2005Annual Report Part II.pdf

This ~ort IS: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) 0 A Resubmission 03/20/2006
ccoul'!!.::!::!::!)lljl ntlnueOj(InCluding power exchanges)
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.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/Q4
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 (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGESMegaWatt Hours
Purchased MegaWatt Hours MegaWatt HoursReceived Delivered(h) (i)
Demand Charges
($)(g)
140,09E
292,80C
022 14f
255 02C
53E
57E
555
444,939
236,135
64,48~
405
56~
9,495
442 000
783,495
579 913
252,000
15,843 940 142 367 13,191 207 107 354 886
FERC FORM NO.1 (ED. 12-90)Page 327.
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
10,148,
17,919,36C
545 54 '
'\;"
Y,..
68,415
. ";';",..
331
985,68~
21C
681 341
209,34E i '
. "
Y1,9~;llQO
...
12E),
:::~:E :;7;2?1
23,62f
448,6DE
508,699 262 941 259 260
Total O+k+l)
of Settlement ($)
(m)
148 033
919 360
988 255
415 871
331
769 180
210
261 260
393,346
126,752
975 337
552 013
23,625
448,605
Line
No.
674 794 88S
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmlssion 03/20/2006
~C~A~ED POWER ~Accou
1t 555)nc u ng power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Duke Energy Trading & Marketing, LLC
2 Duke Energy Trading & Marketing, LLC
3 ENMAX Energy Marketing Inc.
4 EPCOR Merchant and Capital Inc.
5 Eagle Point Irrigation District
6 EI Paso Electric Company
7 EI Paso Electric Company
8 Enron Power Marketing ~r:t;.
9 Eugene Water & Electric Board
Eurus Energy America
ExxonMobile Production Company 51.40 66.49.
FPL Energy Power Marketing, Inc.
Falls Creek
Farmers Irrigation District
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)DA Resubmisslon 03/20/2006
CCOUH\~gg~) (t;ontinueCl)(Including power exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (I) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
491 ,20C 679 52C 679 520
25,81C 862 862 263
46C 2,460
68~261 455 261 455
691 243 265 14~302 387
31 (124 J,..;"f-;J 124 510;O'
20,90C 186 10E 186 108
,O'p,O' 1;a,38'O 380
39,14"427 31C 427 310
99,50.:780,780 127
399,35.950,360 13,861 49.811 852
80C 60C 61,600
71C 164 862 151 371 316,233
241 277 922 678,12/J 956 050
15,843,940 13,142 367 13,191 207 107 354 886 508 699 262 941 259 260 674 794 88E
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
~C~A~ED POWER ~Accou
1t 555)nc u Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy. capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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., 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.
LIne Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Fery, Loyd
2 Fillmore City H::
3 Franklin County Public Utilities Distr
Frito Lay
5 Galesville Dam 0.40 0.40
6 Garland Canal
7 General Chemical Corporation OS"
8 Georgetown Power
9 Glendale, City
Grand Valley Power
Grant County Public Utility District
Grant County Public Utility District
Grant County Public Utility District
Grant County Public Utility District 14.
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04
(2) 0 A Resubmission 03/20/2006
CCOUH\~gg~) llj( nIlnuecj~ .~, ,nlliiCfudlng power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis , enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0). energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
32'11,324
182 19,680 680
066 323,639 323,639
' ..' ,' '
'3121 312
87;./566 406,61 ~449 178
63~118,819 300 855 419 678
3,40C 50,66f 665
75E 81~814
076,25C 076 250
321 321
617 36~.6;O$ti643 052,643
779,011 i ,'7;493;552 493 652
132 660
60C 145,404 201 862 529
15,843 940 13,142 367 191 207 107 354 886 508 699,262 941 259,260 674 794 88E
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
~CHA~ED POWER ~Accou1t 5 5)nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(c)(d)(e)(f)
1 Grant County Public Utility District
2 Grant County Public Utility District
3 Grant County Public Utility District
4 Grays Harbor Public Utility District I~"?,
5 Grays Harbor Public Utility District
6 Heber Light & Power Company Il.;f;
I : 1 ;~J1emJjrl~J~
~; "
241.241.221.
9 Hill Air Force Base Airf,
Hill Air Force Base
Holcim
Hum Wind
Hurricane, City of 11::-:'.;,,
"";-\
Idaho Falls, City of
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 03/20/2006
ccoul'!!. ::!::!t)) .1L;ontlnuenl. ... M '~
'(1nCfudlng power exchanges)' - --
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.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/Q4
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 (t). 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 m, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered ,than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGESMegaWatt Hours
Purchased MegaWatt Hours MegaWatt HoursReceived Delivered
(g)
(h) (i)
Demand Charges
($)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
Ii!::7;23279,891
625
32~
857 13C
91S
234 35 "
"",,:':"
60C
423 00.
336,76.
690,349
1~;~
50,362, 14Si '6451;
;" ".:,. '..:' ":, "
' 1'31
319,65 (
51i,
;:.
46,16€44~
39,35C " \2,540;51(7
843 940 13,142,367 13,191,207 107 354 886 508 699 262 941 259 260
FERC FORM NO.1 (ED. 12-90)Page 327.
LineTotal O+k+l) No.of Settlement ($)
(m)
334
857
241 584
600
423,003
336 762
188,564
503,966
131
319 657
579
161
168
540,577
674 794 88E
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
~CHA~ED POWER ~Accou1t 555)nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Idaho Falls, City of
2 Idaho Power Company
3 Idaho Power Company
4 Idaho Power Company
5 Ingram Warm Springs Ranch
6 Intermountain Power Project
7 J. Aron & Company
8 Kennecott
9 Kennecott
Lacomb Irrigation
Lake Siskiyou
Los Angeles Dept. of Water & Power IDS..
Los Angeles Dept. of Water & Power
Lucky, Paul
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2)0 A Resubmission 03/20/2006
CCO~\~gil)(O ntinued)(Including power ex ang )
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (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 (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
16(100 561 100 560
241 a:".17:'!173
48C 49,250
145,78E 352 074 100,068
88/970 970
556 96E 042,351 24,042 351
681 221 766 91E
+) ,
, 482 766 433
, ,
141 235 944 79~
" ",..."' '' '
-4;58!3 940,206
.:"..,
S;971 667 971 667
302 52/
. ",..,
. ?9;3t7 331 844
23,02;339 427 236 601 576,028
95E 539,25E lib
' ,
17S.f)(iD 714 855
195 94(10,796 321I::"
":,;:.,
142 920
23E 17,8Of 806
843,940 142 367 191 207 107 354 886 508 699,262 941 259 260 674 794,88E
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
PU~C6i'A~ED POWER ~Account 555)(n u Ing power ex angesJ
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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman!Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Magnesium Corporation of America
2 Magnesium Corporation of America LFT
;."
3 Marsh Valley Hydro & Electric Company
Merrill Lynch Commodities, Inc.
5 Middlefork Irrigation District
6 Mink Creek Hydro
7 Mirant Americas Energy Marketing, loP.
8 Monsanto
Morgan City I.:J=/
'/"
Morgan Stanley Capital Group, Inc.50.50.50.
Morgan Stanley Capital Group, Inc.
Mountain Energy 001 001
Municipal Energy Agency of Nebraska
Nephi City 14S'"" ,., "
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
-Wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2)0 A Resubmission 03/20/2006
.v ".
" ""
?tnCfudlng powef~gH~xg~~)((;ontinUea)
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (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 Q), energy charges in column (k), and the total of any other types of charges , including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
159,24E 802 631 802 631
7~;fi~5 732 855
741 243 221 243;227
104,85C 6,498,90C 498,900
821 183 498 089,67~273 172
631 530,09f 530 098
175 279,02~279 024
,,,
9.s:3tJ,22~538,223
37C 370
135 40C 468,000 811 44C 279,440
723,92.221 167 06f 221 167 065
404 291 695
90'272 43.272,432
67C 670
843,940 142,367 13,191,207 107 354 886 508 699,262 941,259 260 674 794 88f
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2) Ei A Resubmission 03/20/2006
~C~A~ED POWER ~Accou
1t 5 5)n u 109 power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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., 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 allnon-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand(a)(b)(c)(d)(e)(f)
1 Nevada Power Company
2 Nevada Power Company
3 Nevada Power Company
4 Nicholson Sunnybar Ranch
5 North Fork Sprague
6 NorthWestem Energy
7 Northern California Power Agency
8 Nucor Corporation
9 O.J. Power Company
Occidental Power Services, Inc.
Odell Creek
PPL Energy Plus, LLC
PPL Montana, LLC ii,
' "':,.
PPL Montana, LLC
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 03/20/2006
ccoul'!!.::!::!::!).,L;OntinUeal. v "v"~l1ncrudJng power exChanges)'- --
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.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/Q4
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (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 m, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges , report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGESMegaWatt Hours
Purchased MegaWatt Hours MegaWatt HoursReceived Delivered
(g)
(h) (i)
Demand Charges
($)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
)i,
;.,
,:?\oon235
42~
56C
525
34E
219
879,325 ,
835,36
38C
153,791
741,95S
23~
348 02~
74E
376 65E ,,
1 ,08C
638,431
" '".,."
~;O34
1,722,000
89C
03S
99~
10,73~
949
15,843 940 13,142 367 13,191 207 107 354 886 508 699 262 941 259,260
FERC FORM NO.1 (ED. 12-90)Page 327.
LineTotal O+k+l) No.of Settlement ($)
(m)
169
881 329
149,479
380
177 010
034
741 958
722,000
42,234
348 022
694
370,915
080
638,437
674 794 88E
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 03/20/2006
PU~CHA~ED POWER ~Accou1t 555)(nclu Ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (I.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Pacific Northwest Generating Cooperati
2 Panda Gila River QS.
3 Panda Gila River
4 Payson City Corporation ILf,
5 Pinnacle West Capital Corporation
6 Pinnacle West Capital Corporation
7 Platte River Power
8 Portland General Electric Co.
9 Portland General Electric Co.L.f
, ",
Portland General Electric Co.
Powerex
Powerex
Powerex
Preston City Hydro
Total
FERC FORM NO.1 (ED. 12.90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
CCOU
H\~gg~) llionnnUeoj
. ~ .~, '~
"lIiicrudlOg power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
977 94C 977 940
22~9,45C 450
25C 950 950
641:645
80C 708,80C 708,800
346,345 926,51S 926,515
6ge
" ".. ,
;2~222
, ,.a~;1'!~88,172
995
'" '' "
tOQ,;PP,100,000
301 61~18,931,
"";,
966 314c""
63E 212 89~212 892
52e 528
706,02E 50,233,551 233 551
67~123 895 123,899
15,843,940 13,142 367 191 207 107 354,886 508,699,262 941 259 260 674 794 88f
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 03/20/2006
PU~CHA~ED POWER ~Account 555)(nclu Ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman!Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Provo City
":'(,.
Public Service Company of Colorado
..,~,
.i''i;;
Public Service Company of Colorado
Public Service Company of New Mexico .x,
5 Public Service Company of New Mexico
6 Public Service Company of New Mexico
7 Public Service Company of New Mexico
8 Puget Sound Energy
9 Quail Mountain, Inc.
Rainbow Energy Marketing
Ralphs Ranch, Inc.
Redding, City of
Reliant Energy Services, Inc.
Riverside, City of
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent I his
ooort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2) 0 A Resubmission 03/20/2006
CCOUH\~gg~~ ll;OOtIOUeOj
, ~ .~, '~
'(1nCTudlng power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average 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 (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
55~553
666 551
...,, '
)~'57 708
279,46;.!508,18E 508,188
02~.-:!!;17J$775
134,40C 923,552 923 552
99,02~666,871 667,171
300,04.371 155 603 525
293 451 16,932 16,982,694
;'", "
1 ,73~733
82~292 70.292 702
26E 19,77E 19,776
21C 99,836 99,836
600 811 460 811,460
641 275,135 275,135
843,940 13,142,367 13,191 207 107,354 886 508 699 262 941 259 260 674 794 88E
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
PU~CHA~ED POWER chAccou1t 5 5)(nClu Ing power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing-
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., 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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Riverside, City of
Rocky Mountain Generation Cooperative
Rocky Mountain Generation Cooperative
Roush Hydro, Inc.
SUEZ Energy Marketing NA, Inc.
Sacramento Municipal Utility District
7 Sacramento Municipal Utility District
8 Salt River Project
9 Salt River Project
San Diego Gas & Electric
Santa Clara, City of
Santiam Water Control District
Seattle City Light
Seattle City Light
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
cco~1~gg~J llJOnUnUeoj
, ~ .~. '~
'(Iiicrudlng power ex ange)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exch~nge Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
61C 104 40C 104,400
12,66E 506,651 506,651
47,81..812
4OE 50E 506
204 01 a 375 62.375,622
218,823 525,21
, ", "
' m i86,910 612 187
31~835,273 835 273
071 095,57
:'", "' .,
:9,~9 098,827
222,92e 12,769,88E 12,769,885
64E 989,77..989 772
131,99~131 994
57E 13,632 131 98E 145 620
/':',""
' ,'oou 650
/.;""
84,641 604 91~
",:( :
Xi
""~';:~
617 866
15,843 940 13,142,367 13,191 207 107 354,886 508,699,262 941 259 260 674 794,88E
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2) 0 A Resubmission 03/20/2006
PU~CHA~ED POWER ~Account 5 (nclu Ing power ex anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Sempra Energy Resources ~QY.
..",..
2 Sempra Energy Solutions
3 Sempra Energy Trading Corp.
4 Sierra Pacific Power Company
5 Sierra Pacific Power Company
6 Sierra Pacific Power Company
7 Simplot Phosphates, LLC
Sirnplot Phosphates, LLC 1"""""'
9 Slate Creek
Snohomish Public Utility District
Southern California Edison Company t"'II""
Southern California Edison Company
Southwestern Public Service Company
Spanish Fork City
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)DA Resubmission 03/20/2006
ccoucH~~g~~)llj( ntlnUed)(li'iCludlng power ex ange)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all. FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered , used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
...,
~t~,
~~?:
218 457
65,55~744,32€744 326
6B4 26~91 ,544 08E 544 810
,;,.",.
41C 25,26C 25,260
55E 071
..'.' ,
242.~~O 314,043
115 325,873 325 873
;."."
: .12,394 394
151 194 620 287 145 1,481 769
29,65.:70B,09C 708,090
53(70C 700
36(736 75E 736,755
60(24,65C 650
4,465 4,469
843 940 142 367 191 207 107 354 886 508,699,262 941 259,260 674 794 8BE
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
PU~CHA~ED POWER ~Accou1t 555)(nclu 109 power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 suppliers 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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Springville City !!-f;";"
, "
State of California Department of Wate
Strawberry Electric Service District
Sunnyside Cogeneration Associates 52.52.42.
5 Swiss Re Financial Products Corporatio
6 Tacoma, City of
7 Tesoro Refining and Marketing Company
8 Thayn Ranch Hydro
9 TransAita Energy Marketing Inc.
~..
TransAita Energy Marketing Inc.
Tri-State Generation & Transmission
G)/.
45.45.42.
Tri-State Generation & Transmission
Tri-State Generation & Transmission
Tucson Electric Power '7""
):""'
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2) 0 A Resubmission 03/20/2006
CCO~\x8~~) (0 ntinued)~naudmg power ex ange)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)\~~($)
of Settlement ($)
(g)
(h)(i)(I)(m)
32~324
40C 80C 11,800
72C 720
416,250 218 250,31~30,500,532
685,
437 503
26,4 H 693 234
14.272
"..,
;"'"7"264 483
401 35,433 126,56~161,996
376,007 131 349,551 0;;1 ,B42i?1~129 507 332
745,502 770,14E 770,145
253,39E 8,451 000 925,10~376 104
55C 347 27~347 274
4,43 183,68~183 684
560
15,843 940 13,142 367 191 207 107 354 886 508 699,262 941 259 260 674 794 88e
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
ooort Is:
Date of Report Year/Period of Report
PaclfiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
PU~CHA~ED POWE~Accou1t 555)(nclu 109 power ex anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Tucson Electric Power
2 Tucson Electric Power
3 Turlock Irrigation District
4 UBS Warburg Energy LLC
5 Utah Associated Municipal Power System 1(J!oi.
,."
6 Utah Associated Municipal Power System
7 Wadeland South LLC
8 Wadeland South LLC
9 Walla Walla, City
Warm Springs Forest Products
Weber County, State of Utah
Western Area Power Administration \""L
Western Area Power Administration
.; ,
Western Area Power Administration
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 03/20/2006
ccou
H~~g~~~ (l;onttnueOj(inCluding power exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reparting
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)~~~($)
of Settlement ($)
(g)
(h)(i)(I)(m)
64'588,28!588,285
12,31~711,795 711 799
07f 210 34C 210,340
621 159 32,453 271 453,271
08C 080
88€102,74C 102 740
'i 593 593
49€625 785 414
045 134 173 294 90~1,429,076
025 104 104 984
"....,.."
350
29,91 f 208,30.
\:.;.,
228 627
675 524 06C 524,060
15,843,940 142 367 13,191 207 107 354 886 508 699 262 941 259 260 674 794 88f
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
PU~C~~ED POWER ~Accou
1t 555)(n u Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Whitney, A. C.
Williams Energy Market & Trading Co.
3 Wolverine Creek Energy LLC
4 Yakima Tieton
5 Accrual True-up
6 Bookout Purchases
7 Bookout Purchases
Potential Liability
~::
9 Potential Liability IAn:,;",
' ..
Trade Purchases
Anaheim, City of WSPP
Arizona Public Service Co.306
Ashland, City of 353
Avista Corp.554
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) n A Resubmission 03/20/2006
CCOUH\~gg~) (l;ontlnUeCl)(lnCludlng power exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service , enter NA in columns (d), (e) and (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. R-eport demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
16,86E O02 62E 002,626
315 230 01.:230,013
98f 911 776 839,244
.~;1'~'6,52,116 730""~ "0
~3;~?;~245,594
15,328,077
"" "
.:e~7)f~Oi#72 687 460,472
..', :
:i~t;3 841,354
.."
~tD33,~.!i 033,935
~t26;4'~,126,453,427
600 18,600
571 392 571 392
, " "
,.~Q5~~79 059 870
743 )Y)""L"'011
871
15,843 940 142,367 13,191 207 1 07 354 886 508,699 262 941,259,260 674 794 88E
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ooort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2) 0 A Resubmission 03/20/2006
PU~CHA~ED POWER ~Account 5 5)(nclu Ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing. of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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 (Le., 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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman!Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Avista Energy, Inc.wspp
BP Energy Company 280
Basin Electric Power Cooperative
Black Hills Power & Light Company 246
5 Bonneville Power Administration 1p'!554
Bonneville Power Administration 554
7 Bonneville Power Administration 368
8 Bonneville Power Administration 237
9 Bonneville Power Administration :lien "
Bonneville Power Administration
Bonneville Power Administration 256
Bonneville Power Administration
:';;".
i ,
Bonneville Power Administration
Bonneville Power Administration 347
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) 0 A Resubmission 03/20/2006
CCO~\~gg~) \lJontlnueojfjnCludlng power ex ange)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (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 m. energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 . line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
36,600 36,600 IlEi,
.::(
..1~~i8pO 109,800
;:;",;,.",,,,'
976
12,223 892
:.'
192,181
10;225 10,225
132 301 899
196,082 196,082
"0"'20,301
~"-
676 034 0"':"843,208
727 937
': ,"'",
"""'1 129,013
689 689 -43 856
..
~;9'1;6&~~1'911'R~8 118 911 588
103,968 104,023 . ,,1'1)27,965 1 ,027 065
1 ,805 359 1 ,814 724 190,000
15,843,940 13,142,367 191 207 1 07 354 886 1 ,508 699,262 941 259 260 674 794 88E
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) 0 A Resubmission 03/20/2006
~C6i'A~ED POWER ~Accou 1t 555)n u 109 power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Chelan County Public Utility District 554
Clark Public Utilities :417
3 Clark Public Utilities 417
Colockum Transmission Company
Deseret Generation & Transmission 280
6 Emerald Peoples Utility District 351
7 Eugene Water & Electric Board
8 Flathead Electric Cooperative
9 Grant County Public Utility District 554
Idaho Power Company 380
Portland General Electric 554
Public Service Company of Colorado
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
CCOU
H\~8~~~ (ContinUed)(Including power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0). energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(I)(I)(m)
831
160 457 096
137 684 209
268 153
852 876 904,267
415 10,386
811 872 181 851
.;';;';;'
10,026 235
" ,
.if8Q;7S3 480 783
447 78,229
298,726 251 264
808 553 189 659
39,785 11,395 256 083
156,754 155,580
70,875 66,036 ;'i 13:1..(534 131 634
15,843,940 13,142 367 191 207 107 354 886 508 699 262 941 259 260 674 794 88f
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 03/20/2006
PU~CH~ED POWER ~Account 555)
(nclu Ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other 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., 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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Public Service Company of Colorado 319
2 Redding, City 364
3 Seattle City Light 554
4 Sempra Energy Solutions
5 Tri-State Generation & Transmission 319
6 Utah Associated Municipal Power System
7 Utah Municipal Power Agency
8 Utah Municipal Power Agency
9 Warm Springs Power Enterprises
Western Area Power Administration Ai:)d
Western Area Power Administration
Weyerhauser
System Deviation ~a.
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2) El A Resubmission 03/20/2006
ccou
~~~~1 (0 ntinued)(InCluding power exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER LinePurchasedMegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)
\fl
of Settlement ($)
(g)
(h)(i)(m)
950
120,575 119,061 ie,
..'
606,934
282 298 278,923 447 349
19,642 296 ;,C,:;E 781 567
165,895 153,006
/::..
224 647
879 22,003 ie,526
605 922 999 625
570 142 180 211
763 887
*" -
237 543
18,248 784 If:'754 814
934 45,994 735,637
181
30,
15,843 940 13,142 367 191 207 107 354,886 508,699,262 941 259,260 674 794 88e
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
\Schedule Page: 326 Line No.Column: I
Green tags.
\Schedule Page: 326 Line No.Column: I
Conservation & Renewables Discount applied to wind project near Arlington, Wyoming and settlement for damages from
non-delivery of generation.
ISchedule Page: 326 Line No.Column:
A uila Merchant Services, Inc. - Contract Termination Date: Se tember 30, 2005.
Schedule Pa e: 326 Line No.Column: I
Hedge payout and option premium.
Column:
Column: I
Line No.Column: I
Column:
Column: I
Line No.Column: I
Line No.Column:
, South Dakota.
Column:
Page 450.
Column: I
Column:
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp ;2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
Line No.Column: I
Column: b
Column: I
Column: I
Line No.Column: b
Line No.Column: I
Column: b
Column: I
Column: b
Column: I
Column: b
Column: I
Line No.Column: I
tember 30, 2024.
Column: I
Line No.Column: I
,---
Column: b
Column: I
Line No.Column: b
Line No.Column: I
Line No.Column: b
IFERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PaclfiCorp (2)A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
Column: I
Column: b
ears written notice.
ears written notice.
Column: b
Column: I
Line No.Column: I
Column: b
notification.
Line No.Column: I
Line No.Column: I
IFERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
Column: b
Column: I
Line No.Column: I
Line No.Column: I
Column: b
Column: I
Column: I
Column: I
Line No.Column: I
Column: I
Column: I
Column: b
Column: I
Line No.Column: I
Line No.
------.J
notification.
notification.
Column: I
f--
Column: b
Column
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 03/20/2006 2005/Q4
FOOTNOTE DATA
Line No.Column: I
Line No.Column: I
Line No.Column: I
Line No.Column: I
Column: b
Column: b
notification.
Column: I
Line No.Column: b
Line No.Column: I
Column: b
Column: I
Line No.Column: I
Line No.Column: I
Column: b
Column: b
IFERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 03/20/2006 2005/Q4
FOOTNOTE DATA
Column: b
Column: I
Column: b
Column: I
Line No.Column: I
Line No.Column: b
Line No.Column: I
Line No.Column: I
Line No.Column: b
Line No.Column: I
Column: b
Column: I
Column: b
Column: I
Column: b
Column: I
Column: I
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
Column: b
Line No.Column: I
Column: b
Column: b
Column: b
Line No.Column: I
Line No.Column: b
Line No.Column: I
Column: b
Column: I
contracts under EITF Issue No. 02-04.
contracts under EITF Issue No. 02-04.
Line No.Column: I
IFERC FORM NO.1 (ED. 12-87)Page 450,
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
Column: I
Column: I
Line No.Column: I
Line No.Column: b
Column: I
Column: I
Line No.Column: b
Line No.Column: I
Line No.Column: I
Line No.Column: I
Line No.Column: b
Column: I
Column: I
Column: I
Column: I
Column: I
Line No.Column: I
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 03/20/2006 2005/Q4
FOOTNOTE DATA
Line No.Column: I
Ie common control.
Line No.Column: I
Line No.Column: I
Line No.Column: I
Line No.Column: I
Line No.Column: b
Line No.Column: I
Line No.Column: I
Line No.Column: I
Line No.Column: b
Line No.Column: I
Line No.Column: I
Line No.Column: I
Column: b
I FERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 328)
Name of Respondent
PacifiCorp
This ~ort (1) ~An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
03/20/2006
Year/Period of Report
End of 2005/Q4
ccoun(Including transactions referred to as 'wheeling
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.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Avista Energy
2 Avista Energy
3 Basin Electric Power COOP
4 Basin Electric Power COOP
5 Basin Electric Power COOP
6 Basin Electric Power COOP
7 Black Hills Power & Light
8 Black Hills Power & Light
9 Black Hills Power & Light
10 Black Hills Power & Light
11 Black Hills Power & Light
12 Bonneville Power Administration
13 Bonneville Power Administration
14 Bonneville Power Administration
15 Bonneville Power Administration
16 Bonneville Power Administration
17 Bonneville Power Administration
Montana-Dakota Utilities
Black Hill Power & Light Company
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
U S Bureau of Reclamation
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Umpqua Indian Utility Cooperative
Bonneville Power Administration
Bonneville Power Administration
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
(lnClu'cf~9 transactions ~lIe7e'cf l~i~~~~~t 4::!OjllJOnnnUeOj
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 (t). 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.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaVVatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(I)
OV-Various Various 534 53'
OV-Various Various 400 40C
OV-Yellowtail Sub Sheridan Sub
OV-Yellowtail Sub Sheridan Sub
136 Dave Johnston Su
OV-Various Various 240 24C
OV-4,432 4,43.
OV-102 247 102,24)
OV-Various Sheridan Sub
OV-Various Wyodak Sub
226 Wyodak Sub
237 Various Various 302
324 Lost Creek Hydro Various 189 319 189,315
256 Various Various 151
OV-Bonneville Power Gazley Substatio
OV-USBR Green Sprin Bonneville Power
368 Malin Sub Malin Sub
508 499.461 499,461
FERC FORM NO.1 (ED. 12-90)Page 329
Blank Page
(Next Page is: 330)
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PaclflCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 03/20/2006FQR !ACCOUQt 450) ((,;ontlnUeCl)(Including transactions reffered to as 'wfIeeling
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 G) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
21,763 763
300 300
218 898 218 898
176 243 176 243
14,400
555 555
18,786 786
485 812 485 812
714 815 r:\71'4R1'786 296
344 250 344,250
.r'. ~
604
838,851
"',: ..,,'
912 975
:?,...": :,
~;27e 312 276
" 4,096,297 096,297
32,524 115 857
400,950 437,400
;;':"" :, ,
213 636
::,
::L,
29,718,962 15.589,467 13,777,337 59,085,766
FERC FORM NO.1 (ED. 12-90)Page 330
Name of Respondent
PacifiCorp
is ~ort Is:(1) ~An Original
(2) A Resubmission
Year/Period of Report
End of 2005/Q4
ccoun(Including transactions referred to as 'wheeling
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.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
1 Bonneville Power Administration
2 Bonneville Power Administration
3 Bridger Valley Rural Elec.
4 BP Energy
5 Calpine Energy
6 Cargill-Alliant, LLC
7 Cargill-Alliant, LLC
8 Constellation Power
9 Deseret Generation & Trans.
10 Deseret Generation & Trans.
11 Deseret Generation & Trans.
12 Deseret Generation & Trans.
13 Eugene Water & Electric Board
14 Fall River Rural Electric
15 Flathead Electric Cooperative
16 Idaho Power Company
17 idaho Power Company
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
01= E\-EGI K!~II Y rYK '-!! m::I"\
'='
\J' CCOU~t 4::!oJll;ommuecJ(Including transactions reffered to as 'wIieeling
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 0) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand
Tariff Number Designation)Designation)(MW)Megavvan Hours MegaWatt Hours No.Received Delivered(e)(f)
(g)
(h)(i)
299 Various Various 231 193,734 193 73'
OV-Various Various 560 56C
213 Blacksfork Sub
OV-30,285 30,281
OV-
OV-891 956 891 95€
OV-129,336 129 33E
OV-150 15(
280 Various Various
342 Mona Sub
OV-952 95.
OV-813
OV-340 34C
322 Targhee Sub Goshen Sub
OV-Yellowtail Sub Various
OV-Red Butte Borah
OV-433
508 499,461 499,461
FERC FORM NO.1 (ED. 12-90)Page 329.
lank Page
(Next Page is: 330.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/Q4
ccoun(Including transactions reffered to as 'wlieelin '
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 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERSEnergy Charges (Other Charges)
($) ($)
(I) (m)
735,053
920 305
100
759 375
29,718,962 15,589,467 13,777 337
FERC FORM NO.1 (ED. 12-90)Page 330.
Total Revenues ($)
(k+l+m)
(n)
983 281
361
741
152 896
234
824,273
372,477
876
759 876
844
32,630
049
986
151 308
082
759,375
708
59,085,766
No.
Name of Respondent
PacifiCorp
his ~ort Is:(1) ~An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
03/20/2006
Year/Period of Report
End of 2005/Q4
ccounIncluding transactions referred to as 'wheelin '
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.
5 J. Aron
6 Moon Lake Electric Association
12 Mil
13 '81ii1jr;ijij"
14 Portland General Electric
15 Portland General Electric
16 Powerex
17 Powerex
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Idaho Power Company
Idaho Power Company
Idaho Power Company
Intermountain Power
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
Line
No.
Morgan Stanley Capital Gr.
Morgan Stanley Capital Gr.
Pacific Gas & Electric
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This
ooort Is:
Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
t:Lt:\,; I KI\,;II Y FQR lJ I Ht:K:::i,(~ ccouot 456)(Continued)
(Including transactions reffered to as 'wneeling
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 (t), 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 0) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
OV-480,000 480 OOC
257 Antelope Sub Antelope Sub
203 Jim Bridger Sub Bridger Pump Station
342 Mona Sub
755 75E
302 Duchesne Duchesne
OV-
OV-104 613 1 04 61 ~
Malin Sub Indian Springs
OV-602 284 602 28~
OV-455 350 455,35C
OV-
OV-
372 Harrison Sub Harrison Sub
OV-642 64,
OV-Bonneville Power Weed Jct. Sub
OV-623 621 623 621
508 499,461 499,461
FERC FORM NO.1 (ED. 12-90)Page 329.
Blank Page
(Next Page is: 330.
Name of Respondent
PacifiCorp
Date of Report(Mo, Da, Yr)
03/20/2006
Year/Period of Report
End of 2005/04
ccoun(Including transactions reffered to as 'wfleeling
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 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERSEnergy Charges (Other Charges)
($) ($)
(I) (m)
641
409,126
721 250
29,718,962 15,589,467 13.777,337
FERC FORM NO.1 (ED. 12-90)Page 330.
Total Revenues ($)JOe
(k+l+m)No.
(n)
316 250
73,824
284
374 779
4,410
641
654 118
413,480
380 827
417 500
154 339
310 153
840
749
883,250
508,604
59,085,766
Name of Respondent
PacifiCorp
his ~ort Is:(1) ~An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
03/20/2006
Year/Period of Report
End of 2005/Q4
ccoun(Including transactions referred to as 'wheeling
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.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Powerex
2 PPL Montana, LLC
3 Public Service Co. of Colorado
4 Public Service Co. of Colorado
5 Rainbow Energy Marketing
6 Rainbow Energy Marketing
7 San Diego Gas & Electric
8 Seawest Windpower, Inc.
9 Sempra Energy
10 Sempra Energy
11 Sempra Energy
12 Sheridan-Johnson Rural EI
13 Sierra Pacific Power Company
14 Sierra Pacific Power Company
15 Southern California Edison
16 State of South Dakota
17 TransAJta Energy
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006Qf CCOUlJt 45t:i)(GontInUeCl)(Includlna transactions reffered to as 'wIieeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERCrate 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 0) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
OV-14,400 40C
OV-087 08/
OV-127 358 127,35f
OV-880 88C
OV-987 98/
OV-440 44C
Malin Sub Indian Springs
OV-Foote Creek Sub
OV-34,423 34.42~
OV-320 32C
OV-Bonneville Power Various
Buffalo Sub Buffalo Sub
OV-360 290 360,290
Pending Pavant Substatio Pavant Substatio
Malin Sub Indian Springs
OV-Yellowtail Sub Wyodak Sub
OV-573 57~
508 499,461 499,461
FERC FORM NO.1 (ED. 12-90)Page 329.
Blank Page
(Next Page is: 330.
Name of Respondent
PacifiCorp
This ~ort Is:(1) ~An Original
(2) A Resubmission
Year/Period of Report
End of 2005/04
ccoun(Including transactions reffered to as 'wIieeling
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.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERSEnergy Charges (Other Charges)
($) ($)
(I) (m)
40,500
245 788
570,635
160
170,400
52,080
Total Revenues ($)
(k+l+m)
(n)
Ine
No.
81,000
245,788
590,041
160
175,431
52,080
250
869
187 723
670
158,391
165
980,567
973
617,730
200
929
100
162,351
670
154 898
346
29,718,962 15,589,467 13,777,337 59,085,766
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent
PacifiCorp
This ~ort Is:(1) ~An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
03/20/2006
Year/Period of Report
End of 2005/Q4
ccoun(Including transactions referred to as 'wheeling
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.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
1 Tri-State Generation & Trans.
2 Tri-State Generation & Trans.
3 Tri-State Generation & Trans.
4 Tri-State Generation & Trans.
5 Tri-State Generation & Trans.
6 Tri-State Generation & Trans.
7 United States Bureau of Reclam.
8 United States Bureau of Reclam.
9 United States Bureau of Reclam.
10 Utah Associated Municipal
11 Utah Associated Municipal
12 Utah Municipal Power Agen.
13 Utah Municipal Power Agen.
14 Warm Springs Power Enterp.
15 Western Area Power Admin.
16 Western Area Power Admin.
17 Western Area Power Admin.
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Utah Associated Municipal Power
Crooked River Irrigation District
U S Bureau of Reclamation
U S Bureau of Reclamation
Utah Associated Municipal Power
Utah Municipal Power Agency
Portland General Electric
Various WAPA Customers In PACE
Western Area Power Administration Western Area Power Administration
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
QF FI II T !~Ccou~t 455)ll,;Onttnuect)(Including transactions reffered to 'as 'wlieeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC~at~ 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 (t), 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 m the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)(9)(h)(i)
123 Difficulty Sub
123 Riverton Sub
123 Thermopolis Sub
123 Platte Sub
123 Various Various
OV-057
Redmond Substation Crooked River Pumps
Franklin Substation Burbank Pumps
Redmond Substation Crooked River Pumps
297 Various Various
OV-142 14,
279 Various Various
OV-348 341
591 Pelton Rereg Station Round Butte Substatn
262 Various Various 327
OV-Wyoming Vanous Wyoming Various 19,120 12(
OV-Wyoming Distribu Wyoming Distribu
508 499,461 499,461
FERC FORM NO.1 (ED. 12-90)Page :,129.
Blank Page
(Next Page is: 330.
Name of Respondent
PacifiCorp
on Inue
Date of Report
(Mo, Da, Yr)
03/20/2006
Year/Period of Report
End of 2005/04
ccounIncluding transactions reffered to as 'wlieeling
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 energYcharges 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 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERSEnergy Charges (Other Charges)
($) ($)
(I) (m)
169
682
809
606,682
740,488
109,725
381 763
111 661
26,843
29,718,962 15,589,467 13,777 337
FERC FORM NO.1 (ED. 12-90)Page 330.
Total Revenues ($)
(k+l+m)
(n)
No.
904
10,164
20,328
10,164
473
173
628
25,309
10,844
819,554
078
376,448
441
119,700
854 394
120 380
010
59,085,766
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 03/20/2006.oF T .!.~ccount 4::10)
(Including transactions referred to as 'wheeling
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.
Line Payment By Energy Received From Energy Delivered To Statistical
No.(Company of Public Authority)(Company of Public Authority)(Company of Public Authority)Classifi-
(Footnote Affiliation)(Footnote Affiliation)(Footnote Affiliation)cation
(a)(b)(c)(d)
Western Area Power Admin.
;;."(..,,' ,""";;"...,
Western Area Power Admin.
;,#';,',;;;)),
Western Area Power Admin.Weber Basin Project Western Area Power Administration
Weyerhaeuser Company Weyerhaeuser Company,Bonneville Power Administration I....~,
...
/';n
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This (gjort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006I OF II Y y" ~!' ,...,....u \r ccount 456)(COmIOUear
(Including transactions reffered to as 'wlieeling
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 (t), 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 G) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegaWaIfHours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
331 Casper Sub
330 Thermopolis Sub
286 Various Various
OV-Western Kraft Su Alvey Substation
508 499,461 499,461
FERC FORM NO.1 (ED. 12-90)Page 329.
Blank Page
(Next Page is: 330.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
03/20/2006
Year/Period of Report
End of 2005/Q4
ccoun
(Including transactions reffered to as 'wIieeling
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 0) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
on nue
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERSEnergy Charges (Other Charges)
($) ($)
(I) (m)
Total Revenues ($)
(k+l+m)
(n)
Ine
No.
125
628
10,164
000
151,622
29,718,962 15,589,467 13,777,337 59,085,766
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
terminating on December 31 2023.
Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
arties and points.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmisslon 03/20/2006 2005/Q4
FOOTNOTE DATA
en Access Transmission Tariff between various arties and points.
Column:
of energy.
IFERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
2008.
Line No.Column:
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
PacifiCorp 1(2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
Ie common control.
on December 31 , 2006
rior eriod adjustment.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2) , A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
Column:
en Access Transmission Tariffbetween various
Column:
2008.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2) . A Resubmission 03/20/2006 200S/Q4
FOOTNOTE DATA
July 31 2014.
of energy.
eement dated November 9, 2000.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
2008.
2006.
arties and points.
u on written notification.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
eement.
Column: d
tenninating January 1, 2032
Column:
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
arties and points.
A. 320) terminatin on December 31 , 2006
IFERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 332)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) 0 A Resubmission 03/20/2006
TRANS" ISSION OF ELECTRICITY BY OTHE ~S (Account 565)
(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), (t) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (t) 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
cOl:nponents 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.
Line TRANSFER OF ENERG'i EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawan-hI~mana .F,nergy ~tner Total Cost ofliou,s liours Charres Charres Charres Trans~ssionAuthority (Footnote Affiliations)Classification Received Delivered(a)(b)(c)(d)(e)(f)
(g)
1 Arizona Public Service
2 Arizona Public Service LFP 202,090 202,090 924,960 924,960
3 Arizona Public Service 233 233 13,986 13,986
4 Arizona Public Service 26,414
5 Arizona Public Service SFP 26,791 26,791 88,663 88,663
6 Ashland, City of FNS 210 210 12,098 12,098
7 Avista Corp.FNS 59,819 150 247 752 247,752
8 Avista Corp.17,945 17,945 56,435 56,435
9 Big Hom R. E. C...i,,An.'~.tn 40,310
Blanding City 429 429
Blanding City LFP 264 264 758 758
Bonneville Power Adm.283 093 650,140
\\;;"
125,954
Bonneville Power Adm.FNS 442,798 788,634
Bonneville Power Adm.LFP 413,909 413,909 348,649 398 363,047
Bonneville Power Adm.165,912 165,912
Bonneville Power Adm.019,715 171,636 39,979,125 544,658 "2.4$2j14~42,975,931
TOTAL 13,788,409 14,005,479 65,348,235 240,079 15,771,985 83,360,299
FERC FORM NO.1/3-Q (REV. 02-04)Page 332
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PaclfiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
TRANS~ ISSION OF ELECTRICITY BY OTHE S (Account 565)
(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 ofthe 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.
Line TRANSFER OF ENERG't EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt--.;nagawatt-g~mamr Fhergy !.IIner Total Cost ofliourslioursChar?eS Char?eS Char?eS Tran5~ssionAuthority (Footnote Affiliations)Classification Received Delivered
(a)(b)(c)(d)(e)(f)
(g)
1 Bonneville Power Adm.SFP 584,856 584 856
2 CISO
'..'
59,858 ,-41.~f 124.984
3 CISO 336,359 336,359 930,499 930,499
4 CISO 734,441
5 Deseret Gen & Trans 371 371
6 Deseret Gen & Trans SFP 145,282 145,282 080,773 080,773
7 Flowell Electric Assoc. 107 107
8 Flowell Electric Assoc. LFP 157 157 274 274
9 Hermiston Gen Co., loP.T,,1~;~~154,938
Idaho Power Company 357 357 374 23,073 26,447
Idaho Power Company FNS 5,428 5,428
Idaho Power Company 553 117 593 163 087 200 37,754 124 954
..,
Idaho Power Company '&.821;m 821,643
Idaho Power Company SFP 162.623 162,623 333,364 333.364
LA Dept of Water & Pwr
:;' "
52,862'52,862
" "" "
LA Dept of Water & Pwr SFP 89,003 89,003 274,313 274 313
TOTAL 13,788,40!14,005,479 65.348,235 240,079 15,771 985 83,360,299
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
TRANS~ ISSION OF ELECTRICITY BY OTHE ~S (Account 565)
(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), (t) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (t) 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.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawan-J.I~mano ~nergy ymer Total Cost ofliourslioursCharresCharresCharresTrans~ssionAuthority (Footnote Affiliations)Classification Received Delivered(a)(b)(c)(d)(e)(f)
(g)
1 MAPPCOR ~yo 895
2 MAPPCOR 19,290
3 Moon Lake Elect. Assoc.FNS 83,284
4 Morgan City 177 177
5 Navajo Tribal Util Aulh 260
6 Nevada Power Company -48,505 -45,477
7 Nevada Power Company 142,016 142,016 284,044 284,044
8 Nevada Power Company 160,869
9 Nevada Power Company SFP 170,466 170,466 764,590 764,590
NorthWestern Energy 121,771
..."
95,443
NorthWestern Energy 76,732 76,976 358.748 358,748
NorthWestern Energy i;..763 544
NorthWestern Energy SFP 152,408 152,408 710,532 710,532
Platte River Power
'."
,;:!IItj 596
Platte River Power SFP 38,317 38,317 161,000 161 000
Portland Gen. Elecbic 14,088 14,088 15,881 15,881
TOTAL 13,788,4Q!14,005,479 65,348,235 240,079 15,771,985 83,360 299
FERC FORM NO.1/3-Q (REV. 02.04)Page 332.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
TRANS!\. ISSION OF ELECTRICITY BY OTHE ~S (Account 565)
(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), (t) 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.
Line TRANSFER OF ENERG'I EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Msgawsn-y~mana .f;nergy ~mer Total Cost ofliourslioursCha
wes
Charres Cha
wes Trans~ssionAuthority (Footnote Affiliations)Classification ReceIVed Delivered(a)(b)(c)(d)(e)(f)
(g)
1 Portland Gen. Electric 832,148 833,322 "151;3&5 151,365
2 PSC of Colorado LFP 154,556 162,506 816,844 816,844
3 PSC of Colorado 536 536 351 351
4 PSC of New Mexico 596 1:(.,549
5 PSC of New Mexico
...?,,,,~
22,134
6 PSC of New Mexico SFP 193,438 193,438 319,575 319,575
7 Puget Sound Energy 355 355 3,412 258
8 Puget Sound Energy 925 925 612 612
9 Puget Sound Energy .ii 199
Seattle City Light SFP 400 400 000 000
Sierra Pacific Power Co 181 181 16,000
...,
16,046
Sierra Pacific Power Co 44,436 44,436 301,187 301 187
Sierra Pacific Power Co . 191.259 101,259
Sierra Pacific Power Co SFP 235 64,235 989,392 989,392
Snohomish PUD No.521 521 956 956
Snohomish PUD No.24,650 24,650 196 61,196
TOTAL 13,788,409 005,479 65,348,235 240 079 15,771 ,985 83,360,299
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) n A Resubmission 03/20/2006
TRANSfo. ISSION OF ELECTRICITY BY OTHE ~S (Account 565)
(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), (t) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (t) 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.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawan-!:,~man\J .Energy \-IIner Total Cost ofliourslioursChar?eS Chawes - Char?eSAuthority (Footnote Affiliations)Classification Received Delivered Trans~ssion
(a)(b)(c)(d)(e)(f)
(g)
1 Suprise Valley Electr.10,542
2 Tacoma. City of 240 240 480 480
3 Tri-5tate Gen & Transm LFP 137,536 150,940 816,844 816,844
4 Tri-5tate Gen & Transm 32,968 32,968 062 062
5 Tn-State Gen & Transm ;;)i
...'\',"'"
125
6 Utah Assoc Muni Pwr Sys SFP 272,413 272,413 197,000 318,983
7 Western Area Power Adm.223
; .
.ft:i~)84,437
8 Western Area Power Adm.FNS 357 250 357,250
9 Western Area Power Adrn.LFP 290,588 290,588 505,000 505,000
Western Area Power Adm,362 362 277 277
Westem Area Power Adm.383
" ".
483,375
"',; .
,:~74i992
Western Area Power Adm.SFP 106,962 106.962 835,800 835,800
Accrual True-up
;)" '
995,644
TOTAL 13,788,40~14,005,479 65,348.235 240,079 15,771 985 83,360,299
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmisslon 03/20/2006 2005/Q4
FOOTNOTE DATA
Column: g
Column:
Column: 9
Column:
Column: 9
Column:
Line No.Column: 9
Line No.Column: 9
Line No.Column: 9
Line No.Column: 9
Line No.Column:
Line No.Column:
Line No.Column:
Line No.Column:
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
ISchedule Page: 332.Line No.: 13
Ancillary services.
!Schedule Page: 332.Line No.: 1
se of facilities.
!Schedule Page: 332.Line No.: 5
Ancillary services.
ISchedule Page: 332.Line No.: 6
Ancillary services.
'Schedule Page: 332.Line No.: 7
Anc services.
chedule Pa e: 332.4 Line No.: 11
Ancillary services and use of facilities.
ISchedule Page: 332.Line No.: 13
Accrual true-up.
Column:
Column:
Column:
Column:
Column:
Column:
Column:
IFERC FORM NO.1 (ED. 12-87) Page 450.
Blank Page
(Next Page is: 335)
Name of Respondent
I This
~ort Is:Date of Rep'ort Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/04
(2) A Resubmission 03/20/2006
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line Descri~tion Amount
No.(b)
Industry Association Dues 846,279
Nuclear Power Research Expenses
Other Experimental and General Research Expenses
Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities
Oth Expn :-=5 000 show purpose, recipient, amount. Group if c: $5,000
Community & Economic Development
Cache Chamber of Commerce 000
Economic Development for Central Oregon 000
Laramie Economic Development Corp 5,000
Oregon Economic Development Assoc.000
City of Pleasant Grove 000
Portland Development Commission 000
Redmond Economic Development 000
Rural Development Initiatives Inc.000
Salt Lake County Treasurer 000
Southern Oregon Regional Economic 000
Utah Center For Rural Life 8,000
Wayne Brown Insitute 000
Yakima County Development 10,000
Other 670
Corporate Memberships and Subscriptions
American Legislative Exchange 000
Assoc. of Edison Illuminating Companies 368
California Climate Action Registry 375
Consortium for Energy Efficiency 000
Davis Chamber of Commerce 000
Intermountain Electrical Assoc.15,000
North American Energy 000
Oregon Business Council 23,622
Pacific NW Utilities Conference Committee 928
Portland Business Alliance 26,265
Rocky Mountain Electrical League 15,000
Salt Lake Chamber of Commerce 255
Sunnyside Inc.000
Utah Foundation 500
Utah Information Technology Assoc.5,000
Utah Taxpayers Assoc.000
West Assoc C/O Tri-State Gen. & Trans. Assoc. Inc.28,511
Western Electricity Coordinating Council 938,310
Wyoming Taxpayers Assoc.950
Other 99,747
TOTAL 008 141
FERC FORM NO.1 (ED. 12-94)Page 335
Name of Respondent
I This 'fijort Is:
Date Qt Rep,ort Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) A Resubmission 03/20/2006
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line DeSCri~tiOn Amount
No.(b)-
Directors Fees - Regional Advisory Boards 168 262
General
98 Early Retirement - OR Reg. Asset Amort.676 947
City of Portland Cable Communctn. & Franchise Mgmt.000
ID Tax Pymt. Reg. Asset Amort.314 756
Glenrock Mine UT 98 (Excl. Recl.) Reg.Asset Amort.152 774
Glenrock Mine UT Stip (Excl. Recl.) Reg.Asset Amort.149 625
Noell Kempf Reg. Asset Amort.332
P&M Strike Reg. Asset Amort.299,449
Scottish Power UK Managment Fee 921 799
Skyline Displays Oregon Inc.030
Transition Plan Reg. Asset Amort.397,888
UT Amortization - Defrd Pension Reg. Asset Amort.159,014
Write off WA share of Centralia Gain 154 525
Y2K Expenses OR Reg. Asset Amort.263 100
Other 860
TOTAL 008,141
FERC FORM NO.1 (ED. 12-94)Page 335.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) Ei A Resubmission 03/20/2006
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403,404 405)
(Except amortization of aquisition adjustments)
1. Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed , list numerically in column (a) each plant subaccount
account or functional classification, as appropriate, to which a rate is applied. 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 (t) 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 bottbm of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Depreciation Amortization of
Line ~eciation Expense for Asset Limited Term Amortization of
No,Functional Classification pense Retirement Costs Electric Plant Other Electric Total
(Account 403)(Account 403.(Account 404)Plant (Acc 405)(a)(b)(c)(d)(e)(f)
1 Intangible Plant 149 930 097 655 45,247 585
2 Steam Production Plant 135 888,269 135,888 269
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 12,983,217 884 13,029,101
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 377 214 82,764 12,459 978
7 Transmission Plant 734,024 734,024
8 Distribution Plant 119,606,858 119 606 858
9 General Plant 39,079,005 634 974 713,979
Common Plant-Electric
TOTAL i J 46,913 552 097 655 420,679,794
. ";i'
B. Basis for Amortization Charges
The amortization of Limited-Term Electric Plant is based on straight-line amortization over the life of the asset.
The amortization of Other Electric Plant consists of costs associated with the merger of PacifiCorp and Utah Power & Light Company. Amortization is
straight-line over a 15 year period.
FERC FORM NO.1 (REV. 12-03)Page 336
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/04(2) n A Resubmission 03/20/2006
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaole I:stlmatea Net Appnea MOrtality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th
~~fandS)7~f
(Perafnt)(per;)nt)rge ~~r
HYDRAULIC PROD
MERWIN (2153)
333.00 WA
334.00 WA 243
336.00 WA
NORTH UMPQUA (48)
331.20 OR 260
FALL CREEK (13)
331.00 OR
334.00 OR
UPPER BEAVER (443)
330.30 UT
OTHER PRODUCTION
CURRANT CREEK
341.00 UT 749 35.
342.00 UT 309 35.
343.00 UT 679 35.
344.00 UT 986 35.
345.00 UT 593 35.
346.00 UT 132 35.
347.00 UT 263 35.
DISTRIBTN PLANT
363.286 10.10.
FERC FORM NO.1 (REV. 12'()3)Page 337
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S; An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
!schedule Page: 336 Line No.11 Column: b
Vehicle depreciation is charged to functional accounts. The following table summarizes the vehicle depreciation expense that was
charged to the functional accounts.
Twelve Months Ended
December 312005 2004
Vehicle Depreciation $ 11 352 594 $ 10 640 857
IFERC FORM NO.1 (ED. 12-87)Page 450.
lank Page
(Next Page is: 350)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PaclfiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
REGULATORY COMMISSION EXPEN
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the current year s expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Line Description Assessed by Expenses Total . LJ~terred
No.(Furnish name of regulatory commission or body the Regulatory Expense for In Account
Commission Current Year 18~.docket or case number and a description of the case)Utility (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
1 Before the Public Service Commission of Utah:
2 Annual Fee 072 706 072 706
3 Other State Regulatory Expenses 228 20,228
5 Before the Public Utility Commission of
6 Oregon:
7 Annual Fee 366 996 366,996
8 Other State Regulatory Expenses 927 927
Before the Public Service Commission of
Wyoming:
Annual Fee 908 943 908,943
Other State Regulatory Expenses 10,742 10,742
Before the Washington Utilities and
Transportation Commission:
Annual Fee 350,271 350 271
Other State Regulatory Expenses 268 268
Before the Idaho Public Utilities Commission:
Annual Fee 312 984 312 984
Other State Regulatory Expenses 15,456 15,456
Before the Public Utilities Commission of
California:
Annual Fee 319 319
Other State Regulatory Expenses 223 223
Before the Federal Energy Regulatory
Commission:
Annual Fee 673 193 673,193
Annual Land Use Fee 779 779
Deferred Regulatory Commission Expense 188,351
Deferred Regulatory Commission Expense
TOTAL 697 553 58,844 756,397 193,351
FERC FORM NO.1 (ED. 12-96)Page 350
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
REGULATORY COMMISSION EXPENSE (Continued)
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25 000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to Contra Amount Deferred in Line
Department I'\c~~~m Amount Account 182.Account Account 182.No.End of Year
(f)
(g)
(h)(i)(k)(I)
Electric 928 072,706
Electric 928 228
Electric 928 366 996
Electric 928 927
Electric 928 908 943
Electric 928 10,742
Electric 928 350 271
Electric 928 268
Electric 928 312 984
Electric 928 10,456
Electric 928 319
Electric 928 223
Electric 928 673,193
Electric 928 12,779
341 002 529,353
928 000
751 397 341,002 000 529,353
FERC FORM NO.1 (ED. 12-96)Page 351
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
~chedule Page: 350 Line No.36 Column:
This amount was defen-ed to account 186.
IFERC FORM NO.1 (ED. 12-87) Page 450.
Blank Page
(Next Page is: 352)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
RESEARCH, DEVELOPMENT, AND DEMONS RATION ACTIVITIES
1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(ldentify
recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, 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:(3) Transmission
(1) Generation a. Overhead
a. hydroelectric b. Underground
i. Recreation fish and wildlife (4) Distribution
Ii Other hydroelectric (5) Environment (other than equipment)
b. Fossil-fuel steam (6) Other (Classify and Include items in excess of $5 000.
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 Councilor the Electric
f. Siting and heat rejection Power Research Institute
Line Classification Description
No.(a)(b)
2 A. Electric R, D & D performed internally
(1) Generation
b. Fossil-fuel steam
Hunter Farm - Water balance study
Hunter Farm - Soil study
Huntington Farm - Water balance study
Huntington Farm - Soil Study
(7) Total Cost Incurred
B. Electric R, D & D performed externally
(1) Research Support National Electric Energy Testing, Research & Applications Center Dues
FERC FORM NO.1 (ED. 12-87)Page 352
Name of Respondent This ~ort Is:Date of Report Yea~Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) D A Resubmission 03/20/2006
RESEARCH, DEVELOPMENT, AND DEMONSTRATIC N ACTIVITIES (Continue)
(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 $5,000 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 $5,000 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.
Costs Incurred Internally Costs Incurred Externally AMOUNTS CHARGED IN CURRENT YEAR Unamortized LineCurre
rc\ Year Current Year Account Amount Accumulation No.
(d)(e)(f)
(g)
683 506 683
20,888 506 20,888
200 506 35,200
665 506 665
436 436
750 930.78,750
FERC FORM NO.1 (ED. 12-87)Page 353
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 03/20/2006
DISTRIBUTION OF SALARIES AND AGES
Report below the distribution of total salaries and wage~ for the year. Segregate amounts originally charged to clearing accounts to
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.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/Q4
(a)
85,370,676
785,323
50,468,100
43,349 635
273,744
Line
No.
Classification Direct PayrollDistribution Total
Electric
Operation
Production
Transmission
Distribution
6 Customer Accounts
7 Customer Service and Informational
8 Sales
Administrative and General
10 TOTAL Operation (Enter Total of lines 3 thru 9)
11 Maintenance
12 Production
13 Transmission
14 Distribution
15 Administrative and General
16 TOTAL Maint. (Total of lines 12 thru 15)
17 Total Operation and Maintenance
18 Production (Enter Total of lines 3 and 12)
19 Transmission (Enter Total of lines 4 and 13)
20 Distribution (Enter Total of lines 5 and 14)
21 Customer Accounts (Transcribe from line 6)
22 Customer Service and Informational (Transcribe from line 7)
23 Sales (Transcribe from line 8)
24 Administrative and General (Enter Total of lines 9 and 15)
25 TOTAL Oper. and Maint. (Total of lines 18 thru 24)
26 Gas
27 Operation
28 Production-Manufactured Gas
29 Production-Nat. Gas (Including Expl. and Dev.
30 Other Gas Supply
31 Storage, LNG Terminaling and Processing
32 Transmission
33 Distribution
34 Customer Accounts
35 Customer Service and Informational
36 Sales
37 Administrative and General
38 TOTAL Operation (Enter Total of lines 28 thru 37)
39 Maintenance
40 Production-Manufactured Gas
41 Production-Natural Gas
42 Other Gas Supply
43 Storage, LNG Terminaling and Processing
44 Transmission
45 Distribution
46 Administrative and General
47 TOTAL Maint. (Enter Total of lines 40 thru 46)
131 282 784
14,415,182
670,730
43,349,635
273,744
FERC FORM NO.1 (ED. 12-88)Page 354
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
DIST IBUTION OF SALARIES AND WAGE S (Continued)
Line Classification Direct Payroll AlI9c~tion of,TotalDistributionPayroll charged forNo.Clearin~ Accounts(a)(b)(d)
Total Operation and Maintenance
Production-Manufactured Gas (Enter Total of lines 28 and 40)
Production-Natural Gas (Including Expl. and Dev.) (Total lines 29
Other Gas Supply (Enter Total of lines 30 and 42)
Storage, LNG Terminaling and Processing (Total of lines 31 thru
Transmission (Lines 32 and 44)
Distribution (Lines 33 and 45)
Customer Accounts (Line 34)
Customer Service and Informational (Line 35)
Sales (Line 36)
Administrative and General (Lines 37 and 46)
TOTAL Operation and Maint. (Total of lines 49 thru 58)
Other Utility Departments
Operation and Maintenance
TOTAL All Utility Dept. (Total of lines 25,59, and 61)371,057,687 371,057,687
Utility Plant
Construction (By Utility Departments)
Electric Plant 139,452 263 139 452 263
Gas Plant
Other (provide details in footnote):
TOTAL Construction (Total of lines 65 thru 67)139,452 263 139,452 263
Plant Removal (By Utility Departments)
Electric Plant
Gas Plant
Other (provide details in footnote):
TOTAL Plant Removal (Total of lines 70 thru 72)
Other Accounts (Specify, provide details in footnote):
Other Income 307 326 307 326
Misc Income Deduction 238 003 238 003
Fuel Stock 883 306 24,883 306
Nonutility 390 955 390,955
TOTAL Other Accounts 30,819,590 819,590
TOTAL SALARIES AND WAGES 541,329,540 541 329,540
FERC FORM NO.1 (ED. 12-88)Page 355
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
PURCHASES AND SALES OF ANCILLAR SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined il') 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), (t) and (g) report the amount of ancillary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e), (t), 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), (t), 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), (t), 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), (t), 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.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant
Unit of Unit of
linE Type of Ancillary Service Number of Units Measure Dollars Number of Units Measure Dollars
No.(a)(b)(c)(d)(e)(f)
(g)
1 Scheduling. System Control and Dispatch MWH MWH
2 Reactive Supply and Voltage MWH MWH
3 Regulation and Frequency Response 53,922,867 MWH 627,659 54,058.952 MWH 649,355
4 Energy Imbalance 54,431 MWH 125,463
5 Operating Reserve - Spinning 51,411,089 MWH 18,826,198 54,014,027 MWH 19,805,869
6 Operating Reserve - Supplement 51,411,089 MWH 18.826,198 53,737,393 MWH 19,758,820
7 Other MWH MWH
8 Total (Lines 1 thru 7)156,745,045 46.280,055 161 755,941 46,088,581
FERC FORM NO.1 (New 2-04)Page 398
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04
(2) CiA Resubmission 03/20/2006
JNTHL Y TRANSMISSION SYSTEM PEAK LOAD
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, 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 0) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for
the definition of each statistical classification.
NAME OF SYSTEM:
Line Monthly Peak Day of Hour of Firm Network Firm Network Long-Term Firm Other Long-Short-Term Firm Other
No.Month MW - Total Monthly Monthly Service for Self Service for Point-to-point Term Firm Point-la-point Service
Peak Peak Others Reservations Service Reservation
(a)(b)(c)(d)(e)(f)
(g)
(f)(f)(f)
1 January 11,847 407 158 405
2 February 781 577 729 158 323
3 March 11,341 869 824 158 490
4 Total for Quarter 34,22,293 960 474 218
5 April 10,80.737 450 158 457
6 May 11,99C 018 627 3,460 886
7 June 14,897 279 098 879
8 Total for Quarter 36,94~652 356 10,716 222
9 July 16,291 20 937 1,424 261 668
August 15,15!540 217 261 141
September 14,05 871 204 261 715
Total for Quarter 45,501 25,348 845 12,783 524
October 769 034 3,730 372
November 13,17:1 974 328 610 260
December 13,65. P 325 358 610 358
Total for Quarter M.7 23,068 720 10,950 990
Total for Year to 156,12 '11;!J61
.....,
7;~5!!
FERC FORM NO.1/3-Q (NEW. 07-04)Page 400
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
IFERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 401a)
Name of Respondent
PacifiCorp
This ~ort Is:(1) ~An Original
(2) A Resubmission
ELECTRIC ENERGY ACCOU T
Date of Report
(Mo, Da, Yr)
03/20/2006
Year/Period of Report
End of 2005lQ4
Line
No.
Item
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
(a)
1 SOURCES OF ENERGY
2 Generation (Excluding Station Use):
3 Steam
4 Nuclear
5 Hydro-Conventional
6 Hydro-Pumped Storage
7 Other
8 Less Energy for Pumping
9 Net Generation (Enter Total of lines 3
through 8)
10 Purchases
11 Power Exchanges:
12 Received
13 Delivered
14 Net Exchanges (Line 12 minus line 13)
15 Transmission For Other (Wheeling)
16 Received
17 Delivered
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
FERC FORM NO.1 (ED. 12-90)
MegaWatt Hours
(b)
45,448 522
273,
690
Page 401a
Line
No.
Item
(a)
21 DISPOSITION OF ENERGY
22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
23 Requirements Sales for Resale (See
instruction 4, page 311.
24 Non-Requirements Sales for Resale (See
instruction 4, page 311.
25 Energy Furnished Without Charge
26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
27 Total Energy Losses
28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
MegaWatt Hours
(b)
646,202
208 189
13,066 252
101 402
967,074
66,989,119
Name of Respondent
PacifiCorp
is ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 03/20/2006
MONTHLY PEAKS AND OUTPUT
(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 on line 2 by month the system s output in Megawatt hours for each month.
(3) Report on line 3 by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
(4) Report on line 4 by month the system s monthly maximum megawatt load (60 minute integration) associated with the system.
(5) Report on lines 5 and 6 the specified information for each monthly peak load reported on line 4.
Year/Period of Report
End of 2005/04
NAME OF SYSTEM:PacifiCorp
Line Monthly Non-Requirments MONTHLY PEAKSales for Resale &No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(f)
29 January 865 427 102 842 864 1800 PST
30 February 118 152 963,223 599 0800 PST
31 March 468 522 198,348 916 0800 PST
32 April 008,514 946,761 740 0900 PST
33 May 095,533 938 014 988 1600 PDT
34 June 503 468 177,502 862 1500 PDT
35 July 341 922 213,327 937 1700 PDT
36 August 160,167 210,569 540 1600 PDT
37 September 351,171 128,135 871 1700 PDT
38 October 427 715 164,811 769 0800 PST
39 November 610,760 009,300 019 1800 PST
40 December 037 768 013,420 438 1800PST
TOTAL 66,989,119 13,066,252
FERC FORM NO.1 (ED. 12-90)Page 401b
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/Q4(2)0 A Resubmission 03/20/2006 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint 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 Met.7. Quantities offuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
~ ; "
No.Name: Carbon Name: ChhllEl '
(a)(b)
ox-Xo
t....)
Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam
Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor Boiler Full Outdoor
Year Originally Constructed 1954 1981
Year Last Unit was Installed 1957 1981
Total Installed Cap (Max Gen Name Plate Ratings-MW)188.414.
Net Peak Demand on Plant - MW (60 minutes)179 379
Plant Hours Connected to Load 8748 8532
Net Continuous Plant Capability (Megawatts)
When Not Limited by Condenser Water 172 380
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 1349858000 2969570000
Cost of Plant: Land and Land Rights 956546 1231557
Structures and Improvements 11774653 46262619
Equipment Costs 77794118 326258635
Asset Retirement Costs
Total Cost 90525317 373752811
Cost per KW of Installed Capacity (line 17/5) Including 479.9858 902.7846
Production Expenses: Oper, Supv, & Engr 109279 1552034
Fuel 12068189 51540497
Coolants and Water (Nuclear Plants Only)
Steam Expenses 1408446 2328660
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 1821392 1109015
Mise Steam (or Nuclear) Power Expenses 2523227 1639630
Rents 13981 12350
Allowances
Maintenance Supervision and Engineering 2511621
Maintenance of Structures 253701 718582
Maintenance of Boiler (or reactor) Plant 2461483 2765009
Maintenance of Electric Plant 415668 721933
Maintenance of Misc Steam (or Nuclear) Plant 284482 1932396
Total Production Expenses 21359848 66807027
Expenses per Net KWh 0158 0225
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Composite Coal Oil Composite
Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)Tons Barrels Tons Barrels
Quantity (Units) of Fuel Bumed 673090 3415 1633731 1929
Avg Heat Cant - Fuel Burned (btu/indicate if nuclear)11514 140000 9826 136542
Avg Cost of Fuel/unit, as Delvd f.b. during year 17.159 74.408 000 31.216 60.296 000
Average Cost of Fuel per Unit Burned 17 .552 000 000 31.477 000 000
Average Cost of Fuel Burned per Million BTU 762 12.655 0.778 602 10.514 605
Average Cost of Fuel Bumed per KWh Net Gen 009 000 009 017 000 017
Average BTU per KWh Net Generation 11482.403 14.876 11497.279 10811.694 725 10815.419
FERC FORM NO.1 (REV. 12"()3)Page 402
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/Q4(2)0 A Resubmission 03/20/2006 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, 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.
Plant Plant Plant Line
Name:;'ic.'Name:
: . ", :,:'" ': : ",
Name:Dave Johnston No.
' ''...
(f)
~""
;c.
,;,:' ', ", '::;'
Steam Steam Steam
Conventional Outdoor Boiler Semi-Outdoor
1984 1979 1959
1986 1980 1972
155.172.816.
154 166 773
8756 8760 8760
148 165 762
193
1180949000 1378673000 5684004000
1291224 137086 10451083
56504294 35360471 48654284
150036067 127281549 365322401
57752 6172882
207889337 162779106 430600650
1336.0497 945.8402 527.1800
22027 247504 625305
8442685 14896313 38577929
762645 1002536
41175 363129
1608481 1734203 12470872
9079 7435 163410
223619 440200
271660 224637 2069773
1802301 1785341 1 0677930
11427 513105 7040108
250474 405835 1114040
13422719 21620238 72739367
0114 0157 0128
Coal Oil Composite Coal Oil Gas Coal Oil Composite
Tons Barrels Tons Barrels MCF Tons Barrels
755949 1616 684593 1356 3865 3829022 8193
8484 141000 10095 122360 1090 8193 140000
11.008 68.752 000 20.828 65.823 000 938 64.342 000
11.021 000 000 21.583 000 176 937 000 000
650 11.609 658 071 000 607 10.943 614
007 000 007 010 000 007 000 007
10861.554 106 10869.660 10025.538 053 11038.285 476 11046.761
FERC FORM NO.1 (REV. 12-03)Page 403
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) 0 A Resubmission 03/20/2006
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 bumed in a plant furnish only the composite heat rate for all fuels burned.
Name of Respondent
PacifiCorp
Line
No.
Item
Year/Period of Report
End of 2005/Q4
(a)
~~~~:
f'!f1,yQ*!";",!1!f;i ~~~~: tt~'iMr:~
(b)
,.,' ".\'
'1;:
;,
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
2 Type of Constr (Conventional, Outdoor, Boiler, etc)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
6 Net Peak Demand on Plant - MW (60 minutes)
7 Plant Hours Connected to Load
8 Net Continuous Plant Capability (Megawatts)
9 When Not Limited by Condenser Water
10 When Limited by Condenser Water
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - KWh
13 Cost of Plant: Land and Land Rights
14 Structures and Improvements
15 Equipment Costs
16 Asset Retirement Costs
17 Total Cost
18 Cost per KW of Installed Capacity (line 17/5) Including
19 Production Expenses: Oper, Supv, & Engr
20 Fuel
21 Coolants and Water (Nuclear Plants Only)
22 Steam Expenses
23 Steam From Other Sources
24 Steam Transferred (Cr)
25 Electric Expenses
26 Misc Steam (or Nuclear) Power Expenses
27 Rents
28 Allowances
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Boiler (or reactor) Plant
32 Maintenance of Electric Plant
33 Maintenance of Misc Steam (or Nuclear) Plant
34 Total Production Expenses
35 Expenses per Net KWh
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
38 Quantity (Units) of Fuel Burned
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
40 Avg Cost of Fuel/unit, as Delvd to.b. during year
41 Average Cost of Fuel per Unit Burned
42 Average Cost of Fuel Burned per Million BTU
43 Average Cost of Fuel Burned per KWh Net Gen
44 Average BTU per KWh Net Generation
Coal
Tons
327289
10453
22.526
23.130
106
011
10568.884
FERC FORM NO.1 (REV. 12-03)Page 402.
Oil
Barrels
217
132599
89.317
000
16.036
000
866
Steam
Outdoor Boiler
1965
1976
81.
8760
647373000
379735
5458473
60030146
65868354
810.1889
169643
7589607
701324
188842
798487
255900
86470
634876
106504
281276
10812929
0167
Composite Coal
Tons
1370873
11181
000
21.597
966
010
10602.839
000
000
109
011
10570.750
Oil
Barrels
6288
140000
000
000
12.719
000
12.789
Steam
Outdoor Boiler
1978
1978
443.
413
7540
403
2891251000
9632717
61232885
229589360
2044846
302499808
682.8438
24447
30077230
3450122
155974
673841
79365
1374385
8893182
3134671
148964
48012181
0166
Composite
000
000
980
010
10615.628
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmisslon 03/20/2006
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, 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.
Plant
, " "'
Plant
Name: HulJtiirUtJitNoi2,
' "
Name: Hunter Unit No.(d) (e)
Name of Respondent
PacifiCorp
Coal
Tons
959423
11192
000
21.603
965
010
10898.902
Oil
Barrels
1850
140000
000
000
13.868
000
522
.." .' ',-;.
Steam
Outdoor Boiler
1980
1980
285.
263
8113
259
1970448000
9632717
50220853
144590660
2044846
206489076
724.5231
24447
20877150
3356185
155974
2383721
72703
1254382
4624149
766636
170808
28918713
0147
Composite Coal
Tons
1547801
11111
000
21.576
971
010
10167.209
000
000
972
010
10904.423
FERC FORM NO.1 (REV. 12-03)
Year/Period of Report
End of 2005/Q4
Plant
Name: tltJiitef -TctalPlsiJf
(f)
,."" ," .
Oil
Barrels
10747
140000
000
000
13.785
000
18.679
Steam
Outdoor Boiler
1983
1983
495.
467
7933
460
3382957000
10239347
89290155
378114194
2044846
479688542
967.8946
24447
34266820
3579703
155974
1668129
80318
1241582
5530965
1499013
143331
48190282
0142
Composite Coal
Tons
3878097
11156
21.226
21.590
968
010
10494.849
000
000
994
010
10185.888
Page 403.
Oil
Barrels
18885
140000
79.017
000
13.438
000
13.469
, '.,"/
Line
.,,
':' No.
. ':',,'
:S'
Steam
Outdoor Boiler
1978
1983
1223.
1132
8736
1123
226
8244656000
29504781
200743893
752294215
6134537
988677426
808.0731
73341
85221200
10386010
467922
-41751
232386
3870349
19048296
5400320
463103
125121176
0152
Composite
000
000
984
010
10508.318
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/Q4(2) 0 A Resubmission 03/20/2006 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. RepQrt
this page gas-turbine and intemal 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. It net peak demand tor 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 otfuel 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 bumed in a plant furnish only the composite heat rate for all fuels burned.
LIne Item Plant Plant
No.Name: Huntington Name:~~:I):1~~;?:U!';~t~::
:~"~\:
;1t:i1
(a)(b)
Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam
Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor Boiler Semi-Outdoor
Year Originally Constructed 1974 1974
Year Last Unit was Installed 1977 1979
Total Installed Cap (Max Gen Name Plate Ratings-MW)996.1541.
Net Peak Demand on Plant - MW (60 minutes)906 1403
Plant Hours Connected to Load 8287 8760
Net Continuous Plant Capability (Megawatts)
When Not Limited by Condenser Water 895 1413
When Limited by Condenser Water
Average Number of Employees 163 346
Net Generation, Exclusive of Plant Use - KWh 6381332000 9837629000
Cost of Plant: Land and Land Rights 2386782 1161925
Structures and Improvements 99598120 131861354
Equipment Costs 360184190 738241440
Asset Retirement Costs 2412956 9719936
Total Cost 464582048 880984655
Cost per KW of Installed Capacity (line 17/5) Including 466.4478 571.6596
Production Expenses: Oper, Supv, & Engr 26434 16254215
Fuel 65320583 119814412
Coolants and Water (Nuclear Plants Only)
Steam Expenses 8203547 2840141
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses
Misc Steam (or Nuclear) Power Expenses 3178935 19133452
Rents 123100 336870
Allowances
Maintenance Supervision and Engineering 1284420 1289676
Maintenance of Structures 1517616 6271663
Maintenance of Boiler (or reactor) Plant 10968477 25844500
Maintenance of Electric Plant 4205130 9300772
Maintenance of Misc Steam (or Nuclear) Plant 1776487 1789784
Total Production Expenses 96604729 164608581
Expenses per Net KWh 0151 0167
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Composite Coal Oil Composite
Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear -Indicate)Tons Barrels Tons Barrels
Quantity (Units) of Fuel Bumed 2912758 14206 5540933 23611
Avg Heat Cont - Fuel Bumed (btu/indicate if nuclear)11048 140000 9370 140000
Avg Cost of Fuel/unit, as Delvd t.b. during year 20.634 79.894 000 21.001 59.571 000
Average Cost of Fuel per Unit Burned 22.036 000 000 21.370 000 000
Average Cost of Fuel Burned per Million BTU 997 13.588 014 140 10.131 152
Average Cost of Fuel Bumed per KWh Net Gen 010 000 0.010 012 000 012
Average BTU per KWh Net Generation 10085.774 13.090 10098.864 10554.620 14.112 10568.732
FERC FORM NO.1 (REV. 12'()3)Page 402.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/Q4(2)0 A Resubmission 03/20/2006 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, 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.
Plant Plant Plant Line
Name: Naughton Name:
...,
Name:Gadsby Steam Plant No.
(d)
,,-
(f)
"'" .."-"",),,
Steam Steam Steam
Outdoor Boiler Conventional Outdoor
1963 1978 1951
1971 1978 1955
707.289.257.
705 276 210
8760 8162 431
700 268 235
145
5238417000 2143956000 32595000
1243566 210526 1259170
59637601 48477838 13837867
293937795 250322392 56204446
4406322
359225284 299010756 71301483
507.9543 1032.1393 276.7915
196891 1084609 62823
60584487 16221252 875554
7045921 9215
36922
5128462 3143743 2322003
38817 40844 3049
1368892
766762 344015 197205
7633839 3904036 398385
1240636 1217400 639435
284518 430067 407436
84248513 26385966 4909007
0161 0123 1506
Coal Gas Composite Coal Oil Composite Gas
Tons MCF Tons Barrels MCF
2720534 97562 1555380 6318 358806
10018 1052 7981 140000 1053
22.484 000 000 10.152 55.647 000 000 000 000
22.307 058 000 10.203 000 000 440 000 000
111 006 109 639 464 652 318 000 000
012 000 012 007 000 007 027 000 000
10405.993 19.593 10425.585 11579.980 17.328 11597.308 11590.336 000 000
FERC FORM NO.1 (REV. 12-03)Page 403.
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/Q4(2)0 A Resubmission 03/20/2006 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and Internal combustion plants of 10,000 Kw or more, and 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 offuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name: Little Mountain Name::,~~)i;
(a)(b)(c)
,/", .
,.+i
Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine Combined Cycle
Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor Boiler Outdoor
Year Originally Constructed 1972 1996
Year Last Unit was Installed 1972 1996
Total Installed Cap (Max Gen Name Plate Ratings-MW)16,279.
Net Peak Demand on Plant - MW (60 minutes)245
Plant Hours Connected to Load 7031 8568
Net Continuous Plant Capability (Megawatts)
When Not Limited by Condenser Water 237
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 94667000 1857143000
Cost of Plant: Land and Land Rights 635 842245
Structures and Improvements 208871 12474622
Equipment Costs 4687536 149739853
Asset Retirement Costs 492532
Total Cost 4897042 163549252
Cost per KW of Installed Capacity (line 17/5) Including 306.0651 584,9401
Production Expenses: Oper, Supv, & Engr
Fuel 3753218 49607000
Coolants and Water (Nuclear Plants Only)
Steam Expenses
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 710662 4875058
Misc Steam (or Nuclear) Power Expenses
Rents 961
Allowances
Maintenance Supervision and Engineering
Maintenance of Structures
Maintenance of Boiler (or reactor) Plant
Maintenance of Electric Plant
Maintenance of Misc Steam (or Nuclear) Plant 66653
Total Production Expenses 2974942 54482058
Expenses per Net KWh 0314 0293
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas Gas
Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear -indicate)MCF MCF
Quantity (Units) of Fuel Bumed 1516478 13141499
Avg Heat Cont - Fuel Burned (btulindicate if nuclear)1060 1021
Avg Cost of Fuel/unit, as Delvd to.b. during year 000 000 000 000 000 000
Average Cost of Fuel per Unit Bumed 475 000 000 775 000 000
Average Cost of Fuel Bumed per Million BTU 335 000 000 699 000 000
Average Cost of Fuel Burned per KWh Net Gen 040 000 000 027 000 000
Average BTU per KWh Net Generation 16980.225 000 000 7221.857 000 000
FERC FORM NO.1 (REV. 12-03)Page 402.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) 0 A Resubmission 03/20/2006
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, 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.Plant Plant
Name: Blundell Name:
(d)
Name of Respondent
PacifiCorp
Plant
Name: VVesiVslleY'
'" ,
C"",c", c'
" ,
,. (f)
" ", ':/;'
.1"
";'
Steam
Outdoor Boiler
1996
1996
61.
8134
174690000
5733734
28701621
34435355
559.9245
4249
4249
0000
"j""
:Ni", "
Steam - Geothermal
Indoor
1984
1984
26.
8584
184820000
31282815
6206229
33542967
557911
71589922
2742.9089
3344
6169
4211469
1540315
840
124081
225965
105308
38081
6255572
0338
000
000
000
000
000
000
000
000
000
000
FERC FORM NO.1 (REV. 12-D3)
" ..
000
000
000
000
000
Gas
MCF
3518586
1045
000
426
321
025
10694.224
000
000
000
000
000
000
000
000
000
000
000
000
000
000
000
Page 403.
000
0.000
000
000
000
YearlPeriod of Report
End of 2005/Q4
,"'' ,
Line
No.
"0',,
Gas Turbine
Outdoor
2002
2002
217.
202
3346
202
343889000
400164
117358
517522
3849
8536686
2457390
16986014
10376
518726
28766
28537958
0830
000
000
000
000
000
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/Q4(2)0 A Resubmission 03/20/2006 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and 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.
Line Item Plant Plant :"" C'
- '" ,
No.Name: Gadsby Gas Peakers Name:
(a)(b)
., .
'f"
;""
'i'\~
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine Gas Turbine
Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor Outdoor
3 Year Originally Constructed 2002 2005
Year Last Unit was Installed 2002
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)141.292.40
6 Net Peak Demand on Plant - MW (60 minutes)122 292
7 Plant Hours Connected to Load 2512 1946
8 Net Continuous Plant Capability (Megawatts)
9 When Not Limited by Condenser Water 121 284
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 166168000 124119000
Cost of Plant: Land and Land Rights 3362684
SUuctu~s and Improvements 4111865 27748874
Equipment Costs 73721008 124698527
Asset Retirement Costs 262682
Total Cost 77832873 156072767
Cost per KW of Installed Capacity (line 17/5) Including 552.0062 533.7646
Production Expenses: Oper, Supv, & Engr 586268
Fuel 2724847 4346449
Coolants and Water (Nuclear Plants Only)
Steam Expenses
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 1645477 570776
Misc Steam (or Nuclear) Power Expenses
Rents 4876
Allowances
Maintenance Supervision and Engineering
Maintenance of Structures 176063 4833
Maintenance of Boller (or reactor) Plant
Maintenance of Electric Plant 599763 306360
Maintenance of Misc Steam (or Nuclear) Plant 147657 6316
Total Production Expenses 5293807 5825878
Expenses per Net KWh 0319 0469
Fuel: Kind (Coal, Gas, 011, or Nuclear)Gas Gas
Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear -indicate)MCF MCF
Quantity (Units) of Fuel Burned 1823779 1312477
Avg Heat Cont - Fuel Burned (btulindicate if nuclear)1053 1043
Avg Cost of Fuel/unit, as Delvd f.b. during year 000 000 000 000 000 000
Average Cost of Fuel per Unit Bumed 494 000 000 516 000 000
Average Cost of Fuel Burned per Million BTU 419 000 000 371 000 000
Average Cost of Fuel Burned per KWh Net Gen 016 000 000 037 000 000
Average BTU per KWh Net Generation 11556.118 000 000 11029.037 000 000
FERC FORM NO.1 (REV. 12-G3)Page 402.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/Q4(2)0 A Resubmission 03/20/2006 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, 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.
Plant Plant Plant Line
Name:Name:Name:No.
(d)(e)(f)
0000 0000 0000
0000 0000 0000
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 000 000 000
FERC FORM NO.1 (REV. 12-03)Page 403.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
!schedule Page: 402 Line No.Column:
Chona
The Cholla Plant is operated by Arizona Public Service Company. Respondent owns Unit No.4 plus 37.44% of related common
facilities. Data re orted re resents res ondent's share. PacifiCo does not have em 10 ees at the Cholla Plant.
chedule Pa e: 402 Line No.Column: d
Colstrip
The Colstrip Plant is operated by PPL Montana, LLC and is jointly owned. Data reported represents respondent's 10% share of
Colstri Plant Units No.3 and No.4. PacifiCo does not have e 10 ees at the Colstri Plant.
chedule Pa e: 402 Line No.Column:
Craig
The Craig Plant is operated by Tri-State Generation and Transmission Association and is jointly owned. Data reported represents
respondent's 19.28% share of Craig Plant Units No.1 and No.2 and 12.86% of common facilities. PacifiCorp does not have
10 ees at the Crai Plant.
chedule Pa e: 402.Line No.Column:
Hayden
The Hayden Plant is operated by Public Service Company of Colorado and is jointly owned. Data reported represents respondent'
24.5% (45 MW) share of Hayden Unit No. I , 12.6% (33 MW) share of Hayden Unit No. 2 and 17.5% of common facilities.
PacifiCo does not have e 10 ees at the Ha den Plant.
chedule Pa e: 402.Line No.Column:
Hunter Plant Unit No.
Hunter Plant Unit No. I is owned by the respondent and Provo City Corporation with an undivided interest of 93.75% and 6.25%
respectively. Data reported in column (c) represents respondent's share. Costs to operate and maintain this unit are charged to
appropriate FERC accounts. Costs that were billed to minority owners for the operation and maintenance (excluding fuel) of this unit
for calendar ear 2005 was $1.4 million and was rimaril char ed to account 506.
Schedule Pa e: 402.Line No.Column: d
Hunter Plant Unit No.
Hunter Plant Unit No.2 is owned by the respondent, Deseret Power Electric Cooperative and Utah Associated Municipal Power
Systems. Each with an undivided interest of60.31 %25.108% and 14.582% respectively. Data reported in column (d) represents
respondent's share. Costs to operate and maintain this unit are charged to appropriate FERC accounts, costs that were billed to
minority owners for the operation and maintenance (excluding fuel) of this unit for calendar year 2005 was $6.5 million and was
rimaril char ed to account 506.
chedule Pa e: 402.Line No.Column:
Hunter
Hunter Unit No. I is owned by the respondent and Provo City Corporation with an undivided interest of 93.75% and 6.25%
respectively. Hunter Unit No.2 is owned by the respondent, Deseret Power Electric Cooperative and Utah Associated Municipal
Power Systems. Each with an undivided interest of 60.3 1%, 25.108% and 14.582% respectively. Data in column (f) represents
respondent's share. Costs to operate and maintain this plant are charged to appropriate FERC accounts, costs that were billed to
minority owners for the operation and maintenance (excluding fuel) of this plant for calendar year 2005 was $7.9 million and was
rimaril char ed to account 506.
Schedule Pa e: 402.Line No.Column:
Jim Bridger
Jim Bridger Plant is operated by PacifiCorp and column (c) represents the respondent's share. Ownership of the plant is as follows:
PacifiCorp 66 2/3%, Idaho Power Company 33 1/3%. Costs to operate and maintain this plant are charged to appropriate FERC
accounts, costs that were billed to minority owners for the operation and maintenance (excluding fuel) of this plant for calendar year
2005 was $27.5 million and was rimaril char ed to account 506.
Schedule Pa e: 402.Line No.Column:
Wyodak
Wyodak: Plant is operated by PacifiCorp and column (e) represents the respondent's share. Ownership of the plant is as follows:
PacifiCorp 80%, Black Hills Corporation 20%. Costs to operate and maintain this plant are charged to appropriate FERC accounts,
costs that were billed to minority owners for the operation and maintenance (excluding fuel) of this plant for calendar year 2005 was
$3.2 million and was rimaril char ed to account 506.
chedule Pa e: 402.Line No.Column:
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 03/20/2006 2005/Q4
FOOTNOTE DATA
Hermiston
The Hermiston Plant is operated by Hermiston Operating Company, LP. and is jointly owned. Data reported on lines 5 through 43
represent's the respondent's 50.0% share of the Hermiston Plant. See Page 326.7 Line 7and 8 of this Fonn No. I for further
information on Hermiston Generatin Co an, LP.
chedule Pa e: 402.Line No.Column:
Camas Co-Gen
PacifiCorp owns the steam turbine generator and associated systems directly related to the operation of this unit at Georgia-Pacific
Corporation s Camas, Washington paper mill. Modifications and upgrades to the existing Camas paper mill were necessary to supply
steam to the turbine and to ensure continued operation of the unit in the event of mill closure. Georgia-Pacific retained ownership of
these modifications. Georgia-Pacific supplies the fuel and delivers the steam to PacifiCorp s turbine. PacifiCorp is responsible for
major maintenance costs only on the repair of the turbine generator and auxiliary equipment. None of the facilities are jointly owned.
Each asset is wholly owned, either by PacifiCorp or Georgia-Pacific Corporation. PacifiCorp does not have employees at the Camas
Paper Mill.
ISchedule Page: 402.Line No.Column:
West Valley
In May 2002, PacifiCorp entered into a 15-year operating lease for an electric generation facility with West Valley Leasing Company,
LLC ("West Valley ). West Valley is a subsidiary ofPPM Energy, Inc. ("PPM"), which is a subsidiary of PHI and an indirect
subsidiary ofScottishPower. The facility consists of five generation units, each rated at 40 megawatts ("MW"), and is located in Utah.
The lease terms granted PacifiCorp two independent early termination options that provide PacifiCorp the right to terminate the lease
and, at PacifiCorp s further option, to purchase the facility for predetermined amounts. On May 28, 2004, PacifiCorp exercised its fITst
option to terminate the West Valley lease. PacifiCorp subsequently exercised its right to rescind the termination on September 28
2004 after determining, through a public process, that the resource could not be replaced on a more economic basis and without
increasing risks to system reliability. PacifiCorp has a second option to terminate the West Valley lease if written notice is provided to
West Valley on or before December 1 2006. PacifiCorp is committed to future minimum lease payments of$15.0 million annually for
ears endin March 31, 2005 throu 2008 and $2.5 million for the ear endin March 31, 2009.
Schedule Pa e: 402.Line No.Column:
Currant Creek
Currant Creek plant phase I is complete and began commercial operations as a simple cycle generating unit in 2005. The units are now
off-line for co letion of Phase n, the combined c cle, which is scheduled to be co lete in 2006.
Schedule Pa e: 402 Line No.42 Column:
The Crai Plant 0 erates on coal with start u rovided b oil and natural
Schedule Pa e: 402 Line No.43 Column:
The Crai Plant 0 erates on coal with start u rovided b oil and natural
Schedule Page: 402 Line No.44 Column:
The Craig Plant operates on coal with start up provided by oil and natural gas. The composite rate is 10 047.527.
osite rate is 1.075.
osite rate is 0.010
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/Q4(2)0 A Resubmission 03/20/2006 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10 000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.2082 FERC Licensed Project No.2082
No.Plant Name: Copco No.Plant Name: Copco No.
(a)(b)(c)
Kind of Plant (Run-of-River or Storage)
Plant Construction type (Conventional or Outdoor)Conventional Conventional
Year Originally Constructed 1918 1925
Year Last Unit was Installed 1922 1925
Total installed cap (Gen name plate Rating in MW)20.27.
Net Peak Demand on Plant-Megawatts (60 minutes)
Plant Hours Connect to Load 356 255
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
(b) Under the Most Adverse Oper Conditions
Average Number of Employees
Net Generation, Exclusive of Plant Use - Kwh 037 000 100,525,000
Cost of Plant
Land and Land Rights 180 375 914
Structures and Improvements 216 025 580,818
Reservoirs, Dams, and Waterways 584 721 898,044
Equipment Costs 627 703 352,405
Roads, Railroads, and Bridges 105 442 240,200
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)714,266 092,381
Cost per KW of Installed Capacity (line 20 / 5)435.7133 336.7549
Production Expenses
Operation Supervision and Engineering 46,769 88,136
Water for Power 330 795
Hydraulic Expenses 266 059
Electric Expenses
Misc Hydraulic Power Generation Expenses 393,422 539 794
Rents 366 901
Maintenance Supervision and Engineering
Maintenance of Structures 487 558
Maintenance of Reservoirs, Dams, and Waterways 911 166,471
Maintenance of Electric Plant 27,926 25,056
Maintenance of Misc Hydraulic Plant 304 28,923
Total Production Expenses (total 23 thru 33)504 049 872,693
Expenses per net KWh 0062 0087
FERC FORM NO.1 (REV. 12-03)Page 406
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 03/20/2006
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Year/Period of Report
End of 2005/Q4
FERC Licensed Project No. 1927
Plant Name:
FERC Licensed Project No. 1927
Plant Name: Cle.rW.f~'2 ,
(e~
FERC Licensed Project No.
Plant Name: Cutler
2420
Outdoor
1953
1953
15.
245
Outdoor
1953
1953
26.
750
1927
1927
30.
832
562 143
412 218
962,137
936,498
329.0999
759 284
035,111
151 380
257 510
11,203,285
430.8956
505 129
751,420
488,103
668,962
566,413
980 027
532.6676
78,308
891
74,025
680
302,851
597
390
20,253
188
135
579,318
0132
109 686
043
129 515
939
474 664
043
746
25,393
13,115
849
862 993
0200
276
995
113,482
657,480
464
570
724
175
196,523
021,137
0109
FERC FORM NO.1 (REV. 12-03)Page 407
Name of Respondent This 'i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/Q4(2) 0 A Resubmission 03/20/2006 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10 000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which Is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.1927 FERC Licensed Project No.
No.Plant Name: Fis~"Cit~"
"""",
Plant Name: '"
(a)(c)
' """,'
1 Kind of Plant (Run-of-River or Storage)Storage
Plant Construction type (Conventional or Outdoor)Outdoor Conventional
Year Originally Constructed 1952 1908
Year Last Unit was Installed 1952 1923
Total installed cap (Gen name plate Rating in MW)11.33.
Net Peak Demand on Plant-Megawatts (60 minutes)
Plant Hours Connect to Load 732 481
8 Net Plant Capability (In megawatts)
(a) Under Most Favorable Oper Conditions
(b) Under the Most Adverse Oper Conditions
Average Number of Employees
Net Generation, Exclusive of Plant Use - Kwh 141 000 852,000
Cost of Plant
Land and Land Rights 50,393
StructUffis and Improvements 562,328 222 357
Reservoirs, Dams, and Waterways 106,806 820,729
Equipment Costs 185 294 716 451
Roads, Railroads, and Bridges 400,007 57,236
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)254,435 867 166
Cost per KW of Installed Capacity (line 20 /5)750.4032 389.9141
Production Expenses
Operation Supervision and Engineering 46,791 147,092
Water for Power 152 194
Hydraulic Expenses 55,490 146,489
Electric Expenses 260
Misc Hydraulic Power Generation Expenses 253,544 085,361
Rents 446 836
Maintenance Supervision and Engineering
Maintenance of Structures 042 20,586
Maintenance of Reservoirs, Dams, and Waterways 19,893 563,042
Maintenance of Electric Plant 18,061 862
Maintenance of Misc Hydraulic Plant 597 127 910
Total Production Expenses (total 23 thru 33)441,276 840,516
Expenses per net KWh 0086 0298
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
PaclfiCorp
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmlssion 03/20/2006
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Year/Period of Report
End of 2005/Q4
FERC Licensed Project No. 2082
Plant Name: Iron Gate
(d)
FERC Licensed Project No. 2082
Plant Name: JC Boyle
(e)
FERC Licensed Project No.
Plant Name:
1927 Line
No.
Outdoor
c, 1962
1962
18.
426
Outdoor
1958
1958
90.
504
Outdoor
1955
1955
31.
7,457
341 706
886 187
031 564
190,106
076 116
525,679
973.6488
984
020,424
591 063
355,657
851 760
873,888
352.7824
740 292
108,579
777 981
407,171
15,034,023
469.9601
63,388
197
039
396,480
260
551 128
306
745
075
103,098
0111
266 218
007
10,236
935 679
469
35,174
127 306
646,488
548
041 777
0091
168 579
651
157 315
569
590,003
269
29,758
674
912
775
201 505
0119
FERC FORM NO.1 (REV. 12-03)Page 407.
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/Q4(2)0 A Resubmission 03/20/2006 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of Installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.1927 FERC Licensed Project No.935
No.Plant Name: Utmolo'ijCii;,,2 Plant Name:
..."
(a)
. "
(bY
' ,
(cl
. '""";.'
Kind of Plant (Run-of-River or Storage)Storage (Re-Reg)
Plant Construction type (Conventional or Outdoor)Outdoor Conventional
Year Originally Constructed 1956 1931
Year Last Unit was Installed 1956 1958
Total installed cap (Gen name plate Rating in MW)33.136.
Net Peak Demand on Plant-Megawatts (60 minutes)148
Plant Hours Connect to Load 555 760
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions 144
(b) Under the Most Adverse Oper Conditions 141
Average Number of Employees
Net Generation, Exclusive of Plant Use - Kwh 130,686,000 406,308,000
Cost of Plant
Land and Land Rights 988,467
Structures and Improvements 691,468 364 532
Reservoirs, Dams, and Waterways 15,611 293 724 817
Equipment Costs 968 771 13,796,408
Roads, Railroads, and Bridges 527 731 793 048
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)19,799,263 53,667,272
Cost per KW of Installed Capacity (line 20 / 5)599.9777 394.6123
Production Expenses
Operation Supervision and Engineering 135,356 877 693
Water for Power 719 043
Hydraulic Expenses 157 731 671 598
Electric Expenses 569
Misc Hydraulic Power Generation Expenses 571,683 250,746
Rents 351 941
Maintenance Supervision and Engineering
Maintenance of Structures 250 52,941
Maintenance of Reservoirs, Dams, and Waterways 55,027 135
Maintenance of Electric Plant 20,146 129,664
Maintenance of Misc Hydraulic Plant 89,788 214 290
Total Production Expenses (total 23 thru 33)073 620 310,051
Expenses per net KWh 0082 0081
FERC FORM NO.1 (REV. 12"()3)Page 406.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 03/20/2006
HYDROELECTRIC GENERATING PLANTSTATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/Q4
FERC Licensed Project No. 1927
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No. 2630
Plant Name: Prospectillo.2 .
Conventional
1949
1950
42.
757
1915
1920
30.
760
Conventional
1928
1928
32.
675
1 ,443,595
390,002
810,396
214,603
858,596
255.4964
36,698
255 294
537 738
635 541
394 262
10,859,533
361.9844
105 168
2,494,274
525,972
995,056
191 385
27,311 855
853.4955
174,923
19,034
203,709
619
714,842
650
023
61,843
19,742
115 898
347,283
0076
134 815
995
130,359
828 655
960
717
583
63,805
94,494
038,833
0268
78,645
128
49,464
483,819
13,946
30,405
84,360
324
021
925,112
0040
FERC FORM NO.1 (REV. 12-03)Page 407.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/Q4(2)0 A Resubmisslon 03120/2006 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10 000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.1927 FERC Licensed Project No.
No.Plant Name: Sljde;oi~"Plant Name:
"'~
:"~i:':'
,""",
(a)
'"
(b)((if
\:r',i ,;r
:(;:
1 Kind of Plant (Run-of-River or Storage)Run-of-River Storage
Plant Construction type (Conventional or Outdoor)Outdoor Conventional
3 Year Originally Constructed 1951 1924
Year Last Unit was Installed 1951 1924
5 Total installed cap (Gen name plate Rating in MW)18.14.
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load 027 285
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
(b) Under the Most Adverse Oper Conditions
Average Number of Employees
Net Generation, Exclusive of Plant Use - Kwh 70,444 000 799 000
Cost of Plant
Land and Land Rights 512 946
Structures and Improvements 544,673 577 230
Reservoirs, Dams, and Waterways 760 975 996 525
Equipment Costs 160,331 072 224
Roads, Railroads, and Bridges 16,778
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)482 757 158 925
Cost per KW of Installed Capacity (line 20 / 5)360.1532 582.7804
Production Expenses
Operation Supervision and Engineering 384 62,913
Water for Power 564 931
Hydraulic Expenses 446 834
Electric Expenses 100
Misc Hydraulic Power Generation Expenses 359,568 398 081
Rents 741 782
Maintenance Supervision and Engineering
Maintenance of Structures 28,406 629
Maintenance of Reservoirs, Dams, and Waterways 032 489
Maintenance of Electric Plant 67,849 188
Maintenance of Misc Hydraulic Plant 882 582
Total Production Expenses (total 23 thru 33)736,972 463,039
Expenses per net KWh 0105 0362
FERC FORM NO.1 (REV. 12-03)Page 406.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 03/20/2006
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/Q4
FERC Licensed Project No. 1927
Plant Name:
FERC Licensed Project No. 2111
Plant Name: SINiftNo.
(e)
FERC Licensed Project No.
Plant Name: Yale
2071 Line
No.
Storage (Re-Reg)
Outdoor
1952
1952
11.
311
Storage
Conventional
1958
1958
240.
220
5,469
Storage
Conventional
1953
1953
134.
166
350
842 310
370,177
137,356
56,124
405,967
764.1788
813 808
118 406
633 791
15,641 995
395 145
67,603,145
281.6798
777 170
069,628
26,160,156
585,956
383 555
976,465
380.4214
56,883
152
55,490
260
250,160
28,906
59,081
276
824
541,068
0129
588,925
074
1 ,290 809
594 882
62,316
624
888
155,211
364 309
099,038
0096
863 690
910
661 721
954 357
576
671
565
44,408
206,831
806 729
0070
FERC FORM NO.1 (REV. 12-03)Page 407.
Name of Respondent This 'i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/Q4(2)0 A Resubmlssion 03/20/2006 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.FERC Licensed Project No.
No.Plant Name: Obnsti:la'Plant Name:
(a)(b)(c)
,yP,
, ',.."
Kind of Plant (Run-of-River or Storage)Run-of-River
Plant Construction type (Conventional or Outdoor)Conventional
Year Originally Constructed 1904
Year Last Unit was Installed 1922
Total installed cap (Gen name plate Rating in MW)10.
Net Peak Demand on Plant-Megawatts (60 minutes)
Plant Hours Connect to Load 877
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
(b) Under the Most Adverse Oper Conditions
Average Number of Employees
Net Generation, Exclusive of Plant Use - Kwh 29,112,000
Cost of Plant
Land and Land Rights 672
Structures and Improvements 263 915
Reservoirs, Dams, and Waterways 524 049
Equipment Costs 25,452
Roads, Railroads, and Bridges 547
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)819 635
Cost per KW of Installed Capacity (line 20 / 5)79.5762 0000
Production Expenses
Operation Supervision and Engineering 720
Water for Power 685
Hydraulic Expenses 38,962
Electric Expenses
Misc Hydraulic Power Generation Expenses 353,298
Rents 668
Maintenance Supervision and Engineering
Maintenance of Structures 280
Maintenance of Reservoirs, Dams, and Waterways 176
Maintenance of Electric Plant 369
Maintenance of Misc Hydraulic Plant 675
Total Production Expenses (total 23 thru 33)462 393
Expenses per net KWh 0159 0000
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
!Schedule Page: 406 Line No.Column: d
Clearwater No.
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31 2005 was $74 983 855: Lemolo 1 , Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda S rings, Slide Creek and the North Umpqua Common Plant.
chedule Pa e: 406 Line No.Column:
Clearwater No.
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement, which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31, 2005 was $74 983 855: Lemolo 1, Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda S rings, Slide Creek and the North U qua Common Plant.
chedule Pa e: 406 Line No.Column:
Cutler
Costs reported for this plant do not include significant intangible costs due to relicensing, which are recorded in FERC account 302
Franchises and Consents, and are not re orted on this a e. The net book value for relicensin at December 31, 2005 was $1 327 846.
chedule Pa e: 406 Line No.Column:
Copco No.
Ponda e for eakin - stora e, U er Klamath Lake.
chedule Pa e: 406 Line No.Column:
Copco No.
Stora e, U er Klamath Lake.
Schedule Pa e: 406 Line No.Column: d
Clearwater No.
orebay for peaking.
~chedule Page: 406 Line No.Column:
Clearwater No.
Foreba for eakin .
chedule Pa e: 406.Line No.Column:
Fish Creek
Costs reported for this plant do not include significant intangible costs due to relicensing, and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31 2005 was $74 983 855: Lemolo 1, Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda S rin s, Slide Creek and the North U ua Common Plant.
Schedule Pa e: 406.Line No.Column:
Grace
Costs reported for this plant do not include significant intangible costs due to relicensing, and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
Bear River s stem for the followin ro ects at December 31 2005 was $16 213 196: Grace, Cove, Oneida and Soda.
Schedule Pa e: 406.Line No.Column:
Lemolo No.
Costs reported for this plant do not include significant intangible costs due to relicensing, and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31 2005 was $74 983 855: Lemolo 1, Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda S rin s, Slide Creek and the North U ua Common Plant.
Schedule Page: 406.Line No.Column:
Fish Creek
Foreba for eakin.
chedule Pa e: 406.Line No.Column: d
Iron Gate
Stora e for re ation.
Schedule Pa e: 406.Line No.Column:
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
JC Boyle
Ponda e for eakin - stora e, U er Klamath Lake.
chedule Pa e: 406.Line No.Column:
Lemolo No.
Stora e, Lemolo Lake.
Schedule Pa e: 406.Line No.Column: b
Lemolo No.
Costs reported for this plant do not include significant intangible costs due to relicensing, and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31 2005 was $74 983,855: Lemolo 1, Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda S rin s, Slide Creek and the North U ua Common Plant.
Schedule Pa e: 406.Line No.Column:
Merwin
Costs reported for this plant do not include significant intangible costs due to relicensing, which are recorded in FERC account 302
Franchises and Consents, and are not re orted on this a e. The net book value for relicensin at December 31 , 2005 was $74 062.
Schedule Pa e: 406.Line No.Column: d
Toketee
Costs reported for this plant do not include significant intangible costs due to relicensing, and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31 , 2005 was $74 983 855: Lemolo 1, Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda S rin s, Slide Creek and the North U ua Common Plant.
chedule Pa e: 406.Line No.Column:
Oneida
Costs reported for this plant do not include significant intangible costs due to relicensing, and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
Bear River system for the following rojects at December 31, 2005 was $16 213 196: Grace, Cove, Oneida and Soda.
chedule Pa e: 406.Line No.Column:
Prospect No.
Costs reported for this plant do not include significant intangible costs due to relicensing, which are recorded in FERC account 302
Franchises and Consents, and are not reported on this page. The net book value for relicensing at Prospect unit numbers 1 , 2, 3 & 4 at
ecember 31 2005 was $127 482.
\Schedule Page: 406.Line No.Column: b
Lemolo No.
StOIa e, Lemolo Lake.
chedule Pa e: 406.Line No.Column: d
Toketee
Ponda e for eakin - stora e, Lemolo Lake.
chedule Pa e: 406.Line No.Column:
Prospect No.
Forebay for peaking.
ISchedule Page: 406.Line No.Column: b
Slide Creek
Costs reported for this plant do not include significant intangible costs due to relicensing, and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31 , 2005 was $74 983 855: Lemolo 1, Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Ump ua Common Plant.
chedule Pa e: 406.Line No.Column:
Soda
Costs reported for this plant do not include significant intangible costs due to relicensing, and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
Bear River s stem for the followin ro ects at December 31 2005 was $16,213,196: Grace, Cove, Oneida and Soda.
chedule Pa e: 406.Line No.Column: d
Soda Springs
IFERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
Costs reported for this plant do not include significant intangible costs due to relicensing, and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31 , 2005 was $74 983 855: Lemolo 1, Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda S rin s, Slide Creek and the North U ua Common Plant.
chedule Pa e: 406.Line No.Column:
Swift No.
Costs reported for this plant do not include significant intangible costs due to relicensing, which are recorded in FERC account 302
Franchises and Consents, and are not r orted on this a e. The net book value for relicensin at December 31 , 2005 was $10 391.
chedule Pa e: 406.Line No.Column: b
Olmstead
The Olmstead Plant is owned by the U.S. Bureau of Land Reclamation. PacifiCorp has a 25-year lease beginning in 1990. The
respondent operates the plant and owns the generation.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) 0 A Resubmission 03/20/2006
G NERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating).2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project
give project number in footnote.
Line Year 1!1Stall~C! l,;a~ac!!'y'~et ...ea~Net GenerationName of Plant Orig.Name Plate atin!Demand Excluding Cost of Plant
No.Const.(In MW)(6~a1n.Plant Use
...
(b)(c)(e)(f)
..;:;(,
1907
.;,
3 Ashton 2381 1917 673
4 Upper Beaver 814 1907 240,000 2,518.381
5 Bend 1913 849,000
6 Big Fork 2652 1910 30,861 000
7 Cline Falls 1943 149 000 302 594
1913 15.57,727,000
1917
!--
Eagle POint 1957 16,337 000 789 838
Eastside 2082 1924 782,000 889,283
Fall Creek 2082 1903 047,000 051 552
Fountain Green 1922 828 000 451 779
Granite 1896 035 000 543,517
Gunlock 1917 76,000 596,774
Last Chance 1983 062,000 677,981
Paris 1910 756 000 316,900
Pioneer 2722 1897 33,533,000
1923 387 000
Prospect No.2630 1912 513,000
Prospect No.2337 1932 31,467 000
Prospect No.2630 1944 777 000
Sand Cove 1926 048,000 858,802
Snake Creek 1910 1.1 796,
Stairs 597 1895 877 000
1915 5,000 330 359
Veyo 1920 536 000 731 646
Viva Naughton 1986 806,000 198,053
Wallowa Falls 308 1921 936 000 761 244
Weber 1744 1911 18,545,000
_?.'
West Side 2082 1908 108,000 351,560~_Ihl! 7,473,802
978 797
,..
Pumping Plant:
Lifton 1917 539 000 758,367
Wind Turbine:
1998 32.33.1 04,394,000 36,266,842
FERC FORM NO.1 (REV. 12-03)Page 410
Name of Respondent This ooort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11
Page 403.4. If net peak demand for 60 minutes is not available, give the which is available, specifying period.5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air In a boiler, report as one plant.
Plant Cost (Ine! Asset Operation Production Expenses Fuel Costs (in cents LineRetire. Costs) Per MW Exc l. Fuel Fuel Maintenance Kind of Fuel (per Million Btu)
(g)
(h)(i)(k)(I)No.
152 784 25,404 541 Water
279,683 668 082 111 020 Water
999 358 135,662 160 Water
774 359 109,143 734 Water
515,946 277 789 274,234 Water
302,594 39,871 146 Water
717 313 177,346 39,825 Water
372,686 168,379 28,379 Water
636 953 378,668 875 Water
590 401 713 698 Water
477 978 429 46,782 Water
823,619 22,372 758 Water
271 759 108,193 34,386 Water
795,699 55,698 75,875 Water
547 966 115,586 51,843 Water
440,139 36,007 19,390 Water
954 884 206 188 104 571 Water
138 345 243,080 052 Water
148 525 76,881 32,190 Water
948 059 167,181 197,951 Water
201 567 28,905 10,798 Water
073,503 898 10,821 Water
765 014 98,158 045 Water
179,463 376 56,454 Water
660,718 926 047 Water
1 ,463 292 79,224 372 Water
618,991 231 350 Water
510 222 51,237 215 Water
708,062 174,530 47,806 Water
585,933 14,866 40,856 Water
065 327
180,001 927
305,116 427 493 Water
112,480 796,319 Wind
FERC FORM NO.1 (REV. 12-03)Page 411
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
!schedule Page: 410 Line No.Column:
Common river s stem costs for the 0 eration of these facilities are allocated to each
Schedule Pa e: 410 Line No.Column:
American Fork hydroelectric project - (American Fork River, Utah)
The FERC issued a surrender order for American Fork on August 4, 2004, which calls for project removal to be completed by
December 2007. Removal costs for this 1.0 MW project are estimated to be approximately $1.2 million, including process and
pennitting costs (adjusted for inflation). The parties have agreed that project removal will begin in September 2006, subject to the
FERC and other re ato a rovals.
chedule Pa e: 410 Line No.Column:
American Fork
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents, and are not reported on this page. The net book value for relicensing at December 31 2005 was $87 939.
This ,cost of lant balance includes $1 036 326 of American Fork asset retirement costs.
Schedule Pa e: 410 Line No.Column:
Ashton
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents, and are not r orted on this a e. The net book value for relicensin at December 31 , 2005 was $412 809.
Schedule Pa e: 410 Line No.Column:
Big Fork
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents, and are not re orted on this age. The net book value for relicensin at December 31, 2005 was $598 319.
chedule Pa e: 410 Line No.Column:
Condit hydroelectric project - (White Salmon River, Washington)
In September 1999, a settlement agreement to remove the 9.6 MW Condit hydroelectric project was signed by PacifiCorp, state and
federal agencies, and non-governmental agencies. Under the original settlement agreement, removal was expected to begin in October
2006, for a total cost to decommission not to exceed $17.2 million, excluding inflation. In early February 2005, the parties agreed to
modify the settlement agreement so that removal will not begin until October 2008, for a total cost to decommission not to exceed
$20.5 million, excluding inflation. The settlement agreement is contingent upon receiving an amended FERC license and removal
order that is not materially inconsistent with the amended settlement agreement and other regulatory approvals. PacifiCorp is in the
rocess of ac uirin all necess ennits, in accordance with the terms and conditions of the amended settlement a eement.
chedule Pa e: 410 Line No.Column:
Cove
Licensed Project No. 20 was issued December 22 2003. It consolidated Licensed Project No. 2401 applicable to both Cove and
Grace Plants (see page 406 for Grace plant) along with License Project No. 472. The FERC included in the Bear River s license a
requirement to evaluate decommissioning the 7.5 MW Cove plant and associated project features. As part of this evaluation,
PacifiCo has been workin with stakeholders to determine the actions that would be re uired to decommission this lant.
chedule Pa e: 410 Line No.Column:
Cove
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
Bear River s stem for the followin ro ects at December 31, 2005 was $16 213,196: Grace, Cove, Oneida and Soda.
Schedule Pa e: 410 Line No.18 Column:
Pioneer
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents, and are not re orted on this a e. The net book value for relicensin at December 31, 2005 was $137 114.
chedule Pa e: 410 Line No.19 Column:
Powerdale hydroelectric project - (Hood River, Oregon)
In June 2003, PacifiCorp entered into a settlement agreement to remove the 6.0 MW Powerdale plant rather than pursue a new license,
based on an analysis of the costs and benefits ofrelicensing versus decommissioning. Removal of the Powerdale plant and associated
project features, which is subject to the FERC and other regulatory approvals, is projected to cost $5.9 million (adjusted for inflation).
The lant will continue to 0 elate until its removal, which is scheduled to commence in 2010.
chedule Pa e: 410 Line No.19 Column:
IFERC FORM NO.1 (ED. 12-S7) Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
Powerdale
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents, and are not reported on this page. The net book value for relicensing at December 31, 2005 was $2 798 836.
This cost of lant balance includes $4 495 035 of Power dale asset retirement costs.
chedule Pa e: 410 Line No.20 Column:
Prospect No.
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents, and are not reported on this page. The net book value for relicensing at Prospect unit numbers 1 3 & 4 on
December 31 2005 was $127 482.
ISchedule Page: 410 Line No.21 Column:
Prospect No.
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents, and are not reported on this page. The net book value for relicensing at Prospect unit numbers 1, 2, 3 & 4 on
ecember 31 2005 was $127 482.
!Schedule Page: 410 Line No.22 Column:
Prospect No.
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents, and are not reported on this page. The net book value for relicensing at Prospect unit numbers 1 , 2, 3 & 4 on
ecember 31 2005 was $127 482.
!Schedule Page: 410 LIne No.25 Column:
Stairs
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents, and are not reported on this age. The net book value for relicensin at December 31, 2005 was $107 731.
chedule Page: 410 Line No.26 Column:
St. Anthony
Licensed Pro ect No. 2381 a licable to both Ashton and St. Anthon lants.
chedule Pa e: 410 Line No.30 Column:
Weber
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents, and are not r orted on this a e. The net book value for relicensin at December 31, 2005 was $445,036.
chedule Pa e: 410 Line No.32 Column:
Keno Regulating Dam
Used in regulating the release of water ftom Klamath Lake and in maintaining proper water surface level in the Klamath River between
Klamath Falls and Keno, Ore on.
chedule Pa e: 410 Line No.33 Column:
Upper Klamath Lake
Storage reservoir for six plants on the Klamath River (Copco No., Copco No., East Side, West Side, John C. Boyle, and Iron
ate).
!Schedule Page: 410 Line No.34 Column:
North Umpqua
Common lant in North U ua Pro ' ect. All common roads e
chedule Pa e: 410 Line No.34 Column: North Umpqua
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302, Franchises and Consents, and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31, 2005 was $74 983 855: Lemolo 1, Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda Sprin s, Slide Creek and the North U qua Common Plant.
chedule Pa e: 410 Line No.40 Column:
Foote Creek Wind Farm
The Foote Creek Wind Farm is operated by Sea West Energy and is jointly owned. Costs reported for this plant represents the
respondents share. Ownership of the plant is as follows: PacifiCorp 78.79%, Eugene Water and Electric Board 21.21 %.
10 ee houses, control e ui ment etc. are in this account.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This 7!)ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
TRANSMISSION LINE STATIST
1. Report information concerning transmission lines, cost of Ii~es, 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.
.IUN (Indicate w
~~~
LENG~H ~ole Wiles)Line Type of ~Dte serc NumberNo.other than u aergroun lines60 cvcle 3 chase)Supporting report circuit miles)
From Operating Designed I un ~(rl,lcIure l1~u~JWes CircuitsStructureo( Lln 1)0 er
(a)(b)(c)(e)Desl
(Wa ed
Ine(d)
(g)
(h)
1 Malin, Oregon Indian Springs., CA 500.500.Steel Tower 47.
2 Midpoint, Idaho Malin, Oregon 500.500.Steel Tower 446.
3 Malin, Oregon Medford, Oregon 500.500.Steel Tower 84.~Dixonville Sub, Oregon 500.500.Steel Tower 58.5 Malin, Oregon Captain Jack, OR 500.500.Steel Tower
Meridian, OR 500.500.Steel Tower 74.00
8 Subtotal 500 kV 716.
Ben Lomond Sub., Utah Borah Substation, Idaho 345.345.Steel- H 135.
Ben Lomond Sub., Utah Terminal Substation, UT 345.345.Steel- D 47.
Spanish Fork Sub., Utah Camp Williams Sub., Utah 345.345.Steel- SP 35.
Huntington Plant, Utah Sigurd Substation, Utah 345.0!345.Steel- H 95.
Huntington PIt. Sub., UT Spanish Fork Sub., Utah 345.345.Steel - H 78.
Terminal Substation, UT Ninety South Sub., Utah 345.345.Steel- SP 16.
Emery Substation, Utah Sigurd Substation, Utah 345.345.Steel- H 75.
Sigurd Substation, Utah Camp Williams Sub., Utah 345.345.Steel - H-P 116.
Camp Williams Sub., Utah Ninety South Sub., Utah 345.345.Steel - SP
Terminal Substation, UT Camp Williams Sub., Utah 345.345.Steel- D 25.
Emery Substation, Utah Camp Williams Sub., Utah 345.345.Steel- H 121.
Newcastle, Utah Utah - Nevada Border 345.345.Steel-54.
Sigurd Substation, Utah Newcastle, Utah 345.345.Steel- D 137.
Goshen Substation, Idaho Kinport Substation, ID 345.345.Steel- H 41.
Huntington Plant, Utah Four Comers Sub., NM 345.345.Wood - U 101.00
Camp Williams Sub., Utah Huntington Plant, Utah 345.345.Wood-107.
Huntington Plant, Utah Pinto Substation, Utah 345.345.Wood - U 158.
Camp Williams Sub., Utah Sigurd Substation, Utah 345.345.Wood - U 70.
Jim Bridger Plant #3, WY Borah Substation, Idaho 345.345.Steel Tower 240.
Jim Bridger Plant #2, WY Kinport Substation, ID 345.345.Steel Tower 234.
Currant Creek Swtchrd, UT Mona Substation, UT 1.00
Subtotal 345 kV 895.
Fairview, Oregon Isthmus, Oregon 230.230.H Frame Wood 12.
Antelope Sub., Idaho Lost River 230kV Line, ID 230.230.Wood - H 20.
TOTAL 15,586.100.189
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) riA Resubmission 03/20/2006
RANSMISSION LINE STATISTICS ((:Ontinued)
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 sale 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 0) to (I) on the book cost at end of year.
COST OF LINE (InCluae In columnij)l:ana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)
(j)
(k)(I)(m)(n)
(p)
1852 134,35E 551,984 686.340
1272.086,40C 151,358,933 154,445.333
272.907,17!38,009,131 40,916,306
1272.1,468,201 19,656,209 21,124,413
1272.23C 1.460,186 1,469,416
1272.769.43!26.247,891 31.017,326
12,374,801 242,284,334 254,659.134
954.229.35,205,343 40,434,996
1272.0 517,22.112,724 630,556
1272.978,401 10,158,595 16,137,001
954.343,20.080,786 20,423,960
954.791.811 670 321 18,462.132
1272.557,85!457 557 015,412
954.296,57E 13,619,157 13,915 735
954.510,49(19,781,894 20,292,384
1272.483,895,713 378,830
1272.308,391 970,336 12,278,733
954.926 251 27,916,136 28.842,387
954.320,87 50,650,316 52,971 188
954.56,05C 13,573,405 13,629,455
95.313,47 571,824 885,301
954.117 66.893,904 011 566
95.893,96!19,285,878 179,843
95.
;"";;..;,
95.36,14,915,113 951,806
1272.128 26,210 545 338 767
1272.099,79!28.002.095 101 891
703 718 703.718
36,910,301 344,675,360 381.585,661
1954.285.610,635 895,957
1795.92!200,282 213,211
79,910.835 503.666,522 583,577,357
FERC FORM NO.1 (ED. 12-87)Page 423
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) Ei A Resubmission 03/20/2006
TRANSMISSION LINE STATIST
1. Report information concerning transmission lines, cost of lir:tes, 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 (9) 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.
(Indicate w
~~~
LENGJ.H ~ole WileS)
Line Type of ~ID t e scf 0 NumberNo.other than u aergroun lines
60 cvcle 3 ohase\Supporting report circuit miles)
From Operating Designed un ~tfl,Jcture f~~1P/es CircuitsStructure. LIn no er
(a)(b)(c)Desl
cwa ed
Ine(d)(e)
(g)
(h)
1 Walla Walla, Washington Hells Canyon, ID 230.230.H Frame Wood 78.
2 Bethel, Oregon Fry, Oregon 230.230.H Frame Wood 26.
3 Fry, Oregon Dixonville, Oregon 230.230.H Frame Wood 45.
4 Alvey, Oregon Dixonville, Oregon 230.230.H Frame Wood 59.
5 Troutdale, Oregon Linneman, Oregon 230.230.Steel Tower
6 Troutdale, Oregon Gresham, Oregon 230.230.Steel Tower
7 McNary, Washington Walla Walla, Washington 230.230.H Frame Wood 56.
8 BPA Heppner, Oregon Dalred Substation, Orego 230.230.H Frame Wood 1.00
9 Sigurd Substation, Utah Garfield, Utah 23G.O(230.Wood - U 117.
Dixonville, Oregon Reston, Oregon 230.230.H Frame Wood 17.. 1
Yamsey, Oregon Klamath Falls, Oregon 230.230.H Frame Wood 56.
Yamsey, Oregon Klamath Falls, Oregon 230.230.Steel Tower
Dixonville, Oregon Lone Pine, Oregon 230.230.H Frame Wood
Klamath Falls, Oregon Medford, Oregon 230.230.H Frame Wood 76.
Klamath Falls, Oregon Malin, Oregon 23G.O(230.H Frame Wood 35.
Table Rock, SW Station, OR Grants Pass, Oregon 230.230.H Frame Wood 35.
Grants Pass, Oregon Days Creek, Oregon 230.230.H Frame Wood 71.
Dixonville, Oregon Dixonville, Oregon 230.230.Wood
Sigurd Substation, Utah Pavant Substation, Utah 230.230.Wood - U 43.
Pavant Substation, Utah Nevada - Utah State line 230.230.Wood. U 98.
Bannock Pass, Idaho Antelope Sub., Idaho 230.230.Wood-76.
Brady Substation, Idaho Treasureton Sub., Idaho 230.230.Wood - U 66.
Ben Lomond Sub., Utah Naughton PIt. #1 , WY 230.230.Wood-88.
Sigurd Substation, Utah Arizona - Utah State line 230.230.Wood-149.
Birch Creek Sub., WY Railroad Substation, WY 230.230.Wood - HSW 12.
Birch Creek Sub., WY Railroad Substation, WY 230.230.Wood - HSW
Ben Lomond Sub., Utah Naughton PIt. #2, WY 230.230.Wood-59.
Ben Lomond Sub., Utah Naughton PIt. #2, WY 230.230.Wood-29.
Chappel Creek, WY Naughton Plant, WY 230.230.Wood Tower 46.
Ben Lomond Sub., Utah Terminal Substation, UT 230.230.Steel- D-74.
Naughton Plant, Wyoming Treasureton Sub., Idaho 230.230.Wood-79.
Naughton Plant, Wyoming Treasureton Sub., Idaho 230.230.Wood-1.00
Swift Plant #1, WA Cowlitz Co. Line, WA 23G.O(230.H Frame Wood
Swift Plant #2, WA BPA Woodland, WA 230.230.H Frame Wood 23.
Union Gap, Washington BPA Midway, WA 230.230.H Frame Wood 39.
TOTAL 15,586.100.189
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
RANSMISSION LINE STATISTICS (( ontinued)
7. Do not report the same transmission line structure twice. ~eport 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 OJ to (I) on the book cost at end of year.
I"V~ I VI'" LINe (tncluae 10 GOlumn OJ Lana EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)(k)(I)(m)(n)
(p)
1272.64,39~10,166,490 10,230,884
1272.351,98 305,456 657,438
1272.485,891 305,485 791 381
54.1,428,14,540,219 15,968,466
54.423,037 423,037
54 .363,574,074 937,791
1272.220,279,512 500,479
95.108,274 108 274
95.390,87f 651,768 042 646
39,971 558,410 598,381
95.
95.473,36€182,655 656,021
95.439,323,401 762,964
95.173,6DE 996,920 170,528
1272.115,44!734,488 849,936
954.191.12 194,926 386,050
1272.379,961 11,725,824 12,105,785
1272.492,100 492,100
95.41,499 372,021 4,413,520
795.
1272.10.2,439,598 444,701
795.72.111 002,140 074,258
1795.426,12€518,653 944,779
~54.22,511,257 533,900
~54.165,051 277,573 1,442,627
~54.181,520,220 701,267
1272.736,03!228,273 964,303
1272.721 522 721,522
54.170,961 900,151 071,118
1272.572,459 10,170,327 10,742,786
54.56,49f 967,418 023,916
54.565 27,749 28,318
54.296,496 297,789
54.103,53.153,518 257,050
1272.172,451 684,681 857,132
79,910,835 503,666,522 583,577,357
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) 0 A Resubmission 03/20/2006
TRANSMISSION LINE STATIST
1. Report information concerning transmission lines, cost of lil)es, 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.
~~Jrd~~~~~~NG~H ~ole WileS)Line IIUI'i Type of
hlJte scfa NumberNo.other than u dergroun lines
60 cvcle 3 ohase)Supporting report circuit miles)
From Operating Designed I un~tfl,lclure u~f~u~JWes CircuitsStructureof LIn 1)0 er
(a)(b)(c)(e)Desl
fWa ed
Ine(d)
(g)
(h)
1 Walla Walla, Washington Lewiston, ID 230.230.H Frame Wood 45.
2 Walla Walla, Washington Wanapum, Washington 230.230.H Frame Wood 33.
3 Pomona, Washington Wanapum, Washington 230.230.H Frame Wood 37.
4 Centralia, Washington BPA Tap, Washington 230.230.H Frame Wood
5 Pomona, Washington Wanapum, Washington 23o.o!230.H Frame Wood
6 Meridian Sub, OR Lone Pine Sub, OR 230.230.
7 Billings, Montana Yellowtail, Montana 230.230.H Frame Wood 59.
8 Yellowtail, Montana Muddy Ridge, Wyoming 230.230.H Frame Wood 176.
9 Sheridan, Wyoming Decker, Montana 230.230.H Frame Wood 13.
Dave Johnston Plant, WY Casper, Wyoming 230.230.H Frame Wood 31.
Yellowtail, Montana Casper, Wyoming 230.230.H Frame Wood 147.
Rock Springs, Wyoming Kemmerer, Wyoming 230.01 230.H Frame Wood 71.00
Rock Springs, Wyoming Atlantic City, Wyoming 23D.O1 230.H Frame Wood 69.
Thermopolis, Wyoming Riverton, Wyoming 230.230.H Frame Wood 51.00
Casper, Wyoming Riverton, Wyoming 230.230.H Frame Wood 110.
Dave Johnston Plant, WY Rock Springs, Wyoming 23o.o!230.H Frame Wood 206.
Dave Johnston Plant, WY Spence, Wyoming 230.230.H Frame Wood 31.
Riverton, Wyoming Atlantic City, Wyoming 230.230.H Frame Wood 50.
Rock Springs, Wyoming Flaming Gorge, Utah 230.230.H Frame Wood 48.
Palisades, Wyoming Green River, Wyoming 230.230.H Frame Wood
Buffalo, Wyoming Gillette, Wyoming 230.230.H Frame Wood 69.
Jim Bridger Plant, WY Point of Rocks, Wyoming 230.230.H Frame Wood
Jim Bridger Plant, WY Point of Rocks, Wyoming 230.230.H Frame Wood
Dave Johnston Plant, WY Yellowcake, Wyoming 230.230.H Frame Wood 69.
Wyodak, WY Sub. Tie Line, WY 230.230.H Frame Wood 1.00
Jim Bridger Plant, WY Point of Rocks Ln 2, WY 23o.o!230.H Frame Wood 35.
Blue Rim, Wyoming South Trona, Wyoming 230.230.H Frame Wood 13.
Monument, Wyoming Exxon Plant, Wyoming 230.230.H Frame Wood 13.
Firehole. Wyoming Mansface, Wyoming 230.230.Steel Pole
Firehole, Wyoming Mansface, Wyoming 230.230.H Frame Wood 10.
Monuments, Wyoming South Trona, Wyoming 230.230.H Frame Wood 24.
Spence Sub., WY Jim Bridger Plant, WY 230.H Frame Wood 47.
Jim Bridger Plant, WY Mustang Sub., Wyoming 230.230.H Frame Wood 73.
Spence Sub., Wyoming Mustang Sub., Wyoming 230.230.H Frame Wood 77.
Rock Springs, Wyoming Flaming Gorge, Utah 230.230.Steel Tower
TOTAL 15,566.100.189
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) D A Resubmission 03/20/2006
RANSMISSION LINE STATISTICS (C ontinued)
7. Do not report the same transmission line structure twice. ~eport Lower voltage Lines and higher voltage lines as one line. Designate in a Jpotnote 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 sale 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 0) to (I) on the book cost at end of year.
l;U::i I UI- LIN~ (InClUde 10 Column U) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)(k)(I)(m)(n)
(p)
1272.366,29C 060,478 6,426,768
954.235,53.243,720 2,479,252
1780.207,664,144 871,267
954.33,88E 165,771 199,656
556.165 514,151 514,320
003,740 003,740
1272.32,99!553,431 586,429
1272.120,945 791,581 912,530
1272.0 26,09.630,118 656,211
~95.14,921 104,994 119,922
1271.0 130,203,061 333,258
1271.52,901 890,363 943,269
54.855 690,125 721,984
1272.11.066,262 123,374
54.592,617 660,474
1272.58,669,930 728,032
1272 33,oo!658,898 691 906
1271.48,281 517 846 566 127
1272.30,76~587,485 618,254
1272.0 681 368 681,380
1272.361,351 282 476 643,827
1272.0 80(140,312 145,112
1272.0 130,166 130,166
1272.294,290 158,106 6,452,396
1272.15,463 15,463
1272.528,467 532,434
1272.872,981 872,981
1272.160,129 160,129
1272.
,;"/,
"\U'
"",
1272.674,008 674,008
1272.726,304 726,304
1272.170,295 170,295
1272.760,523 760,523
1272.542,996 542,996
1272.4,48 746,631 751,113
79,910,835 503,666,522 583,577,357
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
TRANSMISSION LINE STATIST
1. Report information concerning transmission lines, cost of lil)es. 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.
vnl TA~F J~~~G;hH ~ole wiles)Line Type of(Indicate wliere 11:1 t 5J! D NumberNo.other than u aergroun lines
60 cvcle 3 chase)Supporting report circuit miles)
From Operating Designed un ~tfl,lCture I u~f'7~1f,~res CircuitsStructure. Lln 1)0 er
(a)(b)(c)(e)Desl
fWa ed(d)
(g)
(h)
1 Line 59, CA Copco II, CA 230.230.H Frame Wood
2 Arizona/Utah State Line Glen Canyon Sub., Arizona 230.230.H Frame Wood 10.
3 Miners Sub., Wyoming Foote Creek Sub., Wyoming 230.230.29.
4 Monument Sub., Wyoming Craven Creek Sub., Wyoming 20.
5 Point of Rocks Sub., WY Rock Springs, Wyoming 27.
7 Subtotal 230 kV 358.
9 Montana-Idaho State line Grace Plant, Idaho 161.0 161.00 Wood - H 57.90.
Goshen Substation, Idaho Rigby Substation, Idaho 161.0 161.Wood - H 61.
Goshen Substation, Idaho Antelope Substation, ID 161.0 161.Wood-45.
Goshen Substation, Idaho Sugar Mill Substation, ID 161.0 161.00 Wood - SP 17.
Sugar Mill Sub., Idaho Rigby Substation, Idaho 161.01 161.00 Wood - SP 17.
Goshen Substation, Idaho Bonneville Sub., Idaho 161.01 161.00 Wood - SP-20.
Billings, Montana Yellowtail, Montana 161.01 161.H Frame Wood 46.
Big Grassy Sub., ID Idaho Power Line, ID 161.161.00 Wood - H 1.00
Rigby Sub., Idaho Jefferson Roberts, Idaho 161.161.00 Wood - SP 18.
Thermopolis, Wyoming Wapa Tie Line #2, Wyoming 161.0 161.1.00
Subtotal 161 kV 283.90.
Naughton Plant, Wyoming Evanston Substation, WY 138.0 138.Wood - H 67.
Evanston Substation, WY Anschutz Substation, WY 138.0 138.Wood - H
Evanston Substation, WY Anschutz Substation, WY 138.138.Wood-15.
Naughton Plant, Wyoming Carter Creek Sub., WY 138.0 138.Wood - H 36.
Railroad Sub., Wyoming Carter Creek Sub., WY 138.138.Wood-17.
Painter Substation, WY Natural Gas Sub., WY 138.138.Wood - H
Grace Plant, Idaho Termnl. Sub., UT (103-104)138.138.Steel- S 42.
Grace Point, ID Termnl. Sub., UT (103-104)138.0!138.Wood - H 212.
Grace Plant, Idaho Terminal Sub., UT (105)138.0!138.Wood-144.
Grace Plant, Idaho Soda Plant, Idaho 138.138.Wood-
Oneida Plant, Idaho Ovid Substation, Idaho 138.138.Wood - H 23.
Antelope Substation, ID Scoville Sub., Idaho 138.0 138.Wood - H 1.00
Soda Plant, Idaho Monsanto Sub., Idaho 138.0 138.Wood - H
Caribou Substation, ID Grace Plant, Idaho 138.138.Wood-16.
TOTAL 15,586.100.189
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
RANSMISSION LINE STATISTICS (C ontinued)
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 sale 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 OJ to (I) on the book cost at end of year.
COST 'IF LINE (InClude In Column 0) Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)(k)(I)(m)(n)
(p)
335 820,071 824,410
451,363 451,363
968,612 968,612
548,527 548,527
939,085 939,085
10,366.061 249.092.151 259,458.212
97.18,97E 276.226 295,204
97.52C 707,397 734,917
97.2,407,191 2.416,048
97.48.1,456.877 505.104
;,97.27,536 207,650 235,186
954.362,27~811,683 173,962
556.23,36€433,011 1,456,379
556.26,208 26,208
556.76.30€242.793 319,099
12,306 12,306
593.071 12,581,342 13,174,413
95.146,64'036,747 183,392
95.129,13C 480,663 609 793
95.381 290,803 294,184
795.41.411 577,595 619,006
95.72,822 615 895,237
95.12,42 278 836 291,260
1795.765.181 11,900,965 12,666,151
1795.
.."'!.
~50.132.96C 14,178,784 311 744
1795.29C 157,293 160.583
~36.811 485,928 490,745
~97.14€390 538
~97.55E 269,091 271.646
1795.18,28~421,186 439,470
79,910,835 503.666,522 583,577,357
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PaclflCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) Ei A Resubmission 03/20/2006
TRANSMISSION LINE STATIST
1. Report information concerning transmission lines, cost of lil)es, and expenses for year. List each transmission line having nominal voltage of 13.2
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. Exciude 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.
(Indicate w
~~~
~H ~ole wiles)Line Type of Dte scfo NumberNo.other than u dergroun lines
60 cvcle 3 chase)Supporting report circuit miles)
From Operating Designed un ~l~~ure I unf~u~~~res CircuitsStructure1)0 er
(a)(b)(c)(e)DeSi
tWa
'ed(d)
(g)
(h)
1 Caribou Substation, ID Becker Substation, Idaho 136.136.Wood-
2 Treasureton Sub., ID Franklin Sub., Idaho 138.136.Wood -H &S 10.
3 Franklin Substation, ID Smithfield Sub., Utah 138.138.Wood-25.
4 Midvalley Substation, UT Thirty South Sub., UT 138.138.Wood-1.00
5 Angel Substation, UT Smith's UT 138.138.Wood - H 1.00
6 Terminal Substation, UT Kennecott Sub., Utah 138.138.Steel- S
7 Terminal Substation, UT 30 South Switch Rack, UT 138.138.Steel- S
8 Jordan, UT Terminal Substation, UT 138.138.Wood-
9 Wheelon Substation, Utah American Falls Sub., UT 138.138.Wood-82.
Cutler Plant, UT Wheelon Substation, UT 138.138.Wood-1.00
Terminal Substation, UT Helper Substation, Utah 138.138.Wood - H 121.
Hale Plant, Utah Nebo Substation, Utah 138.138.Wood-54.
Carbon Plant, Utah Helper Substation, Utah 138.138.Wood - H
Terminal Substation, UT Tooele Substation, Utah 138.138.Wood - H 29.
Wheelon Substation, Utah Smithfield Sub., Utah 138.138.Wood - H 20.1.00
Helper Substation, Utah Moab Substation, Utah 138.138.Wood - H 118.
Ninetieth South Sub, Utah Carbon Plant, Utah 138.138.Wood - H 75.
Terminal Substation, UT Ninetieth South Sub, UT 138.138.Wood - H 16.
30 South Switch Rack, UT McClelland Sub., Utah 138.136.Wood - SP
Moab Substation, Utah Pinto Substation, Utah 138.138.Wood-58.
Pinto Substation, Utah Abajo, UT 138.138.Wood - H 45.
Carbon Plant, Utah Ashley Substation, Utah 138.138.Wood-92.
McClelland Sub., Utah Cottonwood Sub., Utah 138.138.Wood - SP
Ashley Substation, Utah Vernal Substation, Utah 138.136.Wood-12.
Sigurd Substation, Utah West Cedar Substation, UT 138.138.Wood-120.
Ben Lomond Sub., Utah EI Monte Substation, UT 138.138.Wood - H Sub 19.
Cottonwood Sub., Utah Ninetieth South Sub, Uta 138.138.Wood - SP 11.
Terminal Substation, UT Rowley Substation, Utah 138.138.Wood - H 56.
Huntington Plant, Utah McFadden Substation, UT 138.138.Wood - H
Ben Lamond Sub., Utah EI Monte Substation, UT 136.136.Wood - H 13.
Cottonwood Sub., Utah Silvercreek Sub., Utah 138.138.Wood - SP 37.
Ninetieth South Sub, Utah Taylorsviile Sub., Utah 138.138.Wood - SP
Gadsby Plant, Utah McClelland Sub., Utah 138.138.Wood - SP
Ninetieth South Sub, Utah Oquirrh Substation, Utah 138.138.Wood - SP
Nebo, UT Jerusalem, UT 138.136.Wood Tower 26.
TOTAL 15,566.100.189
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
RANSMISSION LINE STATISTICS (C ontinued)
7. Do not report the same transmission line structure twice. ~eport 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 (I) on the book cost at end of year.
liU;) I ur- LINE (Include In Column OJ Land EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)
(j)
(k)(I)(m)(n)
(p)
~97.14,42 145,941 160,365
1795.101 518,899 558,000
~97.052,130 099 743
193,583 193,583
229 20,229
~50.475,562 480,220
00.254,783 256,620
661,441 773,167 2,434,614
50.118,18C 170,185 288,365
50.69,072 69,072
50.458,795 12,952,742 13,411,541
97.54~512,727 540,272
54.78E 105,200 105,986
97.801 630,248 635,049
97.188,OtE 915,170 103,188
97.33,96E 2,732,252 766,220
95.345,831 290,142 635,978
1272.42743!170,410 597,848
95.62,564,970 627,083
~97.40,11!996,661 036,776
397.43,089,679 132,681
397.725,080 772,454
95.13,73~256,775 270,508
397.54E 272,179 277,725
397.28C 266,001 318,281
95.18,84E 747 328 766,173
95.549,06~231,415 780,479
95.222,28E 254,369 476,655
397.26E 238,882 239,147
95.24,901 916,147 941,048
397.177 82~112,532 290,356
95.17!702,762 707,940
795.56,75!925,859 982,618
95.243 44~1,486,330 729,775
~97.253,53!165,835 419,374
79,910,835 503,666,522 583,577,357
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) nA Resubmission 03/20/2006
TRANSMISSION LINE STATIST
1. Report information conceming transmission lines, cost of lI~es, 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 , Nonutillty 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.
(f~d
~~~~~~~~
~GJ,~ ~gle rWiles)Line Type of NumberNo.other than u ~ergroun~hnes
60 cycle 3 ohase)Supporting report circuit miles)
un ~tlVCture f~~Th~res CircuitsFromOperatingDesignedStructureo~ Lln of 1')0 er
(a)(b)(c)(e)Desl
tf)a ed(d)(9)(h)
1 Ben Lamond Sub., Utah Westem Zircon Sub., UT 138.138.Wood - H 14.
2 Tooele Substation, Utah Oquirrh Substation, Utah 138.138.Wood - SP 21.
3 Wheeton Substation, Utah Nucor Steel Sub., Utah 138.138.Wood - H 14.
4 Nebo Substation, Utah Martin-Marietta Sub., UT 138.138.Wood - H 30.
5 West Cedar Sub., Utah Middleton Substation., UT 138.138.Wood - H 69.
6 Gadsby Plant, Utah Terminal Substation, UT 138.0!138.Wood - H
7 Oquirrh Substation, Utah Kennecott Sub., Utah 138.138.Wood - H
8 Oquirrh Substation, Utah Bamey Substation, Utah 138.138.Wood. HS
9 West Cedar Sub., Utah Pepcon Substation, Utah 138.138.Wood - SP 13.
Taylorsville Substation, UT Mid-Valley Substation, UT 138.138.Steel- SP
Warren Substation, Utah Kimberly Clark Sub., UT 138.138.Wood - HP 14.
Honeyvllle, Utah Promontory, Utah 138.138.Wood Tower 24.
Ninetieth South Sub, Utah Hale Plant, Utah 138.138.Wood Tower 45.
Dumas, UT Bimple, UT 138.138.Wood Tower
Columbia Sub, Utah Sunnyside Co. Gen., Utah 138.138.Wood Tower
Syracuse Sub, Utah Ben Lamond Sub, Utah 138.138.Steel- D-P 18.
Hale Plant, Utah Midway Sub, Utah 138.138.Wood - H 19.
Jordan 138 kV, UT Fifth West 138 kV, UT 138.138.Steel Tower 1.00
Gadsby 138 kV, UT Jordan 138 kV, UT 138.138.Steel Tower
138 kV Riverdale Sub, UT 138 kV Riverdale Sub, U 138.138.Steel Tower 1.00
Panther, UT Willow Creek, UT 138.138.Wood Tower 1.00
Hammer Substation, UT BuUerville Substation, U 138.138.Wood Tower
Midway Substation, UT Sliver Creek Sub, UT 138.138.Wood Tower
Midway Substation, UT Cottonwood Sub, UT 138.138.Wood Tower 10.
McFadden Substation, UT Blackhawk Substation, UT 138.138.11.
West Valley Sub., UT Kearns Substation, UT
Syracuse Substation, UT Clearfleld South Sub., UT 1.00
Subtotal 138 kV 052.
All 115 kV lines 115.115.Wood & Steel 544.
All 69 kV lines 69.69.Wood & Steel 972.1.00
All 57 kV lines 57.57.Wood & Steel 113.
All 46 kV lines 46.46.Wood & Steel 653.
TOTAL 15.586.100.189
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da, Yr)End of 2005/Q4
(2) 0 A Resubmlssion 03/20/2006
RANSMISSION LINE STATISTICS ontinued)
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 sale 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 0) to (I) on the book cost at end of year.
\jU~ I UI'" LINe (lncluae In \jolumn UJ Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)
(j)
(k)(I)(m)(n)
(p)
250.96,45 968,212 064,669
95.252,891 034,761 287,652
95.46,941 909,120 956,067
97.66,45 762,997 1.829,449
97.25,14E 797,258 822,406
1272.668,771 810,473 1,479,244
1795.201 459 201,459
1795.16,66!455,106 471,774
1795.43.59(088,222 131,812
1272.33,461 4,491,548 525,014
97.14,141,422 156,144
97.475,68~874,162 349,844
97.146,42~209,090 355,515
97.136,585 136,585
97.-41
1272.353,104 353,104
97.246,50;938,520 185,023
1272.078,958 078 974
1272.75~381,900 382,655
95.90,674 90,674
397.40,890 40,890
188 391 364,795 553,186
755,012 755,012
690,02E 529,700 12,219,725
747,452 747,452
318 318
141 141
511 170,443,351 178,954 944
510,113,442,183 116,952,538
257 195,382,654 198 639 997
234 713,583 7.754,817
346,077 168 051,564 172,397,641
79,910,835 503,666,522 583,577,357
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
PacifiCorp 1(2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
ISchedule Page: 422 Line No.Column:
The Alvey - Dixonville 500kV line is jointly owned by the respondent and the Bonneville Power Administration ("the BP A"
Ownership of the line is as follows: PacifiCorp 50., the BPA 50.0%. Cost reported for this line reflects the respondents 50.
share. Operation and maintenance costs are shared between the two parties and responsibility is as follows: PacifiCorp 58.0% and the
PA 42.0%.
!schedule Page: 422 Line No.Column:
The Dixonville - Meridian 500kV line is jointly owned by the respondent and the Bonneville Power Administration ("the BP A"
Ownership of the line is as follows: PacifiCorp 50.0%, the BPA 50.0%. Cost reported for this line reflects the respondents 50.
share. Operation and maintenance costs are shared between the two parties and responsibility is as follows: PacifiCorp 58.0% and the
BPA 42.0%.
ISchedule Page: 422 Line No.26 Column: I
Costs are included in the Transmission Line listed above.
!schedule Page: 422.Line No.11 Column: I
osts are included in the Transmission Line listed below.
!schedule Page: 422.Line No.20 Column: I
osts are included in the Transmission Line listed above.
!Schedule Page: 422.Line No.29 Column: I
osts are included in the Transmission Line listed below.
!Schedule Page: 422.Line No.29 Column: I
Costs are included in the Transmission Line listed above.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 424)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/04
(2) Fi A Resubmission 03/20/2006
RANSMISSION LINES ADDED DURING YEAR
1. Report below the information called for concerning Transmission lines added or altered during the year.It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (I) to (0), it is permissible to report in these columns the
Line L.1n~.111'11.:1;;)\iIK\iUII ~ PER ~
No.From
Le!1gth
Type N~~b:~~er Present UltimateMilesMiles
(a)(b)(c)(d)(e)(f)
(g)
1 McClelland Cottonwood Wood Sngl Ckt 18.
'..
Camp Williams Steel H Frame
3 Terminal Tooele Steel Dbl Ckt4~"Tooele Steel Sngl Ckt 15.
5 Terminal Tooele 13.Wood Sngl Ckt 18.
6 Quarry Dimple Dell 1.75 G. Cable
7 Ben Lamond Warren Wood H Frame 11.
8 Riverdale Weber Wood Sngl Ckt 15.
9 EI Monte Riverdale Steel Dbl Ckt
2nd Street Steel Sngl Ckt 18.
2nd Street Steel Dbl Ckt 18.
Jordan Northwest Steel Dbl Ckt 15.
TOTAL 48.153.
FERC FORM NO.1 (REV. 12.Q3)Page 424
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/04
(2) 0 A Resubmisslon 03/20/2006
TRAN MISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are r~ported. Include costs of Clearing Land and Rights-of-Way, and Roads .and
Trails, in column (I) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase
indicate such other characteristic.
Voltage Line
Size Specification conf~uration Land and Poles, Towers Conductors Asset Total No.
Ch)
and pacing'(OP1~ating)Land Rights and Fixtures and Devices Retire. Costs(I)(I)(m)(n)(0)
(p)
795 MCM AAC VerticaU10'138 506,351 506,351 012,702
2x1272 MCI ACSR Horizn1ll27'345
1557 MCM ACSR VerticaU12'138
1557 MCM ACSR VerticaU10'138
795 MCM ACSR VerticaU10'138
1750 MCM AL Cble G. Duct 138 299,080
1272MCM ACSR Horizn1ll14'138 164,431 782 774 947,210
795 MCM ACSR VerticaU5'534,42 280,620 815,045
1272 MCM ACSR VerticaU12'585,459 590 968
795 MCM ACSR VerticaU4'573,69f 1,449,927 023,625
1272 MCM ACSR VerticaU10'
1272 MCM ACSR VerticaU10'
059,96E 16,104,453 164,418
FERC FORM NO.1 (REV. 12-03)Page 425
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
!schedule Page: 424 Line No.Column:
Rebuild of smaller ca aci circuit.
chedule Page: 424 Line No.Column:
Costs for Lines 3 , and 5 from Terminal to Tooele totalin $1 581 174 are shown on line 3.
chedule Pa e: 424 Line No.Column:
Costs for Lines 3, 4, and 5 from Terminal to Tooele totalin $2 585 293 are shown on line 3.
Schedule Pa e: 424 Line No.Column:
osts for Lines 3, 4, and 5 from Terminal to Tooele totaling $4 166 467 are shown on line 3.
!schedule Page: 424 Line No.Column:
0.42 miles of this section re orted on 2003 r oft.
Schedule Page: 424 Line No.Column:
Costs for Lines 3, 4, and 5 from Terminal to Tooele totalin $1 581 174 are shown on line 3.
chedule Pa e: 424 Line No.Column:
osts for Lines 3, 4, and 5 from Terminal to Tooele totaling $2 585 293 are shown on line 3.
!schedule Page: 424 Line No.Column:
Costs for Lines 3, 4, and 5 from Terminal to Tooele totalin $4 166 467 are shown on line 3.
chedule Pa e: 424 Line No.Column:
osts for Lines 3, 4, and 5 from Terminal to Tooele totaling $1 581 174 are shown on line 3.
!schedule Page: 424 Line No.Column:
Costs for Lines 3, 4, and 5 from Terminal to Tooele totalin $2 585 293 are shown on line 3.
chedule Page: 424 Line No.Column:
Costs for Lines 3, 4, and 5 from Terminal to Tooele totaling $4 166 467 are shown on line 3.
'Schedule Page: 424 Line No.10 Column:
Rebuild of smaller ca aci circuit.
chedule Pa e: 424 Line No.11 Column:
Rebuild of smaller ca aci circuit.
chedule PaBe: 424 Line No.12 Column:
Charges were written off as expense.
I FERC FORM NO.1 (ED. 12-87)Page 450.
lank Page
(Next Page is: 426)
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2) 0 A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
California
BIG SPRINGS DISTRIBUTION-UNA TTEN 69.12.
CANBY #2 DISTRIBUTION-UNA TTEN 69.
CASTELLA DISTRIBUTION-UNA TTEN 69.
CLEAR LAKE DISTRIBUTION-UNA TTEN 69.12.
CRESCENT CITY DISTRIBUTION-UNA TTEN 12.
DOG CREEK DISTRIBUTION-UNA TTEN 69.
FORT JONES DISTRIBUTION-UNA TTEN 69.12.
GREENHORN DISTRIBUTION-UNA TTEN 69.12.
HAMBURG DISTRIBUTION-UNA TTEN 69.2.40
HAPPY CAMP DISTRIBUTION-UNA TTEN 69.12.
HORNBROOK DISTRIBUTION-UNA TTEN 69.12.
INTERNATIONAL PAPER DISTRIBUTION-UNA TTEN 69.
LAKE EARL DISTRIBUTION-UNA TTEN 69.12.
LITTLE SHASTA DISTRIBUTION-UNA TTEN 69.
LUCERNE DISTRIBUTION-UNATTEN 69.12.
MACDOEL DISTRI BUTION-UNA TTEN 69.20.
MCCLOUD DISTRIBUTION-UNA TTEN 69.12.
MONTAGUE DISTRIBUTION-UNATTEN 69.12.
MOUNT SHASTA DISTRIBUTION-UNA TTEN 69.12.
NEWELL DISTRIBUTION-UNA TTEN 69.12.
NORTH DUNSMUIR DISTRIBUTION-UNA TTEN 69.12.
NUTGLADE DISTRIBUTION-UNA TTEN 69.
SCOTT BAR DISTRIBUTION-UNA TTEN 69.12.
SEIAD DISTRIBUTION-UNA TTEN 69.12.
SHASTINA DISTRIBUTION-UNATTEN 69.20.
SHOTGUN CREEK DISTRIBUTION-UNATTEN 69.12.
SNOW BRUSH DISTRIBUTION-UNATTEN 69.
SOUTH DUNSMUIR DISTRIBUTION-UNATTEN 69.
TULELAKE DISTRIBUTION-UNATTEN 69.12.47
TUNNEL DISTRIBUTION-UNA TTEN 69.12.
TURKEY HILL DISTRIBUTION-UNATTEN 69.12,
WALKER BRYAN DISTRIBUTION-UNA TTEN 69.12.
WEED DISTRIBUTION-UNA TTEN 69.12.47
YUBA DISTRIBUTION-UNA TTEN 69.12.
YUROK DISTRIBUTION-UNATTEN 69.12.
Total 2358.365.
NUMBER OF SUBSTATIONS UNATTENDED - 35
AL TURAS T /D-UNA TTENDED 115.12.69.
FERC FORM NO.1 (ED. 12-96)Page 426
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04
(2) Ei A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other acCounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
Ii)Ii)
(In MVa)
(f)
(g)
(h)(k)
243
FERC FORM NO.1 (ED. 12-96)Page 427
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
FALL CREEK HYDRO/T/D-UNATTENDED 69.
YREKA TID-UNATTENDED 115.12.69.
Total 299.27.138.
NUMBER OF SUBSTATIONS TID UNATTENDED - 3
AGER TRANSMISSION-ATTEND 115.69.
COPCO #1 HYDRO PLANT TRANSMISSION-ATTEND 69.
COPCO #2 HYDRO PLANT TRANSMISSION-ATTEND 69.
COPCO #2 TRANSMISSION-ATTEND 69.12.
COPCO #2 TRANSMISSION-ATTEND 230.115.
Total 552.205.
NUMBER OF SUBSTATIONS TRANS ATTEND - 5
CRAG VIEW TRANSMISSION-UNA TTEN 115.69.
DEL NORTE TRANSMISSION-UNATTEN 115.69.
IRON GATE HYDRO PLANT TRANSMISSION-UNA TTEN 69.
WEED JUNCTION TRANSMISSION-UNA TTEN 115.69.
Total 414.213.
NUMBER OF SUBSTATIONS TRANS UNATTENDED - 4
Idaho
ALEXANDER DISTRIBUTION-UNA TTEN 46.12.
AMMON DISTRIBUTION-UNA TTEN 69.12.
ANDERSON DISTRIBUTION-UNATTEN 69.12.
ARCO DISTRIBUTION-UNA TTEN 69.12.47
ARIMO DISTRIBUTION-UNA TTEN 46.12.47
BANCROFT DISTRIBUTION-UNA TTEN 46.12.
BELSON DISTRIBUTION-UNA TTEN 69.12.
BERENICE DISTRIBUTION-UNA TTEN 69.12.
CAMAS DISTRIBUTION-UNA TTEN 69.12.
CANYON CREEK DISTRIBUTION-UNATTEN 69.24.
CHESTERFIELD DISTRIBUTION-UNA TTEN 46.12.
CLEMENT DISTRIBUTION-UNA TTEN 69.12.
CLIFTON DISTRIBUTION-UNA TTEN 46.12.47
DOWNEY DISTRIBUTION-UNA TTEN 46.12.
DUBOIS DISTRIBUTION-UNA TTEN 69.12.
EASTMONT DISTRIBUTION-UNA TTEN 69.12.
EGIN DISTRIBUTION-UNA TTEN 69.12.
EIGHT MILE DISTRIBUTION-UNA TTEN 46.12.47
GEORGETOWN DISTRIBUTION-UNA TTEN 69.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da, Yr)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
SUBSTATIONS (Continued)
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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(h)
(In MVa)
(f)
(g)
(I)(k)
129
125
220
150
226
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of R~ort Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, r)End of 2005/Q4(2) n A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
GRACE CITY STATION DISTRIBUTION-UNATTEN 46.12.
HAMER DISTRIBUTION-UNA TTEN 69.12.47
HAYES DISTRIBUTION-UNA TTEN 69.12.
HENRY DISTRIBUTION-UNATTEN 46.12.
HOLBROOD DISTRIBUTION-UNA TTEN 69.12.47
HOOPES DISTRIBUTION-UNATTEN 69.12.
HORSLEY DISTRIBUTION-UNA TTEN 46.12.
8 IDAHO FALLS DISTRIBUTION-UNATTEN 46.12.
9 INDIAN CREEK DISTRIBUTION-UNATTEN 69.12.
JEFFCO DISTRIBUTION-UNA TTEN 69.24.
KETTLE DISTRI BUTION-UNA TTEN 69.24.
LAVA DISTRIBUTION-UNA TTEN 46.12.
LEWISTON DISTRIBUTION-UNATTEN 46.12.
LOGAN CANYON DISTRIBUTION-UNA TTEN 46.
LUND DISTRIBUTION-UNATTEN 46.12.
MCCAMMON DISTRIBUTION-UNA TTEN 46.12.
MENAN DISTRIBUTION-UNATTEN 69.12.
MERRILL DISTRIBUTION-UNATTEN 69.12.
MILLER DISTRIBUTION-UNA TTEN 69.12.
MILLVILLE DISTRIBUTION-UNA TTEN 46,12.
MONTPELIER DISTRIBUTION-UNA TTEN 69.12.
MOODY DISTRIBUTION-UNATTEN 69.24.
NEWDALE DISTRIBUTION-UNA TTEN 69.12.
NEWTON DISTRIBUTION-UNATTEN 46.12.
NIBLEY DISTRIBUTION-UNA TTEN 46.24.
NORTH LOGAN DISTRIBUTION-UNATTEN 46.12.
OSGOOD DISTRIBUTION-UNA TTEN 69.12.
PRESTON DISTRIBUTION-UNA TTEN 46.12.
RANDOLPH DISTRIBUTION-UNA TTEN 46.12.
RAYMOND DISTRIBUTION-UNA TTEN 69.12.47
RENO DISTRIBUTION-UNA TTEN 69.12.
REXBURG DISTRIBUTION-UNA TTEN 69.12.
RICH DISTRIBUTION-UNATTEN 69.12.47
RICHMOND DISTRIBUTION-UNATTEN 46.12.
RIRIE DISTRIBUTION-UNATTEN 69.12.47
ROBERTS DISTRIBUTION-UNA TTEN 69.12.
RUDY DISTRIBUTION-UNATTEN 69.12.
SAND CREEK DISTRIBUTION-UNA TTEN 69.12.
SANDUNE DISTRIBUTION-UNATTEN 69.24.
SHELLEY DISTRIBUTION-UNATTEN 46.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) 0 A Resubmlssion 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)
(g)
(h)(i)(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
SMITH DISTRIBUTION-UNA TTEN 69.12.
SODA DISTRIBUTION-UNATTEN 138.
SOUTH FORK DISTRIBUTION-UNA TTEN 69.12.
SPUD DISTRIBUTION-UNA TTEN 46.12.
ST. CHARLES DISTRIBUTION-UNA TTEN 69.12.
SUGAR CITY DISTRIBUTION-UNA TTEN 69.12.
SUNNYDELL DISTRIBUTION-UNATTEN 69.12.
TANNER DISTRIBUTION-UNA TTEN 46.12.
TARGHEE DISTRIBUTION-UNA TTEN 46.12.
THORNTON DISTRIBUTION-UNATTEN 69.12.
UCON DISTRIBUTION-UNA TTEN 69.12.
WATKINS DISTRI BUTION-UNA TTEN 69.12.47
WEBSTER DISTRIBUTION-UNA TTEN 69.12.
WESTON DISTRIBUTION-UNATTEN 46.12.
WINDSPER DISTRI BUTION-UNA TTEN 69.24.
Total 4531.999.
NUMBER OF SUBSTATIONS DIST UNATTENDED - 74
MALAD T /D-UNA TTENDED 138.46.12.
MUD LAKE T/D-UNATTENDED 69.12.
RIGBY T /D-UNA TTENDED 161.12.69.
SAINT ANTHONY T/D-UNA TTENDED 69.46.12.
Total 437.116.93.
NUMBER OF SUBSTATIONS T/D UNATTENDED - 4
GRACE HYDRO TRANSMISSION-ATTEND 138.46.
Total 138.46.
NUMBER OF SUBSTATIONS TRANS ATTENDED - 1
AMPS TRANSMISSION-UNA TTEN 230.69.
ANTELOPE TRANSMISSION-UNA TTEN 230.161.
ASHTON PLANT TRANSMISSION-UNA TTEN 46.2.40
BIG GRASSY TRANSMISSION-UNA TTEN 161.69.
BONNEVILLE TRANSMISSION-UNATTEN 161.69.
CARIBOU TRANSMISSION-UNA TTEN 138.46.
CONDA TRANSMISSION-UNA TTEN 138.46.
COVE PLANT TRANSMISSION-UNATTEN 46.
FISH CREEK TRANSMISSION-UNA TTEN 161.46.
FRANKLIN TRANSMISSION-UNA TTEN 138.46.
GOSHEN TRANSMISSION-UNA TTEN 345.161.46.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
SUBSTATIONS (Continued)
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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)
(g)
(h)(i)(k)
864
189
314
115
115
250
763
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo; Da, Yr)End of 2005/04(2) n A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
GREEN CANYON TRANSMISSION-UNA TTEN 138.46.
JEFFERSON TRANSMISSION-UNA TTEN 161.69.
LIFTON HYDRO TRANSMISSION-UNA TTEN 69.
ONEIDA TRANSMISSION-UNATTEN 138.12.
OVID TRANSMISSION-UNATTEN 138.69.
SCOVILLE TRANSMISSION-UNA TTEN 138.69.46.
SMITHFIELD TRANSMISSION-UNATTEN 136.46.12.
SUGARMILL TRANSMISSION-UNA TTEN 161.46.69.
9 TREASURETON TRANSMISSION-UNA TTEN 230.138.
Total 3103.1219.173.47
NUMBER OF SUBSTATIONS TRANS UNATTENDED - 20
Oregon
26TH STREET DISTRIBUTION-UNA TTEN 20.
35TH STREET DISTRIBUTION-UNATTEN 20.
AGNESS AVE DISTRIBUTION-UNATTEN 115.12.47
ALDERWOOD DISTRIBUTION-UNA TTEN 69.12.
ARLINGTON DISTRIBUTION-UNATTEN 69.12.
ATHENA DISTRIBUTION-UNA TTEN 69.12.
BANDON TIE DISTRI BUTION-UNA TTEN 20.12.
BEACON DISTRIBUTION-UNA TTEN 69.12.
BEATTY DISTRIBUTION-UNATTEN 69.12.
BELKNAP DISTRI BUTION-UNA TTEN 69.12.
BELMONT DISTRIBUTION-UNA TTEN 69.12.
BLALOCK DISTRIBUTION-UNATTEN 69.12.
BLOSS DISTRIBUTION-UNATTEN 115.12.
BLY DISTRIBUTION-UNATTEN 69.12.
BOISE CASCADE DISTRIBUTION-UNA TTEN 69.11.
BONANZA DISTRIBUTION-UNATTEN 69.12.47
BROOKHURST DISTRIBUTION-UNATTEN 115.12.
BROOKS-SCANLON DISTRIBUTION-UNA TTEN 69.12.
BROWNSVILLE DISTRIBUTION-UNA TTEN 69.20.
BRYANT DISTRIBUTION-UNA TTEN 69.12.
BUCHANAN DISTRIBUTION-UNATTEN 115.20.
BUCKAROO DISTRIBUTION-UNATTEN 69.12.
CAMPBELL DISTRIBUTION-UNA TTEN 115.12.
CANNON BEACH DISTRIBUTION-UNA TTEN 115.12.
CARNES DISTRIBUTION-UNA TTEN 69.12.47
CASEBEER DISTRI BUTION-UNA TTEN 69.20.
CAVEMAN DISTRIBUTION-UNA TTEN 115.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent ThiS ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)
(g)
(h)(i)(k)
233
168
533
2722
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This "OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, 08, Yr)End of 2005/Q4
(2) Ei A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
CHERRY LANE DISTRIBUTION-UNA TTEN 69.12.
CHILOQUIN MARKET DISTRIBUTION-UNA TTEN 69.12.
CHINA HAT DISTRIBUTION-UNATTEN 69.12.
CIRCLE BLVD DISTRIBUTION-UNATTEN 115.20.
CLEVELAND AVE DISTRIBUTION-UNA TTEN 69.12.
CLINE FALLS HYDRO DISTRIBUTION-UNA TTEN 12.
CLOAKE DISTRIBUTION-UNATTEN 69.20.
COBURG DISTRIBUTION-UNA TTEN 69.20.
COLISEUM DISTRIBUTION-UNATTEN 20.
COLUMBIA DSITRIBUTION-UNA TTEN 115.12.57.
COOS RIVER DISTRIBUTION-UNATTEN 115.20.
COQUILLE DISTRIBUTION-UNA TTEN 115.20.
CREEK DISTRIBUTION-UNA TTEN 69.34.
CROOKED RIVER RANCH DISTRIBUTION-UNA TTEN 69.20.
CROWFOOT DISTRIBUTION-UNA TTEN 115.12.
CULLY DISTRI BUTION-UNA TTEN 115.12.47
CULVER DISTRIBUTION-UNA TTEN 69.12.
CUTLER CITY DISTRIBUTION-UNATTEN 20.
DAIRY DISTRIBUTION-UNA TTEN 69.12.
DALLAS DISTRIBUTION-UNA TTEN 115.20.
DALREED DISTRIBUTION-UNA TTEN 230.34.
DESCHUTES DISTRIBUTION-UNA TTEN 69.12.
DEVILS LAKE DISTRIBUTION-UNATTEN 115.20.
DIXON DISTRIBUTION-UNA TTEN 115.
DODGE BRIDGE DISTRIBUTION-UNATTEN 69.20.
DORRIS DISTRIBUTION-UNA TTEN 69.12.47
EAGLE VENEER FII DISTRIBUTION-UNATTEN 20.
EAST VALLEY DISTRIBUTION-UNATTEN 115.12.
EMPIRE DISTRIBUTION-UNATTEN 115.20.
ENTERPRISE DISTRIBUTION-UNA TTEN 69.12.
FERN HILL DISTRIBUTION-UNA TTEN 115.12.
FIELDER CREEK DISTRIBUTION-UNA TTEN 115.20.
FOOTHILLS DISTRIBUTION-UNA TTEN 69.12.
FRALEY DISTRIBUTION-UNA TTEN 69.12.47
GARDEN VALLEY DISTRIBUTION-UNA TTEN 69.20.
GASQUET DISTRIBUTION-UNA TTEN 115.12.
GAZLEY DISTRIBUTION-UNA TTEN 69.12.
GEARHART DISTRIBUTION-UNATTEN 12.
GLENDALE DISTRIBUTION-UNA TTEN 230.12.
GLENEDEN DISTRIBUTION-UNA TTEN 20.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(g)
(In MVa)
(f)(h)(i)(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) n A Resubmlssion 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
GLIDE DISTRIBUTION-UNATTEN 115.12.
GOLD HILL DISTRIBUTION-UNA TTEN 69.12.47
GORDON HOLLOW DISTRIBUTION-UNATTEN 69.12.47
GOSHEN DISTRIBUTION-UNATTEN 115.20.
GRANT STREET DISTRIBUTION-UNA TTEN 115.20.
GRASS VALLEY DISTRIBUTION-UNATTEN 20.
GREEN DISTRIBUTION-UNATTEN 69.12.
GRIFFIN CREEK DISTRIBUTION-UNA TTEN 115.12.
HAMAKER DISTRIBUTION-UNA TTEN 69.12.
HARRISBURG DISTRIBUTION-UNA TTEN 69.20.
HENLEY DISTRIBUTION-UNATTEN 69.12.
HERMISTON DISTRIBUTION-UNA TTEN 69.12.
HILLVIEW DISTRIBUTION-UNA TTEN 115.20.
HINKLE DISTRI BUTION-UNA TTEN 69.12.
HOLLADAY DISTRIBUTION-UNA TTEN 115.12.
HOLLYWOOD DISTRIBUTION-UNA TTEN 115.12.
HOOD RIVER DISTRIBUTION-UNA TTEN 69.12.
HORNET DISTRIBUTION-UNA TTEN 69.12.47
INDEPENDENCE DISTRIBUTION-UNA TTEN 69.20.
JACKSONVILLE DISTRIBUTION-UNA TTEN 115.12.69.
JEFFERSON DISTRIBUTION-UNA TTEN 69.20.
JEROME PRAIRIE DISTRIBUTION-UNA TTEN 115.12.
JORDAN POINT DISTRIBUTION-UNATTEN 115.12.
JOSEPH DISTRIBUTION-UNA TTEN 20.12.
JUNCTION CITY DISTRIBUTION-UNA TTEN 69.20.
KENWOOD DISTRIBUTION-UNATTEN 69.12.47
KILLINGWORTH DISTRIBUTION-UNA TTEN 69.12.
KNAPPA SVENSEN DISTRIBUTION-UNATTEN 115.12.47
LAKEPORT DISTRIBUTION-UNATTEN 69.12.
LAKEVIEW DISTRIBUTION-UNA TTEN 69.12.47
LANCASTER DISTRIBUTION-UNA TTEN 69.20.
LEBANON DISTRIBUTION-UNA TTEN 115.20.
LINCOLN DISTRIBUTION-UNATTEN 115.12.
LOCKHART DISTRIBUTION-UNA TTEN 115.20.
LYONS DISTRIBUTION-UNA TTEN 69.20.
MADRAS DISTRIBUTION-UNA TTEN 69.12.
MALLORY DISTRI BUTION-UNA TTEN 115.12.
MARYS RIVER DISTRIBUTION-UNATTEN 115.20.
MEDCO DISTRIBUTION-UNA TTEN 115.12.
MEDFORD DISTRIBUTION-UNATTEN 69.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) D A Resubmission 03/20/2006
SUBSTATIONS (Continued)
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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
105
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
MERLIN DISTRIBUTION-UNA TTEN 115.12.
MERRILL DISTRIBUTION-UNATTEN 69.12.
MILLER REDWOOD DISTRIBUTION-UNA TTEN 69.12.47
MINAM DISTRIBUTION-UNA TTEN 69.12.
MODOC DISTRIBUTION-UNA TTEN 69.12.
MORO DISTRIBUTION-UNATTEN 20.
MURDER CREEK DISTRIBUTION-UNATTEN 115.20.
MYRTLE CREEK DISTRIBUTION-UNA TTEN 69.12.
9 MYRTLE POINT DISTRIBUTION-UNA TTEN 115.20.
NELSCOTT DISTRIBUTION-UNA TTEN 20.
NEW O'BRIEN DISTRIBUTION-UNA TTEN 115.12.
NORTHCREST DISTRIBUTION-UNA TTEN 69.12.
OAK KNOLL DISTRIBUTION-UNA TTEN 115.12.
OAKLAND DISTRIBUTION-UNA TTEN 115.12.
ORCHARD STREET DISTRI BUTION-UNA TTEN 12.
OREMET FORGE -FII DISTRIBUTION-UNA TTEN 20.
OVERPASS DISTRIBUTION-UNA TTEN 69.12.
PALLETTE DISTRIBUTION-UNA TTEN 69.20.
PARK STREET DISTRIBUTION-UNA TTEN 115.12.
PARKROSE DISTRIBUTION-UNATTEN 57.12.
PATRICKS CREEK DISTRIBUTION-UNA TTEN 115.
PENDLETON DISTRI BUTION-UNA TTEN 69.12.
PEREZ DISTRIBUTION-UNA TTEN 69.12.
PILOT ROCK DISTRIBUTION-UNA TTEN 69.12.
POWELL BUTTE DISTRIBUTION-UNA TTEN 115.12.47
PRINEVILLE DISTRIBUTION-UNA TTEN 115.12.
PROVOL T DISTRIBUTION-UNA TTEN 69.12.47
QUEEN AVE DISTRIBUTION-UNA TTEN 69.20.
RED BLANKET DISTRI BUTION-UNA TTEN 69.
REDMOND DISTRIBUTION-UNA TTEN 115.12.47
REDWOOD DISTRIBUTION-UNATTEN 69.12.
RICH MANUFACTURING DISTRIBUTION-UNATTEN 57.12.
RIDDLE DISTRIBUTION-UNA TTEN 69.12.47
RIDDLE VENEER DISTRIBUTION-UNA TTEN 69.12.
ROGUE RIVER DISTRIBUTION-UNA TTEN 69.12.
ROSEBURG DISTRIBUTION-UNA TTEN 115.20.
ROSS AVE DISTRIBUTION-UNATTEN 69.12.
RUCH DISTRI BUTION-UNA TTEN 69.12.
RUNNING Y DISTRIBUTION-UNA TTEN 69.20.
RUSSELLVILLE DISTRIBUTION-UNA TTEN 115.12.47
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2) n A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
100
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent ThIS 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
SAGE ROAD DISTRIBUTION-UNA TTEN 115.12.
SCENIC DISTRIBUTION-UNA TTEN 115.12.69.
SCIO DISTRIBUTION-UNA TTEN 69.12.
SEASIDE DISTRIBUTION-UNA TTEN 115.12.
SELMA DISTRI BUTION-UNA TTEN 115.12.47
SHASTA WAY DISTRI BUTION-UNA TTEN 12.
SHEVLIN PARK DISTRIBUTION-UNA TTEN 69.12.
SIMONSON DISTRI BUTION-UNA TTEN 69.12.
SIMTAG BOOSTER PUMP DISTRIBUTION-UNA TTEN 34.
SMITH RIVER DISTRIBUTION-UNATTEN 69.12.
SOUTH DUNES DISTRIBUTION-UNA TTEN 115.12.
SOUTHGATE DISTRIBUTION-UNA TTEN 69.20.
SPRAGUE RIVER DISTRIBUTION-UNA TTEN 69.12.
STARFIRE LUMBER FII DISTRIBUTION-UNA TTEN 20.
STATE STREET DISTRI BUTION-UNA TTEN 115.20.
STAYTON DISTRIBUTION-UNA TTEN 69.12.
STEAMBOAT DISTRIBUTION-UNATTEN 115.
STEVENS ROAD DISTRIBUTION-UNA TTEN 115.20.
STONE FOREST FII DISTRIBUTION-UNATTEN 20.0.48
SUTHERLIN DISTRIBUTION-UNA TTEN 115.12.
SWEET HOME DISTRIBUTION-UNATTEN 115.20.
TAKELMA DISTRIBUTION-UNA TTEN 115.20.
TALENT DISTRIBUTION-UNATTEN 69.12.
TEXUM DISTRIBUTION-UNA TTEN 69.12.
TILLER DISTRIBUTION-UNA TTEN 115.12.47
TOLO DISTRIBUTION-UNATTEN 69.12.
TWENTY FOURTH STREET FII DISTRIBUTION-UNA TTEN 20.
UMAPINE DISTRIBUTION-UNATTEN 69.12.
UMATILLA DISTRIBUTION-UNA TTEN 69.12.
US PLYWOOD DISTRIBUTION-UNA TTEN 20.
VERNON DISTRI BUTION-UNA TTEN 69.12.
VILAS DISTRIBUTION-UNA TTEN 115.12.
VILLAGE GREEN DISTRI BUTION-UNA TTEN 115.20.
VINE STREET DISTRIBUTION-UNA TTEN 69.20.
WALLOWA DISTRIBUTION-UNATTEN 69.12.
WARM SPRINGS DISTRIBUTION-UNATTEN 69.20.
WARRENTON DISTRIBUTION-UNA TTEN 115.12.
WASCO DISTRIBUTION-UNA TTEN 20.
WECOMA BEACH DISTRIBUTION-UNATTEN 20.
WESTERN KRAFT DISTRIBUTION-UNATTEN 115.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(f)
(g)
(In MVa)
(h)(i)(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2005/Q4(2) nA Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
WESTON DISTRIBUTION-UNA TTEN 69.12.47
WESTSIDE HYDRO DISTRIBUTION-UNA TTEN 69.12.
WEYERHAUSER DISTRIBUTION-UNA TTEN 69.12.
WHITE CITY DISTRIBUTION-UNA TTEN 115.12.
WILLAMETTE NATIONAL FII DISTRIBUTION-UNA TTEN 20.
WILLOW COVE DISTRIBUTION-UNA TTEN 34.
WINSTON DISTRI BUTION-UNA TTEN 69.12.
YOUNGS BAY DISTRIBUTION-UNA TTEN 115.12.
Total 15716.2577.195.
NUMBER OF SUBSTATIONS DIST UNATENDED - 195
ALBINA T/D-UNATTENDED 115.12.47 69.
APPLEGATE T/D-UNATTENDED 115.69.12.
ASHLAND T/D-UNA TTENDED 115.69.12.47
BEND PLANT T/D-UNATTENDED 69.12.
CAVE JUNCTION TID-UNATTENDED 115.12.69.
HAZELWOOD T/D-UNATTENDED 115.69.12.47
KNOTT T/D- UNATTENDED 115.12.57.
MILE HI T/D-UNA TTENDED 115.69.12.
PILOT BUTTE T/D-UNA TTENDED 230.69.12.47
WINCHESTER T/D-UNATTENDED 115.12.69.
Total 1219.399.338.
NUMBER OF SUBSTATIONS T/D UNATTENDED - 10
CLEARWATER#1 HYDRO PLANT TRANSMISSION-ATTEND 138.
CLEARWATER #2 HYDRO PLANT TRANSMISSION-ATTEND 138.12.
FISH CREEK HYDRO TRANSMISSION-ATTEND 115.
JC BOYLE HYDRO TRANSMISSION-ATTEND 230.11.
LEMOLO #1 HYDRO TRANSMISSION-ATTEND 115.12.
LEMOLO #2 HYDRO TRANSMISSION-ATTEND 115.12.
PROSPECT 1 HYDRO TRANSMISSION-ATTEND 69.
PROSPECT 2 HYDRO TRANSMISSION-ATTEND 69.
PROSPECT 3 HYDRO TRANSMISSION-ATTEND 69.12.
Total 1058.82.
NUMBER OF SUBSTATIONS TRANS ATTENDED - 9
BEND PLANT TRANSMISSION-UNA TTEN
CALAPOOY A TRANSMISSION-UNATTEN 230.69.
CHILOQUIN TRANSMISSION-UNATTEN 230.115.69.
COLD SPRINGS TRANSMISSION-UNA TTEN 230.69.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from ot/1ers, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
4446 397
177
132
187
400
1238
293
119
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04
(2) n A Resubmlssion 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 COVE TRANSMISSION-UNA TTEN 230.69.
2 DAYS CREEK TRANSMISSION-UNA TTEN 115.69.
3 DIAMOND HILL TRANSMISSION-UNATTEN 230.69.
4 DIXONVILLE 115/230 TRANSMISSION-UNA TTEN 230.115.69.
~..
I eN 500.230.
6 EAGLE POINT HYDRO TRANSMISSION-UNA TTEN 115.
EAST SIDE HYDRO TRANSMISSION-UNATTEN 46.12.
FISH HOLE TRANSMISSION-UNATTEN 115.69.
FRY TRANSMISSION-UNA TTEN 230.115.
GRANTS PASS TRANSMISSION-UNA TTEN 230.115.69.
GREEN SPRINGS PLANT TRANSMISSION-UNATTEN 115.69.
HURRICANE TRANSMISSION-UNA TTEN 230.69.
ISTHMUS TRANSMISSION-UNATTEN 230.115.
KENNEDY TRANSMISSION-UNATTEN 69.57.
KLAMATH FALLS TRANSMISSION-UNA TTEN 230.69.
LONE PINE TRANSMISSION-UNA TTEN 230.115.69.f+~I eN 500.230.
MONPAC TRANSMISSION-UNATTEN 115.69.
PONDEROSA TRANSMISSION-UNA TTEN 230.115.
POWERDALE PLANT TRANSMISSION-UNA TTEN 69.
PROSPECT CENTRAL TRANSMISSION-UNA TTEN 115.69.
ROBERTS CREEK TRANSMISSION-UNA TTEN 115.69.
SLIDE CREEK HYDRO TRANSMISSION-UNATTEN 115.
SODA SPRINGS HYDRO TRANSMISSION-UNA TTEN 115.
TROUTDALE TRANSMISSION-UNA TTEN 230.115.69.
TUCKER TRANSMISSION-UNA TTEN 115.69.
WALLOWA FALLS HYDRO TRANSMISSION-UNATTEN 20.
Total 5578.2372,347.
NUMBER OF SUBSTATIONS TRANS UNATTEND - 31
Utah
118TH SOUTH DISTRIBUTION-UNA TTEN 138.12.
ALTAVIEW DISTRIBUTION-UNATTEN 46.12.
AMALGA DISTRIBUTION-UNA TTEN 46.12.
AMERICAN FORK DISTRIBUTION-UNA TTEN 138.12.
ARAGONITE DISTRIBUTION-UNATTEN 46.
AURORA DISTRIBUTION-UNA TTEN 46.12,
BANGERTER DISTRIBUTION-UNA TTEN 138.12.
BEAR RIVER DISTRIBUTION-UNA TTEN 46.12.
BENJAMIN DISTRIBUTION-UNA TTEN 46.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04
(2) Fi A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)
(j)
(k)
344
650
500
458
250
251
733 10
1300
250
500
100
6070
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
BINGHAM DISTRIBUTION-UNA TTEN 46.12.47
BLUE CREEK DISTRIBUTION-UNA TTEN 46.12.
BLUFF DISTRIBUTION-UNA TTEN 69.12.47
BLUFFDALE DISTRIBUTION-UNA TTEN 46.12.
BOTHWELL DISTRIBUTION-UNATTEN 46.12.
BOX ELDER DISTRIBUTION-UNA TTEN 46.12.
BRIAN HEAD DISTRIBUTION-UNATTEN 46.12.
BRICKYARD DISTRIBUTION-UNA TTEN 46.12.
BRIGHTON DISTRIBUTION-UNA TTEN 46.24.
BROOKLAWN DISTRIBUTION-UNA TTEN 46.12.47
BRUNSWICK DISTRIBUTION-UNA TTEN 46.12.
BURTON DISTRIBUTION-UNA TTEN 34.12.
BUSH DISTRIBUTION-UNA TTEN 46.12.
CANNON DISTRIBUTION-UNATTEN 46.12.47
CANYONLANDS DISTRIBUTION-UNA TTEN 69.12.
CAPITOL DISTRIBUTION-UNATTEN 46.12.
CARBIDE DISTRIBUTION-UNA TTEN 46.
CARBONVILLE DISTRIBUTION-UNATTEN 46.12.
CASTO SUBSTATION DISTRIBUTION-UNA TTEN 46.12.
CENTENNIAL DISTRIBUTION-UNA TTEN 138.12.
CENTERVILLE DISTRIBUTION-UNA TTEN 46.12.47
CENTRAL DISTRIBUTION-UNA TTEN 46.12.
CHAPEL HILL DISTRIBUTION-UNA TTEN 138.12.
CHERRYWOOD DISTRIBUTION-UNA TTEN 138.12.
CIRCLEVILLE DISTRIBUTION-UNA TTEN 69.12.
CLEAR CREEK DISTRIBUTION-UNA TTEN 46.12.
CLEAR LAKE DISTRIBUTION-UNATTEN 46.12.
CLEARFIELD DISTRIBUTION-UNA TTEN 46.12.47
CLINTON DISTRIBUTION-UNATTEN 138.12.47
CLIVE DISTRIBUTION-UNA TTEN 46.12.
COALVILLE DISTRI BUTION-UNA TTEN 46.12.
COLD WATER CANYON DISTRIBUTION-UNATTEN 138.12.
COLEMAN DISTRI BUTION-UNA TTEN 138.69.12.47
COLTON WELL DISTRIBUTION-UNATTEN 46.12.
CORINNE DISTRIBUTION-UNATTEN 46.12.47
COVE FORT DISTRIBUTION-UNA TTEN 46.12.
CRESCENT JUNCTION DISTRIBUTION-UNA TTEN 46.
CROSS HOLLOW DISTRIBUTION-UNA TTEN 138.12.47
CUDAHY DISTRIBUTION-UNA TTEN 138.12.47
DAMMERON VALLEY DISTRIBUTION-UNA TTEN 34.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
I -
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) OA Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), m, and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(g)
(h)
(In MVa)
(f)(i)(k)
106
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
DECKER LAKE DISTRIBUTION-UNA TTEN 138.12.47
DELLE DISTRIBUTION-UNA TTEN 46.12.
DELTA DISTRIBUTION-UNA TTEN 46.12.
DESERET DISTRIBUTION-UNATTEN 46.
DEWEYVILLE DISTRIBUTION-UNA TTEN 46.12.47
DIMPLE DELL DISTRI BUTION-UNA TTEN 138.12.47
DIXIE DEER DISTRIBUTION-UNA TTEN 34.12.47
DRAGERTON DISTRIBUTION-UNA TTEN 46.12.
DRAPER DISTRIBUTION-UNA TTEN 46.12.47
DUMAS DISTRIBUTION-UNA TTEN 138.12.
EAST BENCH DISTRIBUTION-UNA TTEN 138.12.47
EAST HYRUM DISTRI BUTION-UNA TTEN 46.12.
EAST LAYTON DISTRIBUTION-UNA TTEN 138.12.47
EAST MILLCREEK DISTRIBUTION-UNA TTEN 46.12.47
EDEN DISTRIBUTION-UNATTEN 46.12.
ELBERTA DISTRIBUTION-UNA TTEN 46.12.
ELK MEADOWS DISTRIBUTION-UNA TTEN 46.12.47
ELSINORE DISTRIBUTION-UNATTEN 46.12.
EMERY CITY DISTRIBUTION-UNA TTEN 69.12.47
EMIGRATION DISTRIBUTION-UNA TTEN 46.12.
ENOCH DISTRIBUTION-UNA TTEN 138.12.
ENTERPRISE VALLEY DISTRIBUTION-UNA TTEN 138.12.47
EUREKA DISTRIBUTION-UNA TTEN 46.12.
FARMINGTON DISTRI BUTION-UNA TTEN 138.12.
FAYETTE DISTRIBUTION-UNATTEN 46.12.
FERRON DISTRIBUTION-UNATTEN 46.12.
FIELDING DISTRIBUTION-UNA TTEN 46.12.
FIFTH WEST DISTRI BUTION-UNA TTEN 138.12.
FLUX DISTRIBUTION-UNA TTEN 46.12.
FOOL CREEK DISTRI BUTION-UNA TTEN 46.12.
FOUNTAIN GREEN DISTRIBUTION-UNA TTEN 46.12.
FREEDOM DISTRIBUTION-UNA TTEN 46.
FRUIT HEIGHTS DISTRIBUTION-UNA TTEN 46.12.
GATEWAY DISTRIBUTION-UNA TTEN 69.12.
GOSHEN DISTRIBUTION-UNA TTEN 46.12.
GRANGER DI STRI BUTION-UNA TTEN 46.12.47
GRANTSVILLE DISTRIBUTION-UNA TTEN 46.12.
GREEN RIVER DISTRIBUTION-UNATTEN 46.12.
GROW DISTRIBUTION-UNATTEN 138.12.46.
GUNNISON DISTRIBUTION-UNA TTEN 46.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) 0 A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0). and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmisslon 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
HAMILTON DISTRIBUTION-UNA TTEN 34.12.
HAMMER DISTRIBUTION-UNA TTEN 138.12.47
HAVASU DISTRIBUTION-UNA TTEN 69.12.
HELPER CITY DISTRIBUTION-UNA TTEN 46.
HENEFER DISTRIBUTION-UNATTEN 46.12.
HIAWATHA DISTRIBUTION-UNA TTEN 46.
HIGHLAND DIST DISTRIBUTION-UNA TTEN 46.12.
HOGGARD DISTRIBUTION-UNA TTEN 138.12.
HOGLE DISTRIBUTION-UNA TTEN 46.12.47
HOLDEN DISTRIBUTION-UNA TTEN 46.12.
HOLLADAY DISTRIBUTION-UNA TTEN 46.12.47
HUNTER DISTRIBUTION-UNA TTEN 46.12.
HUNTINGTON CITY DISTRIBUTION-UNA TTEN 69.12.47
HURRICANE FIELDS DISTRIBUTION-UNA TTEN 34.12.
IRON MOUNTAIN DISTRIBUTION-UNA TTEN 34.
IRON SPRINGS DISTRIBUTION-UNA TTEN 34.12.
IRONTON DISTRIBUTION-UNA TTEN 46.12.
IVINS DISTRIBUTION-UNA TTEN 34.12.
JORDAN NARROWS DISTRIBUTION-UNA TTEN 46.
JORDAN PARK DISTRIBUTION-UNA TTEN 138.12.
JORDANELLE DISTRIBUTION-UNATTEN 138.12.47
JUAB DISTRIBUTION-UNA TTEN 46.12.
JUNCTION DISTRIBUTION-UNA TTEN 69.12.
KAIBAB DISTRIBUTION-UNATTEN 69.12.47
KAMAS DISTRIBUTION-UNA TTEN 46.12.47
KANARRAVILLE DISTRI BUTION-UNA TTEN 34.12.
KEARNS DISTRIBUTION-UNA TTEN 138.12.
KENSINGTON DISTRIBUTION-UNATTEN 46.
LAKEPARK DISTRIBUTION-UNATTEN 138.12.
LARK DISTRIBUTION-UNA TTEN 46.12.
LASAL DISTRIBUTION-UNA TTEN 69.12.47
LAYTON DISTRIBUTION-UNA TTEN 46.12.
LEGRANDE DISTRIBUTION-UNA TTEN 46.12.
LINCOLN DISTRIBUTION-UNATTEN 46.12.
LINDON DISTRI BUTION-UNA TTEN 46.12.47
LISBON DISTRIBUTION-UNA TTEN 69.12.
LITTLE MOUNTAIN DISTRIBUTION-UNA TTEN 46.12.
LOAFER DISTRIBUTION-UNA TTEN 46.12.
LONE TREE DISTRIBUTION-UNA TTEN 34.12.
LOWER BEAVER DISTRI BUTION-UNA TTEN 46.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
ooort Is:
Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(f)
(g)
(h)(i)
(In MVa)
(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (in MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
L YNNDYL DISTRIBUTION-UNA TTEN 46.12.
MAESER DISTRIBUTION-UNATTEN 69.12.47
MAGNA DISTRIBUTION-UNA TTEN 138.12.
MANILA DISTRIBUTiON-UNA TTEN 46.12.
MANTUA DISTRIBUTION-UNA TTEN 46.12.
MAPLETON DISTRIBUTION-UNA TTEN 46.12.
MARRIOTT DISTRIBUTION-UNATTEN 46.12.
MARYSVALE DISTRIBUTION-UNATTEN 46.12.47
MATHIS DISTRIBUTION-UNA TTEN 46.12.
MCCORNICK DISTRIBUTION-UNA TTEN 46.12.
MCKAY DISTRIBUTION-UNATTEN 46.12.47
MEADOWBROOK DISTRIBUTION-UNA TTEN 138.12.47 46.
MEDICAL DISTRIBUTION-UNA TTEN 46.12.47
MELLING DISTRIBUTION-UNA TTEN 34.
MIDLAND DISTRIBUTION-UNATTEN 138.12.
MIDVALE DISTRIBUTION-UNA TTEN 46.12.
MILFORD DISTRIBUTION-UNA TTEN 46.12.
MILFORD TV DISTRIBUTION-UNA TTEN 46.
MINERSVILLE DISTRIBUTION-UNATTEN 46.12.
MOAB CITY DISTRIBUTION-UNA TTEN 69.12.
MONTEZUMA DISTRIBUTION-UNATTEN 69.12.
MOORE DISTRIBUTION-UNA TTEN 69.12.47
MORGAN DISTRIBUTION-UNA TTEN 46.
MORONI DISTRIBUTION-UNA TTEN 46.12.
MORTON COURT DISTRIBUTION-UNA TTEN 138.12.
MOUNTAIN DELL DISTRIBUTION-UNA TTEN 46.12.
MOUNTAIN GREEN DISTRIBUTION-UNATTEN 46.12.
MYTON DISTRIBUTION-UNA TTEN 69.12.
NEW HARMONY DISTRIBUTION-UNA TTEN 69.12.
NEWGATE DISTRIBUTION-UNA TTEN 46.12.
NORTH BENCH DISTRIBUTION-UNATTEN 46.12.47
NORTH CEDAR DISTRIBUTION-UNATTEN 34.
NORTH FIELDS DISTRIBUTION-UNATTEN 46.12.
NORTH OGDEN DISTRIBUTION-UNA TTEN 46.12.47
NORTH SALT LAKE DISTRIBUTION-UNATTEN 46.12.
NORTHEAST DISTRIBUTION-UNATTEN 46.12.
NORTHRIDGE DISTRIBUTION-UNA TTEN 46.12.
OAKLAND AVE DISTRIBUTION-UNA TTEN 46.12.
OAKLEY DISTRIBUTION-UNATTEN 46.12.
OGDEN DEFENSE DEPOT DISTRIBUTION-UNATTEN 46.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) n A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
OL YMPUS DISTRIBUTION-UNA TTEN 46.12.
OPHIR DISTRIBUTION-UNATTEN 46.12.
ORANGE DISTRIBUTION-UNA TTEN 46.12.
ORANGEVILLE DISTRIBUTION-UNA TTEN 69.12.
OR EM DISTRIBUTION-UNA TTEN 46.12.
OREMET DISTRIBUTION-UNA TTEN 115.12.
PACK CREEK RESERVOIR DISTRIBUTION-UNA TTEN 46.12.
PANGUITCH DISTRIBUTION-UNATTEN 69.12.
PARlETTE STATION DISTRIBUTION-UNA TTEN 69.24.
PARK CITY DISTRIBUTION-UNA TTEN 46.12.
PARKWAY DISTRIBUTION-UNA TTEN 138.12.47
PARLEYS DISTRIBUTION-UNA TTEN 46.12.
PELICAN POINT DISTRIBUTION-UNATTEN 46.12.
PINE CANYON DISTRIBUTION-UNA TTEN 132.12.47
PINE CREEK DISTRIBUTION-UNATTEN 46.12.
PINNACLE DISTRIBUTION-UNA TTEN 46.12.
PLAIN CITY DISTRIBUTION-UNA TTEN 138.12.
PLEASANT GROVE DISTRIBUTION-UNATTEN 46.12.
PLEASANT VIEW DISTRIBUTION-UNA TTEN 46.12.
PROMONTORY DISTRIBUTION-UNA TTEN 46.12.
QUAIL CREEK DISTRIBUTION-UNATTEN 34.12.
QUARRY DISTRIBUTION-UNA TTEN 138.12.47
QUITCHAPA DISTRIBUTION-UNATTEN 34.12.
RAINS DISTRIBUTION-UNATTEN 46.
RASMUSON DISTRIBUTION-UNATTEN 46.12.
RATTLESNAKE DISTRIBUTION-UNATTEN 69.24.
RED MOUNTAIN DISTRIBUTION-UNA TTEN 69.34.
RED ROCK DISTRIBUTION-UNA TTEN 69.
REDWOOD DISTRIBUTION-UNA TTEN 46.12.
RESEARCH PARK DISTRIBUTION-UNA TTEN 46.12.
RICHFIELD DISTRIBUTION-UNA TTEN 46.12.
RIDGELAND DISTRIBUTION-UNA TTEN 138.12.
RITER DISTRIBUTION-UNATTEN 46.12.
ROCK CANYON DISTRIBUTION-UNATTEN 69.12.47
ROCKVILLE DISTRIBUTION-UNATTEN 34.12.
ROCKY POINT DISTRIBUTION-UNA TTEN 138.13.
ROSE PARK DISTRIBUTION-UNATTEN 46.12.
ROYAL DISTRIBUTION-UNATTEN 46.
SALINA DISTRIBUTION-UNATTEN 46.12.
SANDY DISTRIBUTION-UNA TTEN 138.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04
(2) 0 A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
SARATOGA DISTRI BUTION-UNA TTEN 138.12.
SCIPIO DISTRIBUTION-UNATTEN 46.12.
SCOFIELD RESERVOIR DISTRIBUTION-UNATTEN 46.
SCOFIELD DISTRIBUTION-UNA TTEN 46.12.47
SECOND STREET DISTRIBUTION-UNA TTEN 46.12.
SEVEN MILE DISTRIBUTION-UNA TTEN 46.12.
SHARON DISTRIBUTION-UNA TTEN 46.12.
SHIVWITS DISTRIBUTION-UNA TTEN 34.
SIXTH SOUTH DISTRIBUTION-UNA TTEN 46.12.
SKULL POINT DISTRIBUTION-UNA TTEN 46.12.
SNARR DISTRIBUTION-UNA TTEN 46.12.47
SNOWVILLE DISTRIBUTION-UNA TTEN 69.12.
SNYDERVILLE DISTRIBUTION-UNA TTEN 138.12.
SOLDIER SUMMIT DISTRIBUTION-UNA TTEN 69.12.
SOUTH JORDAN DISTRIBUTION-UNATTEN 138.12.47
SOUTH MILFORD DISTRIBUTION-UNA TTEN 46.12.
SOUTH MOUNTAIN DISTRIBUTION-UNATTEN 138.12.
SOUTH OGDEN DISTRIBUTION-UNATTEN 46.12.
SOUTH PARK DISTRIBUTION-UNA TTEN 46.12.
SOUTH WEBER DISTRI BUTION-UNA TTEN 138.12.
SOUTH YARD DISTRIBUTION-UNA TTEN 46.
SOUTHEAST DISTRI BUTION-UNA TTEN 46.
SOUTHWEST DISTRIBUTION-UNA TTEN 46.12.
SPANISH VALLEY DISTRIBUTION-UNATTEN 69.12.47
SPRINGDALE DISTRIBUTION-UNATTEN 34.12.
ST. JOHNS DISTRIBUTION-UNATTEN 46.12.
STAIRS DISTRIBUTION-UNA TTEN 12.47
STANSBURY DISTRIBUTION-UNA TTEN 46.12.
SUMMIT CREEK DISTRIBUTION-UNA TTEN 138.12.
SUMMIT PARK DISTRIBUTION-UNA TTEN 46.12.
SUNRISE DISTRI BUTION-UNA TTEN 138.12.
SUPERIOR DISTRIBUTION-UNA TTEN 69.12.
SUTHERLAND DISTRIBUTION-UNA TTEN 46.12.
TABIONA DISTRIBUTION-UNA TTEN 69.12.
TAYLOR DISTRIBUTION-UNA TTEN 46.12.47
THIEF CREEK DISTRIBUTION-UNA TTEN 138.24.
THIRD WEST DISTRIBUTION-UNA TTEN 46.12.
THIRTEENTH SOUTH DISTRIBUTION-UNA TTEN 46.12.47
THOMPSON DISTRIBUTION-UNATTEN 46.
TOQUERVILLE DISTRIBUTION-UNATTEN 69.12.34.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04
(2) Fi A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties. and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) n A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 TRI CITY DISTRI BUTION-UNA TTEN 138.12.
TWENTYTHIRD STREET DISTRIBUTION-UNA TTEN 46.12.
UINTAH DISTRIBUTION-UNATTEN 46.12.47
UNION DISTRIBUTION-UNATTEN 46.12.
UNIVERSITY DISTRIBUTION-UNA TTEN 46.
VALLEY CENTER DISTRIBUTION-UNATTEN 46.12.47
VERMILLION DISTRIBUTION-UNATTEN 46.12.
8 VERNAL DISTRIBUTION-UNATTEN 69.12.
9 VEYO HYDRO DISTRIBUTION-UNA TTEN 34.
VICKERS DISTRIBUTION-UNA TTEN 46.12.
VINEYARD DISTRIBUTION-UNATTEN 46.12.
WALFARE DISTRIBUTION-UNA TTEN 46.12.
WALLSBURG DISTRIBUTION-UNA TTEN 138.12.47
WARREN DISTRIBUTION-UNA TTEN 138.12.47
WASATCH STATE PARK DISTRIBUTION-UNA TTEN 46.12.
WASHAKIE DISTRIBUTION-UNA TTEN 138.
WELBY DISTRIBUTION-UNATTEN 46.12.
WELLINGTON DISTRI BUTION-UNA TTEN 46.12.47
WEST COMMERCIAL DISTRIBUTION-UNA TTEN 46.12.47
WEST JORDAN DISTRIBUTION-UNATTEN 138.12.
WEST OGDEN DISTRI BUTION-UNA TTEN 138.12.47
WEST ROY DISTRIBUTION-UNA TTEN 46.12.
WEST TEMPLE DISTRIBUTION-UNA TTEN 46.
WESTFIELD DISTRIBUTION-UNA TTEN 138.12.
WESTWATER DISTRIBUTION-UNA TTEN 69.12.
WHITE MESA DISTRIBUTION-UNA TTEN 69.12.47
WILLOWCREEK DISTRI BUTION-UNA TTEN 46.12.
WILLOWRIDGE DISTRIBUTION-UNA TTEN 46.12.47
WINCHESTER HILLS DISTRIBUTION-UNA TTEN 34.12.
WINKLEMAN DISTRIBUTION-UNATTEN 46.
WOLF CREEK DISTRIBUTION-UNA TTEN 69.12.47
WOOD CROSS DISTRIBUTION-UNA TTEN 46.12.
WYUTA DISTRIBUTION-UNA TTEN 46.12.
Total 18440.3428.138.
NUMBER OF SUBSTATIONS DIST UNATTENDED - 282
ANGEL T/D-UNATTENDED 138.12.47 46.
BUTLERVILLE T/D-UNATTENDED 138.46.12.47
COTTONWOOD T/D-UNATTENDED 138.12.46.
HALE TID-UNATTENDED 138.46.12,
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) riA Resubmission 03/20/2006
SUBSTATIONS (Continued)
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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)
(g)
(h)(i)(k)
4855 420
135
175
289
114
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
HIGHLAND T/D-UNATTENDED 138.12.46.
JORDAN T/D-UNATTENDED 138.46.12.47
JUDGE T/D-UNATTENDED 46.12.
MCCLELLAND T/D-UNATTENDED 138.46.12.
OQUIRRH T/D-UNATTENDED 138.46.12.
PARRISH T/D-UNATTENDED 138.12.46.
PIONEER PLANT T/D-UNATTENDED 138.46.
RIVERDALE T/D-UNATTENDED 138.46.12.
SEVIER T/D-UNATTENDED 138.46.12.47
SILVER CREEK T/D-UNATTENDED 138.12.46.
SPHINX T/D-UNATTENDED 46.12.
SYRACUSE T/D-UNA TTENDED 138.46.12.47
TAYLORSVILLE T/D-UNATTENDED 138.46.12.
TERMINAL TID-UNATTENDED 345.12.46.
TIMP TID-UNATTENDED 138.46.12.
TOOELE T/D-UNATTENDED 138.46.12.47
WEST VALLEY T/D-UNATTENDED 138.12.
Total 2921.620.459.
NUMBER OF SUBSTATIONS T/D UNATTENDED - 21
BLUNDELL PLANT TRANSMISSION-ATTEND 46.12.
CARBON PLANT TRANSMISSION-ATTEND 138.13.
EMERY TRANSMISSION-ATTEND 138.69.
GADSBY PLANT TRANSMISSION-ATTEND 138.13.46.
GADSBY TRANSMISSION-ATTEND 138.46.
HUNTER PLANT TRANSMISSION-ATTEND 345.23.
HUNTINGTON PLANT TRANSMISSION-ATTEND 345.23.
Total 1288.138.115.
NUMBER OF SUBSTATIONS TRANS ATTENDED - 7
90TH SOUTH TRANSMISSION-UNA TTEN 345.138.
ABAJO TRANSMISSION-UNA TTEN 138.69.
ASHLEY TRANSMISSION-UNA TTEN 138.46.
BARNEY TRANSMISSION-UNATTEN 138.46.
BEN LOMOND TRANSMISSION-UNA TTEN 345.230.138.
BLACKHAWK TRANSMISSION-UNA TTEN 138.69.46.
BOOKCLIFFS TRANSMISSION-UNATTEN 69.46.
CAMERON TRANSMISSION-UNATTEN 138.46.
CAMP WILLIAMS TRANSMISSION-UNA TTEN 345.138.12.
CARBON TRANSMISSION-UNA TTEN 46.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) 0 A Resubmlssion 03/20/2006
SUBSTATIONS (Continued)
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.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(f)
(In MVa)
(Q)(h)(i)(k)
164
340
135
180
100
200
358
1108
130
158
3912
225
783
568
318
1513
981
4413
1538
133
100
1813
100
169
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information call~d for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
COLUMBIA TRANSMISSION-UNA TTEN 138.46.
CRICKET MOUNTAIN REG STA TRANSMISSION-UNA TTEN 46.46.
CUTLER TRANSMISSION-UNA TTEN 138.46.
EL MONTE TRANSMISSION-UNATTEN 138.46.
GARKANE TRANSMISSION-UNA TTEN 69.46.
GRINDING TRANSMISSION-UNA TTEN 138.13.
HELPER TRANSMISSION-UNATTEN 138.46.
HONEYVILLE TRANSMISSION-UNA TTEN 138.46.
9 HORSESHOE TRANSMISSION-UNATTEN 138.46.12.
HUNTINGTON TRANSMISSION-UNA TTEN 345.138.69.
JERUSALEM TRANSMISSION-UNATTEN 138.46.
LAMPO TRANSMISSION-UNATTEN 138.46.
MCFADDEN TRANSMISSION-UNA TTEN 138.46.
MIDDLETON TRANSMISSION-UNA TTEN 138.69.34.
MIDVALLEY TRANSMISSION-UNATTEN 345.138.
MIDWAY CITY TRANSMISSION-UNA TTEN 138.46.
MINERAL PRODUCTS TRANSMISSION-UNA TTEN 69.46.
MOAB TRANSMISSION-UNA TTEN 138.69.
NEBO TRANSMISSION-UNATTEN 138.46.
OLMSTED TRANSMISSION-UNATTEN 46.
PAROWAN VALLEY TRANSMISSION-UNATTEN 230.138.34.
PAVANT TRANSMISSION-UNA TTEN 230.46.
PINTO TRANSMISSION-UNATTEN 345.138.69.
RED BUTTE TRANSMISSION-UNA TTEN 230.138.
SAND COVE HYDRO TRANSMISSION-UNA TTEN 34.
SIGURD TRANSMISSION-UNA TTEN 345.230.138.
SPANISH FORK TRANSMISSION-UNA TTEN 345.138.46.
UPPER BEAVER HYDRO TRANSMISSION-UNA TTEN 46.
WEBER PLANT TRANSMISSION-UNA TTEN 46.
WEST CEDAR TRANSMISSION-UNA TTEN 230.138.34.
Total 6773.2877.634.
NUMBER OF SUBSTATIONS TRANS UNATTENDED - 40
Washington
ATTALIA DISTRIBUTION-UNATTEN 69.12.47
BOWMAN DISTRIBUTION-UNA TTEN 69.12.
CASCADE KRAFT DISTRIBUTION-UNA TTEN 69.12.
CLINTON DISTRIBUTION-UNA TTEN 115.12.
DAYTON DISTRIBUTION-UNA TTEN 69.12.
DODD ROAD DISTRIBUTION-UNA TTEN 69.20.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
313
225
142
270
141
900
138
133
258
400
1124
1017
131
9846
117
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) 0 A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
GRANDVIEW DISTRIBUTION-UNA TTEN 115.12.47 69.
HOPLAND DISTRIBUTION-UNATTEN 115.12.
MILL CREEK DISTRIBUTION-UNA TTEN 69.12.
NACHES HYDRO DISTRIBUTION-UNA TTEN 115.12.
5 NOB HILL DISTRIBUTION-UNA TTEN 115.12.
NORTH PARK DISTRIBUTION-UNA TTEN 115.12.
7 ORCHARD DISTRIBUTION-UNA TTEN 115.12.
8 PACIFIC DISTRI BUTION-UNA TTEN 115.12.
9 POMEROY DISTRIBUTION-UNA TTEN 69.12.
PROSPECT POINT DISTRIBUTION-UNA TTEN 69.12.
PUNKIN CENTER DISTRI BUTION-UNA TTEN 115.12.
RIVER ROAD DISTRIBUTION-UNA TTEN 115.12.47
13'SELAH DISTRIBUTION-UNATTEN 115.12.
SULPHUR CREEK DISTRIBUTION-UNATTEN 115.12.47
SUNNYSIDE DISTRIBUTION-UNATTEN 115.12.
TIETON DISTRIBUTION-UNATTEN 115.12,34.
TOPPENISH DISTRIBUTION-UNATTEN 115.12.
TOUCHET DISTRI BUTION-UNA TTEN 69.12.47
VOELKER DISTRIBUTION-UNATTEN 115.12.
WAITSBURG DISTRIBUTION-UNA TTEN 69.12.
WAPATO DISTRI BUTION-UNA TTEN 115.12.
WENAS DISTRIBUTION-UNA TTEN 115.12.47
WHITE SWAN DISTRIBUTION-UNATTEN 115.12.
WILEY DISTRIBUTION-UNA TTEN 115.12.
Total 2990.382.107.
NUMBER OF SUBSTATIONS DIST UNATTENDED - 30
CENTRAL T/D-UNA TTENDED 69.12.
UNION GAP T/D-UNATTENDED 230.115.12.47
Total 299.127.12.
NUMBER OF SUBSTATIONS T/D UNATTENDED - 2
CONDIT PLANT TRANSMISSION-ATTEND 69.
MERWIN PLANT TRANSMISSION-ATTEND 115.13.
Total 184.15.
NUMBER OF SUBSTATIONS TRANS ATTENDED - 2
OUTLOOK TRANSMISSION-UNA TTEN 230.115.
PASCO TRANSMISSION-UNATTEN 115.69.
POMONA HEIGHTS TRANSMISSION-UNA TTEN 230.115.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) n A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
1071
348
362
183
196
125
300
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations
column (t).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
SWIFT 1 PLANT TRANSMISSION-UNA TTEN 230.13.
WALLA WALLA 230KV TRANSMISSION-UNA TTEN 230.69.
WALLULA TRANSMISSION-UNA TTEN 230.69.
YALE PLANT TRANSMISSION-UNA TTEN 115.13.
Total 1380.463.
NUMBER OF SUBSTATIONS TRANS UNATTENDED - 7
Wyoming
AIR BASE DISTRIBUTION-UNA TTEN 12.47
AMOCO SERVICE PIPE DISTRIBUTION-UNA TTEN 34.
ANTELOPE MINE DISTRIBUTION-UNA TTEN 230.34.
ASTLE STREET DISTRIBUTION-UNA TTEN 34.13.
BAILEY DOME DISTRIBUTION-UNA TTEN 57.12.
BAR X DISTRIBUTION-UNATTEN 230.34.
BELLAMY DISTRIBUTION-UNATTEN 57.12.
BID MUDDY DISTRIBUTION-UNA TTEN 69.12.
BIG PINEY DISTRIBUTION-UNA TTEN 69.24.
BLACKS FORK DISTRIBUTION-UNA TTEN 230.34.
BRIDGER PUMP DISTRIBUTION-UNATTEN 230.34.13.
BRYAN DISTRIBUTION-UNA TTEN 115.12.
BUFFALO TOWN DISTRIBUTION-UNA TTEN 20.
BYRON DISTRIBUTION-UNATTEN 34.
CASSA DISTRIBUTION-UNA TTEN 57.20.
CENTER STREET DISTRIBUTION-UNA TTEN 115.
CHAPMAN STATION DISTRIBUTION-UNA TTEN 46.12.
CHATHAM DISTRIBUTION-UNATTEN 34.
CHUKAR DISTRIBUTION-UNA TTEN 12.
CHURCH AND DWIGHT DISTRIBUTION-UNA TTEN 34.
COKEVILLE DISTRIBUTION-UNA TTEN 46.24.
COLUMBIA-GENEVA DISTRIBUTION-UNA TTEN 230.13.
COMMUNITY PARK DISTRIBUTION-UNATTEN 69.12.
CROOKS GAP DISTRIBUTION-UNA TTEN 34.12.
DEAVER TOWN DISTRIBUTION-UNATTEN 34.
DEER CREEK DISTRIBUTION-UNA TTEN 69.12.47
DJ COAL MINE DISTRIBUTION-UNA TTEN 69.34.
DOUGLAS DISTRIBUTION-UNA TTEN 57.
DRY FORK DISTRIBUTION-UNA TTEN 69.
ELK BASIN DISTRIBUTION-UNA TTEN 34.
EMIGRANT DISTRIBUTION-UNA TTEN 115.12.
EVANS DISTRIBUTION-UNA TTEN 69.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
ooort Is:
Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2) 0 A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease , give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT LIne
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(I)(k)
261
300
120
144
1289
150
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) n A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
EVANSTON DISTRIBUTION-UNA TTEN 138.12.47
FARMERS UNION DISTRIBUTION-UNA TTEN 34.
FIREHOLE DISTRIBUTION-UNA TTEN 230.34.
FORT CASPER DISTRIBUTION-UNA TTEN 69.12.
FORT SANDERS DISTRIBUTION-UNA TTEN 115.13.
FRANNIE DISTRIBUTION-UNA TTEN 230.34.
FRONTIER DISTRIBUTION-UNA TTEN 69,
GARDEN CITY DISTRIBUTION-UNA TTEN 46.12.
GARLAND DISTRIBUTION-UNA TTEN 230.34.
GLEN DO DISTRIBUTION-UNATTEN 57.
GRASS CREEK DISTRIBUTION-UNA TTEN 230.34.
GREAT DIVIDE DISTRIBUTION-UNA TTEN 115.34.
GREYBULL DISTRIBUTION-UNA TTEN 34.
HANNA DISTRIBUTION-UNA TTEN 34.12.
JACKALOPE DISTRIBUTION-UNA TTEN 115.12.
KEMMERER DISTRIBUTION-UNA TTEN 69.24.
KIRBY CREEK PUMPING STATION DISTRIBUTION-UNATTEN 34.
KIRBY CREEK DISTRIBUTION-UNA TTEN 34.
LANDER DISTRIBUTION-UNA TTEN 34.12.
LARAMIE DISTRIBUTION-UNATTEN 115.13.
LINCH DISTRIBUTION-UNA TTEN 69.13.
LITTLE MOUNTAIN DISTRIBUTION-UNA TTEN 230.34.
LOVELL DI STRIBUTION-UNA TTEN 34.
MANDERSON DISTRIBUTION-UNA TTEN 34.
MILL IRON DISTRIBUTION-UNA TTEN 34.13.
MILLS DISTRIBUTION-UNA TTEN 12.47
MOSS JUNCTION DISTRIBUTION-UNA TTEN 46.12.
MURPHY DOME DISTRIBUTION-UNATTEN 34.13.
NUGGETT DISTRIBUTION-UNA TTEN 69.
OPAL DISTRIBUTION-UNA TTEN 46.24.
ORIN DISTRIBUTION-UNA TTEN 57,12.
ORPHA DISTRIBUTION-UNATTEN 57.
PARCO DISTRIBUTION-UNATTEN 34.12.
PINEDALE DISTRIBUTION-UNA TTEN 69.24.
PITCHFORK DISTRIBUTION-UNA TTEN 69.24.
POINT OF ROCKS DISTRIBUTION-UNA TTEN 230.34.
POISON SPIDER DISTRIBUTION-UNA TTEN 69.
POLECAT DISTRIBUTION-UNA TTEN 34.12.
RAINBOW DISTRIBUTION-UNA TTEN 34.13.
RAVEN DISTRIBUTION-UNA TTEN 230,34.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
200
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
RED BUTTE DISTRIBUTION-UNA TTEN 69.12.
REFINERY DISTRI BUTION-UNA TTEN 115.12.
SAGE HILL DISTRIBUTION-UNATTEN 34.13.
SHOSHONI DISTRIBUTION-UNA TTEN 34.2.40
SINCLAIR PIPELINE FII DISTRI BUTION-UNA TTEN 34.
SLATE CREEK DISTRIBUTION-UNA TTEN 69.12.
SOUTH CODY DISTRIBUTION-UNA TTEN 69.24.
SOUTH ELK BASIN DISTRIBUTION-UNA TTEN 34.
SOUTH TRONA DISTRIBUTION-UNA TTEN 230.34.
SPRING CREEK DISTRIBUTION-UNA TTEN 115.13.
SVILAR DISTRI BUTION-UNA TTEN 34.
TEAPOT DISTRIBUTION-UNATTEN 69.12.
TEN MILE DISTRIBUTION-UNA TTEN 69.34.
THERMOPOLIS TOWN DISTRIBUTION-UNA TTEN 34.
THUNDER CREEK DISTRIBUTION-UNATTEN 57.12.
TIPTON FII DISTRIBUTION-UNATTEN 34.
VETERANS DISTRIBUTION-UNA TTEN 34.13.
WARM SPRINGS SPL-FII DISTRIBUTION-UNATTEN 115.
WELCH DISTRIBUTION-UNA TTEN 57.
WEST ADAMS DISTRIBUTION-UNA TTEN 34.
WESTERN CLAY DISTRIBUTION-UNATTEN 34.
WESTVACO DISTRIBUTION-UNATTEN 230.34.
WOODRUFF DISTRIBUTION-UNA TTEN 46.12.
WORLAND TOWN DISTRIBUTION-UNA TTEN 34.
WYOPO DISTRIBUTION-UNA TTEN 230.34.
Total 8069.1387.13.
NUMBER OF SUBSTATIONS DIST UNATTENDED- 97
LABARGE T/D-UNATTENDED 69.24.
BUFFALO T/D-UNA TTENDED 230.20.
HILLTOP TID-UNA TTENDED 115.34.20.
RIVERTON 230 T/D-UNATTENDED 230.12.34.
YELLOWCAKE TID-UNA TTENDED 230.34.
Total 874.127.55.
NUMBER OF SUBSTATIONS T/D UNATTENDED - 5
DAVE JOHNSTON 69KV TRANSMISSION-ATTEND 115.69.
DAVE JOHNSTON PLANT TRANSMISSION-ATTEND 230.115.69.
JIM BRIDGER 345KV TRANSMISSION-ATTEND 345.230.34.
JIM BRIDGER UNITS 1&2 TRANSMISSION-ATTEND 345.22.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04
(2) n A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
150
1672 181
148
214
1358
1084
1122
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
JIM BRIDGER UNITS 3&4 TRANSMISSION-ATTEND 345.22.
NAUGHTON TRANSMISSION-ATTEND 230.69.
WYODAK 230KV TRANSMISSION-ATTEND 230.69.
WYODAK PLANT TRANSMISSION-ATTEND 230.22.
Total 2070.551.172.
NUMBER OF SUBSTATIONS TRANS ATTENDED - 8
BAIROIL TRANSMISSION-UNA TTEN 115.34.57.
CASPER TRANSMISSION-UNATTEN 230.115.69.
CHAPPELL CREEK TRANSMISSION-UNATTEN 230.69.
FOOTE CREEK WIND FARM TRANSMISSION-UNA TTEN 230.34.
GLENDO AUTO TRANSMISSION-UNA TTEN 69.57.
MANSFACE TRANSMISSION-UNA TTEN 230.34.
MIDWEST TRANSMISSION-UNATTEN 230.69.34.
MINERS TRANSMISSION-UNA TTEN 230.115.34.
MUSTANG TRANSMISSION-UNA TTEN 230.115.
OREGON BASIN TRANSMISSION-UNA TTEN 230.34.69.
PLATTE TRANSMISSION-UNATTEN 230.115.34.
RAILROAD TRANSMISSION-UNATTEN 230.138,
ROCK SPRINGS 230 TRANSMISSION-UNA TTEN 230.34.
SAGE TRANSMISSION-UNA TTEN 69.46.
THERMOPOLIS TRANSMISSION-UNATTEN 230.115.
YELLOWTAIL TRANSMISSION-UNATTEN 230.161.
Total 3243.1287.298.
NUMBER OF SUBSTATIONS TRANS UNATTENDED -
CALIFORNIA
Distribution - 35
T/D - 3
Transmission - 9
IDAHO
Distribution - 74
T/D - 4
Transmission - 21
OREGON
Distribution - 195
TID - 10
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease , give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
1122
1232
503
6695
529
196
200
115
165
400
175
100
2281
243
129
446
864
314
2837
4446 397
1238
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PaclflCorp (1) X An Origillal (Mo. Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
Transmission - 40
UTAH
Distribution - 282
5 T/D - 21
Transmission - 47
8 WASHINGTON
Distribution - 30
T/D - 2
Transmission - 9
WYOMING
Distribution - 97
T/D - 5
Transmission - 24
ALL STATES
Distribution - 713
TID - 45
Transmission - 150
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PaclflCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) 0 A Resubmission 03/2.0/2006
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
6363 126
4855 420
3912
14259 132
1071
362
1485
1672 181
148
8976 119
13151 1223
6103 151
34366 490
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
!schedule Page: 426.10 Line No.Column:
The Dixonville 500kV Substation is jointly owned by the respondent and the Bonneville Power Administration ("the BP An
Ownership of the substation is as follows: PacifiCorp 50.0%, the BP A 50.0%. Operation and maintenance costs are shared between
the two arties and res onsibili is as follows: PacifiCo 58.0% and the BP A 42.0%.
chedule Pa e: 426.10 Line No.: 17 Column:
The Meridian 500kV Substation is jointly owned by the respondent and the Bonneville Power Administration ("the BP A"). Ownership
of the substation is as follows: PacifiCorp 50., the BP A 50.0%. Operation and maintenance costs are shared between the two
parties and responsibility is as follows: PacifiCorp 58.0%, and the BP A 42.0%.
IFERC FORM NO.1 (ED. 12-87)Page 450.
INDEX
Schedule Pace 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-
FERC FORM NO.1 (ED. 12-93)Index
INDEX (continued)
Schedule
Deferred
Paae No.
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 ".......................... 2~9
336-337
Directors ......................................................"~05
Discount - premium on long-term debt ..................................,..........................256-257
Distribution of salaries and wages ...............................................................354-355
Dividend appropriations "" ~~8-~~9
Earnings, Retained ............................................................................... ~~8-~~9
Electric energy account ......................................................"" 40~
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 ......................................................"~o~
Instructions for filing the FERC Form ~ ............................................................. i-
Generating plant statistics
hydroelectric (large) ........................................................................406-407
pumped storage (large) .......................................................................408-409
small plants ......................................................"
'"
4~0-4~~
steam-electric (large) "
.................
402-403Hydro-electric generating plant statistics ....................................................... 406-407
Identification ......................................................................,................ ~O~
Important changes during year ......................................................"~08-~09
Income
statement of , by departments ................................................................. ~~4-~~7
statement of, for the year (see also revenues) ............................................... ~~4-~~7
deductions, miscellaneous amortization ...........................................................340
deductions, other income deduction ...............................................................340
deductions, other interest charges ...............................................................340
Incorporation information ......................................................"~o~
FERC FORM NO.1 (ED. 12-95)Index
INDEX (continued)
Schedule PaQe 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 "
'"
J.22-J.23
to statement of changes in financial position "" J.22-J.23
to statement of income "............,.... J.22-J.23
to statement of retained earnings ............................................................ 122-J.23
Nonutility property .................................................................................. 22J.
Nuclear fuel materials ...........................................................................202-203
Nuclear generating plant, statistics .............................................................402-403
Officers and officers' salaries ...................................................................... J.04
Operating
expenses -electric
expenses-electric
Other
............................................................................
320-323
(summary) ......................................................................323
paid-in capital ..................................................................................253
donations received from stockholders .............................................................253
gains on resale or cancellation of reacquired
capital stock ....................................................................................253miscellaneous paid-in capital ....................................................................253
reduction in par or stated value of capital stock ................................................ 253
regulatory assets ................................................................................232
regulatory liabilities ...........................................................................278
Peaks, monthly, and output ........................,...........................................,...... 40J.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
40J.-429
FERC FORM NO.1 (ED. 12-95)Index
INDEX (continued)
SchedulePlant-electric
Paae No.
accumulated provision for depreciation ........................................,.................. 2~9
construction work in progress ................................................,.......,........... 2~6
held for future use ...............................................,.............................. 2~4
in service ...................................................................................204-207
leased to others ............................,.................................................... 2~3
Plant - utility and accumulated provisions for depreciation
amortization and depletion (summary) "....... 20~
Pollution control facilities, accumulated deferred
income taxes .....................................................................................234
Power Exchanges .......,..........................................................................326-327
Premium and discount on long-term debt ......................................,........................256
Premium on capital stock ....................................................,........................ 25~
Prepaid taxes .............................
:......................................................
262-263
Property - losses, extraordinary "
...............
230Pumped 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 ...............................................,......"" 26~
Regulatory commission expenses deferred "
........
233
Regulatory commission expenses for year .............................,............................ 350,..35~
Research, development and demonstration activities ....................,.......................... 352-353
Retained Earnings
amortization reserve Federal ............,........................................."'" ~~9
appropriated "
statement of , for the year ...................................................................
unappropriated "
............................................,.............,............
Revenues - electric operating .....................,................................"
118-119
118-119
118-119
300-30~
Salaries and wages
directors fees "
'"
~05
distribution of "
'..........................................,..........................
354-355
officers
' "
~04
Sales of electricity by rate schedules ...............................................................304
Sales - for resale ...............................................................,............... 3~0-3~~
Salvage - nuclear fuel "
.....................
202-203
Schedules, this report form "
....................
Securities
exchange registration ".................. 250-25~
Statement of Cash Flows ".................... ~20-~21
Statement of income for the year .........................,....................................... ~~4-~~7
Statement of retained earnings for the year ...........................,.......................... ~~8-~~9Steam-electric generating plant statistics .............................,......................... 402-403
Substations ..........................................................................................426
Supplies - materials and "
.......................
227
FERC FORM NO.1 (ED. 12-90)Index
INDEX (continued)
Schedule Pace 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
FERC FORM NO.1 (ED. 12-90)Index
Page
Number
3 - 6
11-
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM for
MULTI-STATE ELECTRIC COMPANIES
, ', ;;), .
i" i
, , - , "
'" '- l, ,, i, 'i ,::; .) ; l) i ,
INDEX
Title
Statement of Utility Operating Income for the Year
Electric Operating Revenues
Electric Operation and Maintenance Expenses
Depreciation and Amortization Expenses
Taxes , Other Than Income Taxes
Non Utility Property Listing
Summary of Allocated Utility Plant and Reserves
Allocated Utility Plant by Account
Allocated Materials and Supplies
M 559 (11000) (12/96)PaQe i
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
dba Utah Power & Light (2) A resubmission Dec. 31 , 2005
STATE OF IDAHO STATEMENT OF OPERATING INCOME FOR THE YEAR
ELECTRIC UTILITY
Line ACCOUNT (Ref)
No.Page
No.Current Year Previous Year
(a)(b)(c)(d)
UTILITY OPERATING INCOME
Operating Revenues (400)172,412 536 152,426 569
Operating Expenses
Operation Expenses (401)92,458,050 022,432
Maintenance Expenses (402)962 196 294 555
Depreciation Expenses (403)090,841 208 083
Amort. & Depl. Of Utility Plant (404-405)812 650 022,413
Amort. Of Utility Plant Acq. Adj (406)353 220 349,496
Amort. Of Property Losses, Unrecovered
Plant and Regulatory Study Costs (407)135 622 388,149
Amort. Of Conversion Expenses (407)
Taxes Other Than Income Taxes (408.587 834 4,400,789
Income Taxes - Federal (409.942 973 093
Other (409.517 263 (106 563)
Provision for Deferred Inc. Taxes (410.19,678,000 193 522
Provision for Deferred Income Taxes - Cr. (411.(16 867 961)(21 671 079)
InvestmentTax Credit Adj. - Net (411.4)(780 533)(769 670)
(Gains) from Disp. Of Utility Plant (411.
Losses from Disp. Of Utility Plant (411.874
(Gains) from emission allowances 084 797)(61 823)
(Gains) Loss on sale of Utility plant 113)(12 157)
TOTAL Utility Operating Expenses
(Enter Total of Lines thru 20)144 806 119 122 353 240
Net Utility Operating Income (Enter Total
line less 21)606,417 073,329
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Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) An Original (Mo, Da , Yr)
dba Utah Power & Light (2) A resubmission Dec. 31 2005
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES -IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
1. POWER PRODUCTION EXPENSES
A. Steam Power Generation
Operation
(500) Operation Supervision and Engineering 542 926 223 279
(501) Fuel 606 735 232 166
(502) Steam Expenses 228 581 060,847
(503) Steam from Other Sources 281 581 283 064
(Less) (504) Steam Transferred - Cr.
(505) Electric Expenses 255 892 191 830
(506) Miscellaneous Steam Power Expenses 109,273 079 393
(507) Rents 790 132 542
TOTAL Operation (Enter Total of lines 12 thru 19)36,081 778 203 121
Maintenance
(510) Maintenance Supervision and Engineering 466 785 483 171
(511) Maintenance of Structures 075 152 138 860
(512) Maintenance of Boiler Plant 673 055 382,442
(513) Maintenance of Electric Plant 989,167 911 717
(514) Maintenance of Miscellaneous Steam Plant 603 126 613 073
TOTAL Maintenance (Enter Total of lines 14 thru 18)807 285 529 263
TOTAL Power Production Expenses - Steam Power (Enter Total of lines 12 thru 19)889 063 732 384
B. Nuclear Power Generation
Operation
(517) Operation Supervision and Engineering
(518) Fuel
(519) Coolants and Water
(520) Steam Expenses
(521) Steam from Other Sources
(Less) (522) Steam Transferred - Cr.
(523) Electric Expenses
(524) Miscellaneous Nuclear Power Expenses
(525) Rents
TOTAL Operation (Enter Total of lines 23 thru 31)
Maintenance
(528) Maintenance Supervision and Engineering
(529) Maintenance of Structures
(530) Maintenance of Reactor Plant Equipment
(531) Maintenance of Electric Plant
(532) Maintenance of Miscellaneous Nuclear Plant
TOTAL Maintenance (Enter Total of lines 34 thru 38)
TOTAL Power Production Expenses - Nuclear Power (Enter Total of lines 32 thru 39)
C. Hydraulic Power Generation
Operation
(535) Operation Supervision and Engineering 286 787 306 553
(536) Water fo Power 030 794
(537) Hydraulic Expenses 282 144 278 812
(538) Electric Expenses 353 407
(539) Miscellaneous Hydraulic Power Generation Expenses 126,594 034 138
(540) Rents 315 5,414
TOTAL Operation (Enter Total of lines 43 thru 48)718,223 634 118
IDAHO SUPPLEMENTAL Page 3
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
dba Utah Power & Light (2) A resubmission Dec. 31 2005
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES -IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
C. Hydraulic Power Generation (Continued)
Maintenance
(541) Maintenance Supervision and Engineering
(542) Maintenance of Structures 146 363
(543) Maintenance of Reservoirs, Dams, and Waterways 123 761 141 811
(544) Maintenance of Electric Plant 163,567 117 976
(545) Maintenance of Miscellaneous Hydraulic Plant 166,487 206 205
TOTAL Maintenance (Enter Total of lines 52 thru 56)523 961 551 355
TOTAL Power Production Expenses - Hydraulic Power (Enter Total of lines 49 thru 57)242 184 185,473
D. Other Power Generation
Operation
(546) Operation Supervision and Engineering 079 551
(547) Fuel 224 881 681 206
(548) Generation Expenses 687 796 617 376
(549) Miscellaneous Other Power Generation Expenses 95,011 626
(550) Rents 211 713 186 035
TOTAL Operation (Enter Total of lines 61 thru 65)260,480 581 794
Maintenance
(551) Maintenance Supervision and Engineering
(552) Maintenance of Structures 13,402 688
(553) Maintenance of Generation and Electric Plant 837 808
(554) Maintenance of Miscellaneous Other Power Generation Plant 109 790
TOTAL Maintenance (Enter Total of lines 68 thru 71)130 348 286
TOTAL Power Production Expenses - Other Power (Enter Total of lines 66 thru 72)390 828 632 080
E. Other Power Supply Expenses
(555) Purchased Power 243 052 738 137)
(556) System Control and Load Dispatching 567 112 733
(557) Other Expenses 093 820 257 668
TOTAL Other Power Supply Expenses (Enter Total of lines 75 thru 77)18,430,439 367 736)
TOTAL Power Production Expenses - (Enter Total of lines 20 , 58, 73 and 78)952 514 182 201
2. TRANSMISSION EXPENSES
Operation
(560) Operation Supervision and Engineering 416 253 260 641
(561) Load Dispatching 290 888 323 550
(562) Station Expenses 705 141
(563) Overhead Line Expenses 141 097 149 555
(564) Underground Line Expenses
(565) Transmission of Electricity by Others 383 141 918 549
(566) Miscellaneous Transmission Expenses 353 578
(567) Rents 130 794 665
TOTAL Operation (Enter Total of lines 82 thru 89)6,411 231 757 679
Maintenance
(568) Maintenance Supervision and Engineering 753 295
(569) Maintenance of Structures
(570) Maintenance of Station Equipment 420 314 499,427
(571) Maintenance of Overhead Lines 553 604 457 360
(572) Maintenance of Underground Lines 425 951
(573) Maintenance of Miscellaneous Transmission Plant 654 956
TOTAL Maintenance (Enter Total of lines 92 thru 97)029 756 971 019
TOTAL Transmission Expenses (Enter Total of ilnes 90 and 98)440 987 728 698
100 3. DISTRIBUTION EXPENSES
101 Operation
102 (580) Operation Supervision and Engineering 070,777 117 913
103 (581) Load Dispatching 438 649 326 521
iDAHO SUPPLEMENTAL Page 4
Name of 'Respondent'This Report Is:Date of Report Year of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
dba Utah Power & Light (2) - A resubmission Dec. 31 2005
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES -IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
104 3 DISTRIBUTION EXPENSES (Continued)
105 (582) Station Expenses 251 857 143 347
106 (583) Overhead Line Expenses 976 827 320,916
107 (584) Underground Line Expenses 27,459 549
108 (585) Street Lighting and Signal System Expenses 644 899
109 (586) Meter Expenses 296 976 351 930
110 (587) Customer Installations Expenses 791 658
111 (588) Miscellaneous Distribution Expenses 989,416 264 933
112 (589) Rents 111 70,395
113 TOTAL Operation (Enter Total of lines 102 thru 112)099 507 624 061
114 Maintenance
115 (590) Maintenance Supervision and Engineering (104)222
116 (591) Maintenance of Structures 88,894 133 619
117 (592) Maintenance of Station Equipment 483 601 365 230
118 (593) Maintenance of Overhead Lines 029,367 893 095
119 (594) Maintenance of Underground Lines 595 740 779 793
120 (595) Maintenance of Line Transformers 748 45,079
121 (596) Maintenance of Street Lighting and Signal Systems 118 740 152 676
122 (597) Maintenance of Meters 250,167 272 055
123 (598) Maintenance of Miscellaneous Distribution Plant 723 572 275 921
124 TOTAL Maintenance (Enter Total of lines 115 thru 123)295 725 933 690
125 TOTAL Distribution Expenses (Enter Total oflinesll3 and 124)395 232 557 751
126 4. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
127 Operation
128 (901) Supervision 362,425 458,877
129 (902) Meter Reading Expenses 207 773 067,465
130 (903) Customer Records and Collection Expenses 035 554 988,422
131 (904) Uncollectible Accounts (151 567)168 950
132 (905) Miscellaneous Customer Accounts Expenses 546 44,407
133 TOTAL Customer Accounts Expenses (Enter Total of linesl2S and 132)498 731 728 121
134 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
135 Operation
136 (907) Supervision 117 070 155,437
137 (908) Customer Assistance Expenses 320,090 219,012
138 (909) Informational and Instructional Expenses 198 554
139 (910) Miscellaneous Customer Service and Informational Expenses 056 180
140 TOTAL Cust. Service and Informational Exp. (Enter Total of lines 136 thru 139)1,478,414 1,441 183
141 6. SALES EXPENSES
142 Operation
143 (911) Supervision
144 (912) Demonstrating and Selling Expenses
145 (913) Advertising Expenses
146 (916) Miscellaneous Sales Expenses
147 TOTAL Sales Expenses (Enter Total of lines 143 thru 146)
148 7. ADMINISTRATIVE AND GENERAL EXPENSES
149 Operation
150 (920) Administrative and General Salaries 132 260 6,475 962
151 (921) Office Supplies and Expense 713,722 948,060
152 (Less) (922) Administrative Expenses Transferred - Cr.717 085)516 855)
153 (923) Outside Services Employee 657 616 165 703
154 (924) Property Insurance 214,477 851 341
155 (925) Injuries and Damages 650 371 707 758
156 (926) Employee Pensions and Benefits 891)876
157
IDAHO SUPPLEMENTAL Page 5
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
dba Utah Power & Light (2) - A resubmission Dec. 31 2005
ALLOCATED ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) -IDAHO
If the amount for previous year is not derived from previously reported figures, explain in footnotes.
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
157 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
158 (927) Franchise Requirements
159 (928) Regulatory Commission Expenses 437 124 352 947
160 (929) Duplicate Charges - Cr.(919,787)(905 784)
161 (930.1) General Advertising Expenses
162 (930.2) Miscellaneous General Expenses 844 618 940 649
163 (931) Rents 467 822 398,434
164 TOTAL Operation (Enter Total of lines 150 thru 163)479 247 14,420,091
165 Maintenance
166 (935) Maintenance of General Plant 175 121 258,941
167 TOTAL Administrative and General Expenses (Enter Total of lines 164 thru 166)654 368 679 032
168 TOTAL Electric Operation and Maintenance Expenses (Enter Total of lines 79 , 125
133,140 147, and 167)109 420 246 316 987
SUMMARY OF ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
Line Functional Classifications Operation Maintenance Total
No.(a)(b)(c)(d)
169 Power Production Expenses
170 Electric Generation:
171 Steam Power 081 778 807 285 889 063
172 Nuclear Power
173 Hydraulic -Conventional 718 223 523 961 242 184
174 Hydraulic - Pumped Storage 260 480 130 348 390 828
175 Other Power Supply Expenses 430 439 18,430,439
176 Total Power Production Expenses 62,490 920 10,461 594 952 514
177 Transmission Expenses 411 231 029 756 7,440 987
178 Distribution Expenses 099 507 295 725 395 232
179 Customer Accounts Expenses 3,498 731 3,498,731
180 Customer Service and Informational Expenses 1,478,414 1,478,414
181 Sales Expenses
182 Adm. and General Expenses 14,479 247 175 121 654 368
183 Total Electric Operation and Maintenance Expenses 92,458 050 16,962 196 109,420 246
IDAHO SUPPLEMENTAL Page 6
STATE OF IDAHO - ALLOCATED
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1)An Original (Mo, Da, Yr)
dba Utah Power & Light (2)A resubmission Dec. 31 , 2005
DEPRECIATION AND AMORTIZATION OF ELECTRIC PALNT (Accounts 403, 404, 405)
(Except amortization of acquisition adjustments)
A. Summary of Depreciation and Amortization Charges
Line Depreciation Amortization of Amortization of
No.Functional Classification Expense Limited-Term Electric Other Electric Total
(Account 403)Plant (Acct. 404)Plant (Acct. 405)
(a)(b)(c)(d)(e)
Intangible Plant 722 722 722 722
Steam Production Plant 729 352 970 816 322
Nuclear Production Plant
Hydraulic Production Plant - Conventional 836 948 836 948
Hydraulic Production Plant - Pumped Storage
Other Production Plant 830,472 958 833,430
Transmission Plant 399,437 399,437
Distribution Plant 918,485 918,485
General Plant 376 146 376 146
Common Plant - Electric
TOTAL 090 841 812 650 903,491
IDAHO SUPPLEMENTAL Page 7
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1)An Original (Mo, Da, Yr)
dba Utah Power & Light (2) - A resubmission Dec. 31 2005
KIND OF TAX AMOUNT
Property 101 607
Other 486 227
Total ( Must agree with page 1 , line 11.587 834
STATE OF IDAHO - ALLOCTED
TAXES, OTHER THAN INCOME TAXES
ACCOUNT 408.
IDAHO SUPPLEMENTAL Page 8
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Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) L- An Original (Mo, Da, Yr)
dba Utah Power & Light (2) A resubmission Dec. 31 , 2005
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Line Amount for Amount for
No.Account Current Year Previous Year
(a)(b)(c)
UTILITY PLANT
In Service
Plant In Service (Classified)831 940 676 806 305 539
Property Under Capital Lease (1)
Plant Purchased or Sold
Completed Construction not Classified 015,845 356 889
Experimental Plant Unclassified
Total (Enter Total of Lines 3 through 7)832 956,521 807 662,428
Leased To Others
Held for Future Use 910 72,496
Construction Work In Process 352 981 5,465 332
Acquisition Adjustments 133 313 629,821
Total Utility Plant (Enter Total of Lines 8 through 12)849 512 725 818 830 077
Accumulated Provision for Depreciation, Amortization & Depletion 372 669,180 356 950 253
Net Utility Plant (Enter Total of Line 13 less Line 14)476 843 545 461 879 824
DETAIL OF ACCUMULATED PROVISION FOR DEPRECIATION , AMORTIZATION AND
DEPLETION
In Service
Depreciation 348,532 849 339 272 027
AmortizationlDepletion of Producing Natural Gas Land And Land Rights
Amortization of Underground Storage Land and Land Rights
Amortization of Other Utility Plant 516 222 678 226
Total In Service (Enter Total of Lines 18 through 21)368 049 071 356 950 253
Leased To Others
Depreciation
Amortization And Depletion
Total Leased to Others (Enter Total of Lines 24 and 25)
Held for Future Use
Depreciation
Amortization
Total Held for Future Use (Enter Total of Lines 28 and 29)
Abandonment of Leases (Natural Gas)
Accumulated Provision for Asset Acquisition Adjustment 620,109
Total Accumulated Provisions (Should Agree With Line 14 above) (Enter Total of Lines
, 26, 20, 31 and 32)372 669,180 356,950 253
(1) Capitalized leases are not included in rate base, they are charged to operating expense.
IDAHO SUPPLEMENTAL Page 10
ELECTRIC PLANT IN SERVICE - STATE OF IDAHO (ALLOCATED)
(In addition to Account 101 , Electric Plant In Service (Classified), this schedule includes Account 102, Electric Plant
Purchased or Sold, Account 103, Experimental Electric Plant Unclassified and
Account 106, Completed Construction Not Classified-Electric.
1. Report below the original cost of electric plant in 3. Credit adjustments of plant accounts should be
service enclosed in parentheses to indicate the negative effect
according to prescribed accounts of such amounts.
2. Do not include as adjustments, corrections of
additions and retirements for the current of the
current or the preceding
year.
Line Balance at End of
No.Account Beginning Balance Year
(a)(b)
(g)
1. INTANGIBLE PLANT
(301) Organization 600 526 600 526
(302) Franchises and Consents 727 395 683,413
(303) Miscellaneous Intangible Plant 605 105 742 224
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)933 026 026,163
2. PRODUCTION PLANT
A Steam Production Plant
(310) Land and Land Rights 185 301 244,409
(311) Structures and Improvements 48,758,510 49,414 695
(312) Boiler Plant Equipment 158 244 865 162 240 660
(313) Engines and Engine Driven Generators
(314) Turbogenerator Units 706 573 999 296
(315) Accessory Electric Equipment 631 898 980 725
(316) Misc. Power Plant Equipment 619,406 615,222
TOTAL Steam Production Plant (Enter Total of lines 8 thru 14)278 146 553 284,495 007
B. Nuclear Production Plant
(320) Land and Land Rights
(321) Structures and Improvements
(322) Reactor Plant Equipment
(323) Turbogenerator Units
(324) Accessory Electric Equipment
(325) Misc. Power Plant Equipment
TOTAL Nuclear Production Plant (Enter Total of lines 17 thru 22)
C. Hydraulic Production Plant
(330) Land and Land Rights 260,967 272 156
(331) Structures and Improvements 954 978 103 909
(332) Reservoirs, Dams, and Waterways 375 315 896 925
(333) Water Wheels, Turbines, and Generators 094 923 294 621
(334) Accessory Electric Equipment 2,452 820 516,400
(335) Misc. Power Plant Equipment 203 104 205 537
(336) Roads, Railroads, and Bridges 794 153 836 302
TOTAL Hydraulic Production Plant (Enter Total of lines 25 thru 31)136 260 125 850
D. Other Production Plant
(340) Land and Land Rights 933 130 023
(341) Structures and Improvements 097 847 1,430 631
(342) Fuel Holders, Products, and Accessories 360 156 288 902
(343) Prime Movers 593 176 436,344
(344) Generators 992 997 657 126
(345) Accessory Electric Equipment 073,101 250 117
(346) Misc. Power Plant Equipment 111 457
TOTAL Other Production Plant (Enter Total of lines
34 thru 40)240 321 253 600
I U I AL t-'roauctlon t-'Iant It::nter lotal OT lines
and41)328 523 134 343 874,457
IDAHO SUPPLEME~Page 11
ELECTRIC PLANT IN SERVICE (Continued) STATE OF IDAHO (ALLOCATED)
Line Balance End of
No.Account Beginning Balance Year
(a)(b)
(g)
3. TRANSMISSION PLANT
(350) Land and Land Rights 646 191 686 358
(352) Structures and Improvements 117 663 241 662
(353) Station Equipment 55,427 664 56,834,436
(354) Towers and Fixtures 007 786 23,444 019
(355) Poles and Fixtures 762 331 955,372
(356) Overhead Conductors and Devices 298,145 348 371
(357) Underground Conduit 150 970 152 628
(358) Underground Conductors and Devices 251,446 254 165
(359) Roads and Trails 725 237 733 376
TOTAL Transmission Plant (Enter Total of lines
44 thru 52)158 387 433 162 650 387
4. DISTRIBUTION PLANT
(360) Land and Land Rights 162 007 162 007
(361) Structures and Improvements 773 572 764 294
(362) Station Equipment 138 149 168 992
(363) Storage Battery Equipment
(364) Poles, Towers, and Fixtures 116 996 48,417 355
(365) Overhead Conductors and Devices 30,491 306 907 691
(366) Underground Conduit 824 283 935 761
(367) Underground Conductors and Devices 19,445 864 776,721
(368) Line Transformers 53,520,662 595 390
(369) Services 587 025 19,469 714
(370) Meters 13,455 852 697 342
(371) Installations on Customer Premises 156 990 157 287
(372) Leased Property on Customer Premises 873 873
(373) Street Lighting and Signal Systems 530,400 540 970
TOTAL Distribution Plant (Enter Total of lines 55 thru 68)210 207 979 214 598 397
5. GENERAL PLANT
(389) Land and Land Rights 572 689 575 581
(390) Structures and Improvements 098 341 228 399
(391) Office Furniture and Equipment 736 083 886 537
(392) Transportation Equipment 335 791 826 670
(393) Stores Equipment 777 399 825 764
(394) Tools, Shop and Garage Equipment 024 287 306 556
(395) Laboratory Equipment 601,465 677,488
(396) Power Operated Equipment 134,402 658 530
(397) Communication Equipment 124 056 629 262
(398) Miscellaneous Equipment 321 045 332 161
SUBTOTAL (Enter Total of lines 71 thru 80)725 558 946 948
(399) Other Tangible Property 528,409 844 324
TOTAL General Plant (Enter Total of lines 81 thru 82)73,253 967 791 272
TOTAL (Accounts 101)806 305 539 831 940 676
(102) Electric Plant Purchased
Plant Sold
(103) Experimental Electric Plant Unclassified
(106) Plant Unclassified 356 889 015 845
TOTAL Electric Plant in Service 807 662,428 832 956 521
IDAHO SUPPLEMENl Page 12
Name of Respondent
PacifiCorp
dba Utah Power & Light
STATE OF IDAHO --ALLOCATED
This Report Is: Date of Report
(1) ..2L An Original (Mo, Da, Yr)
(2) A resubmission
MATERIALS AND SUPPLIES
1. For Account 154, report the amount of plant materials
and operating supplies under the primary functional
classifications as indicated in column (a); estimates of
amounts by function are acceptable. In column (d),
designate the department or departments which use the
class of material
Line
No.
ACCOUNT
(a)
Fuel Stock (Account 151)
Fuel Stock Expenses Undistributed (Account 152)
Residuals and Extracted Products (Account 153)
Plant Materials and Operating Supplies (Account 154)
Assigned to - Construction (Estimated)
Assigned to - Operations and Maintenance
Production Plant (Estimated)
Transmission Plant (Estimated)
Distribution Plant (Estimated)
Assigned to - Other
TOTAL Account 154 (Enter Total of lines 5 thru 10)
Merchandise (Account 155)
Other Materials and Supplies (Account 156)
Nuclear Materials Held for Sale (Account 157) (Not
applicable to Gas Utilities)
Stores Expense Undistributed (Account 163)
TOTAL Materials and Supplies (Per Balance Sheet)
IDAHO SUPPLEMENTAL
Year of Report
Dec. 31 2005
2. Give an explanation of important inventory adjustments
during year (on a supplemental page) showing general
classes of material and supplies and the various
accounts (operating expense, clearing accounts, plant
etc.) affected - debited or credited. Show separately
debits or credits to stores expense clearing, if
applicable.
Balance
Beginning of
Year
(b)
Page 13
Balance
End of Year
(c)
763 273
668 263
931 155
812 349
(319,322)
092 445
855 718
Department or
Departments
Which Use Material
(d)
Electric
Electric
Electric
Electric
Electric