278.00 411.70 21
22
CALIFORNIA 23
Distribution - 42 24
T/D - 2 25
Transmission - 5 26
27
IDAHO 28
Distribution - 65 29
T/D - 5 30
Transmission - 18 31
32
MONTANA 33
Transmission - 3 34
35
OREGON 36
Distribution - 176 37
T/D - 12 38
Transmission - 30 39
40
FERC FORM NO. 1 (ED. 12-96) Page 426.22
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
303 3 1 1
703 7 2
661 4 3
53 3 4
575 4 5
75 1 6
75 1 7
196 2 8
8 1 1 9
20 1 10
157 3 11
20 1 12
100 1 13
100 2 14
140 3 15
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
5186 31
32
33
200 34
35
36
4653 37
1203 38
8374 39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.22
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
UTAH 1
Distribution - 272 2
T/D - 31 3
Transmission - 44 4
5
WASHINGTON 6
Distribution - 30 7
T/D - 3 8
Transmission - 7 9
10
WYOMING 11
Distribution - 83 12
T/D - 8 13
Transmission - 20 14
15
ALL STATES 16
Distribution - 668 17
T/D - 61 18
Transmission - 127 19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 426.23
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
PacifiCorp X / /2019/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i) (j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
1
5830 2
7824 3
11311 4
5
6
1108 7
654 8
1179 9
10
11
1880 12
274 13
3817 14
15
16
14530 17
10397 18
30792 19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.23
Schedule Page: 426.3 Line No.: 13 Column: a
The Antelope 230kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.
Schedule Page: 426.3 Line No.: 15 Column: a
The Big Grassy 161kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.
Schedule Page: 426.3 Line No.: 20 Column: a
The Goshen 345kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.
Schedule Page: 426.3 Line No.: 22 Column: a
The Jefferson 161kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.

Schedule Page: 426.3 Line No.: 23 Column: a
The Midpoint 500kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.
Schedule Page: 426.3 Line No.: 23 Column: g
Represents one 3-phase bank

Schedule Page: 426.3 Line No.: 27 Column: a
The Threemile Knoll 345kV Substation is jointly owned by PacifiCorp and Idaho Power
Company. Ownership and operations and maintenance costs vary by type of asset as defined
in the Joint Ownership and Operating Agreement.

Schedule Page: 426.3 Line No.: 33 Column: a
The Broadview 500kV Substation is jointly owned by PacifiCorp, NorthWestern Energy, Puget
Sound Energy, Inc., Portland General Electric Company and Avista Corporation. Ownership
and operations and maintenance costs vary by type of asset as defined in the Transmission
Agreement.
Schedule Page: 426.3 Line No.: 34 Column: a
The Colstrip 500kV Substation is jointly owned by PacifiCorp, NorthWestern Energy, Puget
Sound Energy, Inc., Portland General Electric Company and Avista Corporation. Ownership
and operations and maintenance costs vary by type of asset as defined in the Transmission
Agreement.
Schedule Page: 426.8 Line No.: 38 Column: a
The Dixonville 500kV Substation is jointly owned by PacifiCorp and Bonneville Power
Administration ("BPA"), each with an undivided interest of 50.0%. Operation and
maintenance costs are shared between the two parties and responsibility is as follows:
PacifiCorp 58.0% and BPA 42.0%.
Schedule Page: 426.9 Line No.: 3 Column: a
The Hurricane 230kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

Schedule Page: 426.9 Line No.: 7 Column: a
The Malin 500kV Substation is jointly owned by PacifiCorp, BPA and Portland General
Electric Company. Ownership and operations and maintenance costs vary by type of asset as
defined in the operation and maintenance agreement.

Schedule Page: 426.9 Line No.: 8 Column: a
The Meridian 500kV Substation is jointly owned by PacifiCorp and BPA, each with an
undivided interest of 50.0%. Operation and maintenance costs are shared between the two
parties and responsibility is as follows: PacifiCorp 58.0% and BPA 42.0%.

Schedule Page: 426.9 Line No.: 15 Column: a
The Roundup 230kV Substation property is owned by PacifiCorp and BPA as defined in the
facility sharing agreement where operation and maintenance costs vary by type of asset and
performance responsibility.

Schedule Page: 426.9 Line No.: 16 Column: a
The Santiam Tie 230kV Substation property is owned by PacifiCorp and BPA as defined in the
facility sharing agreement where operation and maintenance costs vary by type of asset and
responsibility for performance.

Schedule Page: 426.9 Line No.: 17 Column: g
Represents one 3-phase bank

Schedule Page: 426.19 Line No.: 15 Column: a
The Dry Gulch 115kV Substation property is jointly owned by PacifiCorp and Avista
Corporation as defined in the interconnection agreement where operation and maintenance
costs vary by type of asset and performance responsibility.
Schedule Page: 426.19 Line No.: 19 Column: a
The Walla Walla 230kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.
Schedule Page: 426.22 Line No.: 1 Column: a
The Dave Johnston 230kV Substation is jointly owned by PacifiCorp and Black Hills Power
with an undivided interest of 85.0% and 15.0%, respectively. Operation and maintenance
costs are shared between the two parties based on a fixed amount derived as a factor of
the percentage owned of the original installed substation.

Schedule Page: 426.22 Line No.: 2 Column: a
The Jim Bridger 345kV Substation is jointly owned by PacifiCorp and Idaho Power Company.
Ownership and operations and maintenance costs vary by type of asset as defined in the
Joint Ownership and Operating Agreement.

Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
PacifiCorp X
/ /2019/Q4
Line
No. Description of the Non-Power Good or Service
Name of
(c)(b)(a)(d)
Associated/AffiliatedCompany
AccountCharged orCredited
Amount
Credited
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 toan associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should notattempt to include or aggregate amounts in a nonspecific category such as "general".3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Charged or
1 Non-power Goods or Services Provided by Affiliated
2 Coal purchases 162,711,322Bridger Coal Company 151,501
3 Coal purchases 15,086,319Trapper Mining Inc. 151,501
4 Administrative services under the IASA 4,963,789BHE 426.4,426.5,923
5 Administrative services under the IASA 4,401,310MEC 426.4,426.5,923
6 Administrative services under the IASA 494,378MHC Inc. 426.5
7 Administrative services under the IASA 93Kern River Gas Transmission Company 923
8 Gas transportation services 3,080,471Kern River Gas Transmission Company 547
9 Rail services and right-of-way fees 35,201,754BNSF Railway Company 151,501,507,567,589
10 Employee relocation services 1,312,195HomeServices of America, Inc.
11 Travel services 1,193,177Delta Air Lines, Inc.
12 Financial transactions related to energy hedging 14,666,938J. Aron & Company LLC 419,501,507
13 Banking services 1,107,114Wells Fargo & Company
14 Banking services and rating agency fees 355,291U.S. Bank National Association
15 Rating agency fees 500,454Moody's Investors Service, Inc.
16
17
18
19
20 Non-power Goods or Services Provided for Affiliate
21 Information technology and administrative
22 support services 1,341,044Bridger Coal Company 501,557,931,426.5
23 Administrative services under the IASA 428,101MEC
24 Financial transactions related to energy hedging 344,870Wells Fargo & Company 501,547
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (New) Page 429
FERC FORM NO. 1-F (New)
Schedule Page: 429 Line No.: 4 Column: a
This footnote applies to all occurrences of "Administrative services under the IASA" on
page 429. "IASA" is the Intercompany Administrative Services Agreement between Berkshire
Hathaway Energy Company ("BHE") 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 labor, benefits and operational costs incurred. Amounts not
directly assignable to an individual affiliate, such as work performed where multiple
affiliates benefit, are assigned on the basis of allocations, as described below:
Labor and Assets: An equal weighting of each company's labor and assets expressed as a
percentage of the whole ((labor % + assets %) ÷ 2) determines the portion assigned to each
company. Labor is 12 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 for
allocating services that benefit different companies within the BHE organization.
Information Technology Infrastructure: 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 capacity
utilized, number of servers utilized, server processing times, etc.
Plant: This allocator distributes costs of managing the corporate insurance function based
on assets for each affiliate.
Schedule Page: 429 Line No.: 5 Column: b
This footnote applies to all occurrences of "MEC" on page 429. Complete name is
MidAmerican Energy Company.
Schedule Page: 429 Line No.: 9 Column: d
Non-power goods or services provided by BNSF Railway Company are as follows:
$ 35,158,552 Rail services
43,202 Right-of-way fees(1)
$ 35,201,754
(1) Included in the right-of-way fees are amounts related to jointly-owned facilities that
are paid either directly or indirectly to BNSF Railway Company.
Schedule Page: 429 Line No.: 10 Column: c
Accounts charged for HomeServices of America, Inc.: 500, 506, 535, 539, 548, 549, 553,
557, 560, 568, 580, 581, 590, 593, 903, 809 and 921.
Schedule Page: 429 Line No.: 11 Column: c
Accounts charged for Delta Air Lines, Inc.: 107, 416, 426.4, 502, 506, 511, 513, 535, 539,
544, 548, 549, 553, 556, 557, 560, 561.2, 561.5, 568, 569.3, 580, 581, 585, 588, 590, 592,
593, 595, 598, 901, 903, 907, 908, 909, 920, 921, 922 and 928.

Schedule Page: 429 Line No.: 12 Column: b
J. Aron & Company LLC is a subsidary of The Goldman Sachs Group, Inc. which is an
affiliated company.

Schedule Page: 429 Line No.: 13 Column: c
Accounts charged for Wells Fargo & Company: 228.3, 419, 426.5, 427, 431, 903, 921 and 928.

Schedule Page: 429 Line No.: 14 Column: b
U.S. Bank National Association is a subsidary of U.S. Bancorp which is an affiliated
company.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

Schedule Page: 429 Line No.: 14 Column: c
Accounts charged for U.S. Bank National Association: 419, 427, 431, 537, 557, 903, 920,
928 and 930.2.

Schedule Page: 429 Line No.: 15 Column: c
Accounts charged for Moody's Investors Service, Inc.: 181, 186, 427, 428 and 930.2.

Schedule Page: 429 Line No.: 23 Column: c
Accounts charged for MEC: 107, 426.5, 557, 580, 920, 921, 922, 923 and 931.
Name of Respondent
PacifiCorp
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
/ /
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
INDEX
Schedule Page No.
Accrued and prepaid taxes ........................................................................ 262-263
Accumulated Deferred Income Taxes .................................................................... 234
272-277
Accumulated provisions for depreciation of
common utility plant ............................................................................. 356
utility plant .................................................................................... 219
utility plant (summary) ...................................................................... 200-201
Advances
from associated companies .................................................................... 256-257
Allowances ....................................................................................... 228-229
Amortization
miscellaneous .................................................................................... 340
of nuclear fuel .............................................................................. 202-203
Appropriations of Retained Earnings .............................................................. 118-119
Associated Companies
advances from ................................................................................ 256-257
corporations controlled by respondent ............................................................ 103
control over respondent .......................................................................... 102
interest on debt to .......................................................................... 256-257
Attestation ............................................................................................ i
Balance sheet
comparative .................................................................................. 110-113
notes to ..................................................................................... 122-123
Bonds ............................................................................................ 256-257
Capital Stock ........................................................................................ 251
expense .......................................................................................... 254
premiums ......................................................................................... 252
reacquired ....................................................................................... 251
subscribed ....................................................................................... 252
Cash flows, statement of ......................................................................... 120-121
Changes
important during year ........................................................................ 108-109
Construction
work in progress - common utility plant .......................................................... 356
work in progress - electric ...................................................................... 216
work in progress - other utility departments ................................................. 200-201
Control
corporations controlled by respondent ............................................................ 103
over respondent .................................................................................. 102
Corporation
controlled by .................................................................................... 103
incorporated ..................................................................................... 101
CPA, background information on ....................................................................... 101
CPA Certification, this report form ................................................................. i-ii
FERC FORM NO. 1 (ED. 12-93)Index 1
INDEX (continued)
Schedule Page No.
Deferred
credits, other ................................................................................... 269
debits, miscellaneous ............................................................................ 233
income taxes accumulated - accelerated
amortization property ........................................................................ 272-273
income taxes accumulated - other property .................................................... 274-275
income taxes accumulated - other ............................................................. 276-277
income taxes accumulated - pollution control facilities .......................................... 234
Definitions, this report form ........................................................................ iii
Depreciation and amortization
of common utility plant .......................................................................... 356
of electric plant ................................................................................ 219
336-337
Directors ............................................................................................ 105
Discount - premium on long-term debt ............................................................. 256-257
Distribution of salaries and wages ............................................................... 354-355
Dividend appropriations .......................................................................... 118-119
Earnings, Retained ............................................................................... 118-119
Electric energy account .............................................................................. 401
Expenses
electric operation and maintenance ........................................................... 320-323
electric operation and maintenance, summary ...................................................... 323
unamortized debt ................................................................................. 256
Extraordinary property losses ........................................................................ 230
Filing requirements, this report form
General information .................................................................................. 101
Instructions for filing the FERC Form 1 ............................................................. i-iv
Generating plant statistics
hydroelectric (large) ........................................................................ 406-407
pumped storage (large) ....................................................................... 408-409
small plants ................................................................................. 410-411
steam-electric (large) ....................................................................... 402-403
Hydro-electric generating plant statistics ....................................................... 406-407
Identification ....................................................................................... 101
Important changes during year .................................................................... 108-109
Income
statement of, by departments ................................................................. 114-117
statement of, for the year (see also revenues) ............................................... 114-117
deductions, miscellaneous amortization ........................................................... 340
deductions, other income deduction ............................................................... 340
deductions, other interest charges ............................................................... 340
Incorporation information ............................................................................ 101
Index 2FERC FORM NO. 1 (ED. 12-95)
INDEX (continued)
Schedule Page No.

Interest
charges, paid on long-term debt, advances, etc ............................................... 256-257
Investments
nonutility property .............................................................................. 221
subsidiary companies ......................................................................... 224-225
Investment tax credits, accumulated deferred ..................................................... 266-267
Law, excerpts applicable to this report form .......................................................... iv
List of schedules, this report form .................................................................. 2-4
Long-term debt ................................................................................... 256-257
Losses-Extraordinary property ........................................................................ 230
Materials and supplies ............................................................................... 227
Miscellaneous general expenses ....................................................................... 335
Notes
to balance sheet ............................................................................. 122-123
to statement of changes in financial position ................................................ 122-123
to statement of income ....................................................................... 122-123
to statement of retained earnings ............................................................ 122-123
Nonutility property .................................................................................. 221
Nuclear fuel materials ........................................................................... 202-203
Nuclear generating plant, statistics ............................................................. 402-403
Officers and officers' salaries ...................................................................... 104
Operating
expenses-electric ............................................................................ 320-323
expenses-electric (summary) ...................................................................... 323
Other
paid-in capital .................................................................................. 253
donations received from stockholders ............................................................. 253
gains on resale or cancellation of reacquired
capital stock .................................................................................... 253
miscellaneous paid-in capital .................................................................... 253
reduction in par or stated value of capital stock ................................................ 253
regulatory assets ................................................................................ 232
regulatory liabilities ........................................................................... 278
Peaks, monthly, and output ........................................................................... 401
Plant, Common utility
accumulated provision for depreciation ........................................................... 356
acquisition adjustments .......................................................................... 356
allocated to utility departments ................................................................. 356
completed construction not classified ............................................................ 356
construction work in progress .................................................................... 356
expenses ......................................................................................... 356
held for future use .............................................................................. 356
in service ....................................................................................... 356
leased to others ................................................................................. 356
Plant data ...................................................................................336-337
401-429
Index 3FERC FORM NO. 1 (ED. 12-95)
INDEX (continued)
Schedule Page No.
Plant - electric
accumulated provision for depreciation ........................................................... 219
construction work in progress .................................................................... 216
held for future use .............................................................................. 214
in service ................................................................................... 204-207
leased to others ................................................................................. 213
Plant - utility and accumulated provisions for depreciation
amortization and depletion (summary) ............................................................. 201
Pollution control facilities, accumulated deferred
income taxes ..................................................................................... 234
Power Exchanges .................................................................................. 326-327
Premium and discount on long-term debt ............................................................... 256
Premium on capital stock ............................................................................. 251
Prepaid taxes .................................................................................... 262-263
Property - losses, extraordinary ..................................................................... 230
Pumped storage generating plant statistics ....................................................... 408-409
Purchased power (including power exchanges) ...................................................... 326-327
Reacquired capital stock ............................................................................. 250
Reacquired long-term debt ........................................................................ 256-257
Receivers' certificates .......................................................................... 256-257
Reconciliation of reported net income with taxable income
from Federal income taxes ...................................................................... 261
Regulatory commission expenses deferred .............................................................. 233
Regulatory commission expenses for year .......................................................... 350-351
Research, development and demonstration activities ............................................... 352-353
Retained Earnings
amortization reserve Federal ..................................................................... 119
appropriated ................................................................................. 118-119
statement of, for the year ................................................................... 118-119
unappropriated ............................................................................... 118-119
Revenues - electric operating .................................................................... 300-301
Salaries and wages
directors fees ................................................................................... 105
distribution of .............................................................................. 354-355
officers' ........................................................................................ 104
Sales of electricity by rate schedules ............................................................... 304
Sales - for resale ............................................................................... 310-311
Salvage - nuclear fuel ........................................................................... 202-203
Schedules, this report form .......................................................................... 2-4
Securities
exchange registration ........................................................................ 250-251
Statement of Cash Flows .......................................................................... 120-121
Statement of income for the year ................................................................. 114-117
Statement of retained earnings for the year ...................................................... 118-119
Steam-electric generating plant statistics ....................................................... 402-403
Substations .......................................................................................... 426
Supplies - materials and ............................................................................. 227
Index 4FERC FORM NO. 1 (ED. 12-90)
INDEX (continued)
Schedule Page No.
Taxes
accrued and prepaid ......................................................................... 262-263
charged during year ......................................................................... 262-263
on income, deferred and accumulated ............................................................. 234
272-277
reconciliation of net income with taxable income for ............................................ 261
Transformers, line - electric ....................................................................... 429
Transmission
lines added during year ..................................................................... 424-425
lines statistics ............................................................................ 422-423
of electricity for others ................................................................... 328-330
of electricity by others ........................................................................ 332
Unamortized
debt discount ............................................................................... 256-257
debt expense ................................................................................ 256-257
premium on debt ............................................................................. 256-257
Unrecovered Plant and Regulatory Study Costs ........................................................ 230
Index 5FERC FORM NO. 1 (ED. 12-90)