2006Annual Report Part II.pdf

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Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2006/Q4(2) riA Resubmission 05/17/2007
~CHA~ED POWER hAccou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le.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:
RO - 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 RO 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.
as - 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)
Power Purchases
3 Phases Energy Services
AES SeaWest, Inc.
AlIa Energy LLC
,..,
AlIa Energy LLC
American Electric Power
...
Anaheim, City of
Anaheim, City of
Arizona Electric Power Cooperative
Arizona Public Service Co.
Arizona Public Service Co.
Arizona Public Service Co.
Arizona Public Service Co.
Avista Corp.
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 2oo6/Q4
(2) CiA Resubmission 05/17/2007
ccou ~~~L, ll,,;ontlnueoj(Including" power exc anges)
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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 (j+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
399,526
142 12~042 815,329
194
38~12,891 12,891
507 241:23,611 644 23,611,644
13,70,320.14€320,146
19~219,219,764
80(55,10(55,100
325,40(18.617,60f 18,617 608
309,75(926,926,997
99~243 73€243,736
426,905 21,121 13~21,121.133
58,830
918,949 373 073 13,736,640 113.105,200 971,945.158 377,596,202 707,454.15E
FERC FORM NO.1 (ED. 12-90)Page 327
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2006/04
(2) CiA Resubmission 05/17/2007
PU~CHA~ED POWER hAccount 555)(nclu Ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
RO - 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 RO 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.
as - 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 Avista Corp.
2 Avista Energy, Inc.
3 Avista Energy, Inc.
4 BP Energy Company
Ballard Hog Farms Inc.
6 Barclays Bank PLC
7 Barclays Bank PLC
8 Bear Energy LP
9 Beaver City
Bell Mountain Power
Benton County PUD No.
...
Biomass One. loP.
Biomass One, loP.22.19.4 15.
Birch Creek Hydro
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
This ~ort Is:(1) ~An Original
(2) A Resubmission
ccountIncluding 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
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliers 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 megawatt hours 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 HoursPurchased MegaWatt Hours MegaWatt HoursReceived Delivered
(g)
(h) (i)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
922,
Demand Charges Total (j+k+l)
of Settlement ($)
(m)
938,821
44,705
448,023
104,150,119
383
368,
11,533,818
420,676
618
65,209
860,896
090
24,360,020
761 733
26,448,
104,351,
368,
538,
420,
65,
860,
666,250
15,918 949 377 596,202 707,454,373,073 13,736,640 113.105,200 971,945,158
FERC FORM NO.1 (ED. 12-90)Page 327.
Line
No.
This ~rt Is:
(1) l!UAn Original
(2) A Resubmission
PURCHASED POWER (ACCount 555)(Including power exchanges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
RO - 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.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO 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.
as - 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.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Black Hills Power, Inc.
2 Black Hills Power, Inc.
3 Black Hills Power, Inc.
4 Black Hills Power, Inc.
5 Black Hills Wyoming, Inc.
6 Bogus Creek
7 Bogus Creek
8 Bonneville Power Administration
9 Bonneville Power Administration
10 Bonneville Power Administration
11 Bonneville Power Administration
12 Bonneville Power Administration
13 Bonneville Power Administration
14 British Columbia Transmission Corp.
Line
No.
Total
FERC FORM NO.1 (ED. 12-90)
Statistical
Classifi-
cation
FERC Rate Average Actual Demand (MW)
Schedule or Monthly Billing verage verage
Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(c)(d)(e)(f)
575 575 457
Page 326.
This ~rt Is:(1) ~An Original
(2) A Resubmission
ccountIncluding 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
Date of Report
(Mo. Da. Yr)
05/17/2007
Year/Period of Report
End of 2006/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 RO 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 (GO-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.
POWER EXCHANGESMegaWatt Hours
Purchased MegaWatt Hours MegaWatt HoursReceived Delivered
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
Demand Charges
($)
709 500
15,918,949 113.105,200 377 596,202971945,15814,373,073 13,736.640
FERC FORM NO.1 (ED. 12-90)Page 327.
Total (j+k+l)
of Settlement ($)
(m)
11,790
112.941
19,900
141 039
017,770
269
543
578
39,709,500
408,428
004,356
820
33,977,150
953
707,454,
Line
No.
This ~ort Is:
(1) l!JAn Original
(2) A Resubmission
PURCHASED POWER (Account 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da. Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
RO - 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.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO 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.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Burbank, City
2 Burbank, City of
3 COM Hydro
4 Califomia Independent System Operator
5 Califomia Independent System Operator
6 Calpine Energy Services, loP.
Cargill Power Markets, LLC
Cargill Power Markets, LLC
9 Central Oregon Irrigation District
10 Central Valley Water District
11 Chelan County PUD No.
12 Chelan County PUD No.
13 Chelan County PUD No.
14 Citigroup Energy, Inc.
Total
FERC FORM NO.1 (ED. 12-90)
Statistical
Classifi-
cation
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Demand(e) (f)
Average
Monthly Billing
Demand (MW)
(d)
Page 326.
This ~rt Is:(1) ~An Original
(2) A Resubmission
ccountIncluding 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
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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)
103,
29,791
423,
11,
155,291
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
944
1 ,548,
Demand Charges
($)(j)
306,117
16,740.
532
57,388
830,
371
58,
801,
15,918,949 14,373,073 13.736 640 971,945,158 377,596,202113,105,200
FERC FORM NO.1 (ED. 12-90)Page 327.
LineTotal (j+k+l) No.of Settlement ($)
(m)
565
944 612
1 ,548,685
91 ,409
740,257
275
532,736
388,156
136.767
305
69,571
638.003
223,756
42,446,174
707,454.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2006/Q4
(2) CiA Resubmission 05/17/2007
PU~CHA~ED POWER hAccou~t 555)
(nclu 109 power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
RO - 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 RO 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.
as - 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 City of Buffalo
2 Clark Public Utilities
3 Clatskanie Peoples Utility District
4 Colorado River Commission of Nevada
Colorado Springs Utilities
Colorado Springs Utilities
Commercial Energy Management
Conoco Inc.
Constellation Energy Commodities Group
Constellation Energy Commodities Group
Constellation Energy Commodities Group
Coral Power
Cowlitz County PUD No.
Credit Suisse Energy LLC
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/Q4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da. Yr)
(2) A Resubmission 05/17/2007
ccount 5 ontlnuIncluding 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.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliers 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
(g)
(h) (i)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
Demand Charges
($)(j)
24,858
56,
83,732.
73,514
161,
744,
15.918,949 14,373,073 13,736,640 113,105 200 971 945,158 377 596,202
FERC FORM NO.1 (ED. 12-90)Page 327.4
Total O+k+l)
of Settlement ($)
(m)
143 509
505,260
501,460
354 233
43,200
900
119,252
909,802
579,634
350
83,735.243
73,520,543
191 658
844,502
Line
No.
707,454,
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2006/04(2) nA Resubmission 05/17/2007
PU~CHA~ED POWER hAccou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
RO - 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 RO 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.
as - 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 Demam Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Curtiss Uvestock
Curtiss Livestock
DB Energy Trading LLC
DR Johnson Lumber Company
Davis County Waste Management
Deschutes Valley Water District
Deseret Power Electric Cooperative
I!IIiDeseret Power Electric Cooperative 100 100
Deutsche Bank AG
Douglas County Forest Products
Douglas County PUD No.
Douglas County PUD No.
Douglas County PUD No.
Douglas County PUD No.
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
This ~ort Is:(1) ~An Original
(2) A Resubmission
ccountIncluding 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
Date of Report
(Mo. Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (GO-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
(g)
(h) (i)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
Demand Charges
($)
783,495
567,771
12,773.880
918,949 373,073 13,736 640 113,105,200 971.945,158 377,596,202
FERC FORM NO.1 (ED. 12-90)Page 327.
LineTotal G+k+l) No.of Settlement ($)
(m)
663
10,977
860.441
930,474
24.
813,077
617
112,884
115,020
63,138
-61 ,342
2,484,969
1 ,052,465
076,518
707,454,
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
PU~CHA~ED POWER hAccount 555)(nclu Ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
RO - 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 RO 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.
as - 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 Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Draper Irrigation Company
Dry Creek
Duke Energy Trading & Marketing, LLC
Duke Energy Trading & Marketing, LLC
EPCOR Merchant and Capital Inc.
Eagle Point Irrigation District
EI Paso Electric Company
EI Paso Electric Company
Eugene Water & Electric Board
Eurus Energy America
Exxon Mobile Production Company
FPL Energy Power Marketing, Inc.
Falls Creek
Falls Creek 1.6
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 2006/Q4(2) DA Resubmission 05/17/2007
ccouH~~~~L (ContlnueO)M '~(iiicluding power exc anges)
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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/SElTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.
Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
36f 64,647
10.46!507 48!507,489
409,54(241,241 634
97'419,17~419,172
451 1 ,272 71 ~272 719
26!42,325 329,56€371 891
68,26-:oo€26,906
67 ,39(705,723,028
48,03!193,071 193,071
120,63!715,715,673
656,52~995,33~995 332
67~199,95!199,955
231 271
16,60€210,984 556,011 767 002
15,918,949 373,073 13,736,640 113.105,200 971.945,158 377 596,202 707 454 15E
FERC FORM NO.1 (ED. 12-90)Page 327.
This ~ort Is:(1) ~An Original
(2) A Resubmission
PURCHASED POWER (Account 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Name of Respondent
PacifiCorp
Date of Report
(Mo. Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/04
RO - 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 RO 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.
as - 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.
Una
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Farmers Irrigation District
2 Fery, Loyd
3 Fillmore City
4 Foote Creek IV LLC
Fortis Energy Marketing & Trading GP
Franklin County PUD No.
Fri!o Lay
Galesville Dam
9 Garland Canal
10 General Chemical Corporation
11 George DeRuyter & Sons Dairy
12 Georgetown Irrigation Company
13 Georgetown Irrigation Company
14 Georgia Pacific
Total
FERC FORM NO.1 (ED. 12-90)
Statistical
Classifi-
cation
(b)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Demand(e) (f)
FERC Rate
Schedule or
Tariff Number
(c)
0.4
Page 326.
Date of Report(Mo. Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
This ~rt Is:(1) ~An Original
(2) A Resubmission
ccountIncluding 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
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (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.
POWER EXCHANGESMegaWatt Hours
Purchased MegaWatt Hours MegaWatt HoursReceived Delivered
(g)
(h) (i)
Demand Charges
($)(j)
291,526
62,420
138 330
15.918.949 373,073 113.105,20013,736,640
FERC FORM NO.1 (ED. 12-90)Page 327.
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
971 945.158 377,596.202
Total O+k+l)
of Settlement ($)
(m)
246,587
15,108
19,680
125
327 556
514 285
512
638,390
486,066
933
299
305
97,667
538
Une
No.
707 454,
This ~ort Is:(1) ~An Original
(2) A Resubmission
PURCHASED POWER (Account 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Name of Respondent
PacifiCorp
Date of Report(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/04
RO - 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 RO 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.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Gila River Power, loP.
2 Gila River Power, loP.
3 Glendale, City of
4 Glendale, City of
5 Grand Valley Power
6 Grant County PUD No.
7 Grant County PUD No.
8 Grant County PUD No.
9 Grant County PUD No.
10 Grant County PUD No.
11 Grant County PUD No.
12 Grant County PUD No.
13 Grays Harbor PUD
14 Green River Hydro, Inc.
Line
No.
Total
FERC FORM NO.1 (ED. 12-90)
Statistical
Classifi-
cation
(b)
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Demand(e) (f)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
0.4
Page 326.
This ~rt Is:
(1) l2UAn Original
(2) A Resubmission
ccount 5Including 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
Date of Report
(Mo, Da. Yr)
05/17/2007
Year/Period of Report
End of 2006/04
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (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.
POWER EXCHANGESMegaWatt Hours
Purchased MegaWatt Hours MegaWatt HoursReceived Delivered
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
Demand Charges
($)(j)
119,480
36,383
15,918,949 373 073 971,945,158 377 596,20213,736,640 113.105,200
FERC FORM NO.1 (ED. 12-90)Page 327.
Total G+k+l)
of Settlement ($)
(m)
23,931
596,263
025
847.619
485
704
144,059
16,305,910
299,716
245,266
44,515
6,451,300
044,575
160,775
707,454,
Line
No.
Name of Respondent
PacifiCorp
This ~ort Is:(1) l!.JAn Original(2) A Resubmission
PURCHASED POWER IAccount 555)(Including power exchanges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
RO - 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 RO 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.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Heber Light & Power Company
Statistical
Classifi-
cation
FERC Rate Average Actual Demand (MW)
Schedule or Monthly Billing verage verage
Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(c)(d)(e)(f)
232 232 205
Hill Air Force Base
Hum Wind
Hurricane, City of
Idaho Falls, City of
Idaho Falls, City of
Idaho Falls, City of
Idaho Power Company
Idaho Power Company
Idaho Power Company
Intermountain Power Project
J. Aron & Company
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da. Yr)
05/17/2007
Year/Period of Report
End of 2oo6/Q4
This ~ort Is:(1) ~An Original
(2) A Resubmission
ccount 5Including 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.
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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
(g)
(h) (i)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
372
Demand Charges
($)
33,991,479
15,918,949 971,945,158 377 596,202373,073 13,736,640 113,105,200
FERC FORM NO.1 (ED. 12-90)Page 327.
Total G+k+l)
of Settlement ($)
(m)
372 985
43,650
79,452,742
315 851
63,901
33,449
540,153
347,372
225
49,395
10,912,494
25,128 957
630.335
Line
No.
707,454,
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2006/04(2) riA Resubmission 05/17/2007
PU~CHA~ED POWER hAccou~t 555)(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
RO - 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.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO 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.
as - 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 J.P. Morgan Ventures Energy Corp.
2 Kennecott
Kennecott
L&M Angus Ranch, LLC
Lacomb Irrigation
Lake Siskiyou
Lehman Brothers Commodity Services Inc
Los Angeles Dept. of Water & Power
Los Angeles Dept. of Water & Power
Los Angeles Dept. of Water & Power
Luckey, Paul
Luckey, Paul
Magnesium Corporation of America
Magnesium Corporation of America
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent
PacifiCorp
Date of Report
(Mo. Da. Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
This ~ort Is:(1) I.!UAn Original(2) A Resubmission
ccountIncluding 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.
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on .bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
21,346,611
773.
Demand Charges
($)
419,168
15,918.949 113,105,200 971,945,158 377 596 20214.373.073 13,736.640
FERC FORM NO.1 (ED. 12-90)Page 327.
Total (j+k+l)
of Settlement ($)
(m)
21,346,611
773,810
367 090
92,626
228,138
106,201
350,565
970
812
520,251
850
20,235
85,875
512,704
707,454,
Une
No.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
PU~CHA~ED POWER
hAccount 555)(nclu Ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
RO - 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 RO 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.
as - 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 Magnesium Corporation of America
Marsh Valley Hydro & Electric Company
Merrill Lynch Commodities, Inc.
Middlefork Irrigation District
Mink Creek Hydro
Mirant Americas Energy Marketing, loP.
Modesto Irrigation District
Monsanto
Morgan City
Morgan Stanley Capital Group, Inc.
Morgan Stanley Capital Group, Inc.
Morgan Stanley Capital Group, Inc.
Mountain Energy, Inc.
Municipal Energy Agency of Nebraska
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 2006/Q4
(2) riA Resubmission 05/17/2007
ccouHt ~~~L(Contlnued)(Including pow'er exc anges)
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliers 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)
584,328
70:349,349,830
317,421 15,635,491,795
22,47!321 ,33!321 339
13~564.08!564,085
56~38,38,017
20(211,70(211 700
.....
718,514
85~855
271,80(468,000 16,954,84C 17,422,840
40(24,OOC 000
442 01/250,666,250,189,762
02E 026
O4C 227,O4C 227 040
15,918.949 373 073 13,736,640 113,105,200 971 945.158 377,596,202 707,454,15E
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 2oo6/Q4(2) DA Resubmission 05/17/2007
PU~CHA~ED POWER ~ccou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
RO - 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 RO 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.
as - 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 Nephi City
2 Nevada Power Company
3 Nevada Power Company
4 Nevada Power Company
5 Nicholson Sunnybar Ranch
6 Nicholson Sunnybar Ranch
7 North Fork Sprague
8 NorthWestem Energy
9 Northem Califomia Power Agency
Northpoint Energy Solutions Inc.
Nucor Corporation
J. Power Company
Occidental Power Services, Inc.
Odell Creek
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/04
This R~ort Is:(1) ~An Original
(2) A Resubmission
ccountIncluding 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.
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnqte 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
(g)
(h) (i)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
621
Demand Charges
($)(j)
40,916
624
15,918,949 377 ,596,202373.073 13.736,640 113,105.200 971 ,945,158
FERC FORM NO.1 (ED. 12-90)Page 327.
LineTotal O+k+l) No.of Settlement ($)
(m)
621
-47,734
131,500
008,557
131,903
102,608
305,475
20,803
526,625
330,839
722,000
54,991
235,437
23,933
707 454.
This ~ort Is:(1) ~An Original
(2) A Resubmission
PURCHASED POWER (Account 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da. Yr)
05/17/2007
Year/Period of Report
End of 2oo6/Q4
RO - 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 RO 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.
as - 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.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 PPL Energy Plus, LLC
2 PPL Montana, LLC
3 PPL Montana, LLC
4 PPM Energy, Inc.
Pacific Gas & Electric Company
Pacific Northwest Gen. Cooperative
Pacific Summit Energy LLC
8 Pasadena, City of
9 Pasadena, City
10 Payson City Corporation
11 Pinnacle West Capital Corporation
12 Platte River Power
13 Portland General Electric Co.
14 Portland General Electric Co.
Line
No.
Total
FERC FORM NO.1 (ED. 12-90)
Statistical
Classifi-
cation
(b)
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Demand
(~
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Page 326.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da. Yr)End of 2006/Q4(2) riA Resubmission 05/17/2007
ccou
Ht ~~~L\ ll,,;ontlnUed)'(Includlng power exc anges)
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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 (j+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
27C 90(10,900
1OC 000 000
33,154 335,65C 335,650
547,96C 25,358,63E 358,636
16,121:852,161:852 165
461:086,61,086,617
6OC 349,584 349,584
66C 55,42~55,422
20,221:051,02"i 051,024
91€916
245,52E 859,82"i 18,859 824
03€140,258
635
99~101 000
15.918.949 373,073 13,736.640 113.105,200 971 945 158 377 596,202 707,454,15€
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent
PacifiCorp
This ~rt Is:(1) ~An Original
(2) A Resubmission
PURCHASED POWER lAccount 555)(Including power exchanges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Date of Report(Mo, Da. Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
RO - 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 RO 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.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
Statistical
Classifi-
cation
(b)
FERC Rate Average Actual Demand (MW)
Schedule or Monthly Billing verage verage
Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(c)(d)(e)(f)(a)
1 Portland General Electric Co.
2 Powerex
3 Powerex
4 Powerex
5 Preston City Hydro
6 Provo City
Public Service Company of Colorado
8 Public Service Company of New Mexico
9 Public Service Company of New Mexico
10 Public Service Company of New Mexico
11 Puget Sound Energy
12 Puget Sound Energy
13 Quail Mountain, Inc.
14 Quail Mountain, Inc.
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 05/17/2007ccount ontlnuIncluding 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 2006/04
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (GO-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.
B. 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)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
25,027,
Demand Charges
15,918,949 971,945,158 1 ,377 ,596,202373,073 13,736,640 113,105,200
FERC FORM NO.1 (ED. 12-90)Page 327.
Total O+k+l)
of Settlement ($)
(m)
25,050,
590
080
898,471
132 070
065
22,104.656
33,029
800,492
18,484,407
727
13,033,579
054
707,454,
Line
No.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2006/Q4
(2) CiA Resubmission 05/17/2007
~CHA~ED POWER hAccount 555)(nclu Ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
RO - 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 Average
cation Tariff Number Demand (MW)Monthly NCP Demanc Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Rainbow Energy Marketing
2 Ralphs Ranch, Inc.
3 Ralphs Ranch, Inc.
4 Redding, City of
Reliant Energy Services, Inc.
Riverside, City of
Riverside, City of
8 Rocky Mountain Generation Cooperative
....
9 Rocky Mountain Generation Cooperative
Roseburg Forest Products Co.
Roush Hydro, Inc.
SUEZ Energy Marketing NA, Inc.
Sacramento Municipal Utility District
Sacramento Municipal Utility District
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo. Da. Yr)End of 2006/04
(2)DA Resubmission 05/17/2007
'" lV' 'M(lnClI ~~ ccouH!.~~~L (Continued)Including power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (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)
91 ,691 945.080 945,080
" ". .
753
27,711 27,711
10,04/445,19~445,199
60(245,75(245,750
31,44C 756,99E 756,996
1 ,28::28,17!28,175
671 164,48'164,484
58!167 561 167 561
68,08(880,54E 879.762
39E 23,29~23,299
234,97!13,163 13.163,445
173,48!258,252 210
51,611 2,465 42(2,465,420
15,918 949 373,073 13,736,640 113,105,200 971,945,158 377 596,202 707,454.15E
FERC FORM NO.1 (ED. 12-90)Page 327.
This ~ort Is:(1) ~An Original
(2) A Resubmission
PURCHASED POWER (Account 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da. Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
RO - 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 RO 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 con~traints, 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
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Salt River Project
2 Salt River Project
3 San Diego Gas & Electric
4 Santa Clara, City of
Santiam Water Control District
Seattle City Light
Seattle City Light
8 Sempra Energy Solutions
9 Sempra Energy Trading Corp.
10 Sempra Energy Trading Corp.
11 Sempra Energy Trading Corp.
12 Sempra Generation
13 Sierra Pacific Power Company
14 Sierra Pacific Power Company
Total
FERC FORM NO.1 (ED. 12-90)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Demand(e) (f)
Average
Monthly Billing
Demand (MW)
(d)
Page 326.
Name of Respondent
PacifiCorp
Date of Report
(Mo. Da. Yr)
05/17/2007
Year/Period of Report
End of 2006/04
This ~rt Is:(1) !!.IAn Original(2) A Resubmission
ccountIncluding 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.
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
265,
34,840,
1 ,449,
383,
125,41
Demand Charges
($)
13;582
15.918,949 113.105.200 1 ,377 ,596,202373,073 13,736.640 971,945,158
FERC FORM NO.1 (ED. 12-90)Page 327.
Total O+k+l)
of Settlement ($)
(m)
265,525
34,842 120
449,653
383,990
139,001
125
377 693
543,842
895
250
216,941 537
319,614
021
650
707,454
Line
No.
This ~ort Is:(1) ~An Original
(2) A Resubmission
PURCHASED POWER IAccount 555)(Including power exchanges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Name of Respondent
PacifiCorp
Date of Report(Mo, Da. Yr)
05/17/2007
Year/Period of Report
End of 2006/04
RO - 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 RO 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.
as - 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.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Sierra Pacific Power Company
2 Simplot Phosphates, LLC
3 Simplot Phosphates, LLC
4 Simplot Phosphates, LLC
5 Slate Creek
6 Slate Creek
7 Snohomish PUD No.
8 Southem Califomia Edison Company
9 Southem Califomia Edison Company
10 Southwestem Public Service Company
11 Spanish Fork City
12 Springville City
13 State of CA Dept. of Water Resources
14 Strawberry Electric Service District
Une
No.
Total
FERC FORM NO.1 (ED. 12-90)
Statistical
Classifi-
cation
(b)
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Demand(e) (f)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Page 326.
This ~rt Is:
(1) ~An Original
(2) A Resubmission
ccountIncluding 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
Date of Report
(Mo. Da. Yr)
05/17/2007
Year/Period of Report
End of 2006/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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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 HoursPurchased MegaWatt Hours MegaWatt HoursReceived Delivered
(g)
(h) (i)
48,231
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
378,951
Demand Charges
($)(j)
201 242 273.
365,
769
609,43
101
196.
918,949 14,373.073 13,736,640 971,945,158 377,596,202113105,200
FERC FORM NO.1 (ED. 12-90)Page 327.
Total O+k+l)
of Settlement ($)
(m)
2,477 685
588
650,
37,726
84,780
1,474 247
365,
772,125
609.430
374
101
839
196,140
252
707,454,
Line
No.
This ~ort Is:(1) I2S.JAn Original(2) A Resubmission
PURCHASED POWER (Account 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
RO - 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 RO 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.
as - 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.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Sunnyside Cogeneration Associates
2 Sunnyside Cogeneration Associates
3 Swiss Re Financial Products Corp.
4 Swiss Re Financial Products Corp.
5 Sysco Intermountain Foods
6 Tacoma, City
7 Tacoma, City of
8 Tesoro Refining and Marketing Company
9 The Cincinnati Gas & Electric Company
10 The Energy Authority
11 TransAlta Energy Marketing Inc.
12 TransAlta Energy Marketing Inc.
13 Tri-State Generation & Transmission
14 Tri-State Generation & Transmission
Une
No.
Total
FERC FORM NO.1 (ED. 12-90)
Statistical
Classifi-
cation
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Demand(e) (f)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
53.51.44.
Page 326.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da. Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
This ~ort Is:
(1) 12UAn Original
(2) A Resubmission
ccountIncluding 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.
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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
(g)
(h) (i)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
Demand Charges
($)
215,263
398.150
15.918,949 373,073 113,105.200 377 596,202736.640 971 945.158
FERC FORM NO.1 (ED. 12-90)Page 327.
Total G+k+l)
of Settlement ($)
(m)
932 034
27,490,500
435.469
312,497
643
365
759,
11,812,883
268,350
199
124,481 558
29,087 543
273,446
147 288
707,454
Line
No.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2006/04(2) riA Resubmission 05/17/2007
PU~CHA~ED POWER hAccou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
RO - 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.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO 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.
as - 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 Tri-State Generation & Transmission
2 Tucson Electric Power
3 Tucson Electric Power
4 Turlock Irrigation District
5 UBS WartJurg Energy LLC
6 UBS WartJurg Energy LLC
7 Utah Associated Municipal Power System
8 Utah Associated Municipal Power System
9 Utah Associated Municipal Power System
Utah Municipal Power Agency
Utah Municipal Power Agency
Wadeland South LLC
Walla Walla, City of 1.6
Warm Springs Forest Products
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 2006/Q4(2) nA Resubmission 05/17/2007
. ~ .~.
'(t~
ccou
H!.~~~L (Contlnuea)Including power exc anges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (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 (j), energy charges in column (k), and the total of any other types of charges, including
out-oJ-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 Ene"" Cha'9~ Total ij"'~1 No.Received Delivered
($)~ ($)
of Settlement ($)
(g)
(h)(i)
(j)
(k (I) (m)
34,1 ,533,62 . 1 533,843
02~694,85~ 694 853
54,62C 874 83~874 832
43E 436
35C 6,4O4,86(6,404,860
230,231 71,014 151 014 154
328,985
286,401 2,484,000 155,
- .
15,809,555
99,366 89E 366,895
321 319,221 319,221
54~861 24,867
28~5,465 78'1 17,249
14~131,992 464,49C 596,482
15,918,949 14,373 073 13,736,640 113,105,200 1 ,971 945,158 377 596,202 707,454,15E
FERC FORM NO.1 (ED. 12-90)Page 327.
This ~ort Is:(1) I!.JAn Original(2) A Resubmission
PURCHASED POWER IAccount 555)(Including power exchanges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
RO - 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 RO 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.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Warm Springs Forest Products
2 Weber County, State of Utah
3 Weber County, State of Utah
4 Westem Area Power Administration
5 Westem Area Power Administration
6 Westem Area Power Administration
7 Westem Area Power Administration
8 Wolverine Creek Energy LLC
9 Yakima Tieton
10 Accrual True-Up
11 Line Loss Retum
12 Potential Liability
13 Potential Liability
14 Bookout Purchases
Line
No.
Total
FERC FORM NO.1 (ED. 12-90)
Statistical
Classifi-
cation
(b)
FERC Rate Average Actual Demand (MW)
Schedule or Monthly Billing verage verage
Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(c)(d)(e)(f)
Page 326.
This ~rt Is:
(1) ~An Original
(2) A Resubmission
ccountIncluding 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
Date of Report
(Mo, Da. Yr)
05/17/2007
Year/Period of Report
End of 2006/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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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
(g)
(h) (i)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
Demand Charges
($)(j)
918,949 971 945,158 377,596,20214,373,073 13,736 640 113,105,200
FERC FORM NO.1 (ED. 12-90)Page 327.
Total O+k+l)
of Settlement ($)
(m)
713
13,409
67,214
17,524
791,930
572 491
191,994
179,260
363,874
913,758
883,400
285,144
43,600
241,757
707 454,
Line
No.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006104(2) OA Resubmission 05/17/2007
PU~CHA~ED POWER hAccount 555)(nclu Ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
RO - 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 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 RO 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.
as - 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 Demam Monthly CP Demand
(a)(b)(c)(d)(e)(f)
1 Bookout Purchases
2 Trade Purchases
3 Trade Purchases
Power Exchanges
Arizona Public Service Co.306
Avista Corp.554
Avista Energy, Inc.WSPP
Basin Electric Power Cooperative
Black Hills Power, Inc.246
Bonneville Power Administration 554
Bonneville Power Administration 368
Bonneville Power Administration 237
Bonneville Power Administration 237
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
This ~rt Is: Date of Report(1) ~An Original (Mo. Da, Yr)
(2) A Resubmission 05/17/2007ccount ontlnuIncluding 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 2006/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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (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.
B. 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)
26,277
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($) -
(k) (I)
Total (j+k+l)
of Settlement ($)
(m)
004,967 209
400
363,399,841
Demand Charges
($)(j)
569,095
699
54,000
649
144 108
242,612
571 151 584,078
000
908
162,000
55,073
17,221
245,520 675
-44 195
553
15,918,949 373,073 13,736,640 971.945,158 1 ,377 ,596,202113,105,200 707,454,
FERC FORM NO.1 (ED. 12-90)Page 327.
Line
No.
This ~ort Is:(1) !!.IAn Original(2) A Resubmission
PURCHASED POWER (ACcount 555)(Including power exchanges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Date of Report
(Mo, Da. Yr)
05/17/2007
Year/Period of Report
End of 2006/04
Name of Respondent
PacifiCorp
RO - 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 RO 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.
as - 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 verage verage
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration 347
Chelan County PUD No.554
Clark Public Utilities 417
Clark Public Utilities 417
Colockum Transmission Company
Cowlitz County PUD No.554
Deseret Power Electric Cooperative 280
Deseret Power Electric Cooperative 280
Emerald Peoples Utility District 351
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
This ~rt Is:(1) ~An Original(2) A Resubmission
ccountIncluding 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.
Date of Report
(Me, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
Name of Respondent
PacifiCorp
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (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
($)(j)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($) .
(k) (I)
Line
Total G+k+l)No.of Settlement ($)
(m)
820
027
-56,560
111,678.305
619,718
580.000
045,215
16,497.398
1,477 992
2,483,542
209
637
073
860
073
104,872
612,464
106,805
1 ,600,434
17,198
354,555
198,982
84,827
84,486
269,017
205,815
28,637
24,342
918,949 373 073 13,736,640 113,105,200 971,945,158 377 596,202 707,454,
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 2006/Q4
(2) (JA Resubmission 05/17/2007
~CHA~ED POWER hAccount 555)(nclu Ing power exc anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
RO - 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 RO 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.
as - 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)
Emerald Peoples Utility District 351
Eugene Water & Electric Board
Eugene Water & Electric Board
Flathead Electric Cooperative
5 Grant County PUD No.554
Idaho Power Company 380
PPM Energy, Inc.
8 Portland General Electric Co.554
9 Public Service Company of Colorado
Public Service Company of Colorado 319
Redding, City of 364
",',
Redding, City of 364
Seattle City Light 554
Sempra Energy Solutions
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
This ~ort Is:(1) I25.JAn Original(2) A Resubmission
ccountIncluding 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.
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
Name of Respondent
PacifiCorp
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 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
(g)
(h) (i)
Demand Charges
($)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($) ...
(k) (I)
LineTotalO+k+l)No.of Settlement ($)
(m)
898
-43,397
759
402,957
300,904
064,179
067
151 842
800,827
203,459
20,126
398
003
060
292,594
18,398
146,723
73,667
040
127,394
338 300
363
396
20,375
345
347
45,839
216,845
740
145,618
78.746
122 155
327 968
125
15,918,949 373,073 13,736,640 113 105,200 971 945.158 377,596,202 707 454,
FERC FORM NO.1 (ED. 12-90)Page 327.
This ~rt Is:(1) ~An Original
(2) A Resubmission
PURCHASED POWER lAccount 555)(Including power exchanges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., 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:
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/Q4
RO - 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 RO 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" meahs 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.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Tri-State Generation & Transmission
2 Tri-State Generation & Transmission
3 Utah Associated Municipal Power System
4 Utah Associated Municipal Power System
5 Utah Municipal Power Agency
6 Utah Municipal Power Agency
7 Warm Springs Power Enterprises
8 Warm Springs Power Enterprises
9 Westem Area Power Administration
10 Westem Area Power Administration
11 Westem Area Power Administration
12 Weyerhauser
14 System Deviation
Total
FERC FORM NO.1 (ED. 12-90)
Statistical
Classifi-
cation
(b)
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Demand(e) (f)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
. NA
Page 326.
This ~rt Is: Date of Report
(1) I!UAn Original (Mo. Da, Yr)
(2) A Resubmission 05/17/2007ccount ontlnuIncluding 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 2006/04
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 RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k). and the total of any other types of charges, including
out-of-period adjustments, in column (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)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($) . .
(k) (I)
Total (j+k+l)
of Settlement ($)
(m)
14,602
161,072
197,112
258,685
55,556
599 311
236
265,
079,811
743,220
Demand Charges
($)(j)
156,280 153,815
92,397
72,424
24.327
264
069
164
070
238,537
618
64,229
736
494
41 ,834
111
132,889531
15,918,949 373,073 377 596 202 707,454,13.736,640 113,105,200 971 ,945,158
FERC FORM NO.1 (ED. 12-90)Page 327.
Line
No.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
~chedule Page: 326 Line No.Column: I
Green ta s.
chedule Page: 326 Line No.Column: I
Conservation & Renewables Discount applied to wind project near Arlington, Wyoming and settlement for damages from non-delivery
f generation.
!schedule Page: 326 Line No.Column: b
ettlement adjustment.
chedule Page: 326 Line No.Column: I
ettlement adjustment.
!schedule Page: 326 Line No.Column: b
econdary, economy and/or non-firm.
~chedule Page: 326 Line No.11 Column: b
izona Public Service - Contract Tennination Date: October 31, 2020.
~chedule Page: 326 Line No.12 Column: b
Secondary, economy and/or non-firm.
~chedule Page: 326 Line No.14 Column: b
econdary, economy and/or non-firm.
!schedule Page: 326 Line No.14 Column: I
eratin reserves.
Schedule Page: 326.Line No.Column: I
eserve Share.
~chedule Page: 326.Line No.Column: b
econdary, economy and/or non-fInD.
~chedule Page: 326.Line No.Column: I
eratin reserves.
chedule Page: 326.Line No.Column: I
Financial Swap.
~chedule Page: 326.Line No.Column: I
inancial Swap.
~chedule Page: 326.Line No.Column: b
Under Electric Service Agreement sub. ect to tennination upon timely notification.
chedule Page: 326.Line No.12 Column: b
ettlement adjustment.
~chedule Page: 326.Line No.12 Column: I
ettlement adjustment.
~chedule Page: 326.Line No.13 Column: I
Non- eneration agreement.
chedule Page: 326.Line No.Column: b
Settlement adjustment.
~chedule Page: 326.Line No.Column: I
eration and maintenance ex ense associated with the combustion turbine located in Ra id City, South Dakota.
chedule Pa e: 326.Line No.Column: I
eration and maintenance ex ense associated with the combustion turbine located in Ra id City, South Dakota.
chedule Page: 326.Line No.Column: b
econdary, economy and/or non-firm.
~chedule Page: 326.Line No.Column: b
Settlement adjustment.
ISchedule Page: 326.Line No.Column: I
Settlement adjustment.~ule Page: 326.Line No.Column: b
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 05/17/2007 2006/04
FOOTNOTE DATA
Settlement adjustment.
~chedule Page: 326.Line No.Column: I
erating reserves.
Schedule Pa e: 326.Line No.Column: b
Bonneville Power Administration - Contract Termination Date: August 31, 2011.~ule Page: 326.Line No.: 10 Column: b
Bonneville Power Administration - Contract Termination Date: 30 days written notice.
ISchedule Page: 326.Line No.: 10 Column: I
perating reserves.
~chedule Page: 326.Line No.11 Column: b
Secondary, economy and/or non-rum.
ISchedule Page: 326.Line No.11 Column: I
Operating reserves.
~chedule Page: 326.Line No.12 Column: I
reen tags.
~chedule Page: 326.Line No.13 Column: I
Reserve Share.
~chedule Page: 326.Line No.14 Column: I
Reserve Share.
ISchedule Page: 326.Line No.Column: b
econdary, economy and/or non-firm.
~chedule Page: 326.Line No.Column: b
Settlement ad.ustment.
chedule Page: 326.Line No.Column: I
ettlement adjustment.
~chedule Page: 326.Line No.Column: b
Secondary, economy and/or non-rum.
ISchedule Page: 326.Line No.: 10 Column: b
econdary, economy and/or non-firm.
~chedule Page: 326.Line No.: 10 Column: I
oad curtailment.
~chedule Page: 326.Line No.11 Column: b
ettlement adjustment.
~chedule Page: 326.Line No.11 Column: I
perating expense, bond interest, amortization and taxes.
~chedule Page: 326.Line No.12 Column: I
perating expense, bond interest, amortization and taxes.
~chedule Page: 326.Line No.13 Column: I
eserve Share.
chedule Page: 326.Line No.14 Column: I
Financial Swap.
~chedule Page: 326.4 Line No.Column: b
econdary, economy and/or non-rum.
~chedule Page: 326.Line No.Column: I
Financial Swa .
chedule Page: 326.4 Line No.: 10 Column: b
Secondary, economy and/or non-rum.
ISchedule Page: 326.Line No.11 Column: I
Settlement adjustment.
ISchedule Page: 326.4 Line No.12 Column: I
Financial Swap.
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 05/1712007 2006/04
FOOTNOTE DATA
fschedule Page: 326.Line No.13 Column: b
econdary, economy and/or non-finD.
~chedule Page: 326.Line No.13 Column: I
Li uidated damages and liability associated with a er ond at hydro facility located on the Lewis River in the state of Washington.
Schedule Page: 326.4 Line No.14 Column: I
Financial Swa .
chedule Page: 326.Line No.Column: b
Settlement adjustment.
~chedule Page: 326.Line No.Column: I
Settlement ad.ustment.
chedule Page: 326.Line No.Column: b
Settlement adjustment.
~chedule Page: 326.Line No.Column: I
Settlement adjustment.
~chedule Page: 326.Line No.Column: b
Deseret Generation & Transmission - Contract Termination Date: September 30, 2024.
~chedule Page: 326.Line No.Column: I
peration and maintenance expense associated with a coal CITed generating facility located in Vemal, Utah.
~chedule Page: 326.Line No.Column: I
Financial Swap.
~chedule Page: 326.Line No.11 Column: b
ettlement adjustment.
~chedule Page: 326.Line No.11 Column: I
erating ex ense, bond interest, amortization and taxes.
chedule Pa e: 326.Line No.12 Column: I
erating e effie, bond interest, amortization and taxes.
chedule Page: 326.Line No.13 Column: b
Secondary, economy and/or non-finD.
~chedule Page: 326.Line No.13 Column: I
Settlement ad.ustment.
chedule Page: 326.Line No.14 Column: I
eserve Share.
~chedule Page: 326.Line No.Column: b
econdary, economy and/or non-fmn.
~chedule Page: 326.Line No.Column: I
Line loss.
~chedule Page: 326.Line No.11 Column: b
econdary, economy and/or non-finD.
~chedule Page: 326.Line No.13 Column: b
Settlement adjustment.
~chedule Page: 326.Line No.13 Column: I
Settlement adjustment.
~chedule Page: 326.Line No.Column: b
nder Electric Service Agreement subject to termination upon timely notification.
~chedule Page: 326.Line No.Column: I
reen tags.
~chedule Page: 326.Line No.Column: b
econdary, economy and/or non-firm.
~chedule Page: 326.Line No.Column: I
oad curtailment.
~chedule Page: 3~- Line No.10 - 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 05/17/2007 2006/Q4
FOOTNOTE DATA
econdary, economy and/or non-finD.
~chedule Page: 326.Line No.12 Column: b
Settlement adjustment.
~chedule Page: 326.Line No.12 Column: I
ettlement adjustment.
~chedule Page: 326.Line No.14 Column: b
econdary, economy and/or non-finD.
~chedule Page: 326.Line No.14 Column: I
Load curtailment.
~chedule Page: 326.Line No.Column: b
econdary, economy and/or non-rum.
~chedule Page: 326.Line No.Column: b
Secon , economy and/or non-firm.
chedule Page: 326.Line No.Column: b
Under Electric Service Agreement sub.ect to tennination u on timely notification.
chedule Pa e: 326.Line No.Column: b
ettlement adjustment.
~chedule Page: 326.Line No.Column: I
ettlement adjustment.
~chedule Page: 326.Line No.Column: b
rant County Public Utility District No.2 - Contract Tennination Date: 2 years written notice.
~chedule Page: 326.Line No.Column: I
Ancillary services and cost recovery adjustment.
~chedule Page: 326.Line No.Column: I
Operating expense, bond interest, amortization and taxes.
~chedule Page: 326.Line No.Column: I
Operating expense, bond interest, amortization and taxes.
~chedule Page: 326.Line No.10 Column: b
ettlement adjustment.
~chedule Page: 326.Line No.10 Column: I
eratin e ense, bond interest, amortization and taxes.
chedule Pa e: 326.Line No.11 Column: b
econdary, economy and/or non-firm.
~chedule Page: 326.Line No.11 Column: I
eratin reserves.
chedule Page: 326.Line No.12 Column: I
eserve Share.
~chedule Page: 326.Line No.Column: b
Under Electric Service Agreement subject to tennination u on timely notification.
chedule Page: 326.Line No.Column:
Henniston Generating Company, LP. operates the Henniston Plant, and is jointly owned. The respondent owns 50.0% of the plant.
See Page 402.3 Column (c) of this Fonn No. I for further infonnation on the Henniston Plant.
~chedule Page: 326.Line No.Column: b
Settlement adjustment.
ISchedule Page: 326.Line No.Column: I
n peak incentive, supplemental dispatch efficiency expense, start-up charges and committee settlements.
~chedule Page: 326.Line No.Column:
Henniston Generating Company, LP. operates the Henniston Plant, and is jointly owned. The respondent owns 50.0% of the plant.
See Page 402.3 Column (c) of this Fonn No. I for further infonnation on the Henniston Plant.~ule Page: 326.Line No.Column: I
On peak incentive, supplemental dispatch efficiency expense, start-up charges and committee settlements.
IFERC FORM NO.1 (ED. 12-87)Page 450.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da. Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
~chedule Page: 326.Line No.Column: I
Settlement adjustment.
~chedule Page: 326.Line No.Column: b
urricane, City of - Contract Tennination Date: August 31 , 2007.
~chedule Page: 326.Line No.Column: b
ettlement adjustment.
~chedule Page: 326.Line No.Column: I
abor, equipment and administration fees associated with hydro project in Idaho Falls, Idaho.
~chedule Page: 326.Line No.Column: I
Labor, e ui ment and administration fees associated with hydro roject in Idaho Falls, Idaho.
chedule Page: 326.Line No.10 Column: I
ettlement adjustment.
~chedule Page: 326.Line No.11 Column: b
Secondary, economy and/or non-fInD.
~chedule Page: 326.Line No.11 Column: I
erating reserves.
chedule Page: 326.Line No.12 Column: I
eserve Share and Line loss.
~chedule Page: 326.Line No.14 Column: I
Financial Swa .
chedule Page: 326.10 Line No.Column: I
Com ensation for self-generation.
chedule Page: 326.10 Line No.Column: I
ixed annual payment.
~chedule Page: 326.10 Line No.Column: I
inancial Swap.
~chedule Page: 326.10 Line No.Column: b
ettlement adjustment.
~chedule Page: 326.10 Line No.Column: I
ine loss.
!Schedule Page: 326.10 Line No.Column: b
Secondary, economy and/or non-fInD.
!Schedule Page: 326.10 Line No.Column: I
eratin reserves.
chedule Page: 326.10 Line No.10 Column: I
Line loss.
!Schedule Page: 326.10 Line No.11 Column: b
ettlement adjustment.
~chedule Page: 326.10 Line No.11 Column: I
Settlement adjustment.
Ischedule Page: 326.10 Line No.13 Column: b
ettlement adjustment.
!Schedule Page: 326.10 Line No.13 Column: I
Settlement adjustment and erating reserves.
chedule Pa e: 326.11 Line No.Column: b
Magnesium Co oration of America - Contract Tennination Date: December 31 , 2009.
chedule Pa e: 326.11 Line No.Column: I
Operating reserves.
!Schedule Page: 326.11 Line No.Column: I
inancial Swap.
fSchedule Page: 326.11 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 05/17/2007 2006/04
FOOTNOTE DATA
Com ensation for interruptible service and o erating reserves.
chedule Page: 326.11 Line No.Column: b
Under Electric Service Agreement subject to tennination u on timely notification.
chedule Page: 326.11 Line No.11 Column: b
Secondary, economy and/or non-fIrm.
ISchedule Page: 326.11 Line No.12 Column: I
inancial Swap.
~chedule Page: 326.12 Line No.Column: b
Under Electric Service Agreement subject to tennination upon timely notification.
~chedule Page: 326.12 Line No.Column: b
ettlement adjustment.
~chedule Page: 326.12 Line No.Column: I
Line loss.
~chedule Page: 326.12 Line No.Column: b
Secondary, economy and/or non-fIrm.
ISchedule Page: 326.12 Line No.Column: I
ine loss.
~chedule Page: 326.12 Line No.Column: b
ettlement adjustment.
~chedule Page: 326.12 Line No.Column: I
ettlement adjustment.
~chedule Page: 326.12 Line No.Column: I
eserve Share.
~chedule Page: 326.12 Line No.11 Column: I
erating reserves.
chedule Page: 326.13 Line No.Column: b
econdary, economy and/or non-firm.
~chedule Page: 326.13 Line No.Column: b
PPM Ener was an affiliate of the res ondent through March 20, 2006.
chedule Page: 326.13 Line No.Column: b
econdary, economy and/or non-firm.
~chedule Page: 326.13 Line No.10 Column: b
Under Electric Service Agreement subject to tennination upon timely notification.
~chedule Page: 326.13 Line No.12 Column: I
ine loss.
~chedule Page: 326.13 Line No.13 Column: b
ettlement adjustment.
!Schedule Page: 326.13 Line No.13 Column: I
eserve Share and Operation expense plus amortization of unrecovered costs of Cove Project.
chedule Page: 326.13 Line No.14 Column: b
Portland General Electric Company - Contract Tennination Date: Round Butte project no longer operating for power production
oses.
chedule Page: 326.13 Line No.14 Column: I
eration ex ense Ius amortization ofumecovered costs of Cove Pro ect.
chedule Page: 326.14 Line No.Column: I
Reserve Share.
~chedule Page: 326.14 Line No.Column: b
ettlement adjustment.
~chedule Page: 326.14 Line No.Column: I
Settlement adjustment.
!Schedule Page: 326.14 Line No.Column: b
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 05/17/2007 2006/Q4
FOOTNOTE DATA
econdary, economy and/or non-fmn.
~chedule Page: 326.14 Line No.Column: b
nder Electric Service Agreement subject to tennination upon timely notification.
~chedule Page: 326.14 Line No.Column: b
ettlement adjustment.
~chedule Page: 326.14 Line No.Column: I
ine loss.
~chedule Page: 326.14 Line No.Column: b
econdary, economy and/or non-fmn.
~chedule Page: 326.14 Line No.Column: I
perating reserves.
~chedule Page: 326.14 Line No.10 Column: I
ine loss.
~chedule Page: 326.14 Line No.11 Column: b
Settlement ad.ustment.
chedule Page: 326.14 Line No.11 Column: I
eserve Share.
~chedule Page: 326.14 Line No.12 Column: I
eserve Share and Line loss.
~chedule Page: 326.14 Line No.13 Column: b
Settlement ad.ustment.
chedule Page: 326.14 Line No.13 Column: I
Settlement ad"ustment.
chedule Pa e: 326.15 Line No.Column: b
Settlement ad.ustment.
chedule Pa e: 326.15 Line No.Column: I
Settlement adjustment.
~chedule Page: 326.15 Line No.Column: b
Secondary, economy and/or non-fmn.
~chedule Page: 326.15 Line No.Column: b
econdary, economy and/or non-firm.
~chedule Page: 326.15 Line No.10 Column: I
vailability requirement shortfall.
~chedule Page: 326.15 Line No.13 Column: b
acramento Municipal Utility District - Contract Tennination Date: December 31 , 2014.
~chedule Page: 326.15 Line No.13 Column: I
Settlement adjustment.
I$chedule Page: 326.16 Line No.Column: b
Secondary, economy and/or non-fmn.
chedule Page: 326.16 Line No.Column: I
Line loss.
~chedule Page: 326.16 Line No.Column: b
Secondary, economy and/or non-fmn.
I$chedule Page: 326.16 Line No.Column: I
erating reserves.
Schedule Page: 326.16 Line No.Column: I
Reserve Share.
ISchedule Page: 326.16 Line No.Column: b
Settlement adjustment.
~chedule Page: 326.16 Line No.Column: I
Settlement 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 (2)A Resubmlssion 05/17/2007 2006/04
FOOTNOTE DATA
~chedule Page: 326.16 Line No.10 Column: b
econdary, economy and/or non-fmn.
!Schedule Page: 326.16 Line No.11 Column: I
Financial Swa .
chedule Page: 326.16 Line No.13 Column: b
ettlement adjustment.
ISchedule Page: 326.16 Line No.13 Column: I
eserve Share and Line loss.
ISchedule Page: 326.16 Line No.14 Column: b
econdary, economy and/or non-fmn.
ISchedule Page: 326.17 Line No.Column: I
Reserve Share and Line loss.
ISchedule Page: 326.17 Line No.Column: b
ettlement adjustment.
ISchedule Page: 326.17 Line No.Column: I
Settlement ad.ustment.
chedule Page: 326.17 Line No.Column: b
Secondary, economy and/or non-fmn.
ISchedule Page: 326.17 Line No.Column: I
oad curtailinent.
ISchedule Page: 326.17 Line No.Column: b
ettlement adjustment.
ISchedule Page: 326.17 Line No.Column: I
Settlement ad.ustment.
chedule Pa e: 326.17 Line No.Column: b
econdary, economy and/or non-fmn.
ISchedule Page: 326.17 Line No.Column: I
Li uidated dama es.
chedule Pa e: 326.17 Line No.11 Column: b
nder Electric Service Agreement subject to tennination upon timely notification.
ISchedule Page: 326.17 Line No.12 Column: b
nder Electric Service Agreement subject to tennination upon timely notification.
ISchedule Page: 326.17 Line No.14 Column: b
nder Electric Service Agreement subject to tennination upon timely notification.
ISchedule Page: 326.18 Line No.Column: b
Settlement adjustment.
ISchedule Page: 326.18 Line No.Column: I
ettlement adjustment.
ISchedule Page: 326.18 Line No.Column: I
Hedge payout.
ISchedule Page: 326.18 Line No.Column: I
tion premium.
chedule Page: 326.18 Line No.Column: b
econdary, economy and/or non-finD.
ISchedule Page: 326.18 Line No.Column: I
oad curtailment.
ISchedule Page: 326.18 Line No.Column: b
econdary, economy and/or non-finD.
ISchedule Page: 326.18 -Line No.Column: I
Operating reserves.
ISchedule Page: 326.18 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 05/17/2007 2006/04
FOOTNOTE DATA
eserve Share.
~chedule Page: 326.18 Line No.11 Column: b
Transalta Energy Marketing Co . - Contract Tennination Date: June 30, 2007.
chedule Page: 326.18 Line No.11 Column: I
eratin reserve reimbursement.
chedule Page: 326.18 Line No.13 Column: b
ri-State Generation & Transmission - Contract Tennination Date: December 31 2020.
~chedule Page: 326.18 Line No.14 Column: b
econdary, economy and/or non-finn.
~chedule Page: 326.19 Line No.Column: I
Line loss.
~chedule Page: 326.19 Line No.Column: b
econdary, economy and/or non-fmn.
~chedule Page: 326.19 Line No.Column: b
econdary, economy and/or non-fmn.
~chedule Page: 326.19 Line No.Column: I
ettlement on energy variation.
~chedule Page: 326.19 Line No.Column: b
econdary, economy and/or non-fmn.
~chedule Page: 326.19 Line No.Column: I
tart-up and variable operation and maintenance charges.
~chedule Page: 326.19 Line No.10 Column: b
econdary, economy and/or non-fmn.
~chedule Page: 326.19 Line No.14 Column: b
Settlement ad.ustment.
chedule Page: 326.19 Line No.14 Column: I
Settlement ad.ustment.
chedule Page: 326.20 Line No.Column: b
Settlement adjustment.
~chedule Page: 326.20 Line No.Column: I
Settlement ad.ustment.
chedule Pa e: 326.20 Line No.Column: I
Settlement ad.ustment.
chedule Page: 326.20 Line No.Column: b
Second , economy and/or non-finD.
chedule Pa e: 326.20 Line No.Column: I
perating reserves.
~chedule Page: 326.20 Line No.Column: b
Secondary, economy and/or non-fmn.
chedule Page: 326.20 Line No.Column: I
Settlement on energy variation.
~chedule Page: 326.20 Line No.Column: I
eserve Share and Line loss.
~chedule Page: 326.20 Line No.Column: I
Liquidated damages.~dule Page: 326.20 Line No.10 Column: I
Accounting accrual and excess net power cost deferrals.
~chedule Page: 326.20 Line No.11 Column: I
elivery of energy to settle loss dis ute.
~chedule Page: 326.20 Line No.12 Column: b
Settlement 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 (2)A Resubmisslon 05/17/2007 2006/04
FOOTNOTE DATA
~chedule Page: 326.20 Line No.12 Column: I
eserve for potential liabilities associated with payable disputes.
~chedule Page: 326.20 Line No.13 Column: I
Reserve for otentialliabilities associated with ayable disputes.
chedule Pa e: 326.20 Line No.14 Column: b
ettlement adjustment.
~chedule Page: 326.20 Line No.14 Column: I
Reco ition and re oTting of ains and losses on bookouts under EITF Issue No. 03-11.
chedule Page: 326.21 Line No.Column: I
Reco ition and re OTting of gains and losses on bookouts under EITF Issue No. 03-11.
chedule Pa e: 326.21 Line No.Column: b
Settlement adjustment.
~chedule Page: 326.21 Line No.Column: I
Reco .tion and re oTting of ains and losses on ener tradin contracts under EITF Issue No. 02-04.
chedule Page: 326.21 Line No.Column: I
Recognition and re oTting of aIDs and losses on energy trading contracts under EITF Issue No. 02-04.
chedule Page: 326.21 Line No.Column: I
xchange energy expense and Load factoring and storage charges.
~chedule Page: 326.21 Line No.Column: I
oad factoring and storage charges.
~chedule Page: 326.21 Line No.Column: I
balance energy.
~chedule Page: 326.21 Line No.12 Column: I
Liquidated damages.
~chedule Page: 326.21 Line No.13 Column: b
ettlement adjustment.
~chedule Page: 326.21 Line No.13 Column: I
Exchange ener ex ense.
chedule Pa e: 326.21 Line No.14 Column: I
Exchange ener ex ense.
chedule Page: 326.22 Line No.Column: b
Settlement ad.ustment.
chedule Page: 326.22 Line No.Column: I
Imbalance energy.
~chedule Page: 326.22 Line No.Column: I
Imbalance ener
chedule Page: 326.22 Line No.Column: I
Load factoring and storage char es.
chedule Page: 326.22 Line No.Column:
Pacific Northwest Electric Power Planning and Conservation Act, FERC Electric Tariff, Original Volume No. I.
~chedule Page: 326.22 Line No.Column: h
hese megawatt hours re resent book entry only. No actual energy transfer took place.
~chedule Page: 326.22 Line No.Column: ;
ese megawatt hours represent book entry only. No actual energy transfer took place.
~chedule Page: 326.Line No.Column: I
Pacific Northwest Electric Power Planning and Conservation Act, F RC Electric Tariff, Original Volume No.
ISchedule Page: 326.22 Line No.Column: I
xchange energy expense.
~chedule Page: 326.22 ne No.Column: I
xchange energy expense.
~chedule Page: 326.22 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)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
Line No.Column: I
Line No.Column: I
Line No.Column: I
Line No.Column: b
Column: I
Column: I
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: I
Line No.Column: b
Line No.Column: I
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 05/17/2007 2006/Q4
FOOTNOTE DATA
rschedule Page: 326 24 Line No.Column: b
ettlement adjustment.
~chedule Page: 326.24 Line No.Column: I
Imbalance ener
Schedule Page: 326.24 Line No.Column: I
balance energy.
~chedule Page: 326.24 Line No.Column: b
ettlement adjustment.
~chedule Page: 326.24 Line No.Column: I
balance energy.
~chedule Page: 326.24 Line No.Column: I
mbalance energy.
~chedule Page: 326.24 Line No.Column: b
ettlement adjustment.
~chedule Page: 326.24 Line No.Column: I
Imbalance ener
chedule Page: 326.24 Line No.10 Column: I
Imbalance ener
chedule Page: 326.24 Line No.12 Column: I
balance energy.
~chedule Page: 326.24 Line No.14 Column: b
Not applicable: adjustment for inadvertent interchange.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Date of Report
(Mo. Da, Yr)
05/17/2007
ccount(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, Le., 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.
Name of Respondent
PacifiCorp
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
1 Avista Energy
2 Basin Electric Power Cooperative
3 Basin Electric Power Cooperative
4 Black Hills Power & Light Company
5 Black Hills Power & Light Company
6 Black Hills Power & Light Company
7 Black Hills Power & Light Company
8 Bonneville Power Administration
9 Bonneville Power Administration
10 Bonneville Power Administration
11 Bonneville Power Administration
12 Bonneville Power Administration
13 Bonneville Power Administration
14 Bonneville Power Administration
15 Bonneville Power Administration
16 Cargill-Alliant. LLC
17 Cargill-Alliant, LLC
18 Coral Power
19 Conoco Inc.
20 Cowlitz County PUD
21 Deseret Generation & Transmission
22 Eugene Water & Electric Board
23 Eugene Water & Electric Board
24 Fall River Rural Electric Coop.
25 Flathead Electric Cooperative Inc.
26 Idaho Power Company
27 Idaho Power Company
28 Idaho Power Company
29 Idaho Power Company
30 Idaho Power Company
31 Moon Lake Electric Association
32 Morgan Stanley Capital Group, Inc.
33 Morgan Stanley Capital Group. Inc.
34 Pacific Gas & Electric
TOTAL
FERC FORM NO.1 (ED. 12-90)
This ~rt Is:(1) ~An Original
(2) A Resubmission
Year/Period of Report
End of 2006/04
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
PacificCorp Merchant
PacificCorp Merchant
Bonneville Power Administration
Bonneville Power Administration
Black Hills Power & Light Company
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
U S Bureau of Reclamation
Umpqua Indian Utility Cooperative
Bonneville Power Administration
Bonneville Power AdministrationBonneville Power Administration
Bonneville Power Administration Yakama Power
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 2006/Q4
(2) CiA Resubmission 05/17/2007
ccount 456)(Contlnued)(Including transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
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)
(j)
OV-Various Various 263
OV-Yellowtail Sub Sheridan Sub 31,452 31 ,45~
OV-Yellowtail Sub Sheridan Sub 59,184 59,18'1
OV-148,265 148,26~
OV-81,309 81 ,3m
OV-Various Sheridan Sub 138,471 138,471
OV-Various Wyodak Sub 39,202 39,
237 Various Various 310 632,199 632 19~
324 Lost Creek Hydro Pia Various 312,549 312 549
OV-Bonneville Power Adm GazJey Substation 22,638 22,63e
OV-USBR Green Springs Bonneville Power Adm 67,095 095
368 Malin Sub Malin Sub 102 670,858 670,85e
OV-Bonneville Power Adm White SwanIToppenish 058 24.05E
299 Various Various 217 415,829 1 ,415,82~
OV-052 05~
OV-550,741 550,741
OV-52,903 52,90~
OV-
OV-
234 Swift Unit No.Woodland Sub
280 Various Various 105 786,970 786,97C
OV-
332 TIeton Sub Various 11,249 11,249
322 Targhee Sub Goshen Sub
OV-Yellowtail Sub Various 037 031
OV-Red Butte Borah 57,340 34C
OV-73,643 73,64~
OV-120,200 120,20(
257 Antelope Sub Antelope Sub
203 Jim Bridger Sub Bridger Pump Station
302 Duchesne Duchesne 12,794 12,79/
OV-703 703
OV-105.878 105.87e
Malin Sub Indian Springs
129 484,656 39,484,65E
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 2oo6/Q4
ccount(Includin transactions reffered to as w eelin '
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.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Ine
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
432 565
142 985 188,283
128,504 143,191
757 578 757 578
398,462 427 383
592,979 735.942
378,675 447,525
178,217 252,341
312,276
39,789 169,611
400,950 437,400
233,057
78,124 153,719
1,473,459 134,064
13,111 13,111
689,749 036,488
242,228 242,228
642 642
401 6,401
94,254
877,825 809,099
905
151,875 151,875
151 308
547 33,421
759,375 759,375
297 825
749 749
73.824
16,284
18.225 20,010
24,459
771 ,804
627,022
25,915,642 559,495 54,335,509
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)
05/17/2007
Year/Period of Report
End of 2006/Q4
ccount(Includin transactions referred to as 'wheelin '
1. Report all transmission of electricity, Le., 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 PPM Energy Inc.
2 PPM Energy Inc.
3 PPM Energy Inc.
4 PPM Energy Inc.
5 PPM Energy Inc.
6 Portland General Electric.
7 Powerex
8 Powerex
9 Powerex
10 Powder River Energy Corporation
11 PPL Montana. LLC
12 Public Service Company of Colorado
13 Rainbow Energy Marketing
14 Rainbow Energy Marketing
15 San Diego Gas & Electric
16 Seattle City Light
17 Seawest Windpower, Inc.
18 Sempra Energy Trading Corp
19 Sempra Energy Trading Corp
20 Sempra Energy Solutions
21 Sierra Pacific Power Company
22 Sierra Pacific Power Company
23 Southem Califorinia Edison Company
24 State of South Dakota
25 TransAlta Energy
26 Tri-State Generation & Transmission
27 Tri-State Generation & Transmission
28 United States Bureau of Reclamation
29 United States Bureau of Reclamation
30 United States Bureau of Reclamation
31 United States Bureau of Reclamation
32 Utah Associated Municipal Power
33 Utah Associated Municipal Power
34 Utah Municipal Power Agency
TOTAL
FERC FORM NO.1 (ED. 12-90)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
Utah Associated Municipal Power
Utah Municipal Power Agency
Utah Associated Municipal Power
Utah Municipal Power Agency
Page 328.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2006/Q4
(2) CiA Resubmission 05/17/2007
. u\ cLcl,,; I MI""! T r-YM ~ I nCMi='l~ccount 4bb)ll,,;ontmueo)(Including transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
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-245 559 245.55S
OV-982 98~
OV-209 20S
OV-251 251
OV-Exxon Metering Stati Harry Allen/Mona Sub 427 132 427,13~
OV-958 95E
OV-Bonneville Power Adm Weed Jct. Sub 296,269 296,26~
OV-262,513 262
OV-17,469 17,46~
Various Buffalo Sub
OV-47,665 47,66'i
OV-76.089 76,Oa9
OV-35.402 35,40~
OV-400 4OC
Malin Sub Indian Springs
OV-Wallula Sub Mid-
OV-Foote Creek Sub
OV-69,281 69,281
OV-128,432 128,43~
OV-Bonneville Power Adm Various 120,003 120,00~
OV-373 350 373.35C
OV-285,321 285,321
Malin Sub Indian Springs
OV-Yellowtail Sub Wyodak Sub 19,911 19,911
OV-832 832
123 Various Various 167 669 167 669
OV-737 14,731
Franklin Substation Burbank Pumps 18,544 18,544
Pasco Sub Dodd Road Sub
Redmond Substation Crooked River Pumps 732 73~
Redmond Substation Crooked River Pumps
OV-284 2S;1
297 Varjous Various 456 601 615 601 61~
279 Various Various 156 638,349 638,34~
129 39,484,656 39,4S4,65E
FERC FORM NO.1 (ED. 12-90)Page 329.
Blank Page
(Next Page is: 330.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/Q4
ccount
(Including transactions reffered to as 'w eelin '
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.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
649,820 1 ,838.006
297 936 415,986
691,329
944,177
670,625 733,750
142
447 875 579,500
650,482 707 469
86,487 86,487
132
288,951
325,922
210,205
900
33,250
212,625
46,766
186,900
652,632
149,285 194,763
763,889
014 825
593,772
89,100 97,200
6,494
753 74,742
142,671
825 18,544
186
713 10,903
581
728
715,516 719,712
803.160 179,139
25,915,642 14,559,495 54,335,509
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2oo6/Q4(2) DA Resubmission 05/17/2007
UI- I:Lt;:.\,; I nlv.' IT ,":UH V! 1")t:'1~L~ccount 4bO.(Including transactions referred to as 'wheeling
Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
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)
Warm Springs Power Enterprises Warm Springs Enterprises Portland General Electric Co.
Washington Water Power
Westem Area Power Administration Westem Area Power Administration Various WAPA Customers in PACE
Westem Area Power Administration Westem Area Power Administration Various WAPA Customers in PACE
Westem Area Power Administration Westem Area Power Administration Westem Area Power Administration
Weyerhaeuser Company Weyerhaeuser Company Bonneville Power Administration
Accruals
Basin Electric Power Cooperative Westem Area Power Administration Powder River Energy Corp
Basin Electric Power Cooperative Westem Area Power Administration Powder River Energy Corp
Black Hills Power & Light Company PacifiCorp Merchant Montana-Dakota Utilities
Black Hills Power & Ught Company PacifiCorp Merchant Black Hills Power & Light Company
Black Hills Power & Ught Company
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
Bonneville Power Administration Bonneville Power Administration Umpqua Indian Utility Cooperative
Bonneville Power Administration United States Bureau of Reclamatn Bonneville Power Administration
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration
Bonneville Power Administration
Bonnevilie Power Administration Bonneville Power Administration Bonneville Power Administration
Cargill-Alliant, LLC
Cargill-Alliant, LLC
Coral Power
Deseret Generation & Tranmlssion Deseret Generation & Tranmission Deseret Generation & Tranmission
Deseret Generation & Tranmlssion Deseret Generation & Tranmission Deseret Generation & Tranmission
Flathead Electric Cooperative Westem Area Power Administration Flathead Electric Cooperative
Idaho Power Company Nevada Power Company Idaho Power Company
Idaho Power Company
Idaho Power Company
Moon Lake Electric Association Moon Lake Electric Association Moon Lake Electric Association
Morgan Stanley Captial Group, Inc.
Morgan Stanley Captial Group, Inc.
PacifiCorp Power Marketing Stateline Wind Project Various
PacifiCorp Power Marketing Pleasant Valley Various
PPM Energy, Inc.
PPM Energy, Inc.
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 2006/Q4(2) riA Resubmission 05/17/2007I OF II Y I""YH U I , """'v ~....ccount 456)(ContlOued)(Includino transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand lIIfegawatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
591 Pelton Reregulation Round Butte Substati 88,584 88,58-1
OV-
262 Various Various 328 780.125 780,12E
263 Various Various 898 89E
OV-Wyoming Distribution Wyoming Distribution 075 11
OV-Westem Kraft Substa Alvey Substation 269,220 269,22(
OV-Yellowtail Sub Sheridan Sub 118,412
OV-Yellowtail Sub Sheridan Sub 132,008
OV-Various Sheridan Sub 389 124
OV-Various Wyodak Sub 222 064
OV-031
237 Various Various 356,939
, ,
OV-Bonneville Power Ad Gazley Substation 60,042
OV-USBR Green Springs Bonneville Power 156,902
368 Malin Sub Malin Sub.580,774
256 Various Various 447.546
,,- -
299 Various Various 809,081
OV-186,243
OV-202,338
OV-112
280 Various Various 314 866
OV-Various Various 195
OV-Yellowtail Sub Various 15,606
OV-Red Butte Borah 314,450
OV-644,631
OV-212,760
302 Duchesne Duchesne 33,109
OV-222 837
OV-134.748
OV-Wallula Sub (State)Mid-320 585
, ~,
OV-UINTA/Pleasant Vally MPAC 312,310
OV-876,217
OV-221,611
129 39,484,656 39,484,
FERC FORM NO.1 (ED. 12-90)Page 329.
Blank Page
(Next Page is: 330.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2006/04(2) riA Resubmission 05/17/2007
- Of "'L."'V' "':' T ~.. ~- ....0 '~
I); ccounf45Bf(C"ontlnuea)(Including transactions reffered to as 'w eelino'
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.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)Line
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
109,725 119,700
581,300 061 ,809
132 504 155,274
19,793 061
000,443 831,066
973,704 973,704
25,915,642 14,559,495 13,860,372 54,335 509
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2006/04(2) MA Resubmission 05/17/2007
............
";IHI~IIY ccount456.(Including transactions referred to as 'wheeling
Report all transmission of electricity, Le., 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)
PPM Energy, Inc.Stateline Wind Stateline Wind
PPM Energy, Inc.Uinta Uinta
Powerex Bonneville Power Administration CAISO
Powerex
Powerex
Public Service Company of Colorado
Public Service Company of Colorado
Public Service Company of Colorado
Sempra Energy Solutions Bonneville Power Administration Oregon Direct Access
Sierra Pacific Power Company
State of South Dakota Westem Area Power Administration Black Hills Power & Light Company
Tri-State Generation & Transmission
United States Bureau of Reclamation Bonneville Power Administration United States Bureau of Reclamat
United States Bureau of Reclamation Bonneville Power Administration Crooked River Irrigation District
Utah Associated Municipal Power Utah Associated Municipal Power Utah Associated Municipal Power
Utah Municipal Power Agency Utah Municipal Power Agency Utah Municipal Power Agency
Warm Springs Power Enterprises Warm Springs Enterprises Portland General Electric Company
Westem Area Power Administration Westem Area Power Administratio Various WAPA Customers in PACE
Westem Area Power Administration Westem Area Power Administratio Westem Area Power Administratio
Westem Area Power Administration Westem Area Power Administratio Westem Area Power Administratio
Weyerhaeuser Company Weyerhaeuser Company Bonneville Power Administration
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2006/Q4
(2) CiA Resubmission 05/17/2007
. u,r t:1,-t:1,,; I HIyll Y ""YH U I, Ht:H::' ~Account 456)(Contlnued)
(Including transactions reffered to as 'wheeling
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 Megawatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered(e)(f)
(g)
(h)(i)
(j)
OV-614
OV-356
OV-Bonneville Power Ad Weed Jct Sub 062 505
OV-232 345
OV--459,519
OV-115,006
OV-447 698
OV-22,083
OV-Bonneville Power Ad Various 174,753
OV-059,914
OV-Yellowtail Sub Wyodak Sub 55,157
123 Various Various 458,206
Franklin Substation Burbank Pumps 690
Redmond Substation Crooked River 10,226
297 Various Various 125,135
279 Various Various 241,587
591 Pelton Reregulation Round Butte 200,748
...
262 Various Various 650,620
OV-Various Various 1,493
OV-Wyoming Distribution Wyoming Distribution 987
OV-Westem Kraft Sub Alvey Substation 29,764
129 39,484,656 39,484,65E
FERC FORM NO.1 (ED. 12-90)Page 329.
Blank Page
(Next Page is: 330.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2006/Q4(2) riA Resubmission 05/17/2007
cLcl,,; I HIl,,;I I Y rldH U HCH::S
h~ccount 456) (Continued)(Including transactions reffered to as w eel in g
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.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges Energy Charges (Other Charges)Total Revenues ($)une
($)($)($)
(k+l+m)No.
(k)(I)(m)(n)
25,915,642 14,559,495 13,860,372 54,335,509
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 (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 328 Line No.Column: b
Various si atories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
chedule Pa e: 328 Line No.Column:
Various si atories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
chedule Pa e: 328 Line No.Column: d
Non-Firm or Short-Term Firm Transmission Service under the 0 en Access Transmission Tariffbetween various parties and oints.
chedule Page: 328 Line No.Column:
Settlement adjustment.
~chedule Page: 328 Line No.Column: d
vergreen Network Transmission Service under the Open Access Transmission Tariff (S.A. 228 & 233).
~chedule Page: 328 Line No.Column:
ettlement adjustment and Regulation & Frequency Response.
~chedule Page: 328 Line No.Column: d
vergreen Network Transmission Service under the Open Access Transmission Tariff (S.A. 228 & 233).
~chedule Page: 328 Line No.Column:
ettlement adjustment.
~chedule Page: 328 Line No.Column: b
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328 Line No.Column:
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328 Line No.Column: d
Non-Firm or Short-Term Firm Transmission Service under the
chedule Page: 328 Line No.Column:
ettlement adjustment.
~chedule Page: 328 Line No.Column: b
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
chedule Page: 328 Line No.Column:
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328 Line No.Column: d
Non-Firm or Short-Term Firm Transmission Service under the 0 en Access Transmission Tariff between various
chedule Page: 328 Line No.Column:
ettlement adjustment.
',schedule Page: 328 Line No.Column: d
etwork Transmission Service under the Open Access Transmission Tariff (S.A. 67) terminating on December 31, 2006.
~chedule Page: 328 Line No.Column:
ettlement adjustment.
~chedule Page: 328 Line No.Column: d
Point-to-Point Transmission Service under the 0 en Access Transmission Tariff S.A. 67
chedule Pa e: 328 Line No.Column:
Settlement adjustment.
~chedule Page: 328 Line No.Column: d
General Transfer A eement for network service in P ACW. Evergreen.
chedule Page: 328 Line No.Column:
Settlement adjustment and demand dollars plus a fIXed cost calculated using plant investment values at various u.S. government
cilities.
~chedule Page: 328 Line No.Column: d
Network Transmission Service terminating on October 31 2008.
'Schedule Page: 328 Line No.Column:
Demand dollars plus a fixed cost calculated using plant investment values at various u.S. government facilities.
ettlement adjustment.
~chedule Page: 328 Line No.1~ Column: d
IFERC FORM NO.1 (ED. 12-87)
en Access Transmission Tariff between various
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 05/17/2007 2006/04
FOOTNOTE DATA
Network Transmission Service and Distribution Delivery Service under the Open Access Transmission Tariff (S.A. 229) terminating
on September 30, 2011.
ISchedule Page: 32.8 Line No.10 Column:
Settlement a ustment, Prima Delive Service, Distribution Service Char e and Re ulation & Fre uenc
't;chedule Pa e: 328 Line No.11 Column: d
oint-to-Point Transmission Service under the Open Access Transmission Tariff (S.A. 179) terminating on September 30, 2025.
't;chedule Page: 328 Line No.11 Column:
ettlement adjustment.
't;chedule Page: 328 Line No.12 Column: d
alin Transformer use under the AC Intertie Agreement dated June 1 , 1994. Subject to termination upon mutual agreement.
't;chedule Page: 328 Line No.12 Column:
Sole use of facilities charge and Settlement adjustment.
ISchedule Page: 328 Line No.13 Column: d
Network Transmission Service and Distribution Delivery Service under the Open Access Transmission Tariff (S.A. 328) terminating
on February 28 2007.
't;chedule Page: 328 Line No.13 Column:
Primary Delivery Service, Distribution Service Charge and Regulation & Fre uency Res onse.
chedule Page: 328 Line No.14 Column: d
General Transfer A eement for network service in PACE. Evergreen.
chedule Page: 328 Line No.14 Column:
harges for monitoring, scheduling, load following and spinning reserve, Settlement adjustment and Sole use of facilities charge.
't;chedule Page: 328 Line No.15 Column: b
' ..
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
't;chedule Page: 328 Line No.15 Column:
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
't;chedule Page: 328 Line No.15 Column: d
on-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
't;chedule Page: 328 Line No.16 Column: b
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
't;chedule Page: 328 Line No.16 Column:
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
't;chedule Page: 328 Line No.16 Column: d
Non-Firm or Short-Term Firm Transmission Service under the 0 en Access Transmission Tariffbetween various
chedule Page: 328 Line No.16 Column:
ettlement adjustment.
!Schedule Page: 328 Line No.17 Column: b
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328 ne No.17 Column:
Various si atories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
chedule Page: 328 Line No.17 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
!Schedule Page: 328 Line No.18 Column: b
Various si atories to the Original Volume 11 Point-to-Point Transmission Tariff.
chedule Page: 328 Line No.18 Column:
arious signatories to th Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328 Lin~ No.18 Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
ISchedule Page: 328 Line No.19 Column: b
Various signatories to e Original Volume 11 Point to-Point Transmission Tariff.
'Schedule Page: 328 b!"No.19 Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
IFERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
'echedule Page: 328 Line No.19 Column: d
Non-Finn or Short- Tenn Finn Transmission Service under the 0 en Access Transmission Tariff between various
chedule Page: 328 Line No.20 Column: d
Agreement providing for transmission and operation of Cowlitz' Swift 2 Hydro Generation. Payment is for 26% of annual costs of
wift-Cowlitz Transmission Line. Agreement is for the life of Swift Unit No.
iSchedule Page: 328 Line No.20 Column:
Settlement adjustment.
ISchedule Page: 328 Line No.21 Column: d
Transmission Service and Operating Agreement for network service in PACE. Subject to tennination upon mutual agreement.
iSchedule Page: 328 Line No.21 Column:
Charges for monitoring, scheduling, load following and spinning reserve, Settlement adjustment, Distribution Service Charge, Primary
Delive Service and Meter Interro ation Services.
chedule Pa e: 328 Line No.22 Column: b
Various si atories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
chedule Pa e: 328 Line No.22 Column:
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
iSchedule Page: 328 Line No.22 Column: d
on-Finn or Short- Tenn Finn Transmission Service under the Open Access Transmission Tariff between various parties and points.
iSchedule Page: 328 Line No.23 Column: d
Point-to-Point Transmission Service under the en Access Transmission Tariff, (SA 332) tenninating July 1 2007.
chedule Page: 328 Line No.24 Column: d
Point-to-Point Transmission Service tenninatin on July 31, 2028.
chedule Pa e: 328 Line No.24 Column:
ole use of facilities charge and Settlement adjustment.
iSchedule Page: 328 Line No.25 Column: d
Ever een Network Transmission Service and Distribution Delivery Service under the 0 en Access Transmission Tariff (S.A. 227).
chedule Page: 328 Line No.
:.
25 Column:
Primary Delivery Service, Settlement adjustment, Distribution Service Char e and Regulation & Fre uency Res onse.
chedule Page: 328 Line No.26 Column: d
Direct Assignment Facilities Service Agreement under the Open Access Transmission Tariff (S.A. 264) tenninating July 31 , 2014.
iSchedule Page: 328 Line No.27 Column: b
Various si atories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
chedule Page: 328 Line No.27 Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328 Line No.27 Column: d
on-Finn or Short-TenD Finn Transmission Service under the Open Access Transmission Tariffbetween various parties and points.
iSchedule Page: 328 Line No.28 Column: b
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
iSchedule Page: 328 Line No.28 Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
iSchedule Page: 328 Line No.28 Column: d
Non-Finn or Short-TenD Finn Transmission Service under the Open Access Transmission Tariff between various parties and points.
iSchedule Page: 328 Line No.28 Column:
ettlement adjustment.
!Schedule Page: 328 Line No.29 Column: b
0 eration, maintenance or facility lease services with no recei t or delivery of energy.
Schedule Pa e: 328 Line No.29 Column:
Operation, maintenance or facility lease services with no receipt or delivery of energy.
ISchedule Page: 328 Line No.29 Column: d
Antelo e Substation use of facilities.
Schedule Page: 328 Line No.29 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 05/17/2007 2006/04
FOOTNOTE DATA
ole use of facilities charge and Settlement adjustment.
!Schedule Page: 328 Line No.30 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
ISchedule Page: 328 Line No.30 Column:
Operation, maintenance or facility lease services with no receipt or delivery of energy.
ISchedule Page: 328 Line No.30 Column: d
Jim Bridger Pum use of facilities.
chedule Page: 328 Line No.30 Column:
Sole use of facilities charge and Settlement adjustment.
ISchedule Page: 328 Line No.31 Column: d
Transmission Service and Interconnection Agreement for network service in PACE. Terminates in 2047
!Schedule Page: 328 Line No.31 Column:
ettlement adjustment.
!Schedule Page: 328 Line No.32 Column: b
Various si atories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
chedule Page: 328 Line No.32 Column:
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328 Line No.32 Column: d
Non-Finn or Short-Term Finn Transmission Service under the a en Access Transmission Tariff between various
chedule Page: 328 Line No.33 Column: b
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328 Line No.33 Column:
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328 Line No.33 Column: d
on-Finn or Short-Term Finn Transmission Service under the Open Access Transmission Tariffbetween various parties and points.
!Schedule Page: 328 Line No.33 Column:
Settlement adjustment.
!Schedule Page: 328 Line No.34 Column: b
Operation, maintenance or facility lease services with no receipt or delivery of energy.
!Schedule Page: 328 Line No.34 Column:
eration, maintenance or facility lease services with no recei t or delivery of energy.
chedule Pa e: 328 Line No.34 Column: d
Malin to Indian S rings use of facilities Terminating August 1, 2007
chedule Page: 328 Line No.34 Column:
Sole use of facilities charge and demand dollars plus a fIXed cost calculated using plant investment values at various U.S. government
cilities.
!Schedule Page: 328.Line No.Column: b
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328.Line No.Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328.Line No.Column: d
on-Finn or Short-Term Finn Transmission Service under the Open Access Transmission Tariff between various parties and points.
!Schedule Page: 328.Line No.Column:
Settlement adjustment.
ISchedule Page: 328.Line No.Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328.Line No.Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page:
;!?
Line No.Column: d
Non-Finn or Short-Term Firm Transmission Service under ~i!~Open Access Transmission Tariffbetween various parties and points.
!Schedule Page: 328.Line No.Column: m .
IFERC FORM NO. 1 (ED. 12-87)Page 450.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
ettlement adjustment.
!Schedule Page: 328.Line No.Column: d
oint-to-Point Transmission Service under the Open Access Transmission Tariff (S.A. 313).
!Schedule Page: 328.Line No.Column:
Char es for monitorin , schedulin , load followin and s innin reserve, Settlement ad.ustment and Unauthorized Use.
chedule Pa e: 328.Line No.Column: d
oint-to-Point Transmission Service under the Open Access Transmission Tariff (S.A. 314 and 315).
!Schedule Page: 328.Line No.Column:
Charges for monitoring, scheduling, load following and spinning reserve, Settlement adjustment, Unauthorized Use and Regulation &
Fre uency Res onse.
chedule Page: 328.Line No.Column: d
Point-to-Point Transmission Service under the 0 en Access Transmission Tariff (S.A. 279).
chedule Page: 328.Line No.Column:
eposit Refund and Settlement adjustment.
!Schedule Page: 328.Line No.Column: b
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328.Line No.Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328.Line No.Column: d
on-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
!Schedule Page: 328.Line No.Column:
Settlement adjustment.
!Schedule Page: 328.Line No.Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (S.A. 169) terminating on Se tember 30, 2007.
chedule Pa e: 328.Line No.Column:
ettlement adjustment.
!Schedule Page: 328.Line No.Column:b
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
chedule Page: 328.Line No.Column:
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328.Line No.Column: d
Non-Firm or Short-Term Firm Transmission Service under the 0 en Access Transmission Tariff between various
chedule Page: 328.Line No.Column:
ettlement adjustment.
!Schedule Page: 328.Line No.Column: b
Various si atories to the Original Volume 11 Point-to-Point Transmission Tariff.
chedule Page: 328.Line No.Column:
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328.Line No.Column: d
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
!Schedule Page: 328.Line No.10 Column: d
Agreement providing for transmission service nom Western Area Power Administration s Casper Substation in Wyoming and
Yellowtail Substation in Montana to Sheridan-johnson s load at PacifiCo s Buffalo Substation in Wyoming.
chedule Pa e: 328.Line No.10 Column:
Sole use of facilities char~edule Page: 328.Line No.11 Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule page:328.1LTne No.11 Column:
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
chedule Page: 328.Line No.11 Column: d
_-
Non-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
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 05/17/2007 2006/Q4
FOOTNOTE DATA
----
~chedule Page: 328.Line No.11 Column:
Settlement adjustment.
ISchedule Page: 328.Line No.12 Column: b
Various si atories to the Original Volume 11 Point-to-Point Transmission Tariff.
chedule Page: 328.Line No.12 Column:
Various si atories to the Original Volume 11 Point-to-Point Transmission Tariff.
chedule Pa e: 328.Line No.12 Column: d
Non-Finn or Short-Term Firm Transmission Service under the 0 en Access Transmission Tariff between various
chedule Page: 328.Line No.12 Column:
Settlement ad.ustment.
chedule Pa e: 328.Line No.13 Column: b
Various signatories to the on inal Volume 11 Point-to-Point Transmission Tariff.
chedule Pa e: 328.Line No.13 Column:
Various si atories to the Original Volume 11 Point-to-Point Transmission Tariff.
chedule Pa e: 328.Line No.13 Column: d
Non-Firm or Short-Term Finn Transmission Service under the 0 en Access Transmission Tariffbetween various
chedule Page: 328.Line No.13 Column:
Settlement adjustment.
~chedule Page: 328.Line No.14 Column: b
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328.Line No.14 Column:
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328.Line No.14 Column: d
on-Finn or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
~chedule Page: 328.Line No.14 Column:
ettlement adjustment.
~chedule Page: 328.Line No.15 Column: b
eration, maintenance or facility lease services with no recei t or delivery of ener
chedule Page: 328.Line No.15 Column:
eration, maintenance or facility lease services with no recei t or delivery of energy.
chedule Page: 328.Line No.15 Column: d
Malin to Indian S rings use of facilities Terminating August 1 2007
chedule Page: 328.Line No.15 Column:
Sole use of facilities charge.
~chedule Page: 328.Line No.16 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff, (S.A. 289) terminatin November 30, 2008.
chedule Pa e: 328.Line No.16 Column:
xtension of Commencement Date Fee
~chedule Page: 328.Line No.17 Column: d
Direct Assignment Facilities Service Agreement under the Open Access Transmission Tariff (S.A. 264) terminating July 31, 2014.
~chedule Page: 328.Line No.17 Column:
Sole use of facilities charge and Settlement adjustment.
~chedule Page: 328.Line No.18 Column: b
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328.Line No.18 Column:
Various si atories to the Original Volume 11 Point-to-Point Transmission Tariff.
chedule Page: 328.Line No.18 Column: d
on-Firm or Short-Term Firm Transmission Service under the Open Access Transmission Tariffbetween various parties and points.
~chedule Page: 328.Line No.19 Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page:328.Line No.19 Coll!mn:
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 05/17/2007 2006/Q4
FOOTNOTE DATA
arious signatories t the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328.Line No.19 Column: d
Non-inn or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.~ule Page: 328.Line No.19 Column:
ettlement adjustment.
~chedule Page: 328.Line No.: 20 Column: d
Network Transmission Service under the Open Access Transmission Tariff (S.A. 299). Service provided pursuant to rules &
regulations of Oregon Direct Access. Termination upon notification pursuant to Oregon Direct Access and Open Access Transmission
Tariff.
ISchedule Page: 328.Line No.: 20 Column:
Re lation & Fre uency Response and Settlement adjustment.
chedule Pa e: 328.Line No.21 Column: b
Various si atories to the Original Volume 11 Point-to-Point Transmission Tariff.
chedule Page: 328.Line No.21 Column:
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328.Line No.21 Column: d
on-Finn or Short-Term Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
~chedule Page: 328.Line No.21 Column:
ettlement adjustment.
!Schedule Page: 328.Line No.22 Column: b
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328.Line No.22 Column:
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328.Line No.22 Column: d
Non-Finn or Short-Term Finn Transmission Service under the 0 en Access Transmission Tariffbetween various
chedule Pa e: 328.Line No.23 Column: b
0 eration, maintenance or facili lease services with no recei t or delivery of ener
chedule Page: 328.Line No.23 Column:
eration, maintenance or facility lease services with no recei t or delivery of ener
chedule Page: 328.Line No.23 Column: d
Malin to Indian S rings use offacilities Terminatin Au ust 1, 2007
chedule Pa e: 328.Line No.23 Column:
Sole use offacilities charge and demand dollars plus a fIXed cost calculated using plant investment values at various u.S. government
facilities.
~chedule Page: 328.Line No.24 Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (S.A. 170) terminating on May 31 , 2007.
~chedule Page: 328.Line No.24 Column:
ettlement adjustment.
!Schedule Page: 328.Line No.25 Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328.Line No.25 Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328.Line No.25 Column: d
Non-Finn or Short-Term Finn Transmission Service under the 0 en Access Transmission Tariff between various
chedule Page: 328.Line No.25 Column:
ettlement adjustment.
~chedule Page: 328.Line No.26 Co/~mn: b
0 eration, maintenance or facility lease services with no recei t or delivery of energy.
chedule Pa e: 328.Line No.26 Column:
eration, maintenance or facility lease services with no recei t or delivery of energy.
chedule Page: 328.Line No.26 C;olumn: d
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 05/17/2007 2006/04
FOOTNOTE DATA
Transmission Service Agreement for Network Services in PACE Tenninating upon written notification.
ISchedule Page: 328.Line No.26 Column:
ettlement adjustment.
~chedule Page: 328.Line No.27 Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328.Line No.27 Column:
arious signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328.Line No.27 Column: d
Non-Firm or Short- Tenn Finn Transmission Service under the 0 en Access Transmission Tariffbetween various
chedule Pa e: 328.Line No.27 Column:
Settlement adjustment.
~chedule Page: 328.Line No.28 Column: d
March 26, 1957 Columbia Basin Project (Burbank Pum ) wheelin agreement tenninating on Se tember 30, 2007.
chedule Pa e: 328.Line No.28 Column:
ettlement adjustment.
~chedule Page: 328.Line No.29 Column: d
March 26, 1957 Columbia Basin Pro. ect (Burbank Pum ) wheeling agreement tenninating on Se tember 30, 2007.
Schedule Page: 328.Line No.29 Column:
ole use of facilities charge.
~chedule Page: 328.Line No.30 Column: d
ctober 9, 1962 Crooked River Project wheeling agreement.
~chedule Page: 328.Line No.30 Column:
ettlement adjustment.
~chedule Page: 328.Line No.31 Column: d
ctober 9, 1962 Crooked River Project wheeling agreement.
~chedule Page: 328.Line No.31 Column:
Demand dollars plus a fIXed cost calculated using plant investment values at various u.S. government facilities.
~chedule Page: 328.Line No.32 Column: b
Various si atories to the Ori inal Volume 11 Point-ta-Point Transmission Tariff.
chedule Pa e: 328.Line No.32 Column:
arious signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~chedule Page: 328.Line No.32 Column: d
on-Firm or Short-Tenn Finn Transmission Service under the Open Access Transmission Tariff between various parties and points.
~chedule Page: 328.Line No.33 Column: d
Transmission Service and Operating Agreement for network service in PACE. Subject to tennination upon mutual agreement.
~chedule Page: 328.Line No.33 Column:
Char es for monitorin , schedulin , load followin and s innin reserve, Settlement ad.ustment and Distribution Service Char e.
chedule Pa e: 328.Line No.34 Column: d
ransmission Service and Operating Agreement for network service in PACE. Subject to tennination upon mutual agreement.
chedule Page: 328.Line No.34 Column:
Charges for monitoring, scheduling, load following and spinning reserve.
ettlement adjustment.
~chedule Page: 328.Line No.Column: d
Transmission Service Agreement (R.S. 591) tenninatin January 1 2032
chedule Page: 328.Line No.Column:
ettlement adjustme
~chedule Page: 3ID Line No.Column: b
Various si atories to the Original Volume 11 Point-to-Point Transmission Tariff.
chedule Page: 328.Line No.Column:
arious s gnatories to the Original Volume II Point-to-Point Transmission Tariff.
~cheduie Page: 328.Line No.Column: d
- - -----------
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 05/17/2007 2006/04
FOOTNOTE DATA
agreement tenninating on Se tember 30, 2007.
ears; 2003 34 240, 2004 44 938 and 2005 39 234.
ears; 200346 887 200441 748 and 200543 373
ears; 2003 124 174 2004140 846 and 2005124 104
ears; 2003 95,934, 2004 59 369 and 2005 66 761.
ears; 2003 139 546 2004 1 600 663 and 20051 616 730.
ears; 2003 17 361 , 2004 20 239 and 2005 22 442.
ears; 200359 236 200452 506 and 200545 160.
ears; 2003 250 339, 2004 1 252 488 and 2005 1 306 254.
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 05/17/2007 2006/04
FOOTNOTE DATA
ears; 2003 178 574, 2004 93 873 and 2005 42 003.
ears; 2003 358 602 2004337 225 and 2005 366 678.
and 200563 781.
ears; 2003 89 979 and 2004
ears; 2003480 461 and 2004
ears; 200317 902 200418 259 and 200518 996.
ears; 2003146 456 2004152 317 and 2005159 433.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
ears; 200376 347,200451 069 and 200573 332.
ears; 2004 2 179 992 and 20051,470 628.
ears; 2003 10 317, 2004 10 884 and 2005 10 786.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 332)
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo. Da, Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
TRANSr-. ISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Une TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
No.Name of Company or Public Statistical Magawatt-Magawan-emano !;nergy To~~mtfourstioursCharpesCharpes~pes Trans~ssionAuthority (Footnote Affiliations)Classification Received Delivered
(a)(b)(c)(d)(e)(f)
(g)
1 Arizona Public Service 540 540 158 . 19,505
2 Arizona Public Service LFP 182 360 182.360 924 960 924 960
3 Arizona Public Service 723 723 40.484 )-I 40.484
4 Arizona Public Service 341 73.216
5 Arizona Public Service SFP 45.317 45,317 184,311 184,311
6 Ashland, City of FNS 990 990 19,077 077
7 Avista Corp.FNS 680 56,456 279 868 279 868
8 Avista Corp.3,420 420 103 11,103
9 BigHorn R. E.
422
47.013
Blanding City 422
Blanding City LFP 276 276 665
Bonneville Power Adm.175 175 116 481 552 367 937
Bonneville Power Adm.FNS 499.948
143,728
645,425
Bonneville Power Adm.LFP 498,471 1,498,471 695.450 839,178
Bonneville Power Adm.184 752
898 748)-1 184.752
Bonneville Power Adm.102 261 324 822 41.071,953 44.569 778
TOTAL 14,211 761:484.760 72.919,688 701 658 489 287 110,633
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 2006/Q4(2) DA Resubmission 05/17/2007
TRANSfIo ISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Une TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
No.Name of Company or Public Statistical Magawatt-Magawan-l,J.emana !=nergy ymer Total Cost oftiourstioursCharpesCharpesCharpesTrans~issionAuthority (Footnote Affiliations)Classification Received Delivered
(a)(b)(c)(d)(e)(f)
(g)
Bonneville Power Adm.SFP 763 763 819,542 911 958
2 CISO 1,407 921 962,497
3 CISO 787 760
4 CISO SFP 541 604 541 604 536 859 386,390
5 Deseret P. E. 002 002 435 435
6 Deseret P. E. C.SFP 168 192 168.192 080.773 080773
7 EI Paso Elect. Co.200 21,200 991 29.991
8 EI Paso Elect. Co.SFP 45,866 45.866 92.643 643
1659 Rathead Elect. Coop.
Flathead Elect. Coop.SFP 217 056 217 056
Rowell Electric Assoc.
Flowell Electric Assoc.LFP 334 334 263 263
Hermiston Gen Co.. LP.160,187
Idaho Power Company 100
Idaho Power Company FNS 792 792
Idaho Power Company 408 536 445.560 303,229 395 316,624
TOTAL 14.211 761 14,484,760 72.919,688 701.658 19,489 287 110.633
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da. Yr)
(2) A Resubmission 05/17/2007
TRANS ISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4- Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7- Footnote entries and provide explanations following all required data.
Name of Respondent
PacifiCorp
LineNo. Name of Company or Public
Authority (Footnote Affiliations)
(a)
1 Idaho Power Company
2 Idaho Power Company
3 LA Dept of Water & Pwr
4 LA Dept of Water & Pwr
5 LA Dept of Water & Pwr
6 LA Dept of Water & Pwr
7 MAPPCOR
8 Moon Lake Elect. Assoc.
9 Morgan City
10 Navajo Tribal Uti! Auth
11 Nevada Power Company
12 Nevada Power Company
13 Nevada Power Company
14 Nevada Power Company
15 NorthWestern Energy
16 NorthWestern Energy
TOTAL
FERC FORM NO. 1/3-0 (REV. 02-04)
Statistical
Classification
(b)
SFP
SFP
FNS
SFP
Year/Period of Report
End of 2006/04
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERSnergy Total Cost of~?eS TranstlWssion
ffl ~h~
515,042
255.855
251
341
876
950
457
79,476
138
390
63,559
537.712
289,528
016,665
-4 . 484
154,701
938 70.938
248 248
2,475 475
550 550
021 021
257 004 257 004
110,406 110,406
32.383 817
211 14.484 760
Page 332.
255.855
366
341
950
26,527
537 712
016,665
154,701
919.688 701.658 489 287 94,110.633
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4
(2) CiA Resubmission 05/17/2007
TRANS~ ISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le. 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 Sen, 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 ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
No.Name of Company or Public Statistical Magawatt-Magawan-!,J.emana !:;nergy T~~mtioufStioursCharresCharras&1"'. T,",,
'OO""""
Authority (Footnote Affiliations)Classification Received Delivered
(a)(b)(c)(d)(e)(f)
(g)
1 NorthWestern Energy ,;; 785.244
2 NorthWestern Energy SFP 70.828 70.828 330.442 330,442
3 Platte River Power 603
Platte River Power SFP 168,192 168,192 966 000 966.000
5 Portland Gen. Electric 444
6 Portland Gen. Electric 303 303 302 302
7 Portland Gen. Electric 720 520 721 624 143,585
8 PSG of Colorado LFP 97.717 102 759 833 181 833 181
9 PSG of New Mexico 632 632 086 086
PSG of New Mexico 180 180 585 585
PSG of New Mexico 22.146
PSG of New Mexico SFP 132,076 132 076 384,435 384 435
Puget Sound Energy 209 209 066
....
066
Puget Sound Energy
Salt River Project SFP 897 897 657 657
Seattle City Light 685 685 22.569 22.569
TOTAL 211,76f 14,484,760 919.688 701 658 19,489.287 94.110.633
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da. Yr)End of 2006/04(2) DA Resubmission 05/17/2007
TRANSr., ISSION OF ELECTRICITY BY OTHERS (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
No.Name of Company or Public Statistical Magawatt-Magawan-emana ~nergy ~mer Total Cost ofliourslioursCharpesCharpesCharresTrans~ssionAuthority (Footnote Affiliations)Classification Received Delivered
(a)(b)(c)(d)(e)(f)
(g)
1 Seattle City Light SFP 98,075 98.075 236,842 236,842
2 Sierra Pacific Power Co 811
3 Sierra Pacific Power Co 14,261 14,261 97.466 97.466
4 Sierra Pacific Power Co 104,484
5 Sierra Pacific Power Co SFP 33,664 33.664 082.881 082.881
6 Snohomish PUD No.563.591 563,591 465.907 465,907
7 Suprise Valley Electr.770
8 Tri-State Gen & Transm LFP 89,583 634 833.181 833,181
9 Tri-State Gen & Transm 742 742 208 208
Tri-Sta1e Gen & Transm 170
Utah Assoc Muni Pwr Sys 19,730
. -
Utah Assoc Muni Pwr Sys SFP 234,347 234 347 197,000 291.643
Western Area Power Adm.162
Western Area Power Adm.FNS 3,422 850 3,422,850
Western Area Power Adm.LFP 378 003 378.003 275.000 275.000
Western Area Power Adm.32,463 32.463 249.791 249.791
TOTAL 14.211 761 484.760 72.919.688 701,658 19,489.287 110.633
FERC FORM NO. 1/3-a (REV. 02-04)Page 332.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4
(2) E)A Resubmission 05/17/2007
TRANS~ ISSION OF ELECTRICITY BY OTHEI S (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le. 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 as - 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 ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
No.Name of Company or Public Statistical Magawatt-Magawan-l,J.emana """1Iy To18J Cost 01tiouTstioursChar?eS 9'.1'" "'r T ""'~."ooAuthority (Footnote Affiliations)Classification Received Delivered
(a)(b)(c)(d)(e)ro
1 Western Area Power Adm.13,995 ." 665.483
2 Accrual True-up . 598 564
TOTAL 211,76E 14.484 760 919.688 701.658 19.489.287 110,633
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 Resubmlssion 05/17/2007 2006/04
FOOTNOTE DATA
!$chedule Pa e: 332 Line No.Column:
Ancillary services and Use of facilities
!Schedule Page: 332 Line No.Column: g
Ancill services and Use offacilities
chedule Page: 332 Line No.Column: g
se of facilities
~chedule Page: 332 Line No.12 Column: g
Ancillary services and Use of facilities
'Schedule Page: 332 Line No.13 Column: g
se offacilities
~chedule Page: 332 Line No.16 Column: g
Ancillary services and Use offacilities
~chedule Page: 332.Line No.Column: g
Reservation fee
ISchedule Page: 332.Line No.Column: g
Ancillary services
'Schedule Page: 332.Line No.Column: g
Ancillary services
~chedule Page: 332.Line No.Column: g
Ancillary services
~chedule Page: 332.Line No.Column: g
se of facilities
~chedule Page: 332.Line No.13 Column: g
Use offacilities
~chedule Page: 332.Line No.14 Column: g
Ancillary services
~chedule Page: 332.Line No.Column: g
Ancillary services, Use of facilities and Res ondent'ortion of s ecified costs of certain facilities
chedule Page: 332.Line No.Column:
Ancillary services
~chedule Page: 332.Line No.Column: g
Ancillary services
~chedule Page: 332.Line No.Column: g
Transmission service charges and membership fees. MAPPCOR is an affiliate of the respondent effective 3/21/06, the date ofMEHC
erger, until 7/21/06 when membership was withdrawn
~chedule Page: 332.Line No.Column: g
se of facilities
~chedule Page: 332.Line No.10 Column: g
Use of facilities
~chedule Page: 332.Line No.11 Column: g
Ancillary services
~chedule Page: 332.Line No.13 Column: g
Ancillary services
~chedule Page: 332.Line No.Column: g
Use of facilities
~chedule Page: 332.Line No.Column: g
Use of facilities and Respondent's portion of specified costs of certain facilities
~chedule Page: 332.Line No.Column: g
ncillary services
~hedule Page: 332.Line No.Column: g
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 05/17/2007 2006/Q4
FOOTNOTE DATA
Use offacilities
ISchedule Page: 332.Lin,! N!J Column: g
Ancillary services, Use offacilities and Respondent's portion of specified costs of certain facilities
~chedule Page: 332.Line No.11 Column: g
Ancillary services
~chedule Page: 332.Line No.14 Column: g
Ancillary services
ISchedule Page: 332.Line No.Column: g
Ancillary services
ISchedule Page: 332.Line No.Column: g
Ancillary services
~chedule Page: 332.Line No.Column: g
se of facilities
~chedule Page: 332.4 Line No.: 10 Column: g
Ancillary services
~chedule Page: 332.Line No.11 Column: g
Ancillary services
ISchedule Page: 332.Line No.12 Column: g
Ancillary services
ISchedule Page: 332.Line No.13 Column: g
Ancillary services
ISchedule Page: 332;5 Line No.Column: g
Ancill services and Use offacilities
Schedule Page: 332.Line No.Column: g
Accrual true-up
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This
wort
Is:Date of ReRort Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006104
(2) Fi A Resubmission 05/17/2007
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line DeSCri)tion Amount
No.(b)
Industry Association Dues 264,567
Nuclear Power Research Expenses
Other Experimental and General Research Expenses
Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities
Oth Expn ::0-=5,000 show purpose, recipient, amount. Group if -:: $5,000
Community & Economic Development
Cache Chamber of Commerce 000
Humboldt Area Foundation 000
Laramie Economic Development Corp 000
Portland Development Commission 000
Redmond Economic Development 000
Rural Development Initiatives, Inc.000
Wallowa County Chamber of Commerce 000
Wayne Brown Institute 000
Economic Development for Central Oregon 500
Utah Center for Rural Life 000
Klamath County Economic Development 300
Cherbo Publishing Group 970
Salt Lake Area Chamber of Commerce 10,000
South Coast Development Council 17 ,500
Oregon Economic Development Assoc 15,000
Economic Development Corp of Utah 000
Four County Economic Development 25,000
Other 54,200
Corporate Memberships and Subscriptions
American Legislative Exchange 000
Utah Hispanic Chamber of Commerce 000
Utah Technology Council 000
Yakima County Development 000
Foundation for Water & Energy 480
Wyoming Taxpayers Association 766
Califomia Climate Action Registry 500
Wyoming Business Alliance 10,000
Consortium for Energy Efficiency 360
Oregon Business Council 980
Intermountain Electrical Assoc 15,000
Corporate Executive Board 20,000
Utah Taxpayers Association 20,000
Portland Business Alliance 500
Salt Lake Area Chamber of Commerce 30,255
Western Energy Institute 40,000
Utah Foundation 42,000
West Assoc. C/O Tri-State Gen. & Trans. Assoc. Inc.022
TOTAL 696.241
FERC FORM NO.1 (ED. 12-94)Page 335
Name of Respondent This tjort Is:Date of ReRQrt Year/Period of Report
PacifiCorp (1) An Original (Mo. Da. Yr)End of 2006/Q4
(2) Fi A Resubmission 05/17/2007
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line Descri)tiOn Amount
No.(b)
Pacific NW Utilities Conference Committee 75,977
Western Electricity Coordinating Council 381 743
Other 102 759
Directors Fees - Regional Advisory Boards 235,411
General
Purchase of Rocky Mountain Power Name Rights 25,000
Y2K Expenses or Reg. Asset Amortization 59,381
Wrongful Dismissal Settlement 100,000
Glenrock Mine UT Stipulat. (Excluding Reclamation)149.625
P&M Strike Reg. Asset Amortization 199,634
IRS Tax Settlement (Lincoln County, WY PCRBs)903 444
Glenrock Mine UT 1998 Case (Excluding Reclamation)152 774
UT Class Action Lawsuit 666,025
ScottishPower UK Cross Charge 704 128
UT Amortization - Deferred Pension Reg. Asset Amort.159,014
98 Early Retirement - OR Reg. Asset Amort.676,947
Transition Plan Reg. Asset Amort.892 299
MEHC Cross Charge 391,613
Other 567
TOTAL 25.696,241
FERC FORM NO.1 (ED. 12-94)Page 335.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da, Yr)End of 2006/04(2) nA Resubmission 05/17/2007
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 (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Depreciation Amortization of
Une ~iation Expense for Asset Limited Term Amortization of
No.Functional Classification nse Retirement Costs Electric Plant Other Electric Total
(Account 403)(Account 403.(Account 404)Plant (Ace 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 071,466 040 075,506
2 Steam Production Plant 139,371 552 139,371,552
Nuclear Production Plant
Hydraulic Production Plant-Conventional 13,212 926 305 13,252,231
5 Hydraulic Production Plant-Pumped Storage
Other Production Plant 20,718,236 240 199 20,958,435
7 Transmission Plant 54,916,530 54,916,530
8 Distribution Plant 123 780,186 123 780,186
9 Regional Transmission and Market Operation
General Plant 945,776 278,749 42,224 525
Common Plant-Electric
TOTAL 1--'629,719 040 438,578,965
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 cost 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 ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2006/04(2) nA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaole tSlimalea I'lel f\ppllea Monallly Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(In Th?bfandS)7~f
(pe
r:i~nt)
(Percent)
~~~
la)Ie)
Steam Production Plant
Hunter Plant
310.20 UT 246 43.23.
311.00 UT 201 766 43.22.
312.00 UT 514,489 41.22.
314.00 UT 147 308 35.. 3.21.
315.00 UT 98,415 43.22.
316.00 UT 933 40.20.
317.00 UT 681
Jim Bridger Plant
310.20 WY 281 44.18.
311.00 WY 133,224 41.17.
312.00 WY 563 606 37.-4.17.
314.ooWY 141 995 34.-4.16.
315.00 WY 090 43.-4.17.
315.70 WY 42.17.
316.ooWY 881 38.-4.41 16.
317.ooWY 172
Huntington Plant
311.00 UT 100,385 41.-6.16.
312.00 UT 383,518 37.16.
314.ooUT 025 32.16.
315.00 UT 30,826 41.16.
316.00 UT 277 32.5.41 15.
317.00 UT 710
Chona Plant
311.00 AZ 46,531 41.22.49
312.00 AZ 224,663 41.21.
314.00 AZ 52,436 41.21.
315.00 AZ 46,918 44.22.
315.70 AZ 32.22.
316.00 AZ 145 41.56 20.
Dave Johnston Plant
310.20 WY 100 47.18.
311.ooWY 208 34.17.
FERC FORM NO.1 (REV. 12-03)Page 337
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2006/Q4(2) riA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclacle cstlmatea Net Appnea lIIIOi'tality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(In Th
~~fands)7~f
(Pe
r~~nt)
(per;~nt)'(Ne
Life
(a)(a)
312.00 WY 280,525 35.16.
314.00 WY 361 38.16.
315.00 WY 807 43.17.
315.70 WY 36.17.
316.00 WY 985 25.16.
317.00 WY 413 10.
Wyodak Plant
310.20 WY 165 40.20.
311.00 WY 345 42.19.
312.00 WY 209,109 39.19.
314.00 WY 48.781 41.18.
315.00 WY 19,418 43.19.
316.00 WY 839 39.18.
Naughton Plant
310.20 WY 59.20.
311.ooWY 390 38.19.
312.00 WY 233,299 37.19.
314.00 WY 59,085 42.-6.18.
315.00 WY 20,068 45.19.
316.00 WY 775 41.18.
317.00 WY 359
Colstrip Plant
311.00 MT 092 44.2629
312.00 MT 109,820 42.25.
314.00 MT 536 39.24.
315.00 MT 906 44.26.
316.00 MT 181 38.23.
317.00 MT
Craig Plant
311.00 CO 35,749 43.21.
312.00 CO 90,528 42.21.
314.00 CO 19,619 41.20.
315.00 CO 16,400 44.21.
316.00 CO 662 41.19.
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) nA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaole t:stlmatea Net Appuea MonaUty Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(In Thousands)(Per
~fnt)
(pe
r~fnt)-yr 7~)(a)(b)
Gadsby Plant
311.00 UT 878 31.
312.00 UT 982 29.
314.00 UT 174 36.
315.00 UT 579 34.
316.00 UT 761 22.45
Carbon Plant
311.00 UT 195 35.
312.00 UT 53.344 26.
314.00 UT 20,104 32.
315.00 UT 484 39.
316.00 UT 324 28.-5.
Blundell Plant
311.00 UT 683 36.18.
312.00 UT 430 35.18.
314.00 UT 15,569 32.17.
315.00 UT 810 36.18.
316.00 UT 059 35.1.46 17.
317.00 UT 421
James River Plant
311.ooWA 734 20.13.
312.ooWA 798 20.13.
314.ooWA 18,601 19.13.
315.00 WA 302 20.13.
Hayden Plant
311.00 CO 992 49.2.40 21.
312.00 CO 51,076 32.21.
314.00 CO 6,477 41.88 20.41
315.00 CO 481 48.21.
316.00 CO 107 38.19.
IGC
310.20 UT 233 15.
312.00 UT 191
347.00 UT 621
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo. Da. Yr)End of 2006/04(2) DA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle t:sumalea Nel Appllea MonalllY Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th~~~ands)
7~f
(perJjnt)(per~jnt)Y8e 7~)
Hydraulic Production
Swift (218)
330.20 WA 277 77.1.46 33.
330.50 WA 76.33.
331.00 WA 591 71.1.80 1.u5 32.
331.20WA 793 52.32.
331.30 WA 901 46.32.
332.00 W A 524 76.-4.1.65 32.
332.30 WA 110 44.-4.32.
333.00 W A 242 65.32.41
334.00 WA 3,488 60.31.
334.70 WA 331 48.31.
335.00 WA 551 69.1.68 30.
335.30 WA 56.30.
336.00 WA 395 48.-0.32.
Yale (219)
330.20 WA 762 81.1.42 33.
331.ooWA 016 68.1.71 32.
331.20 WA 46.32.
331.30 WA 439 45.32.
332.00 W A 26,117 81.-4.1.58 32.
332.20WA 41.-4.32.
333.00 WA 10,499 56.32.41
334.00 WA 566 48.1.00 31.
334.70 WA 111 47.31.
335.00 W A 549 78.30.
336.00 W A 384 44.32.
MERWIN (215)
330.20 WA 301 101.1.15 33.
330.50 WA 212 103.1.14 33.
331.ooWA 014 57.32.
331.20 WA 13,958 42.1.80 2.47 32.
331.30 WA 121 46.1.80 32.
332.00 WA 001 82.-4.32.
332.20 WA 587 43.-4.32.
332.30 WA 43.32.
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2006/Q4
(2) (JA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaole t::sllmatea Net ApplieD MonalllY Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th(~)andS)
~~)
(pe
rJjmt)
(Pe
r~fnt)1~)
333.00 WA 7,405 69.32.41
334.00 WA 040 39.31.
334.70 WA 346 41.87 31.
335.00 W A 115 38.30.
335.20 WA 100.1.23 30.
336.00 WA 447 66.32.
Merwin (Non) (2151)
331.30 WA 006 43.1.80 32.
332.30 WA 42.-4.32.
336.00 W A 346 43.32.
Merwin (2153)
331.60WA
332.00 WA
333.00 WA 1.62
334.00 WA 489
335.10WA
336.00 W A 1.65
C. Boyle (18)
331.00 OR 995 56.32.
331.30 OR 46.32.
332.00 OR 12,907 74.37.
332.20 OR 091 48.-4.32.
333.00 OR 239 62.1.87 32.41
334.00 OR 146 43.31.
334.70 OR 906 44.2.47 31.
335.00 OR 145 75.1.68 30.
336.00 OR 883 63.-0.1.83 32.
Lemolo #2 (41)
331.00 OR 837 77.36.
33120 OR 61.36.
331.30 OR 67.36.
332.00 OR 16,994 70.1.77 36.47
332.20 OR 788 82.36.47
333.00 OR 666 76.40 -0.36.
334.00 OR 287 59.1.20 35.
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da, Yr)End of 2006/04(2) riA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclacle tstlmatea Net Appuea Monauty Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(In Thousands)Life (per
1:mt)
(pe
r~~nt)r~e ~~f(a)(b)(c)
334.70 OR 49.35.
335.00 OR 68.34.
336.00 OR 650 70.1.63 36.
Iron Gate (610)
330.20 CA 74.33.
331.00 CA 1,494 66.32.
331.20 CA 945 53.32.
331.30 CA 457 55.32.
332.00 CA 221 69.-4.32.
332.20 CA 789 69.-4.32.
333.00 CA 949 72.32.
334.00 CA 191 66.31.
334.70 CA 44.31.
335.00 CA 71.30.
335.20 CA 52.35.
336.00 CA 076 69.-0.32.
Powerdale (27)
330.20 OR 50.15.
331.00 OR 659 42.15.
331.20 OR 15.15.
331.30 OR 33.49 -0.15.
332.00 OR 10.708 37.15.
332.20 OR 004 23.9(J 15.
333.00 OR 516 26.15.
334.00 OR 446 37.15.
334.70 OR 33.15.
335.00 OR 15.43 14.
336.00 OR 31.-0.15.
337.00 OR 145 14.
Grace (457)
331.00 10 296 81.27.
332.00 10 821 71.68 1.79 27.
333.00 10 213 59.27.
334.00 10 586 57.27.
334.7010 27.27.
335.00 10 45.2.42 26.
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da, Yr)End of 2006/04
(2) CiA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle t:sllmateo Net ApplieD Monamy Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th
~~fandS)7~f
(pe
l:wnt)
(pe!~~nt)
YKe 7~f
336.0010 60.1.88 27.
Clearwater #2 (43)
331.00 OR 899 79.36.
331.30 OR 67.36.
332.00 OR 10,478 68.1.80 36.
332.20 OR 63.36.47
333.00 OR 924 84.36.
334.00 OR 234 72.35.
334.70 OR 49.35.
335.00 OR 62.34.
336.00 OR 250 68.36.
LEMOLO #1 (40)
331.00 OR 740 78.36.
332.00 OR 921 81.36.47
332.20 OR 34€83.1.43 36.
333.00 OR 029 70.-0.36.
334.00 OR 716 45.35.
334.70 OR 55.35.
335.00 OR 49.12 34.
336.00 OR 407 80.36.
Cutler (444)
330.20 UT 31.21.
330.30 UT 96.2.43 21.
330.40 UT 74.21.
331.00 UT 774 53.21.
332.00 UT 6,472 51.21.
332.30 UT 27.21.
333.00 UT 110 77.21.
334.00 UT 490 56.20.
335.00 UT 37.20.
336.00 UT 566 39.21.
Toketee (44)
331.00 OR 1,488 62.36.
331.30 OR 67.36.
332.00 OR 387 81.36.47
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2006/Q4(2) nA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDie t:SllmaIeo !'IeI Applleo IVionamy Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th
~~fands)7~~
(pe
r~~nt)
(Pe
r~~nt)
'(!)e
7~f
333.00 OR 318 71.36.
334.00 OR 657 70.35.
334.70 OR 62.40 1.20 1.61 35.
335.00 OR 69.34.
336.00 OR 215 63.46 36.
Prospect #2 (32)
330.20 OR 63.32.
330.40 OR 98.32.
331.00 OR 518 53.1.80 31.
331.20 OR 38.31.
331.30 OR 56.31.
332.00 OR 420 74.-4.31.
332.20 OR 136 51.49 -4.31.
333.00 OR 547 57.-0.29.
334.00 OR 389 42.1.00 30.
334.70 OR 30.30.
335.00 OR 30.30.
336.00 OR 191 57.31.
Prospect #3
(Non) (331)
331.20 OR 31.16.
Pioneer (449)
330.20 UT 132.27.
330.30 UT 111 133.27.
331.00 UT 354 60.26.
331.20 UT 27.1.5C 26.
332.00 UT 837 44.26.
333.00 UT 955 37.26.
334.00 UT 475 43.26.
335.00 UT 47.30.
336.00 UT 56.31.
Lifton (458)
330.20 10 115.1.04 45.
330.30 10 109.45.
331.00 10 224 88.43.
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da, Yr)End of 2006/Q4
(2) fiA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle csllmatea Net Applied Monallty Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th~~fands)7~f
(Pe
rJfnt)(peg;fnt)7~r
331.30 10 50.43.
332.00 10 325 73.1.64 43.
332.20 10 411 51.49 43.
333.00 10 332 101.43.
334.00 10 265 64.1.40 42.
335.00 10 54.1.95 40.
336.00 10 183 113.-0.44.
Oneida (459)
331.00 10 204 69.27.
331.30 10 34.27.
332.00 10 537 64.27.
333.00 10 698 59.-0.27.
334.00 ID 778 53.-0.27.
335.00 10 49.26.
336.00 10 476 57.-o.28.
Oneida
(Non) (559)
331.0010 106.27.
334.00 10 151 55.-0.1.93 27.
Ashton (455)
330.20 10 41.25.
331.00 10 758 48.25.
331.20 10 354 32.25.
332.00 10 490 40.25.
333.00 10 952 40.-0.24.
334.00 10 080 39.-0.24.
334.70 10 35.24.40
335.00 ID 47.23.
336.00 10 110.25.
Copco #1 (611)
330.20 CA 118.33.
330.40 CA 111.33.
331.00 CA 147 58.32.
331.30 CA 56.32.
332.00 CA 633 92.-4.32.
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da. Yr)
End of 2006/Q4(2) DA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle csllmatea Net Appllea Monamy Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(In Thousands)Lif (perJ~nt)(Percent)
'(l)e
Life
la)Ib)Ie)10)
333.00 CA 591 45.-0.32.
334.00 CA 979 54.31.
334.70 CA 45.31.
335.00 CA 67.30.
336.00 CA 105 44.40 32.
North Umpqua (48)
331.00 OR 474 49.36.
331.20 OR 260
331.30 OR 160 64.36.
332.00 OR 374 49.36.47
333.00 OR 40.36.
334.00 OR 512 51.35.
334.70 OR 457 41.35.
335.00 OR 603 45.34.
336.00 OR 396 67.-0.36.
Soda (461)
330.20 10 112.28.
331.00 10 578 78.1.95 27.
332.00 10 991 64.27.
333.00 10 597 58.-0.27.
334.00 ID 459 63.27.
335.00 10 46.26.
Soda (Non) (561)
332.00 10 84.27.
Keno (15)
330.20 OR 87.33.
331.20 OR 46.1.80 32.
331.30 OR 215 55.32.
332.00 OR 770 66.-4.32.
332.20 OR 236 69.-4.32.
334.70 OR 42.31.
336.00 OR 111 67.32.
Fish Creek (45)
331.00 OR 562 72.36.47
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2oo6/Q4(2) nA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaole t:Sllmaleo I'lel ApplieD Monamy Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
ta\(In Th~~fands)7~f
(pe
rJ~nt)
(pe
r~~nt)YKe 7~f
332.00 OR 982 65.36.
332.20 OR 131 45.36.
333.00 OR 054 79.1.53 36.
334.00 OR 143 71.1.70 35.
335.00 OR 72.34.
336.00 OR 400 68.-0.36.
COPCO#2 (612)
331.00 CA 628 47.22.
332.00 CA 898 89.22.
333.00 CA 3,493 38.-0.40 22.
334.00 CA 557 52.24.
334.70 CA 277 35.21.
335.00 CA 36.21.
336.00 CA 240 41.22.
Prospect #3 (33)
331.00 OR 282 42.47 16.
331.30 OR 42.16.
332.00 OR 051 46.16.
332.20 OR 022 23.16.
333.00 OR 923 25.16.
334.00 OR 466 27.16.
335.00 OR 29.4.48 15.
336.00 OR 62.16.
Condit (213)
330.40 WA 95.
331.ooWA 855 38.40 296.28.
331.30WA 158 19.296.31.
332.00 WA 093 39.296.28.
332.30 WA 209 296.39.
333.00 W A 196 25.295.30.
334.00 WA 143 43.295.28.
334.70WA 18.295.32.
335.00 WA 295.39.
336.00 W A 53.296.27.
Condit (Non) (2131)
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2006/Q4(2) nA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaole t:Sllmaleo I'let Appllea Mortality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(In Th
?~fandS)~~f
(Percent)(per;fnt)'(I)e ~~r(a)Cd)
330.20 WA 75.
Soda Springs (46)
331.00 OR 858 80.1.30 36.47
332.00 OR 365 80.36.47
333.00 OR 329 86.54 36.
334.00 OR 791 52.35.
334.70 OR 52.35.
335.00 OR 47.34.
336.00 OR 44.36.
Slide Creek (47)
331.00 OR 609 72.1.59 36.
332.00 OR 009 79.36.
333.00 OR 713 86.-0.36.
334.00 OR 473 50.35.
334.70 OR 43.35.
335.00 OR 50.34.
336.00 OR 50.36.
Clearwater #1 (42)
331.00 OR 562 79.4:3 36.
332.00 OR 199 83.-5.36.
33220 OR 266 85.36.47
333.00 OR 749 83.-0.36.
334.00 OR 194 79.35.
334.70 OR 45.35.
335.00 OR 66.1.54 34.
Klamath (19)
330.20 OR 624 40.33.
330.40 OR 235 63.33.
331.00 OR 37.1.80 32.
331.30 OR 62.32.
332.00 OR 522 48.-4.32.
334.00 OR 525 38.31.
335.00 OR 68.30.
Big Fork (410)
FERC FORM NO.1 (REV. 12-03)Page.337.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo. Da. Yr)End of 2006/Q4
(2) fiA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle t:sllmated Net Appllea Mortality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th~~~andS)(pe!J~nt)(pe!:;~nt)
~~~
331.00 MT 310 53.27.
331.30 MT 76.27.
332.00 MT 338 27.27.
332.20 MT 37.40 2.49 27.
332.30 MT 38.27.
333.00 MT 278 37.27.
334.00 MT 197 52.27.
335.00 MT 32.27.
336.00 MT 101.28.
Prospect #1 (31)
331.00 OR 232 74.31.
331.30 OR 63.1.31 31.
332.00 OR 129 113.-4.31.
333.00 OR 140 75.31.
334.00 OR 74.30.
336.00 OR 69.31.
Prospect #4 (34)
331.00 OR 54.31.
331.30 OR 40.31.
332.00 OR 64.-4.31.
333.00 OR 88.-0.31.
334.00 OR 77.30.
East Side (16)
331.00 OR 101 62.-0.
332.00 OR 1,477 38.7.46
333.00 OR 103 85.-0.7.45
334.00 OR 35.-0.
334.70 OR 17.
335.00 OR 85.
336.00 OR 24.
West side (17)
331.oo0R 40.7.46
331.30 OR 31.-0.
332.00 OR 132 90.70, 7.46
333.00 OR 49.7.45
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2006/04(2) nA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaole csilmaleo Net Appllea Monamy Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(In Th~~fands)Lif (per~fnt)(Percent)
'(8e 7~ffa)
334.00 OR 41.05 -0.20
336.00 OR 66.7.48
Fall Creek (613)
330.40 CA 99.33.
331.00 CA 135 64.0.40 32.
331.30CA 64.1.80 0.40 32.
332.00 CA 530 57.-4.32.
333.00 CA 134 69.32.
334.00 CA 77.31.
Fall Creek (13)
330.20 OR 133.1.22 33.
330.40 OR 99.1.25 33.
331.00 OR
332.00 OR 149 49.-4.32.
334.00 OR 1.72
Cove (456)
331.00 10 136 92.1.50 27.
332.00 10 1:3 67.27.
333.00 10 360 68.-0.27.
334.00 10 146 46.-0.27.
335.00 10 43.26.
336.00 10 113.28.
Paris (460)
331.0010 43.12.
332.00 10 66.1.50 12.
333.00 10 43.12.
334.00 10 105 34.12.
335.00 10 28.12.
Wallowa Falls (29)
331.00 OR 36.-0.13.
331.30 OR 23.13.
332.00 OR 896 22.13.
333.00 OR 51.3.48 13.
334.00 OR 408 24.0.40 13.
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Oa, Yr)End of 2006/Q4(2) riA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle I:snmatea Net Applied Mortality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th
~bfandS)7~~
(pe
r:j~nt)
(per~~nt)7~f
334.70 OR 57.0.40 13.
336.00 OR 311 20.13.
Wallowa Falls
(Non) (292)
334.70 OR 27.13.
St. Anthony (462)
331.00 10 51.1.40 25.
332.00 10 436 42.25.
332.20 10 135 34.25.
333.00 10 496 35.24.
334.00 10 168 41.-0.24.
335.00 10 52.23.
Olmsted (448)
331.00 UT 264 78.-0.13.
334.00 UT 18.0.40 13.
335.00 UT 37.13.
336.00 UT 22.13.
Bend (23)
331.00 OR 49.
331.30 OR 36.
332.00 OR 82.
332.30 OR 37.
333.00 OR 63.
334.00 OR 25.
334.70 OR 535 17.
335.00 OR 34.
336.00 OR 69.
Cline Falls (24)
331.00 OR 117 21.17.
332.00 OR 35.16.
333.00 OR 58.15.
334.00 OR 53.15.
334.70 OR 15.19.
336.00 OR 62.15.
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2006/Q4(2) riA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaole I:.Slimalea I'lel ~pplleo MortalllY ~verage
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
ta)
(In Th
?~fandS)7~f
(Pe
rJ~nt)
(Pe
r~~nt)7~f
Eagle Point (35)
330.20 OR 53.
331.00 OR 128 31.7.46
332.00 OR 188 23.
332.20 OR 37.
333.00 OR 252 36.-0.7.40 7.45
334.00 OR 37.
336.00 OR 112 44.
Weber (454)
331.00 UT 219 55.17.
331.30 UT 148 27.-0.17.
332.00 UT 297 65.45 17.
333.00 UT 874 35.17.
334.00 UT 115 42.-0.16.
335.00 UT 34.16.
336.00 UT 25.17.
Gunlock (463)
331.00 UT 55.17.
332.00 UT 195 75.17.
333.00 UT 121 36.17.
334.00 UT 239 31.16.
335.00 UT 41.16.
336.00 UT 102.-0.17.
Veyo (464)
331.00 UT 38.-0.17.
332.00 UT 356 38.17.
333.00 UT 144 33.17.
334.00 UT 149 22.16.
335.00 UT 41.16.
336.00 UT 62.-0.17.
Sandcove (465)
331.00 UT 48.17.
332.00 UT 421 56.17.
333.00 UT 162 31.17.
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle I::sllmatea Net Appuea Monamy Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(In Thousands)
~~f
(pe
rJ~nt)
(pe
r~~nt)r8e
~~~
(a)(b)
334.00 UT 238 26.16.
336.00 UT 93.17.
Stairs (452)
331.00 UT 368 52.22.
332.00 UT 335 59.22.
333.00 UT 513 37.22.
334.00 UT 161 40.-0.21.
Last Chance (468)
331.00 10 435 38.1.20 22.
332.00 10 849 39.22.
333.00 10 119 40.-0.22.
334.00 10 244 40.-0.21.
336.00 10 41.22.
American Fork (441)
331.00 UT 39.106.28.
332.00 UT 663 44.106.28.
333.00 UT 121 32.106.28.5.48
334.00 UT 123 26.105.29.
335.00 UT 22.105.29.
336.00 UT 15.106.30.
337.00 UT 322 25.
Upper Beaver (443)
330.30 UT
331.00 UT 158 76.1.40 26.
332.00 UT 820 45.26.
333.00 UT 118 68.26.
334.00 UT 401 36.26.
335.00 UT 42.25.
336.00 UT 81.27.
Snake Creek (451)
331.00 UT 48.17.
332.00 UT 423 44.17.
333.00 UT 263 36.17.
334.00 UT 156 38.16.
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) nA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclatJle Estlmatea Net Appllea Mortality f\verage
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th~~fands)7~~
(perJ~nt)
(pe
r:;~nt)7~r
335.00 UT 33.16.
Viva Naughton (467)
331.00 WY 389 52.36.
332.00 WY 104 52.36.
333.00 WY 497 52.1~98 36.
334.00 WY 159 51.35.
335.00 WY 50.34.
Granite (455)
331.00 UT 136 64.2.41 26.
332.00 UT 547 31.26.
333.00 UT 676 46.-0.26.
334.00 UT 183 44.-0.26.
335.00 UT 57.25.
Swift (Non) (262)
334.13.0.40 13.
Fountain Green (446)
331.00 UT 57.
332.00 UT 319 19.
333.00 UT 75.
334.00 UT 27.
335.00 UT 23.
336.00 UT 78.
Other Production Plant
Hermiston Plant
341.oo0R 12,475 34.29.
342.00 OR 32.29.
343.00 OR 101,602 35.1.37 29.
344.00 OR 39,840 35.29.
345.00 OR 070 35.29.
346.00 OR 497 35.1.37 29.
347.00 OR 347
Little Mountain
341.00UT 218 32.
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da. Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle csllmatea Net AppliOO lIIfortality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th~~)andS)
7~~
(Pe
r:i~nt)
(per~~nt)'(8e ~~f
342.00 UT 121 36.
343.00 UT 270 29.
344.00 UT 390 26.
345.00 UT 216 30.
346.00 UT 34.
Currant Creek
341.00 UT 121 35.
342.00 UT 005 35.
343.00 UT 189,447 35.
344.00 UT 63,543 35.
345.00 UT 595 35.
346.00 UT 132 35.
347.00 UT 220 35.
Solar Generating
Utah Solar
344.00 UT 15.12.
Oregon Solar
344.00 OR 15.
Green River Solar
344.00 WY 15.11.
Wyoming Wind
343.00 WY 514 25.20.
344.00 WY 542 25.-0.20.
345.00 WY 211 25.-0.20.
Leaning Juniper
341.00 OR 532 20.
343.00 OR 170,861 20.
344.00 OR 20.
345.00 OR 20.
346.00 OR 20.
347.00 OR 482
Gadsby
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo. Da. Yr)End of 2006/Q4
(2) (JA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaole I:.sIlmatea Net Appuea Monamy Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(In Tho~)andS)
~~f
(pe
r:wnt)
(pe
r~fnt)'(8e 7~f(a)
341.00 UT 122 25.1.38 25.
342.00 UT 258 25.25.
343.00 UT 628 25.25.
344.00 UT 15,874 25.25.
345.00 UT 009 25.25.
Transmission Plant
350.181 70.1.40 46.
352.55,260 65.10.00 49.
353.907,682 58.R1.44.
353.55,509 20.12.
354.380,679 60.30.39.
355.508.939 50.30.3526
356.630 353 60.30.39.
356.356 70.42.
357.277 60.90.54.
358.275 50.20.41.46
359.11,495 70.1.42 57.
Distribution Plant
(Utah and Idaho)
360.271 52.42.
361.25,854 55.10.1.87 42.
362.323 683 55.1.84 RO.47.
362.11,715 15.
363.393 10.10.
363.
364 . 00 310,078 42.75.R1.5 31.
365.212 915 40.20.28.
366.139 469 60.50.49.
367.403,623 50.15.39.
368.381 353 40.30.
369.187,595 50.20.39.
370.98,025 27.RO.18.
371.749 20.10.11.
372.25.10.
373.049 20.30.RO.13.
374.00 ID 938
374.00 UT 101,376
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclacle tsllmatea Net Appllea Monamy Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th
~~fands)7~)
(perJ~nt)
(Pe
r~~nt)Y8e
Distribution Plant
(Oregon)
360.20 OR 556 55.27.47
361.00 OR 345 60.10.1.83 48.
362.00 OR 160,588 55.30.SO.41.
362.70 OR 780 20.10.
364.00 OR 282 793 40.90.RO.31.46
365.00 OR 210,301 45.50.RO.34.
366.00 OR 75,474 53.-40.41.
367.00 OR 133,175 48.15.R1.38.44
368.00 OR 340,096 38.27.
369.10 OR 60.741 50.R1.37.
369.20 OR 122,061 54.1.78 R2.44.
370.00 OR 58,792 27.17.
371.00 OR 434 20.-5.11.
373.00 OR 19.601 40.15.30.
374.00 OR 73,999
Distribution Plant
(Washington)
360.20WA 298 50.25.
361.00WA 166 55.1.86 41.
362.00 WA 804 50.25.R1.38.
362.70 WA 756 18.
364.00 WA 78,881 50.165.R1.40.
365.00 W A 53,162 55.-40.43.
366.00 WA 13,725 60.20.49.
367.00 WA 17,452 45.10.R2.34.
368.00 W A 82,326 45.32.
369.10 WA 708 50.10.R1.5 36.41
369.20 WA 25,031 55.10.45.
370.00 W A 13,639 27.16.
371.00 WA 532 30.15.18.
373.00 WA 570 35.15.23.
374.00WA 17,119
Distribution Plant
(Wyoming)
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo. Da. Yr)End of 2006/Q4(2) riA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle estimated Net Appllea Mortality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th
~~fandS)7~~
(Per~~nt)
(pe
r~)nt)YKe 7~f
360.20 WY 279 50.34.
361.00 WY 254 45.10.R2.33.
362.00 WY 89,706 45.36.
362.70 WY 756 20.
364.00 WY 87,457 45.105.35.
365.00 WY 80,698 50.35.38.
366.00 WY 12,961 50.35.38.44
367.ooWY 363 40.10.00 27.
368.00 WY 95C 40.2.41 R1.5 28.
369.10 WY 969 55.25.43.
369.20 WY 20,907 50.25.38.
370.00 WY 14,692 27.16.
371.ooWY 884 25.10.15.
373.00 WY 127 45.30.34.
374.00 WY 17 .594
Distribution Plant
(Califomia)
360.20 CA 914 55.1.55 23.
361.00 CA 463 50.36.
362.00 CA 13,226 55.25.40.
362.70 CA 218 20.
364.00 CA 278 50.90.R1.5 38.
365.00 CA 31 ,323 60.55.48.
366.00 CA 14,474 50.30.39.
367.00 CA 15,835 45.33.
368.00 CA 41,867 45.52.S1.30.
369.10 CA 434 45.35.
36920 CA 325 55.R2.45.40
370.00 CA 938 27.3.49 17.
371.00 CA 270 25.30.14.
373.00 CA 683 30.35.17.
374.ooCA 142
General Plant (Oregon)
390.00 OR 56,913 45.38.
391.100R 040 26.
392.01 OR 409 13.10.L1.
392.05 OR 773 16.10.9.49
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da, Yr)End of 2006/04(2) DA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaole I:stlmatea Net Appllea Monallty Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th(~)andS)
~~r
(pe
r:ifnt)
(pe
r~fnt)r8e 7~~
392.09 OR 653 39.20.29.
396.03 OR 502 10.37.
396.07 OR 22,553 15.35.R1.5
397.00 OR 83,944 20.14.
General Plant
(Washington)
390.00 WA 10,853 35.30.27.
392.01 WA 337 12.20.
392.05 W A 983 13.10.
392.09 WA 618 33.15.SO.22.
396.03 WA 697 10.15.
396.07 W A 406 12.20.SO.
397.ooWA 12,771 20.R1.12.
General Plant
(Utah, Idaho, Colorado
& New Mexico)
389.40.22.
390.92,545 40.29.
392.24,825 12.15.
392.22,749 15.10.
392.643 28.25.R2.15.
396.773 10.
396.52,305 13.20.
397.88,363 20.SO.12.
399.1 UT 42,454
General Plant
(Wyoming)
390.00 WY 083 40.25.
392.01 WY 787 15.10.
392.05 WY 802 20.13.42
392.09 WY 124 30.19.
396.03 WY 407 10.20.
396.07 WY 23,714 15.40.SO.
397.00 WY 266 20.10.
General Plant
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2006/Q4(2) riA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaDle eStimated Net Applied Mortality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th~~~ands)7~f (PerJ~nt)(per~~nt)7~f
(Califomia)
390.00 CA 412 45.10.32.
392.01 CA 707 11.20.
392.05 CA 804 15.10.
392.09 CA 282 40.30.
396.03 CA 034 10.30.
396.07 CA 683 10.25.
397.00 CA 344 20.13.
General Plant
(Montana)
390.00 MT 351 40.29.
392.01 MT 12.15.10.
392.05 MT
396.07 MT 13.20.11.
397.00 MT 633 20.SO.
General Plant
(IGC)
391.00 UT
391.20 UT 20.
392.01 UT
392.09 UT
394.00 UT
396.07 UT
397.00 UT
General (All states)
390.14,889 15.
391.28,445 20.
391.70,427 20.
391.364 12.
393.13,059 25.
394.60,742 24.
395.567 20.
397.741 11.
398.387 20.
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da. Yr)End of 2oo6/Q4
(2) riA Resubmission 05/17/2007
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line uepreclaole t:stlmatea Net Appllea Mortality Average
No.Account No.Plant Base Avg. Service Salvage Depr. rates Curve Remaining
(a)
(In Th
~~fandS)7~f
(pe
riifnt)
(per~~nt)'(Re 7~r
Mining Operations
(Utah)
399.15 UT 661 188
399.30 UT 13,119 23.FCST
399.30 UT 24.023 29.FCST 19.
399.44 UT 182
399.45 UT 102,389 11.5.45
399.41 UT 11,794 29.FCST 19.
399.51 UT 052 15.S1.5
399.52 UT 180 20.11.
399.60 UT 114 13.SO.
399.61 UT 600 10.
399.70 UT 700 1820 FCST
Mining Operations
(Wyoming)
399.30 WY 187
399.51 WY
399.52 WY 306
FERC FORM NO.1 (REV. 12-03)Page 337.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 336 Line No.12 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 Ending
December 312006 2005
Vehicle Depreciation $ 12,268 419 $ 11 352 594
Line No.Column:
Line No.Column:
Line No.Column:
Line No.Column:
Line No.Column:
Line No.Column:
Line No.Column:
~chedule Page: 336.24 Line No.29 Column:
ully Depreciated
~chedule Page: 336.24 Line No.30 Column:
ully Depreciated
~chedule Page: 336.24 Line No.32 Column:
FERC Sub Acct Description
310.20 Land Rights
315.70 Supervisory Equipment
330.20 Land Rights330.30 Water Rights330.40 Flood Rights330.50 Land Rights-Fish/Wildlife
331.20 Structures & Improvement-Fish/Wildlife331.30 Recreation
332.20 Reservoirs, Dams & Waterways-Fish/Wildlife332.30 Recreation
334.70 Supervisory Equipment
335.20 Misc Power Plant Equip - Fish335.30 Misc Power Plant Equip - Recf.
350.20 Land Rights
353.70 Supervisory Equipment356.20 Clearing & Grading360.20 Land Rights
362.70 Supervisory & Alann Equipment
363.70 Storage Battery Equipment - Supervisory & Alann
369.10 Overhead Services
369.20 Underground Services
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 05/17/2007 2006/Q4
FOOTNOTE DATA
389.
390.30
391.10
391.20
391.30
392.
392.
392.
396.
396.
397.20
399.30
399.43
399.44
399.45
399.
399.
399.
399.
399.
Land Rights
Office Panels
Mainframe Computers
Personal Computers
Office Equipment
Transp. Eqpt - Light Trucks & Vans
Transp. Eqpt - Medium Trucks
Transp. Eqpt - Trailers
Light Power Operated Equipment
Heavy Power Operated Equipment
Mobile Radio Equipment
Structures & Improvements
Surface-Railroad Equipment
Surface-Electric Power Facil
Underground Equipment
Vehicles
Heavy Construction Equipment
Miscellaneous Equipment
Computer Equipment
Mine Development
!Schedule Page: 336.24 Line No.32 Column:
Average remaining life is from the depreciation study of Electric Plant In Service as of March 31 2002.
IFERC FORM NO.(ED. 12-87) Page 450.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo. Da, Yr)End of 2006/04(2) riA Resubmission 05/17/2007
REGULATORY COMMISSION EXPENSES
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 . u~Terrea
No.(Fumish name of regulatory commission or body the Regulatory Expense for In Account
Commission Current Year 18;2.3 ~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 227.839 227 839
3 Other State Regulatory Expenses
5 Before the Public Utility Commission of
6 Oregon:
7 Annual Fee 372,598 372 598
8 Other State Regulatory Expenses
Before the Public Service Commission of
Wyoming:
Annual Fee 874 005 874,005
Other State Regulatory Expenses
Before the Washington Utilities and
Transportation Commission:
Annual Fee 438,221 438 221
Other State Regulatory Expenses
Before the Idaho Public Utilities Commission:
Annual Fee 314 605 314 605
Other State Regulatory Expenses
Before the Public Utilities Commission of
Califomia:
Annual Fee 338 338
Other State Regulatory Expenses 572 572
Before the Public Utilities Commission of
Montana:
Other State Regulatory Expenses
Before the Federal Energy Regulatory
Commission:
Annual Fee 007,050 007,050
Annual Land Use Fee 191 806 191 806
Deferred Regulatory Commission Expense 529,
TOTAL 8,434,462 632 8,435,094 529,353
FERC FORM NO.1 (ED. 12-96)Page 350
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2006/Q4
(2) fiA Resubmission 05/17/2007
REGULATORY COMMISSION EXPENSES (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 1'\(;RJ~~rn AmOUnt Account 182.Account Account 182.No.End of Year
(f)
(g)
(h)(i)(k)(I)
Electric 928 227 839
Electric 928 372 598
Electric 928 874 005
Electric 928
Electric 928 438 221
Electric 928 314 605
Electric 928 338
Electric 928 572
Electric 928
Electric 928 007 050
Electric 928 191 806
332,179 861,532
435,094 332,179 861 532
FERC FORM NO.1 (ED. 12-96)Page 351
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) CiA Resubmission 05/17/2007
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. 0 & 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, 0 & 0 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. 0 & 0 Performed Intemally:a. Overhead
(1) Generation b. Underground
a. hydroelectric (3) Distribution
i. Recreation fish and wildlife (4) Regional Transmission and Market Operation
ii Other hydroelectric (5) Environment (other than equipment)
b. Fossil-fuel steam (6) Other (Classify and include items in excess of $5.000.
c. Intemal combustion or gas turbine (7) Total Cost Incurred
d. Nuclear B. Electric, R, 0 & 0 Performed Extemally:
e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric
1. Siting and heat rejection Power Research Institute
(2) Transmission
Line Classification Description
No.(a)(b)
4 B. Electric R, 0 & 0 performed extemally
(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 Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) fiA Resubmission 05/17/2007
RESEARCH, DE ELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
(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. 0 & 0 items performed intemallyand in column (d) those items performed outside the company costing $5.000 or more,
briefly describing the specific area of R, 0 & 0 (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, 0 & 0
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, 0 &0 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 Intemally Costs Incurred Extemally AMOUNTS CHARGED IN CURRENT YEAR Unamortized Linecurre
rc~ Year Current Year Account Amount Accumulation No.
(d)(e)(f)
(g)
26,250 930.26.250
FERC FORM NO.1 (ED. 12-87)Page 353
This ~rt Is: Date of Report(1) ~An Original (Mo. Da. Yr)
(2) A Resubmission 05/17/2007
DISTRIBUTION OF SALARIES AND WAGES
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 2006/04
(a)
Line
No.
Classification Direct PayrollDistribution Total
Electric
Operation
Production
Transmission
Regional Market
Distribution
7 Customer Accounts
8 Customer Service and Informational
Sales
10 Administrative and General
11 TOTAL Operation (Enter Total of lines 3 thru 10)
12 Maintenance
13 Production
14 Transmission
15 Regional Market
16 Distribution
17 Administrative and General
18 TOTAL Maintenance (Total of lines 13 thru 17)
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 13)
21 Transmission (Enter Total of lines 4 and 14)
22 Regional Market (Enter Total of Unes 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)
24 Customer Accounts (Transcribe from line 7)
25 Customer Service and Informational (Transcribe from line 8)
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 17)
28 TOTAL Oper. and Main!. (Total of lines 20 thru 27)
29 Gas
30 Operation
31 Production-Manufactured Gas
32 Production-Na!. Gas (Including Expl. and Dev.
33 Other Gas Supply
34 Storage, LNG Terminaling and Processing
35 Transmission
36 Distribution
37 Customer Accounts
38 Customer Service and Informational
39 Sales
40 Administrative and General
41 TOTAL Operation (Enter Total of lines 31 thru 40)
42 Maintenance
43 Production-Manufactured Gas
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission
FERC FORM NO.1 (ED. 12-88)Page 354
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da, Yr)End of 2006/04(2) DA Resubmission 05/17/2007
DIST IBUTION OF SALARIES AND WAGES (Continued)
Line Classification Direct Payroll AII!)Catlon ot TotalDistributionPayroll charged forNo.Clearin~ Accounts(a)(b)(d)
Distribution
Administrative and General
TOTAL Main!. (Enter Total of lines 43 thru 49)
Total Operation and Maintenance
Production-Manufactured Gas (Enter Total of lines 31 and 43)
Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
Other Gas Supply (Enter Total of lines 33 and 45)
Storage, LNG Terminaling and Processing (Total of lines 31 thru 47)
Transmission (Lines 35 and 47)
Distribution (Lines 36 and 48)
Customer Accounts (Line 37)
Customer Service and Informational (Line 38)
Sales (Line 39)
Administrative and General (Lines 40 and 49)
TOTAL Operation and Main!. (Total of lines 52 thru 61)
Other Utility Departments
Operation and Maintenance
TOTAL All Utility Dep!. (Total of lines 28, 62, and 64)392 191 898 392,191,898
Utility Plant
Construction (By Utility Departments)
Electric Plant 146,436,771 146,436.771
Gas Plant
Other (provide details in footnote):
TOTAL Construction (Total of lines 68 thru 70)146.436,771 146.436,771
Plant Removal (By Utility Departments)
Electric Plant 306,071 306,071
Gas Plant
Other (provide details in footnote):
TOTAL Plant Removal (Total of lines 73 thru 75)306,071 306 071
Other Accounts (Specify, provide details in footnote):
Fuel Stock 070 870 070.870
Miscellaneous Income Deduction 405 275 405,275
Miscellaneous Nonoperating / Nonutility 049.000 049,000
TOTAL Other Accounts 525,145 525,145
TOTAL SALARIES AND WAGES 569,459,885 569.459,885
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 2006/Q4
(2) fiA Resubmission 05/17/2007
PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during
the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
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 231
Reactive Supply and Voltage MWH MWH
3 Regulation and Frequency Response 508,412 MWH 041 345 58,008.913 MWH 814 214
Energy Imbalance 338,404 MWH -4,871,747
5 Operating Reserve - Spinning 53,666.531 MWH 19.523.182 56,756.279 MWH 20.695,063
6 Operating Reserve. Supplement 666,531 MWH 523,182 56,432,763 MWH 20.574,391
7 Other MWH 556 MWH 27,102
8 Total (Unes 1 thru 7)163,841,474 48.087 709 170.861 107 46.282,254
FERC FORM NO.1 (New 2-04)Page 398
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 05/17/2007
M NTHL Y TRANSMISSION SYSTEM P AK 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 (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the
definition of each statistical classification.
Year/Period of Report
End of 2006/Q4
NAME OF SYSTEM:
Line
No.
Monthly Peak
MW - Total
Day of Hour of Rrm Network
Monthly Monthly Service for SelfPeak Peak
Month
(a)
1 January
(b)
2 February
March
Firm Network Long-Term Firm Other Long-Short-Term Firm Other
Service for Point-to-point Term Firm Point-to-point Service
Others Reservations Service Reservation
(e)(f)
(g)
(h)(i)
(j)
748 347 524
048 212 524
482 242 524 119
23.278 801 10.572 144
872 135 524 871
118 268 524 572
009 478 994
23.999 881 11.208 2,437
290 285 175 202
728 240 175 078
485 074 175 887
26,503 599 525 167
521 778 321 599
614 008 685 575
998 685 555
784 691 729
4 Total for Quarter 1
5 April
6 May
7 June
, '" ',."
8 Total for Ouarter 2
-' , '
/,/o :i'
Total for Ouarter 4
Total Year to
DateNear
FERC FORM NO. 1/3-(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 05/1712007 2006/Q4
FOOTNOTE DATA
~chedule Page: 400 Line No.17 Column:
eflects actual demands of control area load at time of Transmission System Peak.
~chedule Page: 400 Line No.17 Column: f
eflects actual demands of control area load at time of Transmission System Peak.
~chedule Page: 400 Line No.17 Column: g
eflects reservations in effect at time of Transmission System Peak.
~chedule Page: 400 Line No.17 Column: h
Reflects reservations in effect at time of Transmission System Peak.
~chedule Page: 400 Line No.17 Column: i
Reflects reservations in effect at time of Transmission System Peak.
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 ACCOUN
Date of Report
(Mo, Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/04
Line
No.
Item
Report below the information called for conceming 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 9,14,
and 19)
FERC FORM NO.1 (ED. 12-90)
MegaWatt Hours
(b)
45,490,
622
554
~~~
39,484,
272
69,948,921
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 Fumished 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)
797 336
216.028
13,440,509
117,453
377 595
69,948,921
This ~rt Is:(1) ~An Original
(2) A Resubmission
MONTHLY PEAKS AND OUTP T
(1) Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, fumish 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 systems 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.
Date of Report
(Mo. Da, Yr)
05/17/2007
Year/Period of Report
End of 2006/04
Name of Respondent
PacifiCorp
NAME OF SYSTEM:
40 December
Monthly Non-Requirments MONTHLY PEAKSales for Resale &
Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(b)(c)(d)(e)(f)
114,067 176,592 832 1800 PST
507 031 065,469 048 0900 PST
729 110 126 924 525 0800 PST
184 445 061,243 922 0800 PST
222 761 797 465 118 1600 PDT
938,973 289,544 010 1600 PDT
525,589 187 344 322 1500 PDT
132 110 048.674 728 1700 PDT
5,486,362 106,356 8,485 1700 PDT
607 233 162,471 521 0800 PST
065,895 265,417 617 1800 PST
6,435,345 153,010 686 1800 PST
Line
No.Month
(a)
29 January
February
31 March
35 July
36 August
37 September
38 October
39 November
TOTAL 69,948,921 13,440,509
FERC FORM NO.1 (ED. 12-90)Page 401b
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
~chedule Page: 401 Line No.16 Column: b
The megawatt hours (MWh's) reported in Transmission for Other (Wheeling) received and delivered include MWh's for prior year
adjustments for the following years:
2003 - 3 326 140 MWh
2004 - 6 585 066 MWh
2005 - 13 091 537 MWh
IFERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 402)
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)2006/Q4(2) DA Resubmission 05/17/2007 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 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. 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 bumed converted to Mct.7. Quantities of fuel bumed (Line 38) and average cost per unit of fuel
bumed (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 fumish only the composite heat rate for all fuels bumed.
Line Item Plant Plant
No.Name: Carbon Name:
...-
(a)(b)
Kind of Plant (Intemal 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)175 378
Plant Hours Connected to Load 8718 8332
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 1312553000 2755783000
Cost of Plant: Land and Land Rights 956546 1246363
Structures and Improvements 12195375 46531254
Equipment Costs 78255924 327174942
Asset Retirement Costs 313308 35051
Total Cost 91721153 374987610
Cost per KW of Installed Capacity (line 17/5) Including 486.3264 905.7672
Production Expenses: Oper, Supv, & Engr 103478 1526906
Fuel 13633123 45467404
Coolants and Water (Nuclear Plants Only)
Steam Expenses 1235100 2488756
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 1897270 1353347
Misc Steam (or Nuclear) Power Expenses 3853893 1783535
Rents 32322 122887
Allowances
Maintenance Supervision and Engineering 2432903
Maintenance of Structures 233317 675302
Maintenance of Boiler (or reactor) Plant 2403799 3033534
Maintenance of Electric Plant 864401 646757
Maintenance of Misc Steam (or Nuclear) Plant 355705 2501736
Total Production Expenses 24612408 62033067
Expenses per Net KWh 0188 0225
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Composite Coal Oil Composite
Unit (Coal-tons/Oil-barreIlGas-mcflNuclear-indicate)Tons Barrels Tons Barrels
Quantity (Units) of Fuel Bumed 632354 2908 1527105 1855
Avg Heat Cont - Fuel Bumed (btulindicate if nuclear)11709 140000 9712 136093
Avg Cost of Fuel/unit, as Delvd to.b. during year 20.548 77.503 000 28.955 72.751 000
Average Cost of Fuel per Unit Bumed 21.203 000 000 29.685 000 000
Average Cost of Fuel Bumed per Million BTU 905 13.181 920 528 12.728 532
Average Cost of Fuel Bumed per KWh Net Gen 010 000 010 016 000 016
Average BTU per KWh Net Generation 11282.184 13.027 11295.211 10763.724 848 10767.572
FERC FORM NO.1 (REV. 12-03)Page 402
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da, Yr)2006/Q4(2)DA Resubmission 05/17/2007 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,
intemal 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
~~.
Dave Johnston No.
(f)Steam Steam Steam
Conventional Outdoor Boiler Semi-Outdoor
1984 1979 1959
1986 1980 1972
155.172.816.
152 166 761
8735 8760 8760
148 165 762
196
1074271000 1293718000 5776846000
1358276 137086 10451083
57092259 35748677 50207724
152444070 128208774 369677242
39236 50560 6412602
210933841 164145097 436748651
1355.6159 953.7774 534.7070
15765 366810 609319
10318786 16800182 41977590
788639 1226430 44903
18945 431575
951231 1543482 14615932
13025 6142 63611
237912 477176
304305 268272 2543768
3001277 1818239 6598314
310214 572400 6015886
360901 445415 1180612
16321000 23956123 73649935
0152 0185 0127
Coal Oil Composite Coal Oil Gas Coal Oil Composite
Tons Barrels Tons Barrels MCF Tons Barrels
693280 1838 652658 269 7879 4037028 6336
8429 140000 10015 122360 1092 8080 140000
14.457 92.544 000 24.531 111.991 000 990 75.212 000
14.639 000 000 25.613 000 812 10.280 000 000
868 15.738 882 279 21.793 636 12.791 643
009 000 009 012 000 007 000 007
10879.298 10.059 10889.357 10104.783 069 11292.965 449 11299.414
FERC FORM NO.1 (REV. 12-03)Page 403
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)2006/Q4(2)DA Resubmission 05/17/2007 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 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. 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 bumed 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 fumish only the composite heat rate for all fuels bumed.
Line Item Plant Plant
No.Name:Name:
",,-
(a)
.. "
Kind of Plant (Intemal Comb, Gas Turb, Nuclear Steam Steam
Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor Boiler Outdoor Boiler
Year Originally Constructed 1965 1978
Year Last Unit was Installed 1976 1978
Total Installed Cap (Max Gen Name Plate Ratings-MW)81.443 . 00
Net Peak Demand on Plant - MW (60 minutes)413
Plant Hours Connected to Load 8739 8285
Net Continuous Plant Capability (Megawatts)
When Not Limited by Condenser Water 403
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 606990000 3215261000
Cost of Plant: Land and Land Rights 379735 9688975
Structures and Improvements 5991642 61599431
Equipment Costs 61141743 231281082
Asset Retirement Costs 20877 1893538
Total Cost 67533997 304463026
Cost per KW of Installed Capacity (line 17/5) Including 830.6765 687.2755
Production Expenses: Oper, Supv, & Engr 189447
Fuel 9634350 32952944
Coolants and Water (Nuclear Plants Only)
Steam Expenses 714488 2952013
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 216267 41300
Misc Steam (or Nuclear) Power Expenses 876280 2178819
Rents 38319
Allowances
Maintenance Supervision and Engineering 259399
Maintenance of Structures 90097 1465213
Maintenance of Boiler (or reactor) Plant 1276659 5138856
Maintenance of Electric Plant 86487 817681
Maintenance of Misc Steam (or Nuclear) Plant 492411 362184
Total Production Expenses 13835885 45947329
Expenses per Net KWh 0228 0143
Fuel: Kind (Coal, Gas, Oil. or Nuclear)Coal Oil Gas Coal Oil Composite
Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)Tons Barrels MCF Tons Barrels
Quantity (Units) of Fuel Bumed 299289 270 6340 1532085 1830
Avg Heat Cont - Fuel Bumed (btulindicate if nuclear)11002 132579 1118 11180 140000
Avg Cost of Fuel/unit, as Delvd to.b. during year 31.377 92.294 000 000 000 000
Average Cost of Fuel per Unit Bumed 32.009 000 639 21.429 000 000
Average Cost of Fuel Bumed per Million BTU 1.455 16.577 958 11.346 962
Average Cost of Fuel Bumed per KWh Net Gen 0.Q15 000 010 000 010
Average BTU per KWh Net Generation 10849.528 476 10654.631 346 10657.978
FERC FORM NO.1 (REV. 12-03)Page 402.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da, Yr)2006/Q4(2) DA Resubmission 05/17/2007 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,
intemal 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 conceming 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:Hunter Unit No.Name:No.
(e)1-=:Steam Steam Steam
Outdoor Boiler Outdoor Boiler Outdoor Boiler
1980 1983 1978
1980 1983 1983
285.495.1223.
271 459 1143
7288 8129 8760
259 460 1122
225
1828040000 3433975000 8477276000
9688975 10275400 29653350
50557997 89608334 201765762
153975955 378888393 764145430
1893538 1893538 5680614
216116465 480665665 1001245156
758.3034 970.0619 818.3450
18608228 34932246 86493418
2945176 2961088 8858277
41300 41300 123900
-4669798 2791516 300537
31237 35829 105385
1783200 1446619 4695032
7892743 5782359 18813958
3421677 884164 5123522
258996 309695 930875
30312759 49184816 125444904
0166 0143 0148
Coal Oil Composite Coal Oil Composite Coal Oil Composite
Tons Barrels Tons Barrels Tons Barrels
841436 2949 1580669 11726 3954190 16505
11335 140000 11185 140000 11215 140000
000 000 000 000 000 000 21.402 87.456 000
21.810 000 000 21.426 000 000 21.509 000 000
962 14.774 975 958 15.449 986 959 14.874 974
010 000 010 010 000 010 010 000 010
10434.867 485 10444.352 10296.978 20.078 10317.056 10462.363 11.448 10473.811
FERC FORM NO.1 (REV. 12-03)Page 403.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da, Yr)2006/Q4(2) OA Resubmission 05/17/2007 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
bumed (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 fumish only the composite heat rate for all fuels bumed.
Line Item Plant Plant
No.Name: Huntington Name:
(a)(b)
1 Kind of Plant (Intemal 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)916 1400
Plant Hours Connected to Load 8729 8760
Net Continuous Plant Capability (Megawatts)
9 When Not Limited by Condenser Water 895 1413
When Limited by Condenser Water
Average Number of Employees 167 342
Net Generation, Exclusive of Plant Use - KWh 6139007000 10060478000
Cost of Plant: Land and Land Rights 2386782 1161925
Structures and Improvements 100385029 133223694
Equipment Costs 511645641 762621386
Asset Retirement Costs 2709703 9171815
Total Cost 617127155 906178820
Cost per KW of Installed Capacity (line 17/5) Including 619.6056 588.0078
Production Expenses: Oper, Supv, & Engr 12960 16749677
Fuel 56823628 134687486
Coolants and Water (Nuclear Plants Only)
Steam Expenses 6056760 3541899
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 132186
Misc Steam (or Nuclear) Power Expenses 9627725 15298152
Rents 89768 728304
Allowances
Maintenance Supervision and Engineering 1343814 1361822
Maintenance of Structures 1374744 7673456
Maintenance of Boiler (or reactor) Plant 10468523 24789113
Maintenance of Electric Plant 5011369 7067362
Maintenance of Misc Steam (or Nuclear) Plant 1188364 2174513
Total Production Expenses 91997655 183607666
Expenses per Net KWh 0150 0183
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Composite Coal Oil Composite
Unit (Coal-tonslOil-barreI/Gas-mcf/Nuciear-indicate)Tons Barrels Tons Barrels
Quantity (Units) of Fuel Bumed 2621873 12812 5695821 24008
Avg Heat Cont - Fuel Bumed (btu/indicate if nuclear)11219 140000 9219 140000
Avg Cost of Fuel/unit. as Delvd to.b. during year 21.255 81.877 000 23.586 93.706 000
Average Cost of Fuel per Unit Bumed 21.273 000 000 23.252 000 000
Average Cost of Fuel Bumed per Million BTU 948 13.925 965 261 15.936 281
Average Cost of Fuel Bumed per KWh Net Gen 009 000 009 013 000 013
Average BTU per KWh Net Generation 9583.207 12.272 9595.479 10438.953 14.032 10452.984
FERC FORM NO.1 (REV. 12-03)Page 402.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)2006/04(2)DA Resubmission 05/17/2007 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 conceming 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 ~N~'Gadsby Steam Plant No.
(d)(f)
Steam Steam Steam
Outdoor Boiler Conventional Outdoor
1963 1978 1951
1971 1978 1955
707.289.257.
704 278 213
8760 7207 1651
700 268 235
145
4929400000 1886039000 130819000
4290776 210526 1252090
60389753 49345431 13877760
314227168 278145860 56496749
4359064 301453 746792
383266761 328003270 72373391
541.9496 1132.2170 280.9526
501341 2544249 46172
65409065 15020362 7793183
7378618
41914
7102076 991108 2718842
2000 7796 1219
1490534
1 064394 407401 74305
8178136 9158158 531662
3005603 2952695 613311
564432 902250 490962
94738113 31984065 12269656
0192 0170 0938
Coal Gas Composite Coal Oil Composite Gas
Tons MCF Tons Barrels MCF
2603974 153975 1357141 10067 1806776
9852 1057 7979 140000 1056
25.037 000 000 10.589 93.308 000 000 000 000
24.870 214 000 10.376 000 000 313 000 000
262 906 271 650 15.869 692 087 000 000
013 000 013 008 000 008 060 000 000
10408.539 33.701 10442.240 11482.931 31.385 11514.317 14576.132 000 000
FERC FORM NO.1 (REV. 12-03)Page 403.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2006/04(2)DA Resubmission 05/17/2007 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 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. 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 bumed converted to Mct.7. Quantities of fuel bumed (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 fumish only the composite heat rate for all fuels bumed.
Une Item Plant Plant
No.Name: Little Mountain Name:
(a)(b)
1 Kind of Plant (Intemal 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
5 Total Installed Cap (Max Gen Name Plate Ratings-MW)16.279.
Net Peak Demand on Plant - MW (60 minutes)245
7 Plant Hours Connected to Load 7545 7293
8 Net Continuous Plant Capability (Megawatts)
9 When Not Limited by Condenser Water 237
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 100523000 1553240000
Cost of Plant: Land and Land Rights 635 842245
Structures and Improvements 217599 12474621
Equipment Costs 5009047 151035139
Asset Retirement Costs 347334
Total Cost 5227281 164699339
Cost per KW of Installed Capacity (line 17/5) Including 326.7051 589.0534
Production Expenses: Oper, Supv, & Engr
Fuel 4698778 44495571
Coolants and Water (Nuclear Plants Only)
Steam Expenses
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 762636 5775057
Mise Steam (or Nuclear) Power Expenses
Rents 293
Allowances
Maintenance Supervision and Engineering
Maintenance of Structures
Maintenance of Boiler (or reactor) Plant
Maintenance of Electric Plant 222 4710
Maintenance of Misc Steam (or Nuclear) Plant 210332
Total Production Expenses 5672261 50275338
Expenses per Net KWh 0564 0324
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas Gas
Unit (Coal-tonslOil-barreVGas-mcflNuclear-indicate)MCF MCF
Quantity (Units) of Fuel Bumed 1658896 10967684
Avg Heat Cont - Fuel Bumed (btulindicate if nuclear)1056 1019
Avg Cost of FueVunit, as Delvd f.b. during year 000 000 000 000 000 000
Average Cost of Fuel per Unit Bumed 832 000 000 057 000 000
Average Cost of Fuel Bumed per Million BTU 682 000 000 981 000 000
Average Cost of Fuel Bumed per KWh Net Gen 047 000 000 029 000 000
Average BTU per KWh Net Generation 17429.185 000 000 7196.395 000 000
FERC FORM NO.1 (REV. 12-03)Page 402.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2006/Q4(2)DA Resubmission 05/17/2007 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 conceming 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: B/undell Name: Name: No.
(d)
Steam - Geothermal Steam Gas Turbine
Indoor Outdoor Boiler Outdoor
1984 1996 2002
1984 1996 2002
26.61.217.
205
8578 8003 3724
202
190608000 162751000 456624000
31282815
6683493 5733734 116354
33868041 28701621 607789
420763
34435355 724143
2768.3951 559.9245 3371
20065
17688753
13481
3110724
392648 2131781
1624844
1013 13072156
754 404
. 71562
175465
236685 304304
28960 11609
5256591 392648 33209007
0276 0024 0727
Gas
MCF
4676710
1052
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 782 000 000
000 000 000 000 000 000 593 000 000
000 000 000 000 000 000 039 000 000
000 000 000 000 000 000 10780.314 000 000
FERC FORM NO.1 (REV. 12-03)Page 403.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)2006/04(2) DA Resubmission 05/17/2007 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 bumed converted to Mct.7. Quantities of fuel bumed (Line 38) and average cost per unit of fuel
bumed (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 fumish only the composite heat rate for all fuels bumed.
Line Item Plant Plant
No.Name: Gadsby Gas Peakers Name:Currant Creek
(a)(b)(c)
1 Kind of Plant (Intemal Comb. Gas Turb, Nuclear Gas Turbine Gas Turbine
Type of Constr (Conventional, Outdoor. Boiler, etc)Outdoor Outdoor
Year Originally Constructed 2002 2005
Year Last Unit was Installed 2002 2006
Total Installed Cap (Max Gen Name Plate Ratings-MW)141.566.
Net Peak Demand on Plant - MW (60 minutes)127 568
Plant Hours Connected to Load 2795 6596
8 Net Continuous Plant Capability (Megawatts)
9 When Not Limited by Condenser Water 120 540
When Limited by Condenser Water
Average Number of Employees
1;2 Net Generation, Exclusive of Plant Use - KWh 214071000 1760645000
Cost of Plant: Land and Land Rights 3402550
Structures and Improvements 4121643 28120692
Equipment Costs 73768723 300721130
Asset Retirement Costs 219922
Total Cost 77890366 332464294
Cost per KW of Installed Capacity (line 17/5) Including 552.4139 586.4602
Production Expenses: Oper, Supv, & Engr 1169836
Fuel 9393270 53417221
Coolants and Water (Nuclear Plants Only)
Steam Expenses
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 1768800 1410522
Misc Steam (or Nuclear) Power Expenses
Rents 3999 201118
Allowances
Maintenance Supervision and Engineering
Maintenance of Structures 138282 100339
Maintenance of Boiler (or reactor) Plant
Maintenance of Electric Plant 618024 1582831
Maintenance of Misc Steam (or Nuclear) Plant 166281 47866
Total Production Expenses 12088656 57929733
Expenses per Net KWh 0565 0329
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas Gas
Unit (Coal- tons/Oil-barrel/Gas-mcf/N uclear - indicate)MCF MCF
Quantity (Units) of Fuel Bumed 2266714 12400119
Avg Heat Cont - Fuel Bumed (btulindicate if nuclear)1056 1052
Avg Cost of Fuel/unit, as Delvd f.b. during year 000 000 000 000 000 000
Average Cost of Fuel per Unit Bumed 144 000 000 308 000 000
Average Cost of Fuel Bumed per Million BTU 923 000 000 094 000 000
Average Cost of Fuel Bumed per KWh Net Gen 044 000 000 030 000 000
Average BTU per KWh Net Generation 11184.014 000 000 7411.134 000 000
FERC FORM NO.1 (REV. 12-03)Page 402.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2006/Q4(2)DA Resubmission 05/17/2007 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,
intemal 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 conceming 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)
0 . 0000 0000 0 . 0000
0000 0000 0 . 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 05/17/2007 2006/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 36.77% 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
Coistrip
The Colstrip Plant is operated by PPL Montana, LLC and is jointly owned. Data reported represents respondent's 10% share of
Colstrip Plant Units No.3 and No.4. PacifiCorp does not have employees at the Colstrip Plant.
!schedule Page: 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
em 10 ees at the Crai Plant.
chedule Pa e: 402.Line No.Column: b
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., 12.6% (33 MW) share of Hayden Unit No.2 and 17.5% of common facilities.
PacifiCo does not have em 10 ees at the Ha den Plant.
chedule Pa e: 402.Line No.Column:
Hunter Plant Unit No.
Hunter Plant Unit No.1 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 2006 was $.9 million and was rimaril char ed to account 506.
chedule 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 2006 was $10.2 million and was
~::~~/;;:;~:
~~~~~unt
i~:~ No.Column:
Hunter
Hunter Unit No.1 is owned by the respondent and Provo City Corporation with an undivided interest of93.75% 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 60.31 %, 25.1 08% and 14.582% respectively. Data in column (t) 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 2006 was $11.1 million and was
rimaril char ed to account 506.
chedule 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
006 was $25.7 milli n and was rimarily charged to account 506.
!schedule Page: 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 2006 was
$5.1 million and was rimaril char ed to account 506.
chedule Page: 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 Resubmisslon 05/1712007 2006/04
FOOTNOTE DATA
Hermiston
The Hermiston Plant is operated by Hermiston Operating Company, loP. 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 326.9 Line 2 and 3 of this Fonn No.1 for further
infonnation on Henniston Generatin Com an ,loP. PacifiCo does not have an em 10 ees at the Hermiston Plant.
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
aper Mill.
!schedule Page: 402.Line No.Column:
West Valley
For further information regarding the West Valley generating facility, refer to Page 108 Important Changes During the Year Item 4
f this Fonn No.
!schedule Page: 402.Line No.17 Column: d
Blundell
Excluded from the total cost of the Blundell Plant are the production costs associated with the acquisition of Intennountain Geothermal
and Steam Reserve Corporation totaling $15 253 014. The acquisitions are disclosed in Item 2 of the Important Changes During the
ear.
!schedule Page: 402 Line No.42 Column: e3
The Crai Plant 0 erates on coal with start u rovided b oil and natural
chedule Pa e: 402 Line No.43 Column:
The Craig Plant operates on coal with start up provided by oil and natural gas. The composite rate is .012.
!Schedule Page: 402 Line No.44 Column: e3
The Craig Plant operates on coal with start up provided by oil and natural gas. The composite rate is 10 158.752.
!Schedule Page: 402.Line No.42 Column: b3
The Ha den Plant 0 erates on coal with start u rovided b oil and natural as. The com osite rate is 1.457.
chedule Pa e: 402.Line No.43 Column: b3
The Hayden Plant operates on coal with start up provided by oil and natural gas. The composite rate is .015.
!Schedule Page: 402.Line No.44 Column: b3
The Hayden Plant operates on coal with start up provided by oil and natural gas. The composite rate is 10 896.196.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2oo6/Q4(2) OA Resubmission 05/17/2007 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
ootnote. 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 179 965
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 133,926,000 172,649,000
Cost of Plant
Land and Land Rights 180,375 20,914
Structures and Improvements 1 ,228,623 627,772
Reservoirs, Dams, and Waterways 633,051 898,044
Equipment Costs 629 995 360,303
Roads, Railroads. and Bridges 105;442 240,200
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)777.486 147,233
Cost per KW of Installed Capacity (line 20 / 5)438.8743 338.7864
Production Expenses
Operation Supervision and Engineering 101,585 131 040
Water for Power 658 888
Hydraulic Expenses 3,429 630
Electric Expenses
Misc Hydraulic Power Generation Expenses 389,707 545,759
Rents 198 932
Maintenance Supervision and Engineering
Maintenance of Structures 985 27.449
Maintenance of Reservoirs, Dams, and Waterways 28.979 687
Maintenance of Electric Plant 64,481 40,456
Maintenance of Misc Hydraulic Plant 22,563 30,460
Total Production Expenses (total 23 thru 33)633,585 787,301
Expenses per net KWh 0047 0 . 0046
FERC FORM NO.1 (REV. 12-03)Page 406
This ~rt Is: Date of Report(1) ~An Original (Mo, Da. Yr)
(2) DA Resubmission 05/17/2007
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. intemal combustion engine, or gas turbine equipment.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/Q4
FERC Ucensed Project No. 1927
Plant Name: 1IIIIiI~FERC Licensed Project No. 1927 FERC Licensed Project No.
Plant Name: Plant Name:
2420 Line
No.
Outdoor
1953
1953
15.
704
Outdoor
1953
1953
26.
261
1927
1927
30.
066
562,143
464,285
994,651
021 079
401.4053
906,179
483,491
196,313
250,151
12,836,134
493.6975
505,129
774,662
535,549
612,923
566,413
994,676
533.1559
79,843
537
80,303
252
301,314
270
377
16,599
20,417
28,424
545,336
0132
138,674
16,531
139,192
437
456,530
467
31,146
59,954
120,682
50,664
014 277
0249
953
987
112,355
616
524 973
540
692
587
30,837
175,543
937 083
0096
FERC FORM NO.1 (REV. 12-03)Page 407
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)2006/Q4(2) DA Resubmission 05/17/2007 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: Plant Name:
(a)
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 752 736
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 45,984.000 64,463,000
Cost of Plant
Land and Land Rights 50,501
Structures and Improvements 562 328 296,088
Reservoirs, Dams, and Waterways 113,215 820,729
Equipment Costs 205.150 891,357
Roads, Railroads, and Bridges 400,007 236
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)280,700 115 911
Cost per KW of Installed Capacity (line 20 / 5)752.7909 397.4518
Production Expenses
Operation Supervision and Engineering 61,868 113,757
Water for Power 994 085
Hydraulic Expenses 889 134,557
Electric Expenses 185
Misc Hydraulic Power Generation Expenses 231 622 858.326
Rents 198 168
Maintenance Supervision and Engineering
Maintenance of Structures 058 654
Maintenance of Reservoirs, Dams, and Waterways 674 400
Maintenance of Electric Plant 039 65,827
Maintenance of Misc Hydraulic Plant 20.844 76,700
Total Production Expenses (total 23 thru 33)409 371 370,474
Expenses per net KWh 0089 0213
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/Q4
This ~rt Is: Date of Report(1) ~An Original (Mo, Da. Yr)
(2) DA Resubmission 05/17/2007
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, intemal combustion engine, or gas turbine equipment.
FERC Licensed Project No.
Plant Name: Iron Gate
(d)
2082 FERC Licensed Project No.
Plant Name: JC Boyle
(e)
2082 FERC Licensed Project No.
Plant Name:
1927 Line
No.
Outdoor
1962
1962
18.
615
Outdoor
1958
1958
97.
133
Outdoor
1955
1955
31.
474
341,706
895,587
10,009,919
208,523
076,116
531 851
973.9917
26,404
050,476
997 854
14,435,637
883 023
393 394
320.4061
74Q,292
267 011
779.930
407,171
194,404
506.2333
117 914
592
086
361 911
241
486,393
10,358
482
20,307
032 284
0079
328,795
222
16,800
583 768
13.135
20,837
267,993
372 543
963
949,970
0022
173,085
20,340
171,260
538
568,395
575
616
48,211
34,619
61,558
130,197
0075
FERC FORM NO.1 (REV. 12-03)Page 407.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)2006/04(2) DA Resubmission 05/17/2007 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: Plant Name: Merwin
(a)(c)
1 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)146
Plant Hours Connect to Load 476 760
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions 151
(b) Under the Most Adverse Oper Conditions 151
Average Number of Employees
Net Generation, Exclusive of Plant Use - Kwh 167,257 000 547 025,000
Cost of Plant
Land and Land Rights 988,467
Structures and Improvements 842 664 28,192,960
Reservoirs, Dams, and Waterways 17,782,108 689,958
Equipment Costs 012 712 956,384
Roads, Railroads, and Bridges 649,779 793,049
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)22,287,263 620.818
Cost per KW of Installed Capacity (line 20 / 5)675.3716 401.6237
Production Expenses
Operation Supervision and Engineering 175,654 224 113
Water for Power 20,982 4,473
Hydraulic Expenses 176 667 545,421
Electric Expenses 555
Misc Hydraulic Power Generation Expenses 546.661 909.099
Rents 593 040
Maintenance Supervision and Engineering
Maintenance of Structures 22,045 30,080
Maintenance of Reservoirs, Dams, and Waterways 77,432 551
Maintenance of Electric Plant 29,021 30,265
Maintenance of Misc Hydraulic Plant 62,534 282,402
Total Production Expenses (total 23 thru 33)112 144 028,444
Expenses per net KWh 0066 0055
FERC FORM NO.1 (REV. 12-03)Page 406.
This ~ort Is: Date of Report(1) ~An Original (Mo. Da. Yr)(2) DA Resubmission 05/17/2007
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 2006/Q4
FERC Licensed Project No. 1927
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No. 2630
Plant Name: Prospect No.
Line
No.
Conventional
1949
1950
42.
691
1915
1920
30.
760
Conventional
1928
1928
32.
757
492 601
387,433
075 923
214,603
11,170,560
262.8367
36,698
271 755
537,738
634,042
475,603
10,955,836
365.1945
105,168
524 912
23,556,253
037,819
191,385
29,415,537
919.2355
230,619
27,022
227,526
715
689,040
12,922
24,500
555
77,892
80,535
443,326
0061
101,926
987
122,325
728,400
407
17.947
34,597
174,890
63,987
245,466
0277
438,876
052
487
542 989
868
58,788
50,164
43,994
45,077
194.295
0 . 0044
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)2006/04(2) DA Resubmission 05/17/2007 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 Projecl No.1927 FERC Licensed Project No.
No.Plant Name: Plant Name: ~~k
(a)
1 Kind of Plant (Run-of-River or Storage)Run-of-River Storage
Plant Construction type (Conventional or Outdoor)Outdoor Conventional
Year Originally Constructed 1951 1924
Year Last Unit was Installed 1951 1924
Total installed cap (Gen name plate Rating in MW)18.14.
Net Peak Demand on Plant-Megawatts (60 minutes)
Plant Hours Connecl to Load 659 492
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 93.946,000 13,727 000
Cost of Plant
Land and Land Rights 512,946
Structures and Improvements 609 154 577 562
Reservoirs, Dams, and Waterways 009,391 999,719
Equipment Costs 256,853 072 224
Roads, Railroads, and Bridges 16,777
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)892,175 162,451
Cost per KW of Installed Capacity (line 20 / 5)382.8986 583.0322
Production Expenses
Operation Supervision and Engineering 100,573 48,470
Water for Power 726 461
Hydraulic Expenses 96.364 085
Electric Expenses 303
Misc Hydraulic Power Generation Expenses 357.057 368,458
Rents 324 280
Maintenance Supervision and Engineering
Maintenance of Structures 12,411 10,540
Maintenance of Reservoirs. Dams, and Waterways 994 19.529
Maintenance of Electric Plant 20,788 38,303
Maintenance of Misc Hydraulic Plant 48.948 284
Total Production Expenses (total 23 thru 33)709,488 566,410
Expenses per net KWh 0076 0413
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/Q4
This ~rt Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2)
DA
Resubmission 05/17/2007
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. intemal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1927
Plant Name:
FERC Licensed Project No.
Plant Name: Swift No.
(e)
2111 FERC Licensed Project No.
Plant Name: Yale
2071 Line
No.
Storage (Re-Reg)
Outdoor
1952
1952
11.
722
Storage
Conventional
1958
1958
240.
263
801
Storage
Conventional
1953
1953
134.
163
910
858,339
364,564
157,105
56,124
436,132
766.9211
813.808
284,936
633,790
15.621,810
395,145
749,489
282.2895
776 917
6,468 170
26,160,156
14,723,876
1 ,383,555
51,512,674
384.4229
056
994
58,889
185
250,209
273
6,493
28,275
581
22,193
486,148
0079
109,269
943
058,273
291 324
555
17,469
371
12,456
483 519
992,179
0061
188,790
4,407
537.400
711 683
891
430
158
56,970
276,579
804,308
0043
FERC FORM NO.1 (REV. 12-03)Page 407.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2oo6/Q4(2) DA Resubmission 05/17/2007 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: . Plant Name:
(a)(c)
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
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 30,519,000
Cost of Plant
Land and Land Rights
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)816,963
Cost per KW of Installed Capacity (line 20 / 5)79.3168 0 . 0000
Production Expenses
Operation Supervision and Engineering 17,142
Water for Power 339
Hydraulic Expenses 575
Electric Expenses
Misc Hydraulic Power Generation Expenses 325,881
Rents 169
Maintenance Supervision and Engineering
Maintenance of Structures 216
Maintenance of Reservoirs, Dams, and Waterways 538
Maintenance of Electric Plant 33,075
Maintenance of Misc Hydraulic Plant 038
Total Production Expenses (total 23 thru 33)491 973
Expenses per net KWh 0161 0000
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2006/Q4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) DA Resubmission 05/17/2007
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching. and Other Expenses classified as "Other Power Supply Expenses.
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
(d)(e)
0000 0 .0000 0 . 0000
0 . 0000 0000 0000
FERC FORM NO.1 (REV. 12-03)Page 407.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
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 2006 was $73.4 million: Lemolo 1 , Lemolo 2, Clearwater 1
learwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
~chedule Page: 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 2006 was $73.4 million: Lemolo I , Lemolo 2, Clearwater I
Clearwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
~chedule Page: 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 reported on this page. The net book value for relicensing at December 31, 2006 was $1.3
illion.
!Schedule Page: 406 Line No.Column: b
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.
chedule Pa e: 406 Line No.Column: d
Clearwater No.
Foreba for eakin.
chedule Pa e: 406 Line No.Column:
Clearwater No.
Foreba for eakin .
chedule Pa e: 406.Line No.Column: b
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 2006 was $73.4 million: Lemolo I , Lemolo 2, Clearwater I
Clearwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
~chedule Page: 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 system for the following projects at December 31 , 2006 was $15.6 million: Grace, Cove, Oneida and Soda.
!Schedule Page: 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, 2006 was $73.4 million: Lemolo 1 , Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
ISchedule Pa e: 406.Line No.Column: b
Fish Creek
orebay for peak~
!Schedule Page: 406.Line No.lumn: d
Iron Gate
Storage for regulation.
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 05/17/2007 2006/Q4
FOOTNOTE DATA
~ule Page: 406.Line No.Column:
JC Boyle
Ponda e for eakin - stora e, U er Klamath Lake.
chedule Pa e: 406.Line No.Column: f
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, 2006 was $73.4 million: Lemolo 1 , Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda S rin s, Slide Creek and the North Urn ua Common Plant.
chedule 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 , 2006 was $73.4 million: Lemolo 1 , Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda S rin s, Slide Creek and the North Urn ua Common Plant.
chedule Page: 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 hook value for relicensing and settlement on the
Bear River system for the following projects at December 31 , 2006 was $15.6 mIllion: Grace, Cove, Oneida and Soda.
!schedule Page: 406.Line No.Column: b
Lemolo No.
Stora 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: f
Prospect No.
Foreba for eakin .
chedule Pa e: 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 2006 was $73 396 122: Lemolo 1, Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda S rin s, Slide Creek and the North Urn ua Common Plant.
chedule Page: 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 , 2006 was $15 631 506: Grace, Cove, Oneida and Soda.
Schedule Pa e: 406.Line No.Column: d
Soda Springs
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, 2006 was $73 396 122: Lemolo 1 , Lemolo 2, Clearwater 1
learwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
!schedule Page: 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 ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da. Yr)End of 2006/Q4(2) nA Resubmission 05/17/2007
GENERATING 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 Install~d ca~aclty l'iet Pea~Net GenerationName of Plant Orig.Name Plate atiri~Demand Excluding Cost of PlantNo.Cons!.(In MW)Plant Use
6IIIIIIiI-.rI (b)(c)(60
(SJIO.(e)(f)
" ';, "
:M"
, ,
19073 Ashton 2381 1917 831,000
4 Upper Beaver 814 1907 851.000
5 Bend 1913 1.0 025,000
6 Big Fork 2652 1910 391,
7 Cline Falls 1913 273,302,594
1913 13.15.95,240,0009 . 1917
10 Eagle Point 1957 13,381,000 789.838
Eastside 2082 1924 15,163,000 889,283
Fall Creek 2082 1903 770,000 1 ,052,690
Fountain Green 1922 1=iIGranite1896614000 4,543 517
Gunlock 1917 802,000
- ,
Last Chance 1983 921,000 2,712,570
Paris 1910 954,000 313,213
Pioneer 2722 1897 26,989.
1923 444,000
Prospect No.2630 1912 12,102 000 558 455
Prospect No.2337 1932 42,065,000
Prospect No.2630 1944 823,000 201,567
Sand Cove 1926 272 000 856,983
Snake Creek 1910 671,000 905,173
Stairs 597 1895 869,000
1915 330,359
Veyo 1920 0.4 1,405.000 727 360
Viva Naughton 1986 217 000 169,596
Wallowa Falls 308 1921 1.1 895 000 787 123
Weber 1744 1911 20,385,000
West Side 2082 1908 232.000 354,926
7,475,589
978,797
,,"'
Pumping Plant:
Lifton 1917 793,000 290 755
Wind Turbine:
1998 32.32.106,038,000 36,266,842
' " ", '' -- , -- --
Leaning Juniper #1 2006 100.101.57,993,000
FERC FORM NO.1 (REV. 12-03)Page 410
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, intemal 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 intemal combustion or gas turbine equipment, report each as a separate plant. However. if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle. or for preheated combustion air in a boiler. report as one plant.
Plant Cost (Incl Asset Operation Production Expenses Fuel Costs (in cents Line
Retire. Costs) Per MW Exc l. Fuel ruel Maintenance Kind of Fuel (per Million Btu)
(g)
(h)(i)
(j)
(k)(I)
No.
2,453 464 18,142 115 Water
281 707 438,650 65,168 Water
999,358 135,073 118,379 Water
774,359 149,137 243 Water
1 ,503 843 222,159 249,155 Water
302,594 24,190 609 Water
505,375 220,789 82,535 Water
90,084 193,836 40,191 Water
636,953 284,976 49.553 Water
590,401 53,974 12,220 Water
478,495 73.199 26,755 Water
823,619 22,664 14,243 Water
271 759 110,857 31.161 Water
795,131 59,593 34,927 Water
567,960 113,781 273 Water
435,018 36,217 20,050 Water
954,884 304,872 126,777 Water
284,573 279,836 35,302 Water
148,525 125,272 41,939 Water
961 398 253,894 162,358 Water
201,567 083 18,786 Water
071,229 57,861 386 Water
767 096 83.144 33,184 Water
179,463 96,770 21 ,952 Water
660,718 38,651 329 Water
454,720 67,248 39,883 Water
580.535 19,149 14,404 Water
533 748 95,239 Water
708.062 161 571 42,408 Water
591 543 21 ,308 -6,300 Water
766 195,187
894,765 31,772
235,357 435 Water
112,480 924,708 Wind
750,788 944,003 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 Resubmisslon 05/1712007 2006/04
FOOTNOTE DATA
~chedule 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 regulatory approvals. At this time PacifiCorp is currently preparing various other FERC required plans, initiating
project specific pennitting, and competitively bidding the construction. The majority of the physical decommissioning will occur
starting September 2007 and be completed by the end of 2007.
ISchedule Page: 410 Line No.Column:
American Fork
The cost of lant balance includes $1 321 994 of American Fork asset retirement costs.
chedule 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 re orted on this page. The net book value for relicensing at December 31 2006 was $394 034.
Schedule Page: 410 Line No.Column:
Upper Beaver
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, 2006 was $39 992.
chedule Pa e: 410 Line No.Column:
Bend
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, 2006 was $332 351.
ISchedule Page: 4JO 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
ranchises and Consents, and are not reported on this page. The net book value for relicensing at December 31 , 2006 was $585 712.
~chedule Page: 410 Line No.Column:
Condit hydroelectric project - (White Salmon River, Washington)
For a further discussion on the Condit hydroelectric project, refer to Page 108 Important Changes During the Year Item 9 of this
onn No.
~chedule Page: 410 Line No.Column:
Condit
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
ranchises and Consents, and are not reported on this page. The net book value for relicensing at December 31 , 2006 was $264 868.
~chedule Page: 410 Line No.Column:
Cove
In May 2006, the FERC approved PacifiCorp s application to amend the Bear River license and authorized the removal of the 7.5-
nameplate-rated Cove hydroelectric plant and facilities. Decommissioning of the Cove facilities has been completed in accordance
with the license amendment and the approved removal plan. The removal of the dam, flowline and all facilities, with the exception of
the powerhouse, was completed in November 2006. As of December 31 , 2006, $2.8 million has been spent for the decommissioning of
the Cove hydroelectric ro. ect.
chedule Page: 410 Line No.Column: f
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 following projects at December 31 2006 was $15 631 506: Grace, Cove, Oneida and Soda.
Schedule Pa e: 410 Line No.13 Column:
Fountain Green
Costs re orted for this
FERC FORM NO.
which are recorded in FERC account 302
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
Franchises and Consents, and are not reported on this page. The net book value for relicensing at December 31 , 2006 was $12 033.
~chedule Page: 410 Line No.Column:
Gunlock
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 relicensing at December 31, 2006 was $56 993.
chedule Page: 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 reported on this page. The net book value for relicensing at December 31, 2006 was $131 555.
~chedule Page: 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 of relic en sing 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 excluding inflation.
Removal of the plant is scheduled to commence in 2010. However, in November 2006, flooding damaged the Powerdale plant and
rendered its generating capabilities inoperable. In February 2007, the FERC granted PacifiCorp s request to cease generation at the
project until decommissioning activities begin. Also in February 2007, PacifiCorp submitted a request to the FERC to allow the
company to defer the remaining net book value and any additional removal costs of this project as a regulatory asset. PacifiCorp is
awaitin the FERC's re 1 .
chedule Pa e: 410 Line No.19 Column:
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 , 2006 was $2 135 361.
This cost of plant balance includes $5 145 417 of Power dale asset retirement costs.
~chedule 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 number 3 on December
2006 was $117 660.
~chedule 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 re orted on this a e. The net book value for relicensing at December 31 , 2006 was $103 333.
chedule Pa e: 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 re orted on this a e. The net book value for relicensing at December 31, 2006 was $414 166.
chedule Page: 410 Line No.32 Column:
Keno Regulating Dam
Used in regulating the release of water from Klamath Lake and in maintaining proper water surface level in the Klamath River between
amath Falls and Keno, Oregon.
rschedule Page: 410 Line No.33 olumn:
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
Gate).
~chedule Page: 410 Line No.34 Column:
North Umpqua
Common plant in North Umpqua Project. All common roads, employee houses, control equipment, etc. ~e in this account.~dule P~10 Li'1!!lp~~~L!!!J!l:
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 05/17/2007 2006/Q4
FOOTNOTE DATA
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 , 2006 was $73 396 122: Lemolo 1, Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda S rings, Slide Creek and the North Urn ua Common Plant.
chedule Pa e: 410 Line No.40 Column:
Foote Creek Wind Farm
The Foote Creek Wind Fann is operated by SeaWest 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 %.
~chedule Page: 410 Line No.41 Column:
Leaning Juniper #1
The cost of plant balance includes $481 519 of asset retirement costs.
IFERC FORM NO.1 (ED. 12-87) Page 450.
Blank Page
(Next Page is: 422)
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da. Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
TRANSMISSION LINE STATISTICS
1. Report information conceming transmission lines, cost of lin~s, 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.
LENG;hH role miles)Line (Indicate where Type of ~~t e as3of NumberNo.other than ergroun lines
60 cvcle 3 chase)Supporting report circuit miles)
From Operating Designed \Jh~tfl:lcrure qt~~ifwes CircuitsStructureof Line of ~ot er
(a)(b)(c)(e)Desi
(Wated
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.
=-
D""'~ S"b. Oregon 500.500.Steel Tower 58.
I 5!ii11
regOn 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-133.
Ben Lomond Sub., Utah Terminal Substation, UT 345.345.Steel-47.
Spanish Fork Sub.. Utah Camp Williams Sub., Utah 345.345.Steel - SP 35.
Huntington Plant, Utah Sigurd Substation, Utah 345.345 . 00 Steel-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 . 00 Steel - H 75.
Sigurd Substation, Utah Camp Williams Sub., Utah 345.345.Steel - H-116.
Camp Williams Sub., Utah Ninety South Sub., Utah 345.345.Steel - SP 11.
Terminal Substation, UT Camp Williams Sub., Utah 345.345.Steel - D 26.
Emery Substation, Utah Camp Williams Sub., Utah 345.345.Steel-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, 10 345.345.Steel-41.
Huntington Plant, Utah Four Comers Sub., NM 345.345 . 00 Wood . U 101.00
Camp Williams Sub., Utah Huntington Plant, Utah 345.345.Wood - U 107.
Huntington Plant, Utah Pinto Substation, Utah 345.345.Wood - U 160.
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, 10 345.345.Steel Tower 234.
Currant Creek Swtchrd, UT Mona Substation, UT 345.345.Steel- SP
Subtotal 345 kV 898.
Fairview, Oregon Isthmus, Oregon 230.230.H Frame Wood 12.
Antelope Sub., Idaho Lost River 230kV Line, 10 230.230.Wood - H 20.
TOTAL 15.532.108.198
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This R~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. R~port 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. fumish 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 bome 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.
vu;:,t ur- LINt: llncluae In 1,,;0lumn 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)
1852 134 35E 551,984 686,340
272.086,40(151 378.520 154,464.920
272.907 17e 38,019,061 40.926.236
272.468.19.597 617 065,821
272.23C 460.186 469.416
272.769,431:26,255,866 025 301
12,374,8OC 242.263.234 254 638,034
54.229,212,493 442 146
272.0 380,571 22.112,724 493.302
272.508.40~10.158,595 15,667 004
954.343.20,080,786 20.423,960
954.791 811 670.321 18.462 132
272.557,855 457.557 10,015,412
954.296.57E 13,619,157 13,915.735
954.510.49C 19,806,026 20.316,516
272.482,86E 895,713 378 579
272.308,970,336 278,733
954.926,251 27.916.136 842.387
954.320,87~50,650,316 52.971,188
~54.56,05C 13.573.405 13,629,455
1795.313,47i 571 824 885.301
~54.117 893,904 011 566
1795.893,96!19.802,873 20.696,838
1795.
1795.36,702.018 15,738.712
~272.128 22:288 416.868
272.099 053,106 29.152 902
183.901 183.901
36.302.8OC 346.619,837 382 922 637
54.285,32,612.109 897 431
95.12.92~200,282 213.211
83.904,197 548,174.411 632 078,608
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 2006/Q4
(2) CiA Resubmission 05/17/2007
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lin!,s. 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.
~~d1date where ~G;hH role Wiles)Line Type of 'd1t e ascTo Number
No.other than ergroun lines
60 cvcle 3 chase)Supporting report circuit miles)
Un ~tructure ~lru~h~res CircuitsFromOperatingDesignedStructureof Line of ~ot er
(a)(b)(c)(e)DeSi
tnated
Ine
(d)
(g)
(h)
1 Walla Walla, Washington Hells Canyon, 10 230.230.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 23O.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
9 Sigurd Substation, Utah Garfield, Utah 230.230.Wood - U 117.
Dixonville, Oregon Reston, Oregon 230.230.H Frame Wood 17.
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 230.230.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 - U 76.
Brady Substation, Idaho Treasureton Sub., Idaho 230.230.Wood - U 66.
Ben Lomond Sub., Utah Naughton PIt. #1, WY 230.230.Wood. U 88.
Sigurd Substation, Utah Arizona - Utah State line 230.230.Wood. U 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 - U 59.
Ben Lomond Sub., Utah Naughton PIt. #2, WY 230.230.Wood - U 29.
Chappel Creek, WY Naughton Plant, WY 230.230.Wood Tower 46.
Ben Lomond Sub., Utah Terminal Substation, UT 230.230.Steel - D-P 76.
Naughton Plant, Wyoming Treasureton Sub., Idaho 230.230.Wood - U 79.
Naughton Plant, Wyoming Treasureton Sub., Idaho 230.230.Wood - U
Swift Plant #1, WA Cowlitz Co. Line, W A 230.230.H Frame Wood
SwiftPlant#2,BPA Woodland, WA 230.230.H Frame Wood 23.
Union Gap, Washington BPA Midway, WA 230.230.H Frame Wood 39.
TOTAL 15,532.108.198
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This '(!prt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2oo6/Q4
(2) FiA Resubmission 05/17/2007
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines: 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. fumish 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.
I,,;U::; I v,
...........
\,nclude In 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)
(j)
(k)(I)(m)(n)
(p)
272.39~10,250408 314,802
272.351 98,890.221 242 203
272.485.89(409,365 895,261
~54.1,428 605.246 033,493
~54.423.037 423.037
~54.363.574 074 937 791
272.190.398,703 589.67C
1795.108.274 108,274
1795.390 660 343 051 221
39.971 558,410 598,381
95.
95.473,361:181 312 654.678
95.439.323,402 762,965
95.173,601:033,293 206,901
272.115,441:797251 912.699
54.191.12~203,472 394596
272.379 961 11.873,529 253,490
272.492 100 492.100
95.49!372,021 413.520
95.
272.464.779 2,469,882
95.72,111 125,675 197.793
95.426.121 551,502 977.628
~54.22.578.843 601,486
~54.165.051 299,642 464 696
~54.181 04,520,220 701 267
272.736,03(264 786 000.816
272.721 522 721,522
~54.170,900,151 071.118
272.572.45!10,170 327 10.742786
~54.56,491 059,195 115.693
~54.56!749 28.318
~54.29i 297 507 298.800
~54.103.53~276.752 380,284
~272.172,451 709,451 881 902
83,904 197 548 174,411 632.078.608
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This (!prt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da. Yr)End of 2006lQ4
(2) CIA Resubmission 05/17/2007
TRANSMISSION LINE STATISTICS
1. Report information conceming transmIssion lines. cost of lin~s, 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.
O~d1d:t~~~~~LENGJ.H ~Ie wiles)Line Type of 1.lot e Number
No.other than u dergroun lines
60 cvcle 3 chase)Supporting report circuit miles)
From
On ~tructure ~(ru~h~res CircuitsOperatingDesignedStructureof Line of ~ot erDesi
ffi'ated(a)(b)(c)(d)(e)
(g)
(h)
1 Walla Walla, Washington Lewiston, 10 230.230.H Frame Wood 45.
2 Walla Walla. Washington Wanapum, Washington 230.230.H Frame Wood 33.
3 Pomona, Washington Wanapum, Washington 23O.230.H Frame Wood 37.
4 Pomona, Washington Wanapum, Washington 230.230.H Frame Wood
5 Meridian Sub, OR Lone Pine Sub, OR 23O.230.Steel- DC
6 Meridian Sub, OR Lone Pine Sub. OR 230.230.Steel- DC
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 12.
Dave Johnston Plant, WY Casper, Wyoming 230.230.H Frame Wood 31.
Yellowtail, Montana Casper, Wyoming 230.230.H Frame Wood 149.
Rock Springs, Wyoming Kemmerer, Wyoming 230.230.H Frame Wood 71.
Rock Springs, Wyoming Atlantic City, Wyoming 230.230.H Frame Wood 69.
Thermopolis, Wyoming Riverton, Wyoming 230.230.H Frame Wood 51.
Casper, Wyoming Riverton, Wyoming 230.230.H Frame Wood 110.
Dave Johnston Plant, WY Rock Springs, Wyoming 230.230.H Frame Wood 209.
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 Une, WY 230.230.H Frame Wood 1.00
Jim Bridger Plant, WY Point of Rocks Ln 2, WY 230.230.H Frame Wood
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
Spence Sub., WY Jim Bridger Plant, WY 230.230.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. 00
Rock Springs, Wyoming Flaming Gorge. Utah 230.230.Steel Tower
TOTAL 15.532.108.198
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This (!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) nA Resubmission 05/17/2007
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. R~port 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, fumish 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 bome 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,,;u;:, I Ul'" LINE (InClUde In I,,;olumn 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)Ex~nses No.(i)(k)(I)(m)(n)
(p)
~272.366,29C 080.610 446,900
~54.235,53"243,720 479,252
~780.207, 12~664,144 871 267
~56.16~514 180 514,349
003.740 003,740
272.710,553,431 263.966
272.613,921,553 534 800
272.26,630.118 656,211
95.14,92!107 774 122,702
271.130,689,868 820.065
271.52.90!890,363 943,269
:154.31,85!985,190 017 049
272.101.264 158 376
54.67,971 338 039 195
272.58,10.11,354 142 11,412,244
272.33.00!!658.898 691 906
271.48,281 555.604 603,885
272.3O,76S 663264 694.03"
272.681 368 681 380
272.361,351 344,808 706,159
272.8OC 140,312 145 112
272.130,166 130,166
272.294 29C 158,100 452 396
272.15,463 15,463
272.441,494 445,461
272.872 981 872,981
272.160.129 160.129
272.
272.674.008 674 008
272.726.304 726.304
272.170,295 170.295
272.760.523 760,523
~272.542.996 542 996
~272.48.744 631 749.113
83,904.197 548,174 411 632.078.608
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This ~rt Is:Date of Report YeadPeriod m Report
PacifiCorp (1) An Original (Mo. Da, Yr)End of 2006/Q4(2) riA Resubmission 05/17/2007
TRANSMISSION LINE STATISTICS
1. Report information conceming transmission lines, cost of lin~s, 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.
(Indicate ~~'(J
LENG;hH ~Ie Wiles)Line Type of ~Io t e If 0 NumberNo.other than u dergroun lines
60 cvcle. 3 chase)Supporting report circuit miles)
From Operating Designed Un~rvcrure U~f~t!U~h~res CircuitsStructureof Line 0 "t'ot er
(a)(b)(c)(e)Desi
ffi'ated(d)
(g)
(h)
1 Line 59, CA Copco II, CA 230.230.H Frame Wood
2 Arizona/Utah State Une Glen Canyon Sub., Arizona 230.230.H Frame Wood 10.
3 Miners Sub., Wyoming Foote Creek Sub., Wyoming 230.230.Wood - H 29.
4 Monument Sub., Wyoming Craven Creek Sub., Wyoming 230.230.Wood - H 20.
5 Point of Rocks Sub., WY Rock Springs, Wyoming 230.230.Wood - H 27.
7 Subtotal 230 kV 314.
9 Montana-Idaho State line Grace Plant, Idaho 161.161.Wood - H 57.90.
Goshen Substation, Idaho Rigby Substation, Idaho 161.161.Wood. H 61.
Goshen Substation, Idaho Antelope Substation, 10 161.0(161.Wood - H 45.
Goshen Substation, Idaho Sugar Mill Substation, 10 161.0(161.00 Wood - SP 17.
Sugar Mill Sub., Idaho Rigby Substation, Idaho 161.161.00 Wood - SP 17.
Goshen Substation, Idaho Bonneville Sub., Idaho 161.OC 161.00 Wood - SP-23.
Billings, Montana Yellowtail, Montana 161.161.H Frame Wood 46.
Big Grassy Sub., 10 Idaho Power Line, 10 161.OC 161.00 Wood - H
Rigby Sub., Idaho Jefferson Roberts, Idaho 161.0C 161.Wood - SP 18.
Subtotal 161 kV 285.90.
Naughton Plant, Wyoming Evanston Substation, WY 138.138.Wood - H 67.
Evanston Substation, WY Anschutz Substation, WY 138.138.Wood - H
Evanston Substation, WY Anschutz Substation, WY 138.138.Wood - H 15.
Naughton Plant, Wyoming Carter Creek Sub., WY 138.138.Wood - H 36.
Railroad Sub.. Wyoming Carter Creek Sub., WY 138.138.Wood - H 17.
Painter Substation, WY Natural Gas Sub., WY 138.138.Wood - H
Grace Plant, Idaho Termnl. Sub., UT (103-104)138.138.Steel-42.
Grace Point, 10 Termnl. Sub., UT (103-104)138.138.Wood - H 211.00
Grace Plant. Idaho Terminal Sub., UT (105)138.138.Wood - H 143.
Grace Plant, Idaho Soda Plant, Idaho 138.138.Wood - H
Oneida Plant, Idaho Ovid Substation. Idaho 138.138.Wood - H 23.
Antelope Substation, 10 Scoville Sub., Idaho 138.138.Wood - H
Soda Plant, Idaho Monsanto Sub., Idaho 138.138.Wood - H
Caribou Substation, 10 Grace Plant, Idaho 138.138.Wood - H 16.
Caribou Substation, 10 Becker Substation, Idaho 138.138.Wood - H
TOTAL 15.532.108.198
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This (!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4
(2) CiA Resubmission 05/17/2007
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. R~port 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)
B. 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. fumish 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 bome 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.
vV;:' I VI'" LINe llncluae In I,,;olumn U) 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)Ex~nses No.(i)
(j)
(k)(I)(m)(n)
(p)
33~820,071 824,410
451 363 451.363
972.560 972,560
548,527 548,527
939,085 939.085
13,472 011 253 819,344 267,291 355
97.18.971 580.814 599.792
397.27,809 13E 836 656
397.851 594,375 603 232
397.48,482.266 530.493
397.27.531:210.177 237 713
954.362,27~835,396 197 675
556.514 12f 580,456 094.584
556.26.208 26,208
556.76,3OE 242,793 319,099
083,831 13,361 621 15.445,452
1795.146.64!036,183,392
1795.129,13(480.663 609,793
1795.381 290.803 294 184
1795.41.411 577,595 619 006
95.72.622 822,615 895,237
95.12,424 278.836 291 260
95.765,18E 12,938.077 703.263
95.
50.132.96C 15.149,396 15.282.356
95.29C 157.293 160.583
336.555,487 560.304
97.141 390 538
97.551 295.691 298.246
95.18.28'421.185 439,469
~97.14.145,941 160.365
83,904.197 548 174,411 632 078,608
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) nA Resubmission 05/17/2007
TRANSMISSION LINE STATISTICS
1. Report information conceming transmission lines, cost of lin~s. 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.
~~d16ate where'~G;hH role Wiles)Line Type of ~t e as NumberNo.other than ergroun lines
60 cvcle 3 chase)Supporting report circuit miles)
From Operating Designed un ::structure ~lru~~res CircuitsStructureof Line o~oter
(a)(b)(c)(e)Desi
cwated(d)
(g)
(h)
1 Treasureton Sub., 10 Franklin Sub., Idaho 138.138.Wood. H &S 10.
2 Franklin Substation, 10 Smithfield Sub.. Utah 138.138.Wood . H 25.
3 Midvalley Substation, UT Thirty South Sub., UT 138.138.Wood - H
4 Angel Substation, UT Smith's UT 138.138.Wood. H
5 Terminal Substation, UT 30 South Switch Rack, UT 138.138.Steel-
6 Jordan, UT Terminal Substation, UT 138.138.Wood - H
7 Wheelon Substation, Utah American Falls Sub., UT 138.138.Wood - H 82.
8 Cutler Plant, UT Wheelon Substation, UT 138.138.Wood - H
9 Terminal Substation, UT Helper Substation, Utah 138.138.Wood - H 116.
Hale Plant, Utah Nebo Substation, Utah 138.138.00 Wood - H 54.
Carbon Plant. Utah Helper Substation, Utah 138.138.Wood - H
Terminal Substation, UT Tooele Substation, Utah 138.138.Wood - H 42.
Wheelon Substation, Utah Smithfield Sub., Utah 138.138.Wood - H 19.1.00
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 138.138.Wood - SP
Moab Substation, Utah Pinto Substation, Utah 138.138.Wood - H 68.
Pinto Substation. Utah Abajo, UT 138.138.Wood - H 45.
Carbon Plant, Utah Ashley Substation, Utah 138.138.Wood. H 92.
McClelland Sub., Utah Cottonwood Sub., Utah 138.138.Wood. SP
Ashley Substation, Utah Vemal Substation, Utah 138.138.Wood - H 12.
Sigurd Substation, Utah West Cedar Substation, UT 138.138.Wood - H 120.
Ben Lomond Sub., Utah EI Monte Substation, UT 138.138.Wood - H Sub 19.
Cottonwood Sub.. Utah Ninetieth South Sub. Utah 138.138.Wood - SP 11.00
Terminal Substation. UT Rowley Substation, Utah 138.138.Wood. H 56.
Huntington Plant, Utah McFadden Substation, UT 138.138.Wood - H
Ben Lomond Sub., Utah EI Monte Substation. UT 138.138.Wood - H 13.
Cottonwood Sub., Utah Silvercreek Sub., Utah 138.138.Wood - SP 37.
Ninetieth South Sub, Utah Taylorsville 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 10.
Nebo, UT Jerusalem, UT 138.138.Wood Tower 26.
Ben Lomond Sub., Utah Westem Zircon Sub., UT 138.138.Wood. H 14.
Tooele Substation, Utah Oquirrh Substation, Utah 138.138.Wood - SP 21.00
TOTAL 15,532.108.198
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da, Yr)End of 2oo6/Q4
(2) CiA Resubmission 05/17/2007
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. R~port 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. fumish 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 bome 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 G) to (I) on the book cost at end of year.
I,,;Ut; I ut" LINt: llncluae In I,,;Olumn 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)ExP6.nses No.(i)(k)(I)(m)(n)
(p)
r,95.101 540,783 579 884
~7.47,61~055,874 103.481
193.583 193,583
20,229 20,229
00.256,746 258.583
661 776,623 438.070
50.118.18(191 856 310.036
50.072 69,072
1250.45B,79~228,055 18,686,854
97.27,536,553 564.098
54.7BE 105,200 105,986
97.46(8,418.769 428,229
397.188,011 058,173 246,191
97.33,9B!791 316 825.284
95.345,365 124 710.960
272.427,08€237 424 664 510
95.5B,O3C 564,969 622 999
397.11S 996,509 036.624
j97.43.00.089,679 132.681
397.374 751,379 798.753
95.13,1,494,603 508 336
397.54E 272,179 277 725
397.52,28(491 764 544,044
95.18,831.635 850,480
95.549.2,230.643 779 707
795.222.28E 254.369 476,655
397.21X 238 882 239 147
95.901 012,417 037 318
397.177 82~120 552 298,376
r,95.17!468.266 473 444
r,95.56.75~925,859 982.618
1795.243.44!539,061 782,506
~97.253,53!201,496 455.035
~50.96,45 968,212 064 669
1795.252.891 057,617 310,508
83,904.197 548,174,411 632 078.608
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2006/04(2) DA Resubmission 05/17/2007
TRANSMISSION LINE STATISTICS
1. Report information concemlng transmission lines, cost of lin~s, 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.
Line IIVI'!
(Indicate w~~;'J LENG;hH role miles)Type of
i.1g t e ascf of NumberNo.other than ergroun lines
60 cycle 3 phase)Supporting report circuit miles)
From Operating Designed I un titf1,lcture ::j,tru~lwes CircuitsStructureof Line of 'rot er
(a)(b)(c)(e)Desi
(Wated
Ine
(d)
(g)
(h)
1 Wheelon Substation, Utah Nucor Steel Sub., Utah 138.138.Wood. H 14.
2 Nebo Substation, Utah Martin-Marietta Sub., UT 138.138.Wood - H 30.
3 West Cedar Sub., Utah Middleton Substation., UT 138.138.Wood - H 69.
4 Gadsby Plant, Utah Terminal Substation, UT 138.138.Wood - H
5 Oquirrh Substation, Utah Kennecott Sub., Utah 138.138.Wood-
6 Oquirrh Substation, Utah Bamey Substation, Utah 138.138.Wood - HS
7 West Cedar Sub., Utah Pepcon Substation, Utah 138.138.Wood - SP 13.
8 Taylorsville Substation,Mid-Valley Substation, UT 138.138.Steel- SP
9 Warren Substation, Utah Kimberly Clark Sub., UT 138.138.Wood - HP 1.00
Honeyville, Utah Promontory, Utah 138.138.Wood Tower 22.
Ninetieth South Sub, Utah Hale Plant, Utah 138.138.Wood Tower 47.
Dumas, UT Bimple, UT 138.138.Wood Tower
Columbia Sub, Utah Sunnyside Co. Gen., Utah 138.138.Wood Tower
Syracuse Sub, Utah Ben Lomond Sub, Utah 138.138.Steel- D-P 25.
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, UT 138.138.Steel Tower 1.00
Panther, UT Willow Creek, UT 138.138.Wood Tower 1.00
Hammer Substation, UT Butlerville Substation, UT 138.138.Wood Tower
Midway Substation, UT Silver Creek Sub, UT 138.138.Wood Tower 14.
Midway Substation, UT Cottonwood Sub, UT 138.138.Wood Tower 10.
McFadden Substation, UT Blackhawk Substation, UT 138.138.Wood - H 11.
West Valley Sub., UT Keams Substation, UT 138.138.Wood. SP
Syracuse Substation, UT Clearfield South Sub., UT 138.138.Wood - SP
Farmington Substation, UT Parrish Substation, UT 138.138.Steel- DC
Midvalley Substation, UT Cottonwood Substation, UT 138.138.Wood - DC
Taylorsville Substation West Valley Substation, UT 138.138.Steel - DC
Subtotal 138 kV 080.12.
All 115 kV lines 115.115.Wood & Steel 545.
All 69 kV lines 69.69.Wood & Steel 968.1.00
All 57 kV lines 57.57.Wood & Steel 113.
TOTAL 15,532.108.198
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2006/Q4(2) nA Resubmission 05/17/2007
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Rl!!port 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 bome 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.
I,,;Uti I Ul- LINt: \lnCIUae In \,;Olumn 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)(k)(I)(m)(n)
(p)
1795.46,909.120 956.067
~7.66,797 202 863.654
~97.25,141 106,8OC 132,008
272.668,771 810 473 479,244
1795.223,996 223.996
1795.661!455.106 471 774
1795.59C 088,222 131 812
~272.33,46€500,072 533,538
~7.72.141,422 156,144
~97.475,68.874,162 349,844
~97.146.42E 372 182 518.60t
~97.136,585 136.585
~97.-41
~272.353,104 353,104
~97.246 938.520 185.023
~272.078.958 078.974
272.75~381.900 382 655
95.90.674 674
97.890 40,890
188,391 364,795 553,186
755,012 755,012
690,02!581 573 271.598
747,452 747.452
268 234 268.234
677 376 677,376
893.886 893 886
655,525 655,525
002 9BC 002.980
507,181 194.801 189,701 960
510.355 120 523,978 124,034,333
257 34~204 079.532 207 336 875
234 127 254 168.488
83,904,197 548.174,411 632,078.608
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2006/04(2) nA Resubmission 05/17/2007
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lin~s, 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 ~U!.I ~ljt:J'SY)LENG~H ~ole wiles)Line (Indicate where Type of hiD t e seT 0 Number
No.other than u dergroun lines
60 cycle 3 nhase)Supporting report circuit miles)
From Operating I un ::;tructure ~(ru~h~res CircuitsDesignedStructureof Line o~oter
(a)(b)(c)(e)DeSi
fljated(d)
(g)
(h)
1 All 46 kV lines 46.46.Wood & Steel 613.
TOTAL 15.532.108.19B
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. R~port 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 bome 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.
vU;:' I ~, -...- ncluae In 1,,;0lumn 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)Ex~nses No.(i)(k)(I)(m)(n)
(p)
354.6&1 178,184.810 182 539,474
83.904,197 548.174.411 632,078.608
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 (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
!schedule Page: 422 Line No.Column:
The Alvey - Dixonville 500kV line is jointly owned by the respondent and the Bonneville Power Administration ("the BPA"
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%.
~chedule 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., 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
BPA42.0%.
IFERC 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 2006/Q4(2) nA Resubmission 05/17/2007
RANSMISSION LINES ADDED DURI \lG 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 LlnEJ IINlJ ~n7 "'T" Dr-i t't::H ::s I HUI,,; fUR
No.From
Le~gth
Type .1w~rage Present UltimateNumber perMilesMiles
(a)(b)(c)(d)(e)(f)
(g)
1 Ninetieth South Oquirrh Wood ObI. Ckt 18.
2 Middleton St. George Wood H Frame 15.
3 Geneva Hale Steel SP 15.
4 Timp TriCity Steel Obi Ckt 18.
5 Tri City Sunrise 11.06 Steel Obi Ckt 18.
6 Tri City Oquirrh 11.Steel Obi Ckt 18.
7 Orem Vineyard Tap UVSC Sub Wood SP 18.
8 Jim Bridger Dave Johnson Wood H Frame 14.
9 Buffalo Casper Wood H Frame 14.
Harrision Lincoln UG Cable
TOTAL 37.148.
FERC FORM NO.1 (REV. 12-03)Page 424
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2oo6/Q4(2) nA Resubmission 05/17/2007
TRAN MISSION LINES ADDED DURING YE AR (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.
JH::i Voltage LINE COST Line
Size Specification conf~uration Land and Poles, Towers Conductors Asset Total No.and pacing (Operating)Land Rights and Fixtures and Devices Retire. Costs
(h)(i)(k)(I)(m)(n)(0)
(p)
1020 MCM ACCCrrw Vertical/10'138 68.351 984.375 052 731
1272 MCM ACSR Horizon/14'138 120.80!169.388 290,197
1557MCM ACSR Vertical/10'138 266.001 266,008 532,016
1557 MCM ACSR Verticall12'138 582,931 896.387 11,479.325
1557 MCM ACSR Verticall12'138
1557 MCM ACSR Verticall12'138 976 976,973 953.946
397.5 MCM ACSR Verticall10'
1272 MCM ACSR Horizon/20'230 100.48!183 282 283762
1272 MCM ACSR Horizon/20'230 190.290,643 481 516
1000 KCmil NIA 115
17.306.767,056 39.073,493
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 (2)A Resubmission 05/17/2007 2006/04
FOOTNOTE DATA
ISchedule Page: 424
ully Reimbursed.
~chedule Page: 424
Fully Reimbursed.
Line No.Column:
Line No.Column:
IFERC FORM NO.1 (ED. 12-87) Page 450.
Blank Page
(Next Page is: 426)
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo. Da. Yr)End of 2oo6/Q4(2) DA Resubmission 05/17/2007
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)
Califomia
BELMONT DISTRIBUTION-UNATTEN 69.12.47
BIG SPRINGS DISTRIBUTION-UNATTEN 69.12.47
CANBY #2 DISTRIBUTION-UNATTEN 69.2.40
CASTELLA DISTRIBUTION-UNATTEN 69.
CLEAR LAKE DISTRIBUTION-UNATTEN .69.12.
CRESCENT CITY DISTRIBUTION-UNA TTEN 12.
DOG CREEK DISTRIBUTION-UNATTEN 69.2.40
DORRIS DISTRIBUTION-UNATTEN 69.12.47
FORT JONES DISTRIBUTION-UNATTEN 69.12.
GASQUET DISTRIBUTION-UNATTEN 115.12.47
GREENHORN DISTRIBUTION-UNATTEN 69.12.
HAMBURG DISTRIBUTION-UNATTEN 69.
HAPPY CAMP DISTRIBUTION-UNATTEN 69.12.47
HORNBROOK DISTRIBUTION-UNATTEN 69.12.
INTERNATIONAL PAPER DISTRIBUTION-UNA TTEN 69.2.40
LAKE EARL DISTRIBUTION-UNATTEN 69.12.
LITTLE SHASTA DISTRIBUTION-UNATTEN 69.
LUCERNE DISTRIBUTION-UNATTEN 69.12.
MACDOEL DISTRIBUTION-UNATTEN 69.20.
MCCLOUD DISTRIBUTION-UNATTEN 69.12.
MILLER REDWOOD DISTRIBUTION-UNATTEN 69.12.
MONTAGUE DISTRIBUTION-UNATTEN 69.12.
MOUNT SHASTA DISTRIBUTION-UNATTEN 69.12.
NEWELL DISTRIBUTION-UNATTEN 69.12.
NORTH DUNSMUIR DISTRIBUTION-UNATTEN 69.12.
NORTHCREST DISTRIBUTION-UNATTEN 69.12.
NUTGLADE DISTRIBUTION-UNATTEN 69.2.40
PATRICKS CREEK DISTRIBUTION-UNATTEN 115.
PEREZ DISTRIBUTION-UNATTEN 69.12.
REDWOOD DISTRI BUTION-UNA TTEN 69.12.
SCOTT BAR DISTRIBUTION-UNATTEN 69.12.
SEIAD DISTRIBUTION-UNATTEN 69.12.
SHASTINA DISTRIBUTION-UNATTEN 69.20.
SHOTGUN CREEK DISTRIBUTION-UNATTEN 69.12.
SIMONSON DISTRIBUTION-UNATTEN 69.12.47
SMITH RIVER DISTRIBUTION-UNATTEN 69.12.
SNOW BRUSH DISTRIBUTION-UNATTEN 69.
SOUTH DUNSMUIR DISTRIBUTION-UNATTEN 69.
TULELAKE DISTRIBUTION-UNATTEN 69.12.47
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 2006/Q4
(2) riA Resubmission 05/17/2007
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 sale 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)
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 2006/Q4
(2) riA Resubmission 05/17/2007
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)
TUNNEL DISTRIBUTION-UNATTEN 69.12.
TURKEY HILL DISTRIBUTION-UNA TTEN 69.12.47
WALKER BRYAN DISTRIBUTION-UNA TTEN 69.12.
WEED DISTRIBUTION-UNATTEN 69.12.47
YUBA DISTRIBUTION-UNATTEN 69.12.
YUROK DISTRIBUTION-UNA TTEN 69.12.47
Total 3140.484.
NUMBER OF SUBSTATIONS UNATTENDED - 45
AL TURAS T/D-UNATTENDED 115.12.69.
FALL CREEK HYDRO/T/D-UNATTENDED 69.
YREKA T/D-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-UNATTEN 115.69.
DEL NORTE TRANSMISSION-UNA TTEN 115.69.
IRON GATE HYDRO PLANT TRANSMISSION-UNATTEN 69.
WEED JUNCTION TRANSMISSION-UNATTEN 115.69.
Total 414.213.
NUMBER OF SUBSTATIONS TRANS UNATTENDED - 4
Idaho
ALEXANDER DISTRIBUTION-UNA TTEN 46.12.
AMMON DISTRIBUTION-UNATTEN 69.12.
ANDERSON DISTRIBUTION-UNA TTEN 69.12.
ARCO DISTRIBUTION-UNA TTEN 69.12.47
ARIMO DISTRIBUTION-UNATTEN 46.12.47
BANCROFT DISTRIBUTION-UNATTEN 46.12.
BELSON DISTRIBUTION-UNATTEN 69.12.
BERENICE DISTRIBUTION-UNATTEN 69.12.
CAMAS DISTRIBUTION-UNATTEN 69.12.
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 (Me, Qa, Yr)End of 2oo6/Q4(2) DA Resubmission 05/17/2007
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 LineTransformersSpare(In Service) (In MVa)In Service Transformers Type of Equipment Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)(i)(k)
332 113
129
125
220
150
226
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 2006/Q4(2) riA Resubmission 05/17/2007
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)
CANYON CREEK DISTRIBUTION-UNATTEN 69.24.
CHESTERFIELD DISTRIBUTION-UNATTEN 46.12.
CLEMENT DISTRIBUTION-UNATTEN 69.12.
CLIFTON DISTRIBUTION-UNATTEN 46.12.
DOWNEY DISTRIBUTION-UNATTEN 46.12.
DUBOIS DISTRIBUTION-UNATTEN 69.12.
EASTMONT DISTRIBUTION-UNATTEN 69.12.
EGIN DISTRIBUTION-UNATTEN 69.12.
EIGHT MILE DISTRIBUTION-UNATTEN 46 . Q(J 12.47
GEORGETOWN DISTRIBUTION-UNA TTEN 69.12.
GRACE CITY STATION DISTRIBUTION-UNATTEN 46.12.
HAMER DISTRIBUTION-UNATTEN 69.12.
HAYES DISTRIBUTION-UNATTEN 69.12.47
HENRY DISTRIBUTION-UNATTEN 46.12.
HOLBROOD DISTRIBUTION-UNATTEN 69.12.
HOOPES DISTRIBUTION-UNATTEN 69.12.
HORSLEY DISTRIBUTION-UNATTEN 46.12.47
IDAHO FALLS DISTRIBUTION-UNATTEN 46.12.
INDIAN CREEK DISTRIBUTION-UNATTEN 69.12.
JEFFCO DISTRIBUTION-UNATTEN 69.24.
KETTLE DISTRIBUTION-UNATTEN 69.24.
LAVA DISTRIBUTION-UNATTEN 46.12.
LEWISTON DISTRIBUTION-UNATTEN 46.12.
LOGAN CANYON DISTRIBUTION-UNATTEN 46.
LUND DISTRIBUTION-UNATTEN 46.12.47
MCCAMMON DISTRIBUTION-UNATTEN 46.12.
MENAN DISTRIBUTION-UNATTEN 69.12.47
MERRILL DISTRIBUTION-UNATTEN 69.12.
MILLER DISTRIBUTION-UNATTEN 69.12.
MILLVILLE DISTRIBUTION-UNATTEN 46.12.47
MONTPELIER DISTRIBUTION-UNATTEN 69.12.
MOODY DISTRIBUTION-UNATTEN 69.24.
NEWDALE DISTRIBUTION-UNATTEN 69.12.
NEWTON DISTRIBUTION-UNATTEN 46.12.
NIBLEY DISTRIBUTION-UNATTEN 46.24.
NORTH LOGAN DISTRIBUTION-UNATTEN 46.12.47
OSGOOD DISTRIBUTION-UNATTEN 69.12.47
PRESTON DISTRIBUTION-UNATTEN 46.12.47
RANDOLPH DISTRIBUTION-UNATTEN 46.12.
RAYMOND DISTRIBUTION-UNATTEN 69.12.47
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 2006/Q4
(2) CiA Resubmission 05/17/2007
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)
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 2oo6/Q4(2) DA Resubmission 05/17/2007
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)
RENO DISTRIBUTION-UNATTEN 69.12.
REXBURG DISTRIBUTION-UNATTEN 69.12.
RICH DISTRIBUTION-UNATTEN 69.12.
RICHMOND DISTRIBUTION-UNA TTEN 46.12.
RIRIE DISTRIBUTION-UNATTEN 69.12.47
ROBERTS DISTRIBUTION-UNATTEN 69.12.
RUDY DISTRIBUTION-UNATTEN 69.12.
SAND CREEK DISTRIBUTION-UNA TTEN 69.12.
SANDUNE DISTRIBUTION-UNA TTEN 69.24.
SHELLEY DISTRIBUTION-UNATTEN 46.12.
SMITH DISTRIBUTION-UNATTEN 69.12.
SODA DISTRIBUTION-UNATTEN 138.
SOUTH FORK DISTRIBUTION-UNATTEN 69.12.
SPUD DISTRIBUTION-UNA TTEN 46.12.47
ST. CHARLES DISTRIBUTION-UNA TTEN 69.12.
SUGAR CITY DISTRIBUTION-UNATTEN 69.12.
SUNNYDELL DISTRIBUTION-UNA TTEN 69.12.47
TANNER DISTRIBUTION-UNATTEN 46.12.
TARGHEE DISTRIBUTION-UNATTEN 46.12.47
THORNTON DISTRIBUTION-UNATTEN 69.12.
UCON DISTRIBUTION-UNATTEN 69.12.
WATKINS DISTRIBUTION-UNATTEN 69.12.
WEBSTER DISTRIBUTION-UNATTEN 69.12.
WESTON DISTRIBUTION-UNATTEN 46.12.47
WINDSPER DISTRIBUTION-UNA TTEN 69.24.
Total 4531.999.
NUMBER OF SUBSTATIONS DIST UNATTENDED - 74
MALAD T/D-UNATTENDED 138.46.12.47
MUD LAKE T/D-UNATTENDED 69.12.
RIGBY T/D-UNATTENDED 161.12.69.
SAINT ANTHONY T/D-UNATTENDED 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-UNATTEN 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 2006/Q4(2) nA Resubmission 05/17/2007
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)
(j)
(k)
834
189
314
115
115
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This R~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da. Yr)End of 2oo6/Q4(2) riA Resubmission 05/17/2007
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)
ANTELOPE TRANSMISSION-UNATTEN 230.161.
ASHTON PLANT TRANSMISSION-UNA TTEN 46.
BIG GRASSY TRANSMISSION-UNATTEN 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-UNATTEN 345.161.46.
GREEN CANYON TRANSMISSION-UNA TTEN 138.46.
JEFFERSON TRANSMISSION-UNATTEN 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 138.46.12.
SUGARMILL TRANSMISSION-UNA TTEN 161.46.69.
TREASURETON TRANSMISSION-UNATTEN 230.138.
Total 3105.1219.173.
NUMBER OF SUBSTATIONS TRANS UNATTENDED - 20
Oregon
26TH STREET DISTRIBUTION-UNATTEN 20.
35TH STREET DISTRIBUTION-UNATTEN 20.
AGNESS AVE DISTRIBUTION-UNATTEN 115.12.
ALDERWOOD DISTRIBUTION-UNATTEN 69.12.
ARLINGTON DISTRIBUTION-UNATTEN 69.12.47
ATHENA DISTRIBUTION-UNA TTEN 69.12.
BANDON TIE DISTRIBUTION-UNATTEN 20.12.
BEACON DISTRIBUTION-UNATTEN 69~12.
BEALL LANE DISTRIBUTION-UNATTEN 115.12.
BEATTY DISTRIBUTION-UNATTEN 69.12.
BELKNAP DISTRIBUTION-UNATTEN 69.12.47
BLALOCK DISTRIBUTION-UNATTEN 69.12.
BLOSS DISTRIBUTION-UNATTEN 115.12.
BLY DISTRIBUTION-UNATTEN 69.12.
BOISE CASCADE DISTRIBUTION-UNATTEN 69.11.
BONANZA DISTRIBUTION-UNATTEN 69.12.
BROOKHURST 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 2006/Q4
(2) CiA Resubmission 05/17/2007
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 sale 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 LineTransformersSpare(In Service) (In MVa)In Service Transformers Type of Equipment Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)(i)(k)
250
763
233
168
533
2678
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 2oo6/Q4
(2) riA Resubmission 05/17/2007
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)
1 BROOKS-SCANLON DISTRIBUTION-UNATTEN 69.12.47
BROWNSVILLE DISTRIBUTION-UNATTEN 69.20.
BRYANT DISTRIBUTION-UNATTEN 69.12.
BUCHANAN DISTRIBUTION-UNA TTEN 115.20.
BUCKAROO DISTRIBUTION-UNATTEN 69.12.
CAMPBELL DISTRIBUTION-UNATTEN 115.12.47
CANNON BEACH DISTRIBUTION-UNA TTEN 115.12.
CARNES DISTRIBUTION-UNATTEN 69.12.
9 CASEBEER DISTRIBUTION-UNATTEN 69.20.
CAVEMAN DISTRIBUTION-UNA TTEN 115.12.
CHERRY LANE DISTRIBUTION-UNATTEN 69.12.
CHILOQUIN MARKET DISTRIBUTION-UNATTEN 69.12.
CHINA HAT DISTRIBUTION-UNA TTEN 69.12.
CIRCLE BLVD DISTRIBUTION-UNATTEN 115.20.
CLEVELAND AVE DISTRIBUTION-UNATTEN 69.12.
CLINE FALLS HYDRO DISTRIBUTION-UNATTEN 12.
CLOAKE DISTRIBUTION-UNA TTEN 69.20.
COBURG DISTRIBUTION-UNATTEN 69.20.
COLISEUM DISTRIBUTION-UNATTEN 20.
COLUMBIA DSITRIBUTION-UNATTEN 115.12.57.
COOS RIVER DISTRIBUTION-UNATTEN 115.20.
COQUILLE DISTRIBUTION-UNATTEN 115.20.
CREEK DISTRIBUTION-UNA TTEN 69.34.
CROOKED RIVER RANCH DISTRIBUTION-UNATTEN 69.20.
CROWFOOT DISTRIBUTION-UNATTEN 115.12.
CULLY DISTRIBUTION-UNATTEN 115.12.
CULVER DISTRIBUTION-UNATTEN 69.12.
CUTLER CITY DISTRIBUTION-UNATTEN 20.
DAIRY DISTRIBUTION-UNATTEN 69.12.
DALLAS DISTRIBUTION-UNATTEN 115.20.
DALREED DISTRIBUTION-UNATTEN 230.34.
DESCHUTES DISTRIBUTION-UNATTEN 69.12.
DEVILS LAKE DISTRIBUTION-UNATTEN 115.20.
DIXON DISTRIBUTION-UNATTEN 115.
DODGE BRIDGE DISTRIBUTION-UNATTEN 69.20.
EAST VALLEY DISTRIBUTION-UNATTEN 115.12.
EMPIRE DISTRIBUTION-UNATTEN 115.20.
ENTERPRISE DISTRIBUTION-UNATTEN 69.12.
FERN HILL DISTRIBUTION-UNATTEN 115.12.
FIELDER CREEK DISTRIBUTION-UNA TTEN 115.20.
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 2006/Q4(2) DA Resubmission 05/17/2007
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 LineTransformersSpare(In Service) (In MVa)In Service Transformers Type of Equipment Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)(i)
(j)
(k)
13 .
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 2006/Q4(2) riA Resubmission 05/17/2007
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)
1 FOOTHILLS DISTRIBUTION-UNATTEN 69.12.47
FRALEY DISTRIBUTION-UNATTEN 69.12.
GARDEN VALLEY DISTRIBUTION-UNATTEN 69.20.
GAZLEY DISTRIBUTION-UNATTEN 69.12.47
GEARHART DISTRIBUTION-UNATTEN 12.
GLENDALE DISTRIBUTION-UNATTEN 230.12.
GLENEDEN DISTRIBUTION-UNATTEN 20.
8 GLIDE DISTRIBUTION-UNATTEN 115.12.
9 GOLD HILL DISTRIBUTION-UNATTEN 69.12.
GORDON HOLLOW DISTRIBUTION-UNA TTEN 69.12.
GOSHEN DISTRIBUTION-UNA TTEN 115.20.
GRANT STREET DISTRIBUTION-UNATTEN 115~00 20.
GRASS VALLEY DISTRIBUTION-UNATTEN 20.
GREEN DISTRIBUTION-UNATTEN 69.12.
GRIFFIN CREEK DISTRIBUTION-UNATTEN 115.12.
HAMAKER DISTRIBUTION-UNATTEN 69.12.
HARRISBURG DISTRIBUTION-UNA TTEN 69.20.
HENLEY DISTRIBUTION-UNATTEN 69.12.
HERMISTON DISTRIBUTION-UNATTEN 69.12.
HILLVIEW DISTRIBUTION-UNATTEN 115.20.
HINKLE DISTRIBUTION-UNATTEN 69.12.
HOLLADAY DISTRIBUTION-UNATTEN 115.12.
HOLLYWOOD DISTRIBUTION-UNATTEN 115.12.
HOOD RIVER DISTRIBUTION-UNA TTEN 69.12.
HORNET DISTRIBUTION-UNATTEN 69.12.
INDEPENDENCE DISTRIBUTION-UNATTEN 69.20.
JACKSONVILLE DISTRIBUTION-UNATTEN 115.12.69.
JEFFERSON DISTRIBUTION-UNA TTEN 69.20.
JEROME PRAIRIE DISTRIBUTION-UNATTEN 115.12.47
JORDAN POINT DISTRIBUTION-UNATTEN 115.12.
JOSEPH DISTRIBUTION-UNATTEN 20.12.
JUNCTION CITY DISTRIBUTION-UNATTEN 69.20.
KENWOOD DISTRIBUTION-UNATTEN 69.12.
KILLINGWORTH DISTRIBUTION-UNATTEN 69.12.
KNAPPA SVENSEN DISTRIBUTION-UNATTEN 115.12.
LAKEPORT DISTRIBUTION-UNATTEN 69.12.
LAKEVIEW DISTRIBUTION-UNATTEN 69.12.
LANCASTER DISTRIBUTION-UNATTEN 69.20.
LEBANON DISTRIBUTION-UNATTEN 115.20.
LINCOLN 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 2006/Q4
(2) CiA Resubmission 05/17/2007
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)
105
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 2006/04(2) riA Resubmission 05/17/2007
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)
LOCKHART DISTRIBUTION-UNATTEN 115.20.
LYONS DISTRIBUTION-UNATTEN 69.20.
MADRAS DISTRIBUTION-UNATTEN 69.12.
MALLORY DISTRIBUTION-UNATTEN 115.12.
MARYS RIVER DISTRIBUTION-UNATTEN 115.20.
MEDCO DISTRIBUTION-UNA TTEN 115.12.47
MEDFORD DISTRIBUTION-UNATTEN 69.12.
MERLIN DISTRIBUTION-UNATTEN 115.12.
MERRILL DISTRIBUTION-UNATTEN 69.12.
MINAM DISTRIBUTION-UNA TTEN 69.12.
MODOC DISTRIBUTION-UNATTEN 69.12.
MORO DISTRIBUTION-UNA TTEN 20.
MURDER CREEK DISTRIBUTION-UNATTEN 115.20.
MYRTLE CREEK DISTRIBUTION-UNATTEN 69.12.
MYRTLE POINT DISTRIBUTION-UNATTEN 115.20.
NELSCOTT DISTRIBUTION-UNATTEN 20.
NEW O'BRIEN DISTRIBUTION-UNATTEN 115.12.47
OAK KNOLL DISTRIBUTION-UNATTEN 115.12.
OAKLAND DISTRIBUTION-UNATTEN 115.12.
ORCHARD STREET DISTRIBUTION-UNATTEN 12.
OVERPASS DISTRIBUTION-UNATTEN 69.12.
PALLETTE DISTRIBUTION-UNATTEN 69.20.
PARK STREET DISTRIBUTION-UNATTEN 115.12.
PARKROSE DISTRIBUTION-UNATTEN 57.12.
PENDLETON DISTRIBUTION-UNATTEN 69.12.
PILOT ROCK DISTRIBUTION-UNATTEN 69.12.
POWELL BUTTE DISTRIBUTION-UNATTEN 115.12.
PRINEVILLE DISTRIBUTION-UNA TTEN 115.12.47
PROVOL T DISTRIBUTION-UNATTEN 69.12.
QUEEN AVE DISTRIBUTION-UNA TTEN 69.20.
RED BLANKET DISTRIBUTION-UNATTEN 69.
REDMOND DISTRIBUTION-UNATTEN 115.12.
RICH MANUFACTURING DISTRIBUTION-UNATTEN 57.12.47
RIDDLE DISTRIBUTION-UNATTEN 69.12.47
RIDDLE VENEER DISTRIBUTION-UNATTEN 69.12.
ROGUE RIVER DISTRIBUTION-UNATTEN 69.12.47
ROSEBURG DISTRIBUTION-UNATTEN 115.20.
ROSS AVE DISTRIBUTION-UNATTEN 69.12.
RUCH DISTRIBUTION-UNATTEN 69.12.
RUNNING Y DISTRIBUTION-UNA TTEN 69.20.
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 2006/Q4(2) DA Resubmission 05/17/2007
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 sale 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 ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo. Da, Yr)End of 2006/Q4
(2) FiA Resubmission 05/17/2007
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)
1 RUSSELLVILLE DISTRIBUTION-UNATTEN 115.12.47
SAGE ROAD DISTRIBUTION-UNATTEN 115.12.47
SCENIC DISTRIBUTION-UNATTEN 115.12.47 69.
SCIO DISTRIBUTION-UNA TTEN 69.12.
SEASIDE DISTRIBUTION-UNATTEN 115.12.
SELMA DISTRIBUTION-UNATTEN 115.12.
SHASTA WAY DISTRIBUTION-UNATTEN 12.47
SHEVLIN PARK DISTRIBUTION-UNA TTEN 69.12.
SIMTAG BOOSTER PUMP DISTRIBUTION-UNATTEN 34.
SOUTH DUNES DISTRIBUTION-UNATTEN 115lXJ 12.
SOUTHGATE DISTRIBUTION-UNA TTEN 69.20.
SPRAGUE RIVER DISTRIBUTION-UNA TTEN 69.12.47
STATE STREET DISTRIBUTION-UNATTEN 115.20.
STAYTON DISTRIBUTION-UNATTEN 69.12.
STEAMBOAT DISTRIBUTION-UNA TTEN 115.
STEVENS ROAD DISTRIBUTION-UNATTEN 115.20.
SUTHERLIN DISTRIBUTION-UNATTEN 115.12.
SWEET HOME DISTRIBUTION-UNATTEN 115.20.
TAKELMA DISTRIBUTION-UNATTEN 115.20.
TALENT DISTRIBUTION-UNATTEN 69.12.
TEXUM DISTRIBUTION-UNATTEN 69.12.
TILLER DISTRIBUTION-UNATTEN 115.12.
TOLO DISTRIBUTION-UNATTEN 69.12.47
UMAPINE DISTRIBUTION-UNATTEN 69.12.
UMATILLA DISTRIBUTION-UNATTEN 69.12.
US PLYWOOD DISTRIBUTION-UNATTEN 20.
VERNON DISTRIBUTION-UNATTEN 69.12.47
VILAS DISTRIBUTION-UNATTEN 115.12.
VILLAGE GREEN DISTRIBUTION-UNA TTEN 115.20.
VINE STREET DISTRIBUTION-UNATTEN 69.20.
WALLOWA DISTRIBUTION-UNATTEN 69.12.
WARM SPRINGS DISTRIBUTION-UNATTEN 69.20.
WARRENTON DISTRIBUTION-UNATTEN 115.12.
WASCO DISTRIBUTION-UNATTEN 20.
WECOMA BEACH DISTRIBUTION-UNATTEN 20.
WESTERN KRAFT DISTRIBUTION-UNATTEN 115.12.
WESTON DISTRIBUTION-UNATTEN 69.12.47
WESTSIDE HYDRO DISTRIBUTION-UNATTEN 69.12.
WEYERHAUSER DISTRIBUTION-UNATTEN 69.12.47
WHITE CITY 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 2006/Q4(2) riA Resubmission 05/17/2007
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 sale 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 LineTransformersSpareTotal Capacity No.(In Service) (In MVa)In Service Transformers Type of Equipment Number of Units
(h)
(In MVa)
(f)
(g)
(i)(k)
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 2006/Q4(2) riA Resubmission 05/17/2007
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)
1 WILLOW COVE DISTRIBUTION-UNATTEN 34.
WINSTON DISTRIBUTION-UNATTEN 69.12.47
YOUNGS BAY DISTRIBUTION-UNATTEN 115.12.
Total 14924.2460.195.
NUMBER OF SUBSTATIONS DIST UNATENDED - 180
ALBINA T/D-UNATTENDED 115.12.69.
APPLEGATE T/D-UNATTENDED 115.69.12.
ASHLAND T/D-UNATTENDED 115.69.12.
BEND PLANT T/D-UNATTENDED 69.12.47
CAVE JUNCTION T ID-UNA TTENDED 115.12.69.
HAZELWOOD T/D-UNATTENDED 115.69.12.
KNOTT T/D- UNATTENDED 115.12.47 57.
MILE HI T/D-UNATTENDED 115.69.12.
PILOT BUTTE T/D-UNATTENDED 230.69.12.
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 115.12.47
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.
TOKETEE HYDRO TRANSMISSION-ATTEND 115.
Total 1173.89.
NUMBER OF SUBSTATIONS TRANS ATTENDED -
BEND PLANT TRANSMISSION-UNATTEN
CALAPOOY A TRANSMISSION-UNATTEN 230.69.
CHILOQUIN TRANSMISSION-UNATTEN 230.115.69.
COLD SPRINGS TRANSMISSION-UNATTEN 230.69.
COVE TRANSMISSION-UNA TTEN 230.69.
DAYS CREEK TRANSMISSION-UNA TTEN 115.69.
DIAMOND HILL TRANSMISSION-UNATTEN 230.69.
DIXONVILLE 115/230 TRANSMISSION-UNATTEN 230.115.69.
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 2006/04
(2) riA Resubmission 05/17/2007
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)
(j)
(k)
4379 364
177
132
187
400
1238
343
119
344
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 2006/Q4(2) DA Resubmission 05/17/2007
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
(c)(d)(e).TRANSMISSION-UNATTEN 500.230.
2 EAGLE POINT HYDRO TRANSMISSION-UNATTEN 115.
3 EAST SIDE HYDRO TRANSMISSION-UNATTEN 46.12.47
4 FISH HOLE TRANSMISSION-UNA TTEN 115.69.
5 FRY TRANSMISSION-UNATTEN 230.115.
6 GRANTS PASS TRANSMISSION-UNATTEN 230.115.69.
7 GREEN SPRINGS PLANT TRANSMISSION-UNA TTEN 115.69.
8 HURRICANE TRANSMISSION-UNA TTEN 230.69.
9 ISTHMUS TRANSMISSION-UNA TTEN 230.115.
KENNEDY TRANSMISSION-UNA TTEN 69.57.
KLAMATH FALLS TRANSMISSION-UNATTEN 230.69.
LONE PINE TRANSMISSION-UNA TTEN 230.115.69.
TRANSMISSION-UNATTEN 500.230.14 MONPAC TRANSMISSION-UNATTEN 115.69.
PONDEROSA TRANSMISSION-UNATTEN 230.115.
POWERDALE PLANT TRANSMISSION-UNATTEN 69.
PROSPECT CENTRAL TRANSMISSION-UNA TTEN 115.69.
ROBERTS CREEK TRANSMISSION-UNATTEN 115.69.
SLIDE CREEK HYDRO TRANSMISSION-UNATTEN 115.
SODA SPRINGS HYDRO TRANSMISSION-UNATTEN 115.
TROUTDALE TRANSMISSION-UNATTEN 230.115.69.
TUCKER TRANSMISSION-UNA TTEN 115.69.
WALLOWA FALLS HYDRO TRANSMISSION-UNA TTEN 20.
Total 5578.2372.47 347.
NUMBER OF SUBSTATIONS TRANS UNATTEND - 31
Utah
106TH SOUTH DISTRIBUTION-UNATTEN 138.12.
118TH SOUTH DISTRIBUTION-UNATTEN 138.12.47
70TH SOUTH DISTRIBUTION-UNATTEN 138.12.
ALTAVIEW DISTRIBUTION-UNA TTEN 46.12.
AMALGA DISTRIBUTION-UNATTEN 46.12.47
AMERICAN FORK DISTRIBUTION-UNATTEN 138.12.
ARAGONITE DISTRIBUTION-UNATTEN 46.
AURORA DISTRIBUTION-UNATTEN 46.12.
BANGERTER DISTRIBUTION-UNATTEN 138.12.
BEAR RIVER DISTRIBUTION-UNATTEN 46.12.47
BENJAMIN DISTRIBUTION-UNATTEN 46.12.
BINGHAM DISTRIBUTION-UNATTEN 46.12.
BLUE CREEK DISTRIBUTION-UNATTEN 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 2oo6/Q4
(2) CiA Resubmission 05/17/2007
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 Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(0)(h)(i)
(j)
(k)
650
500
458
250
251
733
1300
250
500
100
6070
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 2006/04(2) nA Resubmission 05/17/2007
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)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 BLUFF DISTRIBUTION-UNA TTEN 69.12.
BLUFFDALE DISTRIBUTION-UNATTEN 46.12.
BOTHWELL DISTRIBUTION-UNATTEN 46.12.
BOX ELDER DISTRIBUTION-UNATTEN 46.12.47
BRIAN HEAD DISTRIBUTION-UNATTEN 46.12.
BRICKYARD DISTRIBUTION-UNA TTEN 46.12.
BRIGHTON DISTRIBUTION-UNATTEN 46.24.
8 BROOKLAWN DISTRIBUTION-UNATTEN 46.12.
BRUNSWICK DISTRIBUTION-UNATTEN 46.12.47
BURTON DISTRIBUTION-UNATTEN 34.12.
BUSH DISTRIBUTION-UNA TTEN 46.12.47
CANNON DISTRIBUTION-UNATTEN 46.12.
CANYONLANDS DISTRIBUTION-UNATTEN 69.12.
CAPITOL DISTRIBUTION-UNATTEN 46.12.
CARBIDE DISTRIBUTION-UNATTEN 46.
CARBONVILLE DISTRIBUTION-UNATTEN 46.12.47
CASTO SUBSTATION DISTRIBUTION-UNATTEN 46.12.47
CENTENNIAL DISTRIBUTION-UNATTEN 138.12.
CENTERVILLE DISTRIBUTION-UNATTEN 46.12.47
CENTRAL DISTRIBUTION-UNATTEN 46.12.
CHAPEL HILL DISTRIBUTION-UNATTEN 138.12.47
CHERRYWOOD DISTRIBUTION-UNATTEN 138.12.
CIRCLEVILLE DISTRIBUTION-UNA TTEN 69.12.
CLEAR CREEK DISTRIBUTION-UNA TTEN 46.12.47
CLEAR LAKE DISTRIBUTION-UNATTEN 46.12.
CLEARFIELD SOUTH DISTRIBUTION-UNATTEN 138.12.
CLEARFIELD DISTRIBUTION-UNA TTEN 46.12.
CLINTON DISTRIBUTION-UNATTEN 138.12.47
CLIVE DISTRIBUTION-UNATTEN 46.12.
COALVILLE DISTRIBUTION-UNATTEN 46.12.47
COLD WATER CANYON DISTRIBUTION-UNATTEN 138.12.
COLEMAN DISTRIBUTION-UNATTEN 138.69.12.
COLTON WELL DISTRIBUTION-UNATTEN 46.12.47
CORINNE DISTRIBUTION-UNATTEN 46.12.
COVE FORT DISTRIBUTION-UNATTEN 46.12.
CRESCENT JUNCTION DISTRIBUTION-UNATTEN 46.
CROSS HOLLOW DISTRIBUTION-UNATTEN 138.12.
CUDAHY DISTRIBUTION-UNATTEN 138~12.
DAMMERON VALLEY DISTRIBUTION-UNATTEN 34.12.47
DECKER LAKE DISTRIBUTION-UNATTEN 138.12.
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 2006/Q4(2) DA Resubmission 05/17/2007
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)(0)(h)(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 (Me, Da, Yr)End of 2oo6/Q4
(2) CiA Resubmission 05/17/2007
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)
1 DELLE DISTRIBUTION-UNATTEN 46.12.
DELTA DISTRIBUTION-UNATTEN 46.12.
DESERET DISTRIBUTION-UNATTEN 46.
DEWEYVILLE DISTRIBUTION-UNATTEN 46.12.
5 DIMPLE DELL DISTRIBUTION-UNATTEN 138.12.
DIXIE DEER DISTRIBUTION-UNATTEN 34.12.
7 DRAPER DISTRIBUTION-UNATTEN 46.12.
8 DUMAS DISTRIBUTION-UNATTEN 138.12.47
9 EAST BENCH DISTRIBUTION-UNA TTEN 138.12.
EAST HYRUM DISTRIBUTION-UNA TTEN 46.12.
EAST LAYTON DISTRIBUTION-UNATTEN 138.12.
EAST MILLCREEK DISTRIBUTION-UNATTEN 46.12.47
EDEN DISTRIBUTION-UNATTEN 46.12.
ELBERTA DISTRIBUTION-UNATTEN 46.12.47
ELK MEADOWS DISTRIBUTION-UNATTEN 46.12.
ELSINORE DISTRIBUTION-UNATTEN 46.12.
EMERY CITY DISTRIBUTION-UNATTEN 69.12.47
EMIGRATION DISTRIBUTION-UNATTEN 46.12.
ENOCH DISTRIBUTION-UNA TTEN 138.12.47
ENTERPRISE VALLEY DISTRIBUTION-UNATTEN 138.12.
EUREKA DISTRIBUTION-UNATTEN 46.12.
FARMINGTON DISTRIBUTION-UNATTEN 138.12.
FAYETTE DISTRIBUTION-UNATTEN 46.12.
FERRON DISTRIBUTION-UNATTEN 46.12.
FIELDING DISTRIBUTION-UNATTEN 46.12.
FIFTH WEST DISTRIBUTION-UNATTEN 138.12.
FLUX DISTRIBUTION-UNATTEN 46.12.47
FOOL CREEK DISTRIBUTION-UNATTEN 46.12.47
FOUNTAIN GREEN DISTRIBUTION-UNATTEN 46.12.47
FREEDOM DISTRIBUTION-UNATTEN 46.
FRUIT HEIGHTS DISTRIBUTION-UNATTEN 46.12.
GATEWAY DISTRIBUTION-UNATTEN 69.12.
GORDON AVENUE DISTRIBUTION-UNATTEN 138.12.
GOSHEN DISTRIBUTION-UNATTEN 46.12.47
GRANGER DISTRIBUTION-UNATTEN 46.12.47
GRANTSVILLE DISTRIBUTION-UNATTEN 46.12.47
GREEN RIVER DISTRIBUTION-UNATTEN 46.12.
GROW DISTRIBUTION-UNATTEN 138.12.47 46.
GUNLOCK HYDRO DISTRIBUTION-UNATTEN 34.
GUNNISON DISTRIBUTION-UNA TTEN 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 2oo6/Q4(2) DA Resubmission 05/17/2007
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 LineTransformersSpareType of Equipment Total Capacity No.(In Service) (In MVa)In Service Transformers Number of Units
(In MVa)
(f)
(g)
(h)(i)
(j)
(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 2006/Q4(2) riA Resubmission 05/17/2007
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)
1 HAMILTON DISTRIBUTION-UNA TTEN 34.12.
2 HAMMER DISTRIBUTION-UNATTEN 138.12.
3 HAVASU DISTRIBUTION-UNATTEN 69.12.
HELPER CITY DISTRIBUTION-UNATTEN 46.
5 HENEFER DISTRIBUTION-UNATTEN 46.12.47
HIAWATHA DISTRIBUTION-UNATTEN 46.
7 HIGHLAND DIST DISTRIBUTION-UNATTEN 46.12.47
8 HOGGARD DISTRIBUTION-UNATTEN 138.12.
9 HOGLE DISTRIBUTION-UNATTEN 46.12.
HOLDEN DISTRIBUTION-UNATTEN 46.12.
HOLLADAY DISTRIBUTION-UNATTEN 46.12.47
HUNTER DISTRIBUTION-UNA TTEN 46.12.47
HUNTINGTON CITY DISTRIBUTION-UNATTEN 69.12.
HURRICANE FIELDS DISTRIBUTION-UNATTEN 34.12.47
IRON MOUNTAIN DISTRIBUTION-UNA TTEN 34.
IRON SPRINGS DISTRIBUTION-UNATTEN 34.12.47
IRONTON DISTRIBUTION-UNATTEN 46.12.
IVINS DISTRIBUTION-UNATTEN 34.12.47
JORDAN NARROWS DISTRIBUTION-UNATTEN 46.
JORDAN PARK DISTRIBUTION-UNATTEN 138.12.
JORDANELLE DISTRIBUTION-UNATTEN 138.12.
JUAB DISTRIBUTION-UNATTEN 46.12.47
JUNCTION DISTRIBUTION-UNATTEN 69.12.
KAIBAB DISTRIBUTION-UNATTEN 69.12.
KAMAS DISTRIBUTION-UNATTEN 46.12.
KANARRAVILLE DISTRIBUTION-UNATTEN 34.12.
KEARNS DISTRIBUTION-UNATTEN 138.12.
KENSINGTON DISTRIBUTION-UNATTEN 46.
LAKE PARK DISTRIBUTION-UNATTEN 138.12.
LARK DISTRIBUTION-UNATTEN 46.12.
LASAL DISTRIBUTION-UNATTEN 69.12.
LAYTON DISTRIBUTION-UNATTEN 46.12.47
LEGRANDE DISTRIBUTION-UNATTEN 46.12.
LINCOLN DISTRIBUTION-UNATTEN 46.12.
LINDON DISTRIBUTION-UNATTEN 46.12.
LISBON DISTRIBUTION-UNATTEN 69.12.
LITTLE MOUNTAIN DISTRIBUTION-UNATTEN 46.12.
LOAFER DISTRIBUTION-UNATTEN 46.12.
LONE TREE DISTRIBUTION-UNATTEN 34.12.
LOWER BEAVER DISTRIBUTION-UNATTEN 46.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
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)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006/04
(2) CiA Resubmission 05/17/2007
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).
Une 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 46.12.47
MAESER DISTRIBUTION-UNATTEN 69.12.
MAGNA DISTRIBUTION-UNATTEN 138.12.
MANILA DISTRIBUTION-UNATTEN 46.12.47
MANTUA DISTRIBUTION-UNATTEN 46.12.
MAPLETON DISTRIBUTION-UNATTEN 46.12.47
MARRIOTT DISTRIBUTION-UNATTEN 46.12.
MARYSVALE DISTRIBUTION-UNATTEN 46.12.47
MATHIS DISTRIBUTION-UNATTEN 46.12.47
MCCORNICK DISTRIBUTION-UNA TTEN 46.12.
MCKAY DISTRIBUTION-UNATTEN 46.12.
MEADOWBROOK DISTRIBUTION-UNATTEN 138.12.46.
MEDICAL DISTRIBUTION-UNA TTEN 46.12.47
MELLING DISTRIBUTION-UNATTEN 34.
MIDLAND DISTRIBUTION-UNATTEN 138.12.
MIDVALE DISTRIBUTION-UNA TTEN 46.12.
MILFORD DISTRIBUTION-UNATTEN 46.12.
MILFORD TV DISTRIBUTION-UNATTEN 46.
MINERSVILLE DISTRIBUTION-UNATTEN 46.12.
MOAB CITY DISTRIBUTION-UNATTEN 69.12.47
MONTEZUMA DISTRIBUTION-UNA TTEN 69.12.
MOORE DISTRIBUTION-UNATTEN 69.12.
MORGAN DISTRIBUTION-UNATTEN 46.
MORONI DISTRIBUTION-UNATTEN 46.12.
MORTON COURT DISTRIBUTION-UNATTEN 138.12.
MOUNTAIN DELL DISTRIBUTION-UNATTEN 46.12.
MOUNTAIN GREEN DISTRIBUTION-UNATTEN 46.12.
MYTON DISTRIBUTION-UNA TTEN 69.12.
NEW HARMONY DISTRIBUTION-UNATTEN 69.12.
NEWGATE DISTRIBUTION-UNATTEN 46.12.
NORTH BENCH DISTRIBUTION-UNATTEN 46.12.
NORTH CEDAR DISTRIBUTION-UNA TTEN 34.
NORTH FIELDS DISTRIBUTION-UNATTEN 46.12.
NORTH OGDEN DISTRIBUTION-UNATTEN 46.12.
NORTH SALT LAKE DISTRIBUTION-UNA TTEN 46.12.47
NORTHEAST DISTRIBUTION-UNATTEN 46.12.47
NORTHRIDGE DISTRIBUTION-UNATTEN 46.12.
OAKLAND AVE DISTRIBUTION-UNATTEN 46.12.
OAKLEY DISTRIBUTION-UNATTEN 46.12.
OGDEN DEFENSE DEPOT DISTRIBUTION-UNATTEN 46.12.47
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This R~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2006/04(2) OA Resubmission 05/17/2007
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)(0)(h)(i)
(j)
(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo. Da, Yr)End of 2006/04
(2) riA Resubmission 05/17/2007
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)
1 OLYMPUS DISTRIBUTION-UNATTEN 46.12.
OPHIR DISTRIBUTION-UNATTEN 46.12.
ORANGE DISTRIBUTION-UNATTEN 46.12.
ORANGEVILLE DISTRIBUTION-UNATTEN 69.12.
OREM DISTRIBUTION-UNATTEN 46.12.
OREMET DISTRIBUTION-UNATTEN 115.12.
PACK CREEK RESERVOIR DISTRIBUTION-UNATTEN 46.12.47
8 PANGUITCH DISTRIBUTION-UNATTEN 69.12.
9 PARlETTE STATION DISTRIBUTION-UNA TTEN 69.24.
PARK CITY DISTRIBUTION-UNATTEN 46.12.
PARKWAY DISTRIBUTION-UNATTEN 138.12.
PARLEYS DISTRIBUTION-UNATTEN 46.12.
PELICAN POINT DISTRIBUTION-UNATTEN 46.12.
PINE CANYON DISTRIBUTION-UNA TTEN 138.12.
PINE CREEK DISTRIBUTION-UNATTEN 46 . Q(J 12.
PINNACLE DISTRIBUTION-UNATTEN 46.12.
PLAIN CITY DISTRIBUTION-UNATTEN 138.12.47
PLEASANT GROVE DISTRIBUTION-UNATTEN 46.12.
PLEASANT VIEW DISTRIBUTION-UNATTEN 46.12.
PROMONTORY DISTRIBUTION-UNATTEN 46.12.
QUAIL CREEK DISTRIBUTION-UNATTEN 34.12.47
QUARRY DISTRIBUTION-UNATTEN 138.12.
QUITCHAPA DISTRIBUTION-UNATTEN 34.12.47
RAINS DISTRIBUTION-UNATTEN 46.
RASMUSON DISTRIBUTION-UNATTEN 46.12.
RATTLESNAKE DISTRIBUTION-UNATTEN 69.24.
RED MOUNTAIN DISTRIBUTION-UNATTEN 69.34.
RED ROCK DISTRIBUTION-UNATTEN 69.
REDWOOD DISTRIBUTION-UNATTEN 46.12.
RESEARCH PARK DISTRIBUTION-UNATTEN 46.12.
RICHFIELD DISTRIBUTION-UNATTEN 46.12.
RIDGELAND DISTRIBUTION-UNATTEN 138.12.
RITER DISTRIBUTION-UNA TTEN 46.12.
ROCK CANYON DISTRIBUTION-UNATTEN 69.12.
ROCKVILLE DISTRIBUTION-UNATTEN 34.12.47
ROCKY POINT DISTRIBUTION-UNATTEN 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 ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2oo6/Q4
(2) CiA Resubmission 05/17/2007
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)
(j)
(k)
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 2006/Q4(2) riA Resubmission 05/17/2007
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)
1 SARATOGA DISTRIBUTION-UNATTEN 138.12.47
SCIPIO DISTRIBUTION-UNATTEN 46.12.
SCOFIELD RESERVOIR DISTRIBUTION-UNATTEN 46.
SCOFIELD DISTRIBUTION-UNATTEN 46.12.
SECOND STREET DISTRIBUTION-UNATTEN 46.12.47
SEVEN MILE DISTRIBUTION-UNATTEN 46.12.
SHARON DISTRIBUTION-UNATTEN 46.12.
SHIVWITS DISTRIBUTION-UNATTEN 34.
9 SIXTH SOUTH DISTRIBUTION-UNATTEN 46.12.47
SKULL POINT DISTRIBUTION-UNATTEN 46.12.
SNARR DISTRIBUTION-UNATTEN 46.12.
SNOWVILLE DISTRIBUTION-UNATTEN 69.12.
SNYDERVILLE DISTRIBUTION-UNATTEN 138.12.
SOLDIER SUMMIT DISTRIBUTION-UNATTEN 69.12.
SOUTH JORDAN DISTRIBUTION-UNATTEN 138.12.
SOUTH MILFORD DISTRIBUTION-UNATTEN 46.12.
SOUTH MOUNTAIN DISTRIBUTION-UNATTEN 138.12.47
SOUTH OGDEN DISTRIBUTION-UNATTEN 46.12.
SOUTH PARK DISTRIBUTION-UNATTEN 46.12.
SOUTH WEBER DISTRIBUTION-UNATTEN 138.12.
SOUTH YARD DISTRIBUTION-UNATTEN 46.
SOUTHEAST DISTRIBUTION-UNATTEN 138.12.46.
SOUTHWEST DISTRIBUTION-UNATTEN 46.12.47
SPANISH VALLEY DISTRIBUTION-UNATTEN 69.12.
SPRINGDALE DISTRIBUTION-UNATTEN 34.12.
ST. JOHNS DISTRIBUTION-UNATTEN 46.12.
STAIRS DISTRIBUTION-UNATTEN 12.47
STANSBURY DISTRIBUTION-UNATTEN 46.12.
SUMMIT CREEK DISTRIBUTION-UNATTEN 138.12.
SUMMIT PARK DISTRIBUTION-UNATTEN 46.12.
SUNRISE DISTRIBUTION-UNA TTEN 138.12.47
SUPERIOR DISTRIBUTION-UNATTEN 69.12.
SUTHERLAND DISTRIBUTION-UNATTEN 46.12.47
TABIONA DISTRIBUTION-UNATTEN 69.12.
TAYLOR DISTRIBUTION-UNATTEN 46.12.
THIEF CREEK DISTRIBUTION-UNATTEN 138.24.
THIRD WEST DISTRIBUTION-UNATTEN 46.12.
THIRTEENTH SOUTH DISTRIBUTION-UNATTEN 46.12.
THOMPSON DISTRIBUTION-UNATTEN 46.
TOQUERVILLE DISTRIBUTION-UNATTEN 69.12.34.
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 2006/Q4
(2) (JA Resubmission 05/17/2007
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 sale 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
a~ected 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 ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2oo6/Q4(2) DA Resubmission 05/17/2007
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 MVaexcept 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)
TRI CITY DISTRIBUTION-UNATTEN 138.12.
TWENTYTHIRD STREET DISTRIBUTION-UNATTEN 46.12.
UINT AH DISTRIBUTION-UNATTEN 46.12.
UNION DISTRIBUTION-UNATTEN 46.12.
UNIVERSITY DISTRIBUTION-UNATTEN 46.
VALLEY CENTER DISTRIBUTION-UNATTEN 46.12.
VERMILLION DISTRIBUTION-UNATTEN 46.12.
VERNAL DISTRIBUTION-UNATTEN 69.12.
VEYO HYDRO DISTRIBUTION-UNA TTEN 34.
VICKERS DISTRIBUTION-UNATTEN 46.12.47
VINEYARD DISTRIBUTION-UNATTEN 46.12.
WALFARE DISTRIBUTION-UNA TTEN 46.12.
WALLSBURG DISTRIBUTION-UNATTEN 138.12.
WARREN DISTRIBUTION-UNATTEN 138.12.
WASATCH STATE PARK DISTRIBUTION-UNATTEN 46.12.
WASHAKIE DISTRIBUTION-UNATTEN 138.
WELBY DISTRIBUTION-UNATTEN 46.12.47
WELLINGTON DISTRIBUTION-UNATTEN 46.12.
WEST COMMERCIAL DISTRIBUTION-UNATTEN 46.12.
WEST JORDAN DISTRIBUTION-UNATTEN 138.12.
WEST OGDEN DISTRIBUTION-UNATTEN 138.12.
WEST ROY DISTRIBUTION-UNATTEN 46.12.
WEST TEMPLE DISTRIBUTION-UNATTEN 46.
WESTFIELD DISTRIBUTION-UNATTEN 138.12.
WESTWATER DISTRIBUTION-UNATTEN 69.12.
WHITE MESA DISTRIBUTION-UNATTEN 69.12.
WILLOWCREEK DISTRIBUTION-UNATTEN 46.12.
WILLOWRIDGE DISTRIBUTION-UNATTEN 46.12.
WINCHESTER HILLS DISTRIBUTION-UNATTEN 34.12.
WINKLEMAN DISTRIBUTION-UNATTEN 46.
WOLF CREEK DISTRIBUTION-UNATTEN 69.12.
WOOD CROSS DISTRIBUTION-UNATTEN 46.12.
WYUTA DISTRIBUTION-UNATTEN 46.12.
Total 19079.3476.184.
NUMBER OF SUBSTATIONS DIST UNATTENDED - 285
ANGEL T/D-UNATTENDED 138.12.46.
BUTLERVILLE T/D-UNATTENDED 138.46.12.47
COTTONWOOD T/D-UNATTENDED 138.12.46.
HALE T/D-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 2006/Q4
(2) riA Resubmission 05/17/2007
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 Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)
(g)
(h)(i)(k)
4983 419
135
175
289
114
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
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)
HIGHLAND T/D-UNATTENDED 138.12.46.
JORDAN T/D-UNATTENDED 138.46.12.
JUDGE T/D-UNATTENDED 46.12.
MCCLELLAND T/D-UNATTENDED 138.46.12.
OQUIRRH T/D-UNATTENDED 138.46.12.
PARRISH TID-UNATTENDED 138.12.46.
PIONEER PLANT T/D-UNATTENDED 138.46.
RIVERDALE TID-UNATTENDED 138.46.12.47
SEVIER T/D-UNATTENDED 138.46.12.47
SILVER CREEK T/D-UNATTENDED 138.12.46.
SPHINX TID-UNATTENDED 46.12.
SYRACUSE T/D-UNATTENDED 138.46.12.
TAYLORSVILLE TID-UNATTENDED 138.46.12.
TERMINAL T/D-UNATTENDED 345.12.46.
TIMP T/D-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 TID 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-UNATTEN 138.69.
ASHLEY TRANSMISSION-UNATTEN 138.46.
BARNEY TRANSMISSION-UNA TTEN 138.46.
BEN LOMOND TRANSMISSION-UNATTEN 345.230.138.
BLACKHAWK TRANSMISSION-UNATTEN 138.69.46.
BOOKCLIFFS TRANSMISSION-UNATTEN 69.46.
CAMERON TRANSMISSION-UNA TTEN 138.46.
CAMP WILLIAMS TRANSMISSION-UNATTEN 345.138.12.
CARBON TRANSMISSION-UNATTEN 46.
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 2006/Q4(2) DA Resubmission 05/17/2007
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 LineTransformersSpare(In Service) (In MVa)In Service Transformers Type of Equipment Number of Units Total Capacity No.
(In MVa)
(f)
(g)
(h)(i)
(j)
(k)
164
340
135
180
100
600
358
1108
130
158
4312
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
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo. Da. Yr)End of 2006/Q4(2) riA Resubmission 05/17/2007
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)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
COLUMBIA TRANSMISSION-UNATTEN 138.46.
CRICKET MOUNTAIN REG STA TRANSMISSION-UNATTEN 46.46.
CUTLER TRANSMISSION-UNA TTEN 138.46.
EL MONTE TRANSMISSION-UNATTEN 138.46.
GARKANE TRANSMISSION-UNATTEN 69.46.
GRINDING TRANSMISSION-UNATTEN 138.13.
HELPER TRANSMISSION-UNATTEN 138.46.
HONEYVILLE TRANSMISSION-UNATTEN 138.46.
HORSESHOE TRANSMISSION-UNATTEN 138.46.12.
HUNTINGTON TRANSMISSION-UNATTEN 345.138.69.
JERUSALEM TRANSMISSION-UNATTEN 138.46.
LAMPO TRANSMISSION-UNATTEN 138.46.
MCFADDEN TRANSMISSION-UNATTEN 138.46.
MIDDLETON TRANSMISSION-UNATTEN 138.69.34.
MIDVALLEY TRANSMISSION-UNA TTEN 345.138.
MIDWAY CITY TRANSMISSION-UNATTEN 138.46.
MINERAL PRODUCTS TRANSMISSION-UNATTEN 69.46.
MOAB TRANSMISSION-UNATTEN 138.69.
NEBO TRANSMISSION-UNATTEN 138.46.
OLMSTED TRANSMISSION-UNA TTEN 46.2.40
PAROW AN VALLEY TRANSMISSION-UNA TTEN 230.138.34.
PAVANT TRANSMISSION-UNATTEN 230.46.
PINTO TRANSMISSION-UNATTEN 345.138.69.
RED BUTTE TRANSMISSION-UNATTEN 230.138.
SAND COVE HYDRO TRANSMISSION-UNATTEN 34.
SIGURD TRANSMISSION-UNATTEN 345.230.138.
SPANISH FORK TRANSMISSION-UNA TTEN 345.138.46.
UPPER BEAVER HYDRO TRANSMISSION-UNATTEN 46.
WEBER PLANT TRANSMISSION-UNATTEN 46.
WEST CEDAR TRANSMISSION-UNATTEN 230.138.34.
Total 6773.2877.634 . 44
NUMBER OF SUBSTATIONS TRANS UNATTENDED - 40
Washington
ATTALIA DISTRIBUTION-UNATTEN 69.12.
BOWMAN DISTRIBUTION-UNATTEN 69.12.
CASCADE KRAFT DISTRIBUTION-UNATTEN 69.12.
CLINTON DISTRIBUTION-UNATTEN 115.12.
DAYTON DISTRIBUTION-UNATTEN 69.12.47
DODD ROAD DISTRIBUTION-UNATTEN 69.20.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Me, Da, Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
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)
(j)
(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 ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da. Yr)End of 2006/04
(2) CiA Resubmission 05/17/2007
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)
1 GRANDVIEW DISTRIBUTION-UNATTEN 115.12.47 69.
HOPLAND DISTRIBUTION-UNATTEN 115.12.47
MILL CREEK DISTRIBUTION-UNATTEN 69.12.
NACHES HYDRO DISTRIBUTION-UNATTEN 115.12.
NOB HILL DISTRIBUTION-UNATTEN 115.12.47
NORTH PARK DISTRIBUTION-UNATTEN 115.12.
7 ORCHARD DISTRIBUTION-UNATTEN 115.12.
8 PACIFIC DISTRIBUTION-UNATTEN 115.12.
9 POMEROY DISTRIBUTION-UNATTEN 69.12.
PROSPECT POINT DISTRIBUTION-UNATTEN 69.12.47
PUNKIN CENTER DISTRIBUTION-UNATTEN 115.12.
RIVER ROAD DISTRIBUTION-UNA TTEN 115.12.
SELAH DISTRIBUTION-UNATTEN 115.12.
SULPHUR CREEK DISTRIBUTION-UNATTEN 115.12.
SUNNYSIDE DISTRIBUTION-UNATTEN 115.12.
TIETON DISTRIBUTION-UNATTEN 115.12.34.
TOPPENISH DISTRIBUTION-UNATTEN 115.12.
TOUCHET DISTRIBUTION-UNATTEN 69.12.47
VOELKER DISTRIBUTION-UNATTEN 115.12.47
WAITSBURG DISTRIBUTION-UNATTEN 69.12.
WAPATO DISTRIBUTION-UNATTEN 115.12.
WENAS DISTRIBUTION-UNATTEN 115.12.47
WHITE SWAN DISTRIBUTION-UNATTEN 115.12.
WILEY DISTRIBUTION-UNATTEN 115.12.47
Total 2990.382.107.
NUMBER OF SUBSTATIONS DIST UNATTENDED - 30
CENTRAL T/D-UNATTENDED 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.
YALE PLANT TRANSMISSION-ATTEND 230.13.
Total 414.29.
NUMBER OF SUBSTATIONS TRANS ATTENDED - 3
OUTLOOK TRANSMISSION-UNATTEN 230.115.
PASCO TRANSMISSION-UNATTEN 115.69.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
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 Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)
(j)
(k)
1071
348
362
183
144
340
125
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 2006/Q4
(2) CiA Resubmission 05/17/2007
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)
POMONA HEIGHTS TRANSMISSION-UNATTEN 230.115.
SWIFT 1 PLANT TRANSMISSION-UNATTEN 230.13.
WALLA WALLA 230KV TRANSMISSION-UNATTEN 230.69.
WALLULA TRANSMISSION-UNATTEN 230.69.
Total 1265.450.
NUMBER OF SUBSTATIONS TRANS UNATTENDED - 6
Wyoming
AIR BASE DISTRIBUTION-UNATTEN 12.2.40
ANTELOPE MINE DISTRIBUTION-UNATTEN 230.34.
ASTLE STREET DISTRIBUTION-UNA TTEN 34.13.
BAILEY DOME DISTRIBUTION-UNATTEN 57.12.
BAR X DISTRIBUTION-UNATTEN 230.34.
BID MUDDY DISTRIBUTION-UNATTEN 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-UNATTEN 115.12.47
BUFFALO TOWN DISTRIBUTION-UNATTEN 20.
BYRON DISTRIBUTION-UNATTEN 34.
CASSA DISTRIBUTION-UNATTEN 57.20.
CENTER STREET DISTRIBUTION-UNATTEN 115.
CHAPMAN STATION DISTRIBUTION-UNATTEN 46.12.
CHATHAM DISTRIBUTION-UNATTEN 34.
CHUKAR DISTRIBUTION-UNA TTEN 12.
CHURCH AND DWIGHT DISTRIBUTION-UNATTEN 34.
COKEVILLE DISTRIBUTION-UNATTEN 46.24.
COLUMBIA-GENEVA DISTRIBUTION-UNATTEN 230.13.
COMMUNITY PARK DISTRIBUTION-UNATTEN 69.12.47
CROOKS GAP DISTRIBUTION-UNATTEN 34.12.47
DEER CREEK DISTRIBUTION-UNATTEN 69.12.
OJ COAL MINE DISTRIBUTION-UNA TTEN 69.34.
DOUGLAS DISTRIBUTION-UNATTEN 57.
DRY FORK DISTRIBUTION-UNATTEN 69.
ELK BASIN DISTRIBUTION-UNATTEN 34.
EMIGRANT DISTRIBUTION-UNATTEN 115.12.
EVANS DISTRIBUTION-UNATTEN 69.12.
EVANSTON DISTRIBUTION-UNATTEN 138.12.47
FARMERS UNION DISTRIBUTION-UNATTEN 34.
FIREHOLE DISTRIBUTION-UNA TTEN 230.34.
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 2006/Q4(2) DA Resubmission 05/17/2007
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)
(j)
(k)
300
261
300
120
1145
150
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da. Yr)End of 2006/Q4(2) riA Resubmission 05/17/2007
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)
1 FORT CASPER DISTRIBUTION-UNATTEN 69.12.47
2 FORT SANDERS DISTRIBUTION-UNATTEN 115.13.
3 FRANNIE DISTRIBUTION-UNATTEN 230.34.
4 FRONTIER DISTRIBUTION-UNATTEN 69.
5 GARDEN CITY DISTRIBUTION-UNATTEN 46.12.
6 GARLAND DISTRIBUTION-UNATTEN 230.34.
7 GLENDO DISTRIBUTION-UNATTEN 57.
8 GRASS CREEK DISTRIBUTION-UNATTEN 230.34.
9 GREAT DIVIDE DISTRIBUTION-UNATTEN 115.34.
GREYBULL DISTRIBUTION-UNATTEN 34.
HANNA DISTRIBUTION-UNA TTEN 34.12.
JACKALOPE DISTRIBUTION-UNATTEN 115.12.47
KEMMERER DISTRIBUTION-UNA TTEN 69.24.
KIRBY CREEK PUMPING STATION DISTRIBUTION-UNATTEN 34.
KIRBY CREEK DISTRIBUTION-UNATTEN 34.
LANDER DISTRIBUTION-UNA TTEN 34.12.
LARAMIE DISTRIBUTION-UNATTEN 115~OO 13.
LINCH DISTRIBUTION-UNATTEN 69.13.
LITTLE MOUNTAIN DISTRIBUTION-UNATTEN 230.34.
LOVELL DISTRIBUTION-UNATTEN 34.
MANDERSON DISTRIBUTION-UNATTEN 34.50
MILL IRON DISTRIBUTION-UNATTEN 34.13.
MILLS DISTRIBUTION-UNATTEN 12.47
MOSS JUNCTION DISTRIBUTION-UNATTEN 46.12.
MURPHY DOME DISTRIBUTION-UNATTEN 34.13.
NUGGETT DISTRIBUTION-UNATTEN 69.
OPAL DISTRIBUTION-UNA TTEN 46.24.
ORIN DISTRIBUTION-UNATTEN 57.12.
ORPHA DISTRIBUTION-UNATTEN 57.
PARCO DISTRIBUTION-UNATTEN 34.12.
PINEDALE DISTRIBUTION-UNATTEN 69.24.
PITCHFORK DISTRIBUTION-UNATTEN 69.24.
POINT OF ROCKS DISTRIBUTION-UNA TTEN 230.34.
POISON SPIDER DISTRIBUTION-UNATTEN 69.2.40
POLECAT DISTRIBUTION-UNA TTEN 34.12.
RAINBOW DISTRIBUTION-UNATTEN 34.13.
RAVEN DISTRIBUTION-UNATTEN 230.34.
RED BUTTE DISTRIBUTION-UNATTEN 69.12.
REFINERY DISTRIBUTION-UNATTEN 115.12.
SAGE HILL DISTRIBUTION-UNATTEN 34.13.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
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 sale 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)
200
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 2006/Q4
(2) CiA Resubmission 05/17/2007
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)
1 SHOSHONI DISTRIBUTION-UNATTEN 34.
SLATE CREEK DISTRIBUTION-UNA TTEN 69.12.
SOUTH CODY DISTRIBUTION-UNATTEN 69.24.
SOUTH ELK BASIN DISTRIBUTION-UNATTEN 34.
5 SOUTH TRONA DISTRIBUTION-UNATTEN 230.34.
6 SPRING CREEK DISTRIBUTION-UNATTEN 115.13.
7 SVILAR DISTRIBUTION-UNATTEN 34.
8 TEAPOT DISTRIBUTION-UNA TTEN 69.12.
9 TEN MILE DISTRIBUTION-UNATTEN 69.34.
THERMOPOLIS TOWN DISTRIBUTION-UNATTEN 34.
THUNDER CREEK DISTRIBUTION-UNA TTEN 57.12.
TIPTON FII DISTRIBUTION-UNATTEN 34.
VETERANS DISTRIBUTION-UNATTEN 34.13.
WELCH DISTRIBUTION-UNATTEN 57.
WEST ADAMS DISTRIBUTION-UNATTEN 34.
WESTERN CLAY DISTRIBUTION-UNATTEN 34.
WESTVACO DISTRIBUTION-UNATTEN 230.34.
WOODRUFF DISTRIBUTION-UNATTEN 46.12.
WORLAND TOWN DISTRIBUTION-UNATTEN 34.
WYOPO DISTRIBUTION-UNATTEN 230.34.
Total 7793J1 1360.13.
NUMBER OF SUBSTATIONS DIST UNATTENDED- 92
LABARGE T/D-UNATTENDED 69.24.
BUFFALO T/D-UNATTENDED 230.20.
HILLTOP TID-UNATTENDED 115.34.20.
RIVERTON 230 TID-UNATTENDED 230.12.47 34.
YELLOWCAKE TID-UNATTENDED 230.34.
Total 874.127.55.
NUMBER OF SUBSTATIONS T/D UNATTENDED - 5
DAVE JOHNSTON PLANT TRANSMISSION-ATTEND 230.115.69.
JIM BRIDGER 345KV TRANSMISSION-ATTEND 345.230.34.
JIM BRIDGER UNITS 1-4 TRANSMISSION-ATTEND 345.22.
NAUGHTON TRANSMISSION-ATTEND 230.69.
WYODAK 230KV TRANSMISSION-ATTEND 230.69.
WYODAK PLANT TRANSMISSION-ATTEND 230.22.
Total 1610.527.103.
NUMBER OF SUBSTATIONS TRANS ATTENDED - 6
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da. Yr)End of 2006/Q4(2) DA Resubmission 05/17/2007
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 sale 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)
150
1662 172
148
1358
1084
1122
1232
503
5359
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 2006/Q4(2)DA Resubmission 05/17/2007
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)
1 BAIROIL TRANSMISSION-UNATTEN 115.34.57.
2 CASPER TRANSMISSION-UNA TTEN 230.115.69.
3 CHAPPELL CREEK TRANSMISSION-UNATTEN 230.69.
FOOTE CREEK WIND FARM TRANSMISSION-UNATTEN 230.34.
5 GLENDO AUTO TRANSMISSION-UNATTEN 69.57.
6 MANSFACE TRANSMISSION-UNATTEN 230.34.
7 MIDWEST TRANSMISSION-UNA TTEN 230.69.34.
8 MINERS TRANSMISSION-UNA TTEN 230.115.34.
9 MUSTANG TRANSMISSION-UNATTEN 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-UNATTEN 230.34.
SAGE TRANSMISSION-UNATTEN 69.46.
THERMOPOLIS TRANSMISSION-UNA TTEN 230.115.
YELLOWTAIL TRANSMISSION-UNA TTEN 230.161.
Total 3243.1287.298.
NUMBER OF SUBSTATIONS TRANS UNATTENDED - 16
CALIFORNIA
Distribution - 45
TID - 3
Transmission - 9
IDAHO
Distribution - 74
T/D - 4
Transmission - 21
OREGON
Distribution - 180
TID - 10
Transmission - 41
UTAH
Distribution - 285
T/D - 21
Transmission - 47
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
'0ort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2006/Q4
(2) CiA Resubmission 05/17/2007
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 Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
517
196
200
115
165
400
175
100
2269
332 113
129
446
834
314
2793
4379 364
1238
6413 135
4983 419
4312
14259 132
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 2006/Q4(2) riA Resubmission 05/17/2007
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)
WASHINGTON
Distribution - 30
T/D - 2
Transmission - 9
WYOMING
Distribution - 92
TID - 5
Transmission - 22
ALL STATES
Distribution - 706
TID - 45
Transmission - 149
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 2006/Q4(2) riA Resubmission 05/1712007
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)
1071
362
1485
1662 172
148
7628 101
13261 1205
6503 152
33024 479
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 05/1712007 2006/04
FOOTNOTE DATA
~chedule Page: 426.10 Line No.Column:
The Dixonville 500kV Substation is jointly owned by the respondent and the Bonneville Power Administration ("the BPA"
Ownership of the substation is as follows: PacifiCorp 50., the BPA 50.0%. Operation and maintenance costs are shared between
the two arties and res onsibili is as follows: PacifiCo 58., and the BPA 42.0%.
chedule Pa e: 426.10 Line No.13 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 BPA 50.0%. Operation and maintenance costs are shared between the two
parties and responsibility is as follows: PacifiCorp 58., and the BP A 42.0%.
I FERC FORM NO.1 (ED. 12-87)Page 450.
INDEX
Schedule PaQe 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
work in progress
work in progress
Control
- common utility plant ..........................................................356
- electric ......................................................................216
- other utility departments ................................................. 200-201
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
PaQe 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 ................................................................................219
336-337
Directors ............................................................................................105
Discount - premium on long-term debt .............................................................256-257
Distribution of salaries and wages ...............................................................354-355
Dividend appropriations ..........................................................................118-119
Earnings, Retained ...............................................................................118-119
Electric energy account ..............................................................................401
Expenses
electric operation and maintenance ...........................................................320-323
electric operation and maintenance, summary ...................................................... 323
unamortized debt .................................................................................256
Extraordinary property losses ........................................................................230
Filing requirements, this report form
General information ..................................................................................101
Instructions for filing the FERC Form 1 ............................................................. i-
Generating plant statistics
hydroelectric (large) ........................................................................406-407
pumped storage (large) .......................................................................408-409
small plants .................................................................................410-411
steam-electric (large) .......................................................................402-403Hydro-electric generating plant statistics ....................................................... 406-407
Identification .......................................................................................101
Important changes during year ....................................................................108-109
Income
statement of, by departments .................................................................114-117
statement of , for the year (see also revenues) ............................................... 114-117
deductions, miscellaneous amortization ...........................................................340
deductions, other income deduction ...............................................................340
deductions, other interest charges ...............................................................340
Incorporation information ............................................................................101
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 ..................................................................
Long-term debt ...................................................................................256-257
Losses-Extraordinary property ........................................................................230
Materials and supplies ...............................................................................227
Miscellaneous general expenses .......................................................................335
Notes
to balance sheet .............................................................................122-123
to statement of changes in financial position ................................................ 122-123
to statement of income .......................................................................122-123
to statement of retained earnings ............................................................122-123
Nonutility property ..................................................................................221
Nuclear fuel materials ...........................................................................202-203
Nuclear generating plant, statistics .............................................................402-403
Officers and officers ' salaries ......................................................................104
Operating
expenses-electric
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 ....................................................................................253
miscellaneous paid-in capital ....................................................................253
reduction in par or stated value of capital stock ................................................ 253
regulatory assets ................................................................................232
regulatory liabilities ...........................................................................278
Peaks, monthly, and output ...........................................................................401
Plant, Common utility
accumulated provision for depreciation .............................,......,......,.......,.......356
acquisition adjustments ..........................................................................356
allocated to utility departments .................................................................356
completed construction not classified ............................................................356
construction work in progress ....................................................................356
expenses .........................................................................................356
held for future use .......-......................................................................356
in service .......................................................................................356
leased to others .................................................................................356
Plant data .........-.........................................................................336-337
401-429
FERC FORM NO.(ED. 12-95)Index
INDEX (continued)
Schedule
Plant - electric
Paqe No.
accumulated provision for depreciation ...........................................................219
construction work in progress ....................................................................216
held for future use ..............................................................................214
in service ...................................................................................204-207
leased to others .................................................................................213
Plant - utility and accumulated provisions for depreciation
amortization and depletion (summary) .............................................................201
Pollution control facilities. accumulated deferred
income taxes .....................................................................................234
Power Exchanges ........................................................................
..........
326-327
Premium and discount on long-term debt ...............................................................256
Premium on capital stock .............................................................................251
Prepaid taxes ....................................................................................262-263
Property - losses. extraordinary .....................................................................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 ......................................................................261
Regulatory commission expenses deferred ..............................................................233
Regulatory commission expenses for year ..........................................................350-351
Research, development and demonstration activities ............................................... 352-353
Retained Earnings
amortization reserve Federal .....................................................................119
appropriated .................................................................................118-119
statement of , for the year ...................................................................118-119
unappropriated ...............................................................................118-119
Revenues - electric operating ....................................................................300-301
Salaries and wages
directors fees ...................................................................................105
distribution of ..............................................................................354-355
officers' ........................................................................................104
Sales of electricity by rate schedules ...............................................................304
Sales - for resale ...............................................................................310-311
Salvage - nuclear fuel ...........................................................................202-203
Schedules, this report form ..........................................................................2-4
Securities
exchange registration ........................................................................250-251
Statement of Cash Flows ..........................................................................120-121
Statement of income for the year .................................................................114-117
Statement of retained earnings for the year ...................................................... 118-119Steam-electric generating plant statistics ....................................................... 402-403
Substations ..........................................................................................426
Supplies - materials and .............................................................................227
FERC FORM NO.1 (ED. 12-90)Index
INDEX (continued)
Schedule Paae 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
, -
;' c. '
Pacific Power
Rocky Mountain Power
825 NE Multnomah St,
Suite 2000
Portland, Oregon 97232
~~~ t~t~QI~J~
May 14, 2007 ,.. Ii
-- ,
Idaho Public Utilities Commission ; . I,t: .
o. Box 83720
Boise, Idaho 83720-0074
:y,
VIA OVERNIGHT DELIVERY
Attn: Jean D. Jewell
Commission Secretary
RE:Commission Annual Report 2006 and FERC Form
PacifiCorp (dba Rocky Mountain Power) submits for filing an original and seven (7)
conformed copies of the Idaho Public Utilities Commission Annual Report 2006.
The Federal Energy Regulatory Commission on April 2, 2007, extended the deadline for
filing the 2006 FERC Forms Nos. 1 and 1-F to May 18 2007 to accommodate software
changes made to implement Order No. 668. Upon filing with the FERC, a copy ofthe
FERC Form 1 will be provided.
It is respectfully requested that all formal correspondence and Staff requests regarding
this matter be addressed to:
By E-mail (preferred):datarequest~Pacifi Corp. com
By Fax:(503) 813 - 6060
By regular mail:Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
Informal inquires may be directed to Brian Dickman, Regulatory Manager at (801) 220-
4975.
~K,
~p-
Jeffrey K. Larsen
Vice President, Regulation
Enclosure
Page
Number
3 - 6
11 - 12
ANNUAL REPORT
IDAHO SUPPLEMENT TO FERC FORM 1
for
MULTI-STATE ELECTRIC COMPANIES
INDEX
Title
Statement of UtilityOperating 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)Page i
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) -.X An Original (Mo. Da . Yr)
dba Rocky Mountain Power (2) - A resubmission Dec. 31 2006
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)191 718 430 172,412 536
Operating Expenses
Operation Expenses (401)111 025.044 92,458.050
Maintenance Expenses (402)806,411 962 196
Depreciation Expenses (403)903,466 090 841
Amort. & Depl. Of Utility Plant (404-405)731 281 812 650
Amort. Of Utility Plant Acq. Adj (406)345 553 353 220
Amort. Of Property Losses. Unrecovered
Plant and Regulatory Study Costs (407)127 332 135 622
Amort. Of Conversion Expenses (407)
Taxes Other Than Income Taxes (408.4,713 059 587 834
Income Taxes - Federal (409.059 656 942 973
Other (409.1) 384 559 517.263
Provision for Deferred Inc. Taxes (410.22,423 945 678 000
Provision for Deferred Income Taxes - Cr. (411.(20 746 871)(16,867 961)
Investment Tax Credit Adj. - Net (411.4)(757 790)(780.533)
(Gains) from Disp. Of Utility Plant (411.
Losses from Disp. Of Utility Plant (411.874
(Gains) from emission allowances 028 006)084,797)
(Gains) Loss on sale of Utility plant 4,401 113)
TOTAL Utility Operating Expenses
(Enter Total of Lines thru 20)165 992 040 144 806 119
Net Utility Operating Income (Enter Total of
line less 21)726 390 606,417
IDAHO SUPPLEMENT Page 1
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Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) A resubmission Dec. 31. 2006
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 1,423 471 542,926
(501) Fuel 709 593 30.606.135
(502) Steam Expenses 026,498 228,581
(503) Steam from Other Sources 204 737 281 581
(Less) (504) Steam Transferred - Cr.
(505) Electric Expenses 259,442 255 892
(506) Miscellaneous Steam Power Expenses 927 056 109 273
(507) Rents 423 790
TOTAL Operation (Enter Total of lines 12 thru 19)624 220 081 778
Maintenance
(510) Maintenance Supervision and Engineering 468 058 466 785
(511) Maintenance of Structures 225 047 075 152
(512) Maintenance of Boiler Plant 677 023 673.055
(513) Maintenance of Electric Plant 046 959 989.167
(514) Maintenance of Miscellaneous Steam Plant 720 797 603.126
TOTAL Maintenance (Enter Total of lines 14 thru 18)137 884 807 285
TOTAL Power Production Expenses - Steam Power (Enter Total of lines 12 thru 19)762 104 889 063
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
l528) 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 469 765 286,787
(536) Water fo Power 233 030
(537) Hydraulic Expenses 291 951 282,144
(538) Electric Expenses 239 353
(539) Miscellaneous Hydraulic Power Generation Expenses 140 206 126.594
(540) Rents 968 11,315
TOTAL Operation (Enter Total of lines 43 thru 48)923 362 718 223
IDAHO SUPPLEMENTAL Page 3
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) - A resubmission Dec. 31, 2006
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 67,621 146
(543) Maintenance of Reservoirs, Dams, and Waterways 514 123,761
(544) Maintenance of Electric Plant 802 163 567
(545) Maintenance of Miscellaneous Hydraulic Plant 160 401 166 487
TOTAL Maintenance (Enter Total of lines 52 thru 56)378 338 523 961
TOTAL Power Production Expenses - Hydraulic Power (Enter Total of lines 49 thru 57 301 700 242 184
D. Other Power Generation
Operation
(546) Operation Supervision and Engineering 799 079
(547) Fuel 006 930 224 881
(548) Generation Expenses 823 058 687,796
(549) Miscellaneous Other Power Generation Expenses 184 830 011
(550) Rents 039 843 211 713
TOTAL Operation (Enter Total of lines 61 thru 65)128,460 260 480
Maintenance
(551) Maintenance Supervision and Engineering
(552) Maintenance of Structures 978 13.402
(553) Maintenance of Generation and Electric Plant 174 251 837
(554) Maintenance of Miscellaneous Other Power Generation Plant 943 109
TOTAL Maintenance (Enter Total of lines 68 thru 71)221 172 130 348
TOTAL Power Production Expenses - Other Power (Enter Total of lines 66 thru 72)349 632 390 828
E. Other Power Supply Expenses
(555) Purchased Power 258 182 16.243 052
(556) System Control and Load Dispatching 156 680 567
(557) Other Expenses (1)044 692 093.820
TOTAL Other Power Supply Expenses (Enter Total of lines 75 thru 77)29,459 554 18,430,439
TOTAL Power Production Expenses - (Enter Total of lines 20, 40, 58, 73 and 78)872 990 952 514
2. TRANSMISSION EXPENSES
Operation
(560) Operation Supervision and Engineering 489 289 416 253
(561) Load Dispatching 413 845 290 888
(562) Station Expenses 182 36.r05
(563) Overhead Line Expenses 146 315 141 091
(564) Underground Line Expenses
(565) Transmission of Electricity by Others 951 344 383 141
(566) Miscellaneous Transmission Expenses 209 12.353
(567) Rents 718 130 794
TOTAL Operation (Enter Total of lines 82 thru 89)164 902 411 231
Maintenance
(568) Maintenance Supervision and Engineering 247 753
(569) Maintenance of Structures 123 513
(570) Maintenance of Station Equipment 634 569 420 314
(571) Maintenance of Overhead Lines 681 901 553 604
(572) Maintenance of Underground Lines 425
(573) Maintenance of Miscellaneous Transmission Plant 624 654
TOTAL Maintenance (Enter Total of lines 92 thru 97)1.486 854 029 756
TOTAL Transmission Expenses (Enter Total of lines 90 and 98)651 756 7,440 987
100 3. DISTRIBUTION EXPENSES
101 Operation
102 (580) Operation Supervision and Engineering 098 834 070 777
103 (581) Load Dispatching 555 963 438.649
1) The Idaho amount in FERC account 557 is $3 327 115. However. this amount has been increased by $5 717 577
because of the estimated impact of the embedded cost differentials on Idaho results.
iDAHO SUPPLEMENTAL Page 4
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) - A resubmlssion Dec. 31 2006
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 301,436 251 857
106 (583) Overhead Line Expenses 981 364 976 827
107 (584) Underground Line Expenses 356 27,459
108 (585) Street Lighting and Signal System Expenses 705 644
109 (586) Meter Expenses 250 591 296,976
110 (587) Customer Installations Expenses 791
111 (588) Miscellaneous Distribution Expenses 854 252 989 416
112 (589) Rents 63,459 111
113 TOTAL Operation (Enter Total of lines 102 thru 112)127 960 099 507
114 Maintenance
115 (590) Maintenance Supervision and Engineering 103 119 (104)
116 (591) Maintenance of Structures 122 120 894
117 (592) Maintenance of Station Equipment 737 720 483 601
118 (593) Maintenance of Overhead Lines 084 720 029 367
119 (594) Maintenance of Underground Lines 665 916 595 740
120 (595) Maintenance of Line Transformers 755 148
121 (596) Maintenance of Street Lighting and Signal Systems 162 262 118 740
122 (597) Maintenance of Meters 329 306 250 167
123 (598) Maintenance of Miscellaneous Distribution Plant 023 723,572
124 TOTAL Maintenance (Enter Total of lines 115 thru 123)227 941 295 725
125 TOTAL Distribution Expenses (Enter Total of Iinesll3 and 124)355 901 395 232
126 4. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
127 Operation
128 (901) Supervision 618 181 362,425
129 (902) Meter Reading Expenses 302,465 207 773
130 (903) Customer Records and Collection Expenses 135 630 035 554
131 (904) Uncollectible Accounts 529 196 (151 567)
132 (905) Miscellaneous Customer Accounts Expenses 131 546
133 TOTAL Customer Accounts Expenses (Enter Total of Iinesl2S and 132)635 603 3,498 731
134 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
135 Operation
136 (907) Supervision 523 117 070
137 (908) Customer Assistance Expenses 907 191 320 090
138 (909) Informational and Instructional Expenses 166 803 198
139 (910) Miscellaneous Customer Service and Informational Expenses 863 056
140 TOTAL Cust. Service and Informational Exp. (Enter Total of lines 136 thru 139)137 380 478 414
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 299,478 132 260
151 (921) Office Supplies and Expense 616 567 713 722
152 (Less) (922) Administrative Expenses Transferred - Cr.373 580)(1,717 085)
153 (923) Outside Services Employee 078 856 657 616
154 (924) Property Insurance 373 951 214,477
155 (925) Injuries and Damages 590,464 650 371
156 (926) Employee Pensions and Benefrts 891)
157
IDAHO SUPPLEMENTAL Page 5
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) -1L An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) - A resubmisslon Dec. 31 2006
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 390 300 437 124
160 (929) Duplicate Charges - Cr.(542 617)(919,787)
161 (930.1) General Advertising Expenses
162 (930.2) Miscellaneous General Expenses 909 228 844 618
163 (931) Rents 480 956 467 822
164 TOTAL Operation (Enter Total of lines 150 thru 163)823 603 479 247
165 Maintenance
166 (935) Maintenance of General Plant 354 222 175 121
167 TOTAL Administrative and General Expenses (Enter Total of lines 164 thru 166)1/1 825 654 368
168 TOTAL Electric Operation and Maintenance Expenses (Enter Total of lines 79, 99, 125, 133
140 147, and 167)131 831,455 109 420 246
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 624 220 137.884 762 104
172 Nuclear Power
173 Hydraulic -Conventional 923 362 378,338 301,700
174 Hydraulic - Pumped Storage 128,460 221 172 349 632
175 Other Power Supply Expenses 29,459 554 459 554
176 Total Power Production Expenses 135 596 10,737,394 90,872 990
177 Transmission Expenses 164.902 1,486 854 651 756
178 Distribution Expenses 127 960 227 941 355,901
179 Customer Accounts Expenses 635 603 635 603
180 Customer Service and Informational Expenses 137 380 137 380
181 Sales Expenses
182 Adm. and General Expenses 823 603 354 222 13,177,825
183 Total Electric Operation and Maintenance Expenses 111 025 044 806,411 131,831 455
IDAHO SUPPLEMENTAL Page 6
STATE OF IDAHO - ALLOCATED
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) 2 An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) - A resubmisslon Dec. 31, 2006
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (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 (Acc!. 404)Plant (Ace!. 405)
(a)(b)(c)(d)(e)
Intangible Plant 587 666 587,666
Steam Production Plant 746 936 746,936
Nuclear Production Plant
Hydraulic Production Plant - Conventional 833 266 833,266
Hydraulic Production Plant - Pumped Storage
Other Production Plant 349 978 143 615 493,593
Transmission Plant 3,463 283 463 283
Distribution Plant 111 151 111 151
General Plant 398 852 398 852
Common Plant - Electric
TOTAL 903 466 731 281 25,634 747
IDAHO SUPPLEMENTAL Page 7
Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1)1..An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2)A resubmission Dec. 31, 2006
STATE OF IDAHO - ALLOCTED
TAXES, OTHER THAN INCOME TAXES
ACCOUNT 408.
KIND OF TAX AMOUNT
Property 197,756
Other 515 303
Total ( Must agree with page 1 , line 11.713 059
IDAHO SUPPLEMENTAL Page 8
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Name of Respondent This Report Is:Date of Report Year of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
dba Rocky Mountain Power (2) A resubmission Dec. 31 2006
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)893 828 894 831 940 676
Property Under Capital Lease (1)
Plant Purchased or Sold
Completed Construction not Classified 513 375 015 845
Experimental Plant Unclassified
Total (Enter Total of Lines 3 through 7)895 342 269 832 956 521
Leased To Others
Held for Future Use 386 910
Construction Work In Process 6,479,405 352 981
Acquisition Adjustments 913 346 133 313
Total Utility Plant (Enter Total of Lines 8 through 12)911.805.406 849 512 725
Accumulated Provision for Depreciation, Amortization & Depletion 388 719 168 372 669 180
Net Utility Plant (Enter Total of Line 13 less Line 14)523 086 238 476 843 545
DETAIL OF ACCUMULATED PROVISION FOR DEPRECIATION, AMORTIZATION
AND DEPLETION
In Service
Depreciation 362 838 523 348 532 849
AmortizationlDepletion of Producing Natural Gas Land And Land Rights
Amortization of Underground Storage Land and Land Rights
Amortization of Other Utility Plant 842,498 516 222
Total In Service (Enter Total of Lines 18 through 21)383 681 021 368 049 071
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 038 147 620 109
Total Accumulated Provisions (Should Agree With Line 14 above) (Enter Total of
Lines 22 , 31 and 32)388 719 168 372 669 180
(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
(302) Franchises and Consents 683.413 123,440
(303) Miscellaneous Intangible Plant 742 224 31,486 022
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)026 163 609,462
2, PRODUCTION PLANT
A Steam Production Plant
(310) Land and Land Rights 244,409 339 915
(311) Structures and Improvements 49A14 69b 917 983
(312) Boiler Plant Equipment 162,240660 173 511 758
(313) Engines and Engine Driven Generators
(314) Turbogenerator Units 999 296 298 085
(315) Accessory Electric Equipment 980 725 751 217
(316) Misc. Power Plant Equipment 615.222 746,430
TOTAL Steam Production Plant (Enter Total of lines 8 thru 14)284,495 007 296 565 388
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 272 156 235 857
(331) Structures and Improvements 103.909 190,443
(332) Reservoirs, Dams, and Waterways 896 925 041,462
(333) Water Wheels, Turbines, and Generators 294 621 551 218
(334) Accessory Electric Equipment 516.400 622 265
(335) Misc. Power Plant Equipment 205.537 162 623
(336) Roads, Railroads, and Bridges 836 302 861 326
TOTAL Hydraulic Production Plant (Enter Total of lines 25 thru 31)125 850 665 194
D. Other Production Plant
(340) Land and Land Rights 130.023 358,547
(341) Structures and Improvements 1,430 631 185 075
(342) Fuel Holders, Products, and Accessories 288.902 885 649
(343) Prime Movers 17,436 344 132 083
(344) Generators 657 126 122 230
(345) Accessory Electric Equipment 250 117 219 284
(346) Misc. Power Plant Equipment 60,457 234 652
TOTAL Other Production Plant (Enter Total of lines
34 thru 40)253 600 137 520
I U I AL proauctlOn Plant (~nter lotal ot lines
and41)343 874,457 382 368 102
IDAHO SUPPLEME~Page 11
ELECTRIC PLANT IN SERVICE (Continued) STATE OF IDAHO (ALLOCATED)
Line Balance End ofNo.Account Beginning Balance Year
(a)(b)
(g)
3. TRANSMISSION PLANT
(350) Land and Land Rights 686 358 829 621
(352) Structures and Improvements 24~662 3,484 958
(353) Station Equipment 834,436 743 201
(354) Towers and Fixtures 23,444 019 007 308
(355) Poles and Fixtures 955 372 095 956
(356) Overhead Conductors and Devices 348 371 667 239
(357) Underground Conduit ~ 52 628 206 674
(358) Underground Conductors and Devices 254 165 458 773
(359) Roads and Trails 733 376 724 896
TOTAL Transmission Plant (Enter Total of lines
44 thru 52)162 650 387 169 218 626
4. DISTRIBUTION PLANT
(360) Land and Land Rights ~62 007 250 719
(361) Structures and Improvements 764 294 786 125
(362) Station Equipment ~68 992 577 972
(363) Storage Battery Equipment
(364) Poles, Towers, and Fixtures 48,417 355 811 012
(365) Overhead Conductors and Devices 907 691 156 819
(366) Underground Conduit 935 761 316 271
(367) Underground Conductors and Devices ~ 9 776 721 797 084
(368) Line Transformers 595 390 088 551
(369) Services 19,469 7~4 842 503
(370) Meters 697 342 729 088
(371) Installations on Customer Premises ~57 287 159 013
(372) Leased Property on Customer Premises 873 873
(373) Street Lighting and Signal Systems 540 970 553 612
TOTAL Distribution Plant (Enter Total of lines 55 thru 68)214 598 397 229 073 642
5. GENERAL PLANT
(389) Land and Land Rights 575 581 572 069
(390) Structures and Improvements 228 399 417 259
(391) Office Furniture and Equipment 886 537 146 962
(392) Transportation Equipment 826 670 6,484 813
(393) Stores Equipment 825 764 881 684
(394) Tools, Shop and Garage Equipment 306 556 3,438 252
(395) Laboratory Equipment 677,488 010 083
(396) Power Operated Equipment 658 530 705 262
(397) Communication Equipment ~ 3 629 262 973 668
(398) Miscellaneous Equipment 332, ~61 312 878
SUBTOTAL (Enter Total of lines 71 thru 80)946 948 942 930
(399) Other Tangible Property 844 324 616 132
TOTAL General Plant (Enter Total of lines 81 thru 82)791 272 559 062
TOTAL (Accounts 101)831 940 676 893 828 894
(102) Electric Plant Purchased
Plant Sold
(103) Experimental Electric Plant Unclassified
(106) Plant Unclassified 015 845 513 375
TOTAL Electric Plant in Service 832 956 521 895 342 269
IDAHO SUPPLEMENT Page 12
Name of Respondent
PacifiCorp
dba Rocky Mountain Power
STATE OF IDAHO --ALLOCATED
This Report Is: Date of Report
(1) 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
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 , 2006
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
Year
Page 13
Department orBalance Departments
End of Year Which Use Material(c) (d)
295 021 Electric
4,417 830 Electric
Electric
Electric
Electric
605 586
552)
014 864
309 885