20121129Avista to Staff 28-30,32,34-38,41,etc.pdf

Avista Corp.
1411 East Mission P.O. Box 3727
Spokane. Washington 99220-0500
Telephone [phone]
Toll Free 800-727-9170
A-Insma
Corp.
November 28, 2012
?NOV 2 9 ::
IDAHO UbLL JTL!TIE MM1
Idaho Public Utilities Commission
472 W. Washington St.
Boise, ID 83720-0074
Attn: Karl T. Klein
Weldon B. Stutzman
Deputy Attorney General
Re: Production Request of the Commission Staff in Case Nos. AVU-E-12-08 and
AVU-G- 12-07
Dear Mr. Klein and Mr. Stutzman,
Enclosed are an original and three copies of Avista's responses to IPUC Staffs production
requests in the above referenced docket. Included in this mailing are Avista's responses to
production requests 028, 029, 030, 032, 034, 035 - 038, 041, 043 - 046, 048 - 056, and 069.
The electronic versions of the responses were emailed on 11/28/12 and are also being provided
in electronic format on the CD included in this mailing.
Also included are Avista's CONFIDENTIAL responses to PR 044C, 050C, 051C, 053C, 054C,
055C. This response contains TRADE SECRET, PROPRIETARY or CONFIDENTIAL
information and is separately filed under IDAPA 31.01.01, Rule 067 and 233, and Section 9-
340D, Idaho Code, and pursuant to the Protective Agreement between Avista and IPUC Staff
dated October 16, 2012. It is being provided under a sealed separate envelope, marked
CONFIDENTIAL.
If there are any questions regarding the enclosed information, please contact Paul Kimball at
[phone] or via e-mail at paul.kimba1lavistacorp.com
Sincerely,
Paul Kimball
Regulatory Analyst
Enclosures
CC: all parties
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/21/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Robert Lafferty
REQUESTER: IPUC RESPONDER: Steve Wenke
TYPE: Production Request DEPARTMENT: Generation Engineers
REQUEST NO.: Staff-028 TELEPHONE: [phone]
REQUEST:
Please provide all economic analysis including risk analysis of installing the new Rathdrum CT
controller.
RESPONSE:
Please see Staff PR 028 Attachment A (Project 31005013 Rathdrum Mark V Controllers.xlsx) -
A final report that identifies the cost of the Mark V Replacement done on Unit 2 in 2007.
Please see Staff PR 028 Attachment B (Rathdrum CT Ui Mark VIE Controller.xlsx) - The
business case used for the 2012 Capital Expense request. The project was delayed to 2013 due to
manpower constraints and the higher than desired cost provided by GE. This is detailed more in
the "Sole Source Justification" document that also is provided as Attachment D.
Please see Staff _PR_028 Attachment C (Rathdrum CT Replace Mark V Controller (2013).pdf) -
The request for funding for the 2013 budget year. This is reflective of the shift from 2012 to 2013
construction period. It does not reflect the reduced purchase price offered by GE.
Please see Staff_PR_028 Attachment D (Sole Source Justification.pdf) - This write up provides
justification to get supplies from GE and the estimated price of the new Mark VIE system provided
by GE.
Please also see the Company's response to Staff_PR_045 for updated transfers to plant for 2012
and 2013.
Project 31005013
IGEJ,IJik,J. 612,691.77 I
26,428.69
1,234.41
513,263.10
14,515.62
197,777.34
146,269.09
5,677.90
1,600.78
Staff—PR-028 Attachment A All Costs Page 1 of 3
Staff—PR-028 Attachment A All Costs Page 2 of 3
Jun 8, 2011 1 0.40

GE Portions 612,691.77
Staff_PR_028 Attachment A All Costs Page 3 of 3
Capital Investment Business Case
4vtsr*
StaffPR_028 Attachment 8 Page 1 of 2
AV,s1*
Capital Investment Business Case
Internal Labor Availability: 0 low Probaboity 0 Medium Probability El Hi Probab6ty Enterprise Tech: DYES attach form El NO or Not Required
Contract Labor: El YES 0 NO Facilities: DYES - attach form El NO or Not-Required
Capital Tools: DYES attach form El NO or Not Required
Fleet: DYES- attach torso El NO Or Not Required
10000
0000
8000
7000
6000
5000
• I • 4000
3000
2000
1000
0
C Unit lAvatlable Hours
• Unit 2 Available Hours
• Period Hours
Prepared signature
Reviewed signature
Director/Manager
Other Party Review signature
(if necessary) Director/Manager
Year
Estimated Project Cash Flow
30.00%
25.00%
i 20.00%
15.00%
10.00%
5.00%
0.00%
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Staff._PR028 Attachment B Page 2 of 2
.IXVESUE
Capital Review Template
Staff—PR-028 Attachment C Page 1 of 2
Capital Review Template
Prepared signature
Reviewed signature
(if necessary) Director/Manager
Other Party Review signature
(if necessary) Director/Manager
This space is to be used for photographs, charts, or other data that may be useful in evaulating the project
Staff—PR-028 Attachment C
Page 2 of 2
ff1 itI1IiI
insiructions: CaWkie &dion for Secilon i/as appropriate.
SECTION I - BID EVALUATION
Request for Proposal No. _ Recomniended Supplier
1. Is the recommendation based on low—eg price? vex No
If "Yes", sign and forward with a general requisition and all supporting documentation to Purchasing.
If "No". complete remainder of form. (if your recommendation is not based on lowest price or is based on lowest
evaluated price, complete this form and forward with all supporting documentation to Purchasing.
1 Slate reason for supplier seic lion (Le.., delivery constraints specification conformance. commCiial
msnutcturmg and/or other technical coesiderat tons)
SECTION II— SOLE SOURCE JUSTIFICATION
Estinmted Purchase Value $300,000
Description of Proposed Material Ptwchase
CTh Mark V to Mark Vie control system migration for Rathdrum CT Unit I
Reason for Sale Source Selection:
Rathdrum Combustion Turbine (RCT) Unit I is a GE 7EA combustion turbine. RCT Unit 1 is controlled by a GE
Mark V control system (early 1990's technoLogy), which is an OEM proprietary system. GeUCraiIOIt Engiuecrin
wants to keep our turbines at Rathdrum and other GE turbines controlled by the OEM control systems. The system his
been reliable but has many obsolete components,. whidiwiH cease to be supported by GE in 2014. This proposal was
reviewed only in 2012, but the price was unattractive. The purchase price for this Mark Vie migration has been
reduced by GE and is now in line with our expectations. The price has been arrived at In conjunction with of the
negotiations to extend our Long Term Service Agment with GE at our Coyote Springs Unit 2 Generating Station.
Responsible Manager Date
Reviewed by PwhasIflg
Buyer's Signature:
Staff—PR-028 Attachment D Page 1 of 1
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/19/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Robert Lafferty
REQUESTER: IPUC RESPONDER: Steve Wenke
TYPE: Production Request DEPARTMENT: Generation Engineers
REQUEST NO.: Staff-029 TELEPHONE: [phone]
REQUEST:
Please provide all economic analysis including risk analysis of installing the new Water Supply
System for Kettle Falls.
RESPONSE:
Please see Staff_DR_029 Attachment A (Kettle Falls New Water Supply System.pdf) - This is the
business case used for the 2012 Capital Expense request. The project was delayed to 2013 due to
manpower constraints created by the Rathdrum CT Hot Gas Path project.
Please see Staff _DR_029 Attachment B (Kettle Falls Water Supply Project Business Case and
Review.pdf) - The request for funding for the 2013 budget year. This is reflective of the shift from
2012 to 2013 construction year.
Please see Staff_DR_029 Attachment C (NPV Cost Analysis-i 10627.xlsx) - An economic
analysis used in the decision process that illustrates the options being considered and their
anticipated costs. As evidenced by this analysis, there were several scenarios in play. As we
negotiated with the City, and their position became clearer, we were able to -realize that Scenario 6
was our best option. The option ultimately pursued was Scenario 6, which was the lowest
estimated cost.
Please see Staff DR 029 Attachment D (Financial Analysis Result.pdf) - A copy of an e-mail
used to prepare the Capital Expense Business Case. It identifies that the analysis shows 8.27%
IRR.
Please see Staff DR 029 Attachment E (Business Case KF Water) - This is an analysis performed
as part of the business case. Do to the voluminous nature of this file it is being provided in
electronic form only.
Please also see the Company's response to Staff_PR_045 for updated transfers to plant for 2012
and 2013.
Capital Investment Business Case
ANOW
Page lof2
Staff—PR-029 Attachment A Page 1 of 2
50000
0
Capital Investment Business Case
Internal Labor Availability: Dow Pobbiiity Dowdiwn Pbnblhty EJ High pobabley Enterprise Tech: Dyes - otoch fono El NO or Not Rnqined
Contract Labor: 21 YES Dec Facilities: D YES -Hitachfonn Elgoar Not eeqtgrnd
Capital Tools: Dyes - onad foot El NO or Not Retired
Fleet: DYES- aftxh font E) NO Or Not Reqoired
Prepared signature
Reviewed signature
Director/Manager
Other Party Review signature
(if necessary) Director/Manager
This space is to be used for photographs, charts, or other data that may be useful in evaulating the project
root; lIflSOOlZ Page o sEa ob.00,oCworeooa000ononOoc0000 r*wOOoF SR$nNoOEroroo*OrOwHY Onten Ow
Staff—PR-029 Attachment A Page 2 of 2
Capital Review Template
AOWSTA
Staff—PR-029 Attachment B Page 1 of 3
Airss TA
Capital Review Template
Staff—PR-029 Attachment B Page 2 of 3
Capital Review Template
Prepared signature
Reviewed signature
(if necessary) Director/Manager
Other Party Review signature
(if necessary) Director/Manager
This item is requesting an overall increase in the project budget by $300,000 to complete the development work. However, because of project delays experienced this year, the net shift of
this request is to add a request for $600000 in budget year 2012. Please make sure to capture this request.
-
Staff—PR-029 Attachment B Page 3 of 3
38.05 gpm(ann avg)
342.47 gpm(ann avg)
380.52 gpm(ann avg)
3 4 5 6 7 8 9
2012 2013 2014 2015 2016 2017 2018
$0.39 $0.40 $0.41 $0.41 $0.42 $0.43 $0.44
$0.78 $0.80 $0.81 $0.83 $0.84 $0.86 $0.88
$5,202 $5,306 $5,412 $5,520 $5,631 $5,743 $5,858
$0069 $0.070 $0071 $0.073 $0074 $0.076 $0.077
$1,379 $1,421 $1,463 $1,507 $1,552 $1,599 $1,647
- 552 614 614 614 614 614
- 180,000 200,000 200,000 200,000 200,000 200,000
- 552 614 675 675 675 675
- 180,000 200,000 220,000 220,000 220,000 220,000
250 $ 255 $ 260 $ 265 $ 271 $ 276 $ 282
130,000 90,000 55,000 30,000 15,000
61 AF/yr
552 AF/yr
614 AF/yr

1 2

2010 2011

$0.38 $0.38

$0.75 $0.77

$5,000 $5,100

$0066 $0.067

$1,300 $1,339
$
Kettle Falls GS
Water Supply NPV Analysis
ASSUMPTIONS
Total Annual Water Use, Kgal/yr 200,000
Percent Potable Water Use 10%
2012
Assumed Water Rights Acquisition (Non-pot), Kgallyr
Assumed Water Rights Acquisition (All), Kgal/yr -
MAV Sequence, Kgal/yr 130,000
Discount Rate 7.08%
General Inflation/Escalation Rate 2%
Water Rights Cost Escalation Rate 3%
Pumping Power, kW-yr/AF (60% eff; 300ft lift) 0.078
Base Year Cost of Power for Pumping, $IkWh $0.066
Base Year City Residential Water Rate, $/Kgal $0.75
Base Year Cost of Water Rights, $/AF/yr $1,300
Base Year Water System O&M Cost, $tyr $5,000
WRs Acquisition Transaction Cost $0
Cost to Establish Well on Site and Tie In $500,000
City River Water Cost, Percent of Residential 33%
Base Rate, $/mo $250
Include Terminal Value for Water Rights? Yes
CALCULATED VALUES
Potable Water Use, Kgal/yr 20,000
Non-potable Water Use, Kgal'r 180,000
Total Water Use, Kgallyr 200,000
ANNUAL FACTOR TABLE
City Water Rate, Current Avista Contract, $/Kgal
City Residential Water Rate, $/KgaI
O&M Cost, $/yr
Cost of Pumping Power, $/kWh
Cost of Water Rights, $/AF/yr
Avista WRs Holdings (Non-pot) (AFY)
Avista WRs Holdings (Non-pot) (Kgal/yr)
Avista WRs Holdings (All) (AFY)
Avista WR5 Holdings (All) (Kgal/yr)
Base rate per month
MAV Structure, Kgal/yr
2013 2014 2015 2016
180,000 20,000 - -
180,000 20,000 20,000 -
90,000 55,000 30,000 15,000
244 $/AF
Staff-PR-029 Attachment C Page 1 of 10
Kettle Falls GS
Water Supply NPV Analysis
SCENARIOS NPV 2010 2011 2012 2013 2014 2016 2016 2017 01
1)Water Rates Continue at Current Rates $ 1,207,858 $ 75,000 $ 76,500 $ 78,030 $ 79,591 $ 81,182 $ 82,806 $ 84,462 $ 86,151 $ 87,874
2)Water Rates Transition to Residential Rates
• Water Rates Under Current Agreement $ 75,000 $ 76,500 $ - $ - $ - $ - $ - $ - $ -
• Pay City Residential Rates $ - $ - $ 156,060 $ 159,181 $ 162,365 $ 165,612 $ 168,924 $ 172,303 $ 175,749
Total $ 2,203,957 $ 75,000 $ 76,500 $ 156,060 $ 159,181 $ 162,365 $ 165,612 $ 168,924 $ 172,303 $ 175,749
3)Non-Potable from Well, City WR5; Potable from City
City Water Use, Kgal 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000
MAV Shortfall - - - -
• Water rates under current agreement $ 75,000 $ 76,500 $ - $ - $ - $ - $ - $ - $ -
• Cost to install well and piping system $ - $ 500,000 $ - $ - $ - $ - $ - $ - $ -
• Potable water from City at residential rate $ - $ - $ 15,606 $ 15,918 $ 16,236 $ 16,561 $ 16,892 $ 17,230 $ 17,575
• Non-potable water from well ©%of residential rate $ - $ - $ 46,350 $ 47,277 $ 48,222 $ 49,187 $ 50,171 $ 51,174 $ 52,197
• MAV charges $ - $ - $ - $ - $ - $ - $ -
• Base rate charges $ - $ - $ 3,000 $ 3,060 $ 3,121 $ 3,184 $ 3,247 $ 3,312 $ 3,378
• Well O&M cost $ - $ - $ 5,202 $ 5,306 $ 5,412 $ 5,520 $ 5,631 $ 5,743 $ 5,858
• Cost of power for well $ - $ - $ 26,025 $ 26,545 $ 27,076 $ 27,617 $ 28,170 $ 28,733 $ 29,308
Total $ 1,875,651 $ 75,000 $ 576,500 $ 96,182 $ 98,106 $ 100,068 $ 102,070 $ 104,111 $ 106,193 $ 108,317
4) Non-Potable Transition to AVA WRs; Potable from City
City Water Use, Kgal
MA Shortfall
• Water Rates Under Current Agreement
• Cost to install well and piping system
• Potable water from City wells at residential rate
• Non-potable from wells © % of residential rate
• Avista acquires WRs
• MAy Charges
• Base rate charges
• Well O&M cost
• Cost of power for well
• Avista sells water rights
Total $ 1,763,231
200,000 200,000 200,000 20,000 20,000 20,000 20,000 20,000 20,000
70,000 35,000 10,000 -
$ 75,000 $ 76,500 $ - $ - $ - $ - $ - $ - $ -
$ - $500,000$ - $ - $ - $ - $ - $ - $ -
$ - $ - $ 15,606 $ 15,918 $ 16,236 $ 16,561 $ 16,892 $ 17,230 $ 17,575
$ - $ - $ 46,350$ - $ - $ - $ - $ - $ -
$ - $ - $ - $ 784,591 $ 89,792 $ - $ - $ - $ -
$ - $ - $ - $ 18,385 $ 9,377 $ 2,733 $ -
$ - $ - $ 3,000 $ 3,060 $ 3,121 $ 3,184 $ 3,247 $ 3,312 $ 3,378
$ - $ - $ 5,202 $ 5,306 $ 5,412 $ 5,520 $ 5,631 $ 5,743 $ 5,858
$ - $ - $ 26,025 $ 26,545 $ 27,076 $ 27,617 $ 28,170 $ 28,733 $ 29,308
$ 75,000 $ 576,500 $ 96,182 $ 853,805 $ 151,014 $ 55,615 $ 53,940 $ 55,019 $ 56,120
5) All Water from Well; City WR5
City Water Use, Kgal
MA Shortfall
• Water Rates Under Current Agreement
• Cost to install well and piping system
• All Water from wells © % of residential rate
• MAV Charges
• Base rate charges
• Well O&M cost
• Cost of power for well
Total $
200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000
$ 75,000 $ 76,500 $ - $ - $ - $ - $ - $ - $ -
$ - $500,000$ - $ - $ - $ - $ - $ - $ -
$ - $ - $ 51,500 $ 52,530 $ 53,580 $ 54,652 $ 55,745 $ 56,860 $ 57,997
$ - $ - $ 3,000 $ 3,060 $ 3,121 $ 3,184 $ 3,247 $ 3,312 $ 3,378
$ - $ - $ 5,202 $ 5,306 $ 5,412 $ 5,520 $ 5,631 $ 5,743 $ 5,858
$ - $ - $ 28,916 $ 29,495 $ 30,084 $ 30,686 $ 31,300 $ 31,926 $ 32,564
1,779,087 $ 75,000 $ 576,500 $ 88,618 $ 90,390 $ 92,198 $ 94,042 $ 95,923 $ 97,841 $ 99,798
6) Total Transition to AVA WRs
City Water Use, Kgal 200,000 200,000 200,000 20,000 -
MA Shortfall - 70,000 55,000
Staff-PR-029 Attachment C
30,000 15,000
Page 2 of 10
• Water Rates Under Current Agreement
• Cost to install well and piping system
• Water from well © % of residential rate
• Avista acquires WRs
• MAV Charges
• Base rate charges
• Well O&M cost
• Cost of power for well
• Avista sells water rights
Total
Kettle Falls GS
Water Supply NPV Analysis
$ 75,000 $ 76,500 $ - $ - $ - $ - $ - $ - $ -
$ - $500,000$ - $ - $ - $ - $ - $ - $ -
$ - $ - $ 51,500 $ 5,253 $ - $ - $ - $ - $ -
$ - $ - $ - $ 784,591 $ 89,792 $ 92,486 $ - $ - $ -
$ - $ - $ - $ 18,385 $ 14,735 $ 8,198 $ 4,181
$ - $ - $ 3,000 $ 3,060 $ 3,121 $ 3,184 $ 3,247 $ 3,312 $ 3,378
$ - $ - $ 5,202 $ 5,306 $ 5,412 $ 5,520 $ 5,631 $ 5,743 $ 5,858
$ - $ - $ 28,916 $ 29,495 $ 30,084 $ 30,686 $ 31,300 $ 31,926 $ 32,564
$ 1,656,338 $ 75,000 $ 576,500 $ 88,618 $ 846,090 $ 143,144 $ 140,074 $ 44,359 $ 40,981 $ 41,801
7) Continue Old Agreement; Acquire WRs; Potable from City
City Water Use, KgaI
• Water Rates Under Current Agreement
• Cost to install well and piping system
• Potable water from City at residential rate
• Non-potable from City at residential rate
• Avista acquires WR5
• Well O&M cost
• Cost of power for well
• Avista sells water rights
Total $ 1,779,122
200,000 200,000 200,000 20,000 20,000 20,000 20,000 20,000 20,000
$ 75,000 $ 76,500 $ - $ - $ - $ - $ - $ - $ -
$ - $500,000$ - $ - $ - $ - $ - $ - $ -
$ - $ - $ 15,606 $ 15,918 $ 16,236 $ 16,561 $ 16,892 $ 17,230 $ 17,575
$ - $ - $ 140,454$ - $ - $ - $ - $ - $ -
$ - $ - $ - $ 784,591 $ 89,792 $ - $ - $ - $
$ - $ - $ 5,202 $ 5,306 $ 5,412 $ 5,520 $ 5,631 $ 5,743 $ 5,858
$ - $ - $ 26,025 $ 26,545 $ 27,076 $ 27,617 $ 28,170 $ 28,733 $ 29,308
75,000 576,500 187,287 832,360 138,517 49,699 50,693 51,707 52,741
Staff-PR-029 Attachment C
Page 3 of 10
Kettle Falls GS
Water Supply NPV Analysis
ASSUMPTIONS
Total Annual Water Use, Kgallyr
Percent Potable Water Use
Assumed Water Rights Acquisition (Non-pot), Kgal/yr
Assumed Water Rights Acquisition (All), Kgal/yr
MAV Sequence, Kgal/yr
Discount Rate
General Inflation/Escalation Rate
Water Rights Cost Escalation Rate
Pumping Power, kW-yr/AF (60% eff; 300ft lift)
Base Year Cost of Power for Pumping, 5/kWh
Base Year City Residential Water Rate, $/Kgal
Base Year Cost of Water Rights, $/AF/yr
Base Year Water System O&M Cost, $Iyr
WRs Acquisition Transaction Cost
Cost to Establish Well on Site and Tie In
City River Water Cost, Percent of Residential
Base Rate, $/mo
Include Terminal Value for Water Rights?
CALCULATED VALUES
Potable Water Use, Kgal'r
Non-potable Water Use, Kgallyr
Total Water Use, Kgal/yr
ANNUAL FACTOR TABLE
City Water Rate, Current Avista Contract, $/Kgal
City Residential Water Rate, $/Kgal
O&M Cost, s/yr
Cost of Pumping Power, $/kWh
Cost of Water Rights, $/AF/yr
Avista WRs Holdings (Non-pot) (AFY)
Avista WR5 Holdings (Non-pot) (Kgal/yr)
Avista WRs Holdings (All) (AFY)
Avista WRs Holdings (All) (Kgal/yr)
Base rate per month
MAV Structure, Kgal/yr
10 11 12 13 14 15 16 17 18 19 20
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
$0.45 $0.46 $0.47 $0.48 $0.49 $0.49 $0.50 $0.51 $0.53 $0.54 $0.55
$0.90 $0.91 $0.93 $0.95 $0.97 $0.99 $1.01 $1.03 $1.05 $1.07 $1.09
$5,975 $6,095 $6,217 $6,341 $6,468 $6,597 $6,729 $6,864 $7,001 $7,141 $7,284
$0079 $0080 $0.082 $0084 $0085 $0.087 $0.089 $0.091 $0.092 $0.094 $0.096
$1,696 $1,747 $1,800 $1,853 $1,909 $1,966 $2,025 $2,086 $2,149 $2,213 $2,280
614 614 614 614 614 614 614 614 614 614 614
200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000
675 675 675 675 675 675 675 675 675 675 675
220,000 220,000 220,000 220,000 220,000 220,000 220,000 220,000 220,000 220,000 220,000
$ 287 $ 293 $ 299 $ 305 $ 311 $ 317 $ 323 $ 330 $ 336 $ 343 $ 350
Staff-PR-029 Attachment C Page 4 of 10
Kettle Falls GS
Water Supply NPV Analysis
SCENARIOS 2019 2020 2021 2022 2023 2024 2025 QZ 2028 2029
1)Water Rates Continue at Current Rates $ 89,632 $ 91,425 $ 93,253 $ 95,118 $ 97,020 $ 98,961 $ 100,940 $ 102,959 $ 105,018 $ 107,118 $ 1b9,261
2)Water Rates Transition to Residential Rates
• Water Rates Under Current Agreement $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• Pay City Residential Rates $ 179,264 $ 182,849 $ 186,506 $ 190,236 $ 194,041 $ 197,922 $ 201,880 $ 205,918 $ 210,036 $ 214,237 $ 218,522
Total $ 179,264 $ 182,849 $ 186,506 $ 190,236 $ 194,041 $ 197,922 $ 201,880 $ 205,918 $ 210,036 $ 214,237 $ 218,522
3)Non-Potable from Well, City WRs; Potable from C
City Water Use, Kgal 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000
MA Shortfall
• Water rates under current agreement $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• Cost to install well and piping system $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• Potable water from City at residential rate $ 17,926 $ 18,285 $ 18,651 $ 19,024 $ 19,404 $ 19,792 $ 20,188 $ 20,592 $ 21,004 $ 21,424 $ 21,852
• Non-potable water from well © % of residential rate $ 53,241 $ 54,306 $ 55,392 $ 56,500 $ 57,630 $ 58,783 $ 59,958 $ 61,158 $ 62,381 $ 63,628 $ 64,901
• MAy charges
• Base rate charges $ 3,446 $ 3,515 $ 3,585 $ 3,657 $ 3,730 $ 3,805 $ 3,881 $ 3,958 $ 4,038 $ 4,118 $ 4,201
• Well O&M cost $ 5,975 $ 6,095 $ 6,217 $ 6,341 $ 6,468 $ 6,597 $ 6,729 $ 6,864 $ 7,001 $ 7,141 $ 7,284
• Cost of power for well $2% $ 30,492 $ 31,102 $ 31,724 $ 32,358 $ 33,005 $ 33,666 $ 34,339 $ 35,026 $ 35,726 $ 36,441
Total $ 110,483 $ 112,693 $ 114,947 $ 117,246 $ 119,591 $ 121,983 $ 124,422 $ 126,911 $ 129,449 $ 132,038 $ 134,679
4)Non-Potable Transition to AVA WRs; Potable frot
City Water Use, KgaI
MAV Shortfall
• Water Rates Under Current Agreement
• Cost to install well and piping system
• Potable water from City wells at residential rate
• Non-potable from wells © % of residential rate
• Avista acquires WR5
• MAV Charges
• Base rate charges
• Well O&M cost
• Cost of power for well
• Avista sells water rights
Total
5)All Water from Well; City WRs
City Water Use, KgaI
MAV Shortfall
• Water Rates Under Current Agreement
• Cost to install well and piping system
• All Water from wells @ % of residential rate
• MAV Charges
• Base rate charges
• Well O&M cost
• Cost of power for well
Total
6)Total Transition to AVA WRs
City Water Use, Kgal
MA Shortfall

20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000
$ 17,926 $ 18,285 $ 18,651 $ 19,024 $ 19,404 $ 19,792 $ 20,188 $ 20,592 $ 21,004 $ 21,424 $ 21,852
$ 3,446 $ 3,515 $ 3,585 $ 3,657 $ 3,730 $ 3,805 $ 3,881 $ 3,958 $ 4,038 $ 4,118 $ 4,201
$ 5,975 $ 6,095 $ 6,217 $ 6,341 $ 6,468 $ 6,597 $ 6,729 $ 6,864 $ 7,001 $ 7,141 $ 7,84
$ 29,894 $ 30,492 $ 31,102 $ 31,724 $ 32,358 $ 33,005 $ 33,666 $ 34,339 $ 35,026 $ 35,726 $ 36,441
$ 57,242 $ 58,387 $ 59,555 $ 60,746 $ 61,961 $ 63,200 $ 64,464 $ 65,753 $ 67,068 $ 68,409 $ 69,778

200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000
$ 59,157 $ 60,340 $ 61,547 $ 62,778 $ 64,034 $ 65,314 $ 66,620 $ 67,953 $ 69,312 $ 70,698 $ 72,112
$ 3,446 $ 3,515 $ 3,585 $ 3,657 $ 3,730 $ 3,805 $ 3,881 $ 3,958 $ 4,038 $ 4,118 $ 4,201
$ 5,975 $ 6,095 $ 6,217 $ 6,341 $ 6,468 $ 6,597 $ 6,729 $ 6,864 $ 7,001 $ 7,141 $ 7,284
$ 33,216 $ 33,880 $ 34,558 $ 35,249 $ 35,954 $ 36,673 $ 37,406 $ 38,154 $ 38,917 $ 39,696 $ 40,490
$ 101,794 $ 103,830 $ 105,907 $ 108,025 $ 110,185 $ 112,389 $ 114,637 $ 116,930 $ 119,268 $ 121,654 $ 124,087
Staff-PR-029 Attachment C Page 5 of 10
Kettle Falls GS
Water Supply NPV Analysis
• Water Rates Under Current Agreement $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• Cost to install well and piping system $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• Water from well © % of residential rate $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
*Avista acquires WRs $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• MAV Charges
• Base rate charges $ 3,446 $ 3,515 $ 3,585 $ 3,657 $ 3,730 $ 3,805 $ 3,881 $ 3,958 $ 4,038 $ 4,118 $ 4,201
• Well O&M cost $ 5,975 $ 6,095 $ 6,217 $ 6,341 $ 6,468 $ 6,597 $ 6,729 $ 6,864 $ 7,001 $ 7,141 $ 7,284
• Cost of power for well $ 33,216 $ 33,880 $ 34,558 $ 35,249 $ 35,954 $ 36,673 $ 37,406 $ 38,154 $ 38,917 $ 39,696 $ 40,490
• Avista sells water rights $, - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -,
èl,974 Total $ 42,637 $ 43,490 $ 44,360 $ 45,247 $ 46,152 $ 47,075 $ 48,016 $ 48,977 $ 49,956 $ 50,955 $
7) Continue Old Agreement; Acquire WRs; Potable
City Water Use, Kga! 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000
• Water Rates Under Current Agreement $ - $ $ - $ - $ - $ - $ - $ - $ - $ - $ -
• Cost to install well and piping system $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• Potable water from City at residential rate $ 17,926 $ 18,285 $ 18,651 $ 19,024 $ 19,404 $ 19,792 $ 20,188 $ 20,592 $ 21,004 $ 21,424 $ 21,852
• Non-potable from City at residential rate $ - $ - $ - $ - $ - $ - $ - - $ - $ - $ -
• Avista acquires WR5 $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• Well O&M cost $ 5,975 $ 6,095 $ 6,217 $ 6,341 $ 6,468 $ 6,597 $ 6,729 $ 6,864 $ 7,001 $ 71141 $ 7,284
• Cost of power for well $ 29,894 $ 30,492 $ 31,102 $ 31,724 $ 32,358 $ 33,005 $ 33,666 $ 34,339 $ 35,026 $ 35,726 $ 36,441
• Avista sells water rights $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Total 53,796 54,872 55,969 57,089 58,230 59,395 60,583 61,795 63,030 64,291 65,577
Staff-PR-029 Attachment C Page 6 of 10
Kettle Falls GS
Water Supply NPV Analysis
ASSUMPTIONS
Total Annual Water Use, Kgal/yr
Percent Potable Water Use
Assumed Water Rights Acquisition (Non-pot), KgaI/yr
Assumed Water Rights Acquisition (All), Kgal/yr
MAV Sequence, KgaI/yr
Discount Rate
General Inflation/Escalation Rate
Water Rights Cost Escalation Rate
Pumping Power, kW-yr/AF (60% eff; 300ft lift)
Base Year Cost of Power for Pumping, $/kWh
Base Year City Residential Water Rate, $IKgal
Base Year Cost of Water Rights, $/AFIyr
Base Year Water System O&M Cost, S/yr
WRs Acquisition Transaction Cost
Cost to Establish Well on Site and Tie In
City River Water Cost, Percent of Residential
Base Rate, 51mo
Include Terminal Value for Water Rights?
CALCULATED VALUES
Potable Water Use, Kgal/yr
Non-potable Water Use, Kgal/yr
Total Water Use, KgaI/yr
ANNUAL FACTOR TABLE
City Water Rate, Current Avista Contract, $/KgaI
City Residential Water Rate, $/KgaI
O&M Cost, $/yr
Cost of Pumping Power, 5/kWh
Cost of Water Rights, $/AF/yr
Avista WRs Holdings (Non-pot) (AFY)
Avista WRs Holdings (Non-pot) (Kgal/yr)
Avista WRs Holdings (All) (AFY)
Avista WRs Holdings (All) (Kgallyr)
Base rate per month
MAV Structure, Kgallyr
21 22 23 24 25 26 27 28 29 30
2030 2031 2032 2033 2034 2035 2036 2037 2038 2039
$0.56 $0.57 $0.58 $0.59 $0760 $0.62 $0.63 $0.64 $0.65 $0.67
$1.11 $1.14 $1.16 $1.18 $1.21 $1.23 $1.26 $1.28 $1.31 $1.33
$7,430 $7,578 $7,730 $7,884 $8,042 $8,203 $8,367 $8,534 $8,705 $8,879
$0098 $0.100 $0102 $0104 $0.106 $0.108 $0110 $0113 $0.115 $0117
$2,348 $2,418 $2,491 $2,566 $2,643 $2,722 $2,804 $2,888 $2,974 $3,064
614 614 614 614 614 614 614 614 614 614
200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000
675 675 675 675 675 675 675 675 675 675
220,000 220,000 220,000 220,000 220,000 220,000 220,000 220,000 220OQO 220,000
$ 357 $ 364 $ 371 $ 379 $ 386 $ 394 $ 402 $ 410 $ 418 $ 427
Staff_PR_029 Attachment C Page 7 of 10
Kettle Falls GS
Water Supply NPV Analysis
SCENARIOS 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039
1)Water Rates Continue at Current Rates $ 111,446 $ 113,675 $ 115,948 $ 118,267 $ 120,633 $ 123,045 $ 125,506 $ 128,016 $ 130,577 $ 133,188
2)Water Rates Transition to Residential Rates
• Water Rates Under Current Agreement $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• Pay City Residential Rates $ 222,892 $ 227,350 $ 231,897 $ 236,535 $ 241,266 $ 246,091 $ 251,013 $ 256,033 $ 261,154 $ 266,377
Total $ 222,892 $ 227,350 $ 131,897 $ 236,535 $ 241,266 $ 246,091 $ 251,013 $ 256,033 $ 261,154 $ 266,377
3)Non-Potable from Well, City WRs; Potable from C
City Water Use, Kgal 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000
MAV Shortfall
• Water rates under current agreement $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• Cost to install well and piping system $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• Potable water from City at residential rate $ 22,289 $ 22,735 $ 23,190 $ 23,653 $ 24,127 $ 24,609 $ 25,101 $ 25,603 $ 26,115 $ 26,638
• Non-potable water from well © % of residential rate $ 66,199 $ 67,523 $ 68,873 $ 70,251 $ 71,656 $ 73,089 $ 74,551 $ 76,042 $ 77,563 $ 79,114
• MAV charges
• Base rate charges $ 4,285 $ 4,370 $ 4,458 $ 4,547 $ 4,638 $ 4,731 $ 4,825 $ 4,922 $ 5,020 $ 5,121
• Well O&M cost $ 7,430 $ 7,578 $ 7,730 $ 7,884 $ 8,042 $ 8,203 $ 8,367 $ 8,534 $ 8,705 $ 8,879
• Cost of power for well $ 37,169 $ 37,913 $ 38,671 $ 39,445 $ 40,233 $ 41,038 $ 41,59 $ 42,696 $ 43,550 $ 44,421
Total $ 137,372 $ 140,120 $ 142,922 $ 145,780 $ 148,696 $ 151,670 $ 154,703 $ 157,797 $ 160,953 $ 164,172
4)Non-Potable Transition to AVA WRs; Potable fro,
City Water Use, Kgal 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000
MA Shortfall
• Water Rates Under Current Agreement $ - $ - $ - $ - $ - $ - $ - $ - $ - $
• Cost to install well and piping system $ - $ T $ - $ - $ - $ - $ - $ - $ - $ -
• Potable water from City wells at residential rate $ 22,289 $ 22,735 $ 23,190 $ 23,653 $ 24,127 $ 24,609 $ 25,101 $ 25,603 $ 26,115 $ 26,638
• Non-potable from wells @ % of residential rate $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• Avista acquires WRs $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• MAV Charges
• Base rate charges $ 4,285 $ 4,370 $ 4,458 $ 4,547 $ 4,638 $ 4,731 $ 4,825 $ 4,922 $ 5,020 $ 5,121
• Well O&M cost $ 7,430 $ 7,578 $ 7,730 $ 7,884 $ 8,042 $ 8,203 $ 8,367 $ 8,534 $ 8,705 $ 8,79
• Cost of power for well $ 37,169 $ 37,913 $ 38,671 $ 39,445 $ 40,233 $ 41,038 $ 41,859 $ 42,696 $ 43,550 $ 44,421
• Avista sells water rights $ - $ - $ - $ - $ - $ - $ - $ - $ - $ (1,880,046)
Total $ 71,173 $ 72,597 $ 74,049 $ 75,530 $ 77,040 $ 78,581 $ 80,153 $ 81,756 $ 83,391 $ (1,794,988)
5)All Water from Well; City WR5
City Water Use, Kga! 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000
MAV Shortfall
• Water Rates Under Current Agreement $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• Cost to install well and piping system $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
• All Water from wells © % of residential rate $ 73,554 $ 75,025 $ 76,526 $ 78,057 $ 79,618 $ 81,210 $ 82,834 $ 84,491 $ 86,181 $ 87,904
• MAV Charges
• Base rate charges $ 4,285 $ 4,370 $ 4,458 $ 4,547 $ 4,638 $ 4,731 $ 4,825 $ 4,922 $ 5,020 $ 5,121
• Well O&M cost $ 7,430 $ 7,578 $ 7,730 $ 7,884 $ 8,042 $ 8,203 $ 8,367 $ 8,534 $ 8,705 $ 8,879
• Cost of power for well $ 41,299 $ 42,125 $ 42,968 $ 43,827 $ 44,704 $ 45,598 $ 46,510 $ 47,440 $ 48,89 $ 49,357
Total $ 126,568 $ 129,100 $ 131,682 $ 134,315 $ 137,002 $ 139,742 $ 142,536 $ 145,387 $ 148,295 $ 151,261
6) Total Transition to AVA WR8
City Water Use, Kgal
MA Shortfall
Staff-PR-029 Attachment C
Page 8 of 10
Kettle Falls GS
Water Supply NPV Analysis
$ 4,285 $ 4,370 $ 4,458 $ 4,547 $ 4,638 $ 4,731 $ 4,825 $ 4,922 $ 5,020 $ 5,121
$ 7,430 $ 7,578 $ 7,730 $ 7,884 $ 8,042 $ 8,203 $ 8,367 $ 8,534 $ 8,705 $ 8,879
$ 41,299 $ 42,125 $ 42,968 $ 43,827 $ 44,704 $ 45,598 $ 46,510 $ 47,440 $ 48,389 $ 49,357
$ - $ - $ - $ - $ - $ - $ - $ - $ - $ (2,068,051)
$ 53,014 $ 54,074 $ 55,156 $ 56,259 $ 57,384 $ 58,532 $ 59,702 $ 60,896 $ 62,114 $ (2,004,694)
20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000 20,000
$ 22,289 $ 22,735 $ 23,190 $ 23,653 $ 24,127 $ 24,609 $ 25,101 $ 25,603 $ 26,115 $ 26,638
$ 7,430 $ 7,578 $ 7,730 $ 7,884 $ 8,042 $ 8,203 $ 8,367 $ 8,534 $ 8,705 $ 8,879
$ 37,169 $ 37,913 $ 38,671 $ 39,445 $ 40,233 $ 41,038 $ 41,859 $ 42,696 $ 43,550 $ 44,421
$ - - $ - $ - $ - $ - $ - $ - $ - $ (1,880,04)
66,888 68,226 69,591 70,983 72,402 73,850 75,327 76,834 78,370 (1,800,108)
• Water Rates Under Current Agreement
• Cost to install well and piping system
• Water from well © % of residential rate
• Avista acquires WR5
• MAV Charges
• Base rate charges
• Well O&M cost
• Cost of power for well
• Avista sells water rights
Total
7) Continue Old Agreement; Acquire WRs; Potable
City Water Use, Kgal
• Water Rates Under Current Agreement
• Cost to install well and piping system
• Potable water from City at residential rate
• Non-potable from City at residential rate
• Avista acquires WRs
• Well O&M cost
• Cost of power for well
• Avista sells water rights
Total
Staff-PR-029 Attachment C Page 9 of 10
Pump Power caic
From Crane, pg B-9, theoretical power to pump I Oogpm with a lift of 300ft is
If the pump is 60% efficient, required power will be
Therefore, power to pump Igpm is
An AF equals
One AF/yr equates, on an average basis, to
Therefore, power to pump equivalent of I AF/yr equals
7.58 kW
12.63 -kW
0.126 kW/gpm
325,900 gal
0.620 gpm
0.0783 kW-yr/AF
Staff_PR_029 Attachment C (NPV Cost Analysis-1 1Utc Page 10 of 10
Wenke, Steve
From: Thorson, Neil
Sent: Tuesday, August 30, 2011 3:24 PM
To: Wenke, Steve
Subject: IRR for Projects
Steve,
For the CS2 Exciter project, use 19.41% IRR. For the Kettle Falls water, use 8.27% IRR.
The assumptions:
CS2 —4 days outage every 10 years.
Kettle Falls Water - Savings based on conversion to residential rate with a projected !% escalation rate per year. We
may get a better rate, but it would probably involve us paying up front for system improvements on the KF city water
system.
Neil
1
Staff—PR-029 Attachment D Page 1 of 1
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/16/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Scott Kinney
REQUESTER: IPUC RESPONDER: Scott Waples
TYPE: Production Request DEPARTMENT: System Planning
REQUEST NO.: Staff-030 TELEPHONE: [phone]
REQUEST:
Please provide the economic analysis for the CNC project, including any risk analysis done.
Please also provide a copy of the agreement for the project.
RESPONSE:
While there were several reasons why Avista was a sponsor of the CNC transmission project,
Avista's sponsorship was based upon two primary objectives: (i) to obtain access to additional
resources and additional import capacity to serve the needs of Avista' s native load customers, and
(ii) to maintain and enhance system reliability.
The CNC transmission project offered an opportunity for Avista to access resources that would
help Avista meet its intermediate and long-term future renewable resource needs in order to satisfy
its renewable portfolio standard requirements, as well as, other resources to meet future native
load. In the context of integrating variable renewable resources, future access to regulation or
shaping services from BC Hydro was also a consideration.
To the extent Avista intends to consider any new resources, renewable or otherwise, that reside
outside its service territory to meet the future needs of the Company's native load customers, the
Company must maintain and develop additional import capacity on its transmission system to
accommodate such resources. The vast majority of the Company's current transmission import
capability flows through its interconnections with the Bonneville Power Administration. The
CNC transmission project not only offered an opportunity to provide for future increase in import
capability, but provided an opportunity to diversify that import capability.
The CNC transmission project also would serve to enhance system reliability both from a regional
standpoint and specifically for Avista's system. The CNC transmission project would provide an
EHV (extra-high voltage) source on the west side of Avista's service territory, increasing the
overall reliability of Avista's transmission grid. Avista currently has only three 500 kV sources
supporting its transmission system; the Company's Bell, Hatwai and Hot Springs
interconnections, which are all with the Bonneville Power Administration.
By participating as a sponsor of the CNC transmission project, Avista was able to affect certain
determinations regarding the project, including the choice of the overland alternative from
Southeast British Columbia to Northern California, and the planned interconnection with Avista's
transmission system at Devils Gap.
Additionally, Avista was an affected party that needed to participate in review and analysis of the
project as part of the Company's coordinated regional planning obligations under Attachment K to
its Open Access Transmission Tariff.
Pagel of 2
Please see Staf PR 030 Attachment A for a copy of the Pacific Northwest to California feasibility
stud-y. Also see Staff_PR_030 Attachment B for a copy of the CNC contracts.
As noted in Mr. Kinney's direct testimony starting at page 10, the cost accrued by Avista for its
participation in the CNC regional transmission project was $758,000. Of this amount, $537,000 is
the amount Avista paid for its share of the initial sponsorship of the CNC transmission project
pursuant to the Stage One Project Development Agreement, and $221,000 consisted of the direct
transmission planning expenses incurred by Avista. Avista is amortizing these expenses over a
three-year period beginning in 2012, resulting in a 2013 rate period amortization expense of
$253,000 ($88,000 Idaho share). The amortization period expense represents the method
proposed in the Company's last general rate case (AVU-E-1 1-0 1) that was resolved through a
"black-box" settlement.
Page 2 of 2
FINAL
"k W~i e' k6ia
NE-W-- TRANSMISSION
FEASIBILITY.SSESSMENT
Northwest—California Transmission Steering Committee
Brown-field Optimization Group
April 12,2011
Staff_PR030 Attachment A Page 1 of 63
FINAL
Table of Contents
1.Executive Summary .................... .. ................................................................................ 1
2.Introduction .................................................................................................................5
3.Transmission Assessment Tasks...................................................................................6
4.Facilities Considered for Brown-field Alignments ......................................................... 7
S. Study Objective ........................................8

5.1 Options ......................................................................................................................................... 8

5.2 Study Cases.................................................................................................................................11

5.3 Study Standards and Criteria.....................................................................................................11

5.4 Contingencies ........................................................................................................................... ..11

5.5 Study Scope................................................................................................................................11
6.Study Results ..............................................................................................................12

6.1 Option 1: All AC ......................................................................................................................... .12

6.2 Option 2: New AC in Oregon, COTP converted to DC. ............................................................. 22

6.3 Option 3: Convert NEO-COB to DC, COTP Converted to DC ..................................................... 29

6.4 Option 4: All DC ........................................ 39
7.Key Findings ...............................................................................................................43
8.Next Steps ..................................................................................................................45
Staff—PR-030 Attachment A Page 2 of 63 1
FINAL
Tables
Table 1: Preliminary PNW:Calrfomia Brown-field Planning Options .10
Table 2: Option la–Comparison of Path and Line Flows ...................................................... 13
Table 3: Option 1 a–Comparison of Category B Overloads .................................................... 14
Table 4: Option Ia– Potential Mitigation Measures for Category B Impacts......................... 14
Table 5: Option la–Comparison of Category D Overloads ................................................... l5
Table 6: Option la—Potential Mitigation Measures for Category D Impacts......................... 15
Table 7: Option lb—Comparison of Path and Line Rows..................................................... 16
Table 8: Option lb–Comparison of Category -B Overloads .................................................... 17
Table 9: Option I b– Potential Mitigation Measures for Category B Impacts ......................... 17
Table 10: Option lb--Comparison of Category DOverloads ................................................. 18
Table 11: Option lb—Potential Mitigation Measures for Category D Impacts....................... 18
Table 12: Option Ic–Comparison of Path and Line Flows ..................................................... 19
Table 13: Option 1c–Comparison of Category B Overloads.................................................. 20
Table 14: Option Ic– Potential Mitigation Measures for Category B impacts ........................ 20
Table 15: Option Ic–Comparison of Category D Overloads ................................................. 21
Table 16: Option 1c—Potential Mitigation Measures for Category D impacts ....................... 22
Table 17: Option 2a–Comparison of Path and Line Flows .................................................... 23
Table 18: Option 2a–Comparison of Category B Overloads ................................................. 24
Table 19: Option 2a—Potential Mitigation Measures for Category B Impacts ....................... 24
Table 20: Option 2a–Comparison of Category C Overloads ................................................. 24
Table 21: Option 2a—Potential Mitigation Measures for Category C Impacts....................... 24
Table 22: Option 2a–Comparison of Category D Overloads ................................................. 25
Table 23: Option 2a—Potential Mitigation Measures for Category D Impacts....................... 26
Table 24: Option 2b–Comparison of Path and Line Flows .................................................... 27
Table 25: Option 2b–Comparison of Category B Overloads ......... 28
Table 26: Option 2b—Potential Mitigation Measures for Category B Impacts.......................28
Table 27: Option 2b–Comparison of Category C Overloads ................................................. 28
Table 28: Option 2b—Potential Mitigation Measures for Category C Impacts ....................... 28
Table 29: Option 3a–Comparison of Path and Line Flows ....................................................30
Table 30: Option 3a–Comparison of Category B Overloads .................................................30
Table 31: Option 3a—Potential Mitigation Measures for Category B Impacts.......................31
Table 32: Option 3a–Comparison of Category C Overloads ................................................. 32
Table 33: Option 3a—Potential Mitigation Measures for Category C Impacts....................... 33
Staff—PR-030 Attachment A Page 3 of 63
FINAL
Table 34: Option 3a–Comparison of Category D-Overloads .34
Table 35: Option 3a—Potential Mitigation Measures for Category D impacts ....................... 35
Table 36: Option 3b–Comparison of Path and Line Flows .................................................... 36
Table 37: Option 3b–Comparison of Category BOverloads ................................................. 37
Table 38: Option 3b—Potential Mitigation Measures for Category B Impacts....................... 37
Table 39: Option 3b--Comparison of Category C Overloads................................................. 37
Table 40: Option 3b—Potential Mitigation Measures for Category C Impacts....................... 38
Table 41: Option 3b–Comparison of Category D Overloads ................................................. 38
Table 42: Option 3b—Potential Mitigation Measures for -Category D Impacts....................... 39
Table 43: Option 4–Comparison of Path and Line Flows ...................................................... 40
Table 44: Option 4–Comparison of Category B Overloads..................................................... 41
Table 45: Option 4—Potential Mitigation Measures for Category B impacts ......................... 41
Table 46: Option 4–Comparison of Category C Overloads ...................................................41
Table 47: Option 4—Potential Mitigation Measures for Category C Impacts.........................42
Table 48: Option 4–Comparison of Category D Overloads ................................................... 42
Table 49: Option 4—Potential Mitigation Measures for Category 0 Impacts......................... 42
Attachments
Attachment 1: Map of Conceptual Routing Alignments: NEO - COB............................ 47
Attachment 2: Table of Conceptual Routing Segments: NEO - COB........................... 48
Attachment 3: -Preliminary Review of Northwest Alignments....................................... 52
Attachment 4: NEO Area Configuration.................................................................... q4
Attachment 5: 2010 Existing System Diagram........................................................ 55
Attachment 6: Option I (Ca Opt IA) - New AC & 2 nd COTP.................................. 56
Attachment 7: Option 2 (Ca Opt 2) - AC + COTP DC ............................................ 57
Attachment 8: Option 3 (Ca Opt 2) - Convert/New DC + COTP DC...................... 58
Attachment 9: Option 4 (Ca Opt 5) - New DC........................................................ 59
iv
Staff—PR-030 Attachment A Page 4 of 63
FINAL
The Pacific Northwest (PNW)-Califomia Committee' was formed to analyze (1)the use of the
existing COI transfer capability and (2) the possibility of new transmission between the PNW
and California using brown-field alignments.
The first analysis was conducted by the Transmission Utilization Group. This group
investigated the use of the existing COI_ transfer capability and the ability of generation and
load entities to access any underutilized capability. That analysis showed that while there is
unused COI transmission capacity at times, there is no long term firm transmission capacity
to meet the needs of the generation and load entities.
The second analysis was conducted by the Brown-field Optimization Group (BOG) to assess
potential brown-field alignments for new transmission between the Pacific Northwest and
Northern California. This-analysis focused on Oregon and was based on the findings from an
earlier brown-field study for California. This report presents the-BOG findings.
The BOG considered the following brown-field routes in Oregon (Attachment 1, 2 and 3):
• PACI: This route follows the existing 500 kV AC lines from NEO-McNary-Coyote
Springs-Slatt-Buckley-COB
• PDCI: This route follows the existing 500 kV AC line from NEO-McNary to the
Pacific DC Intertie (PDCI). From there, this route follows the PDCI to a point
south of Sand Springs where a new right-of-way would be required to COB.
• East: This route follows the existing 138 kV, 230 kV, and 500 kV AC lines from
NEO-Quarts-Burns-Summer Lake- COB.
• West: This route is very similar to the PACt route with the exception that the 230
kV corridor between the PACI and the Cascades to COB would be utilized. This
route goes through the cities of Bend and Redmond and may be challenging to
permit.
• Boardman: This route is an alternative between Slatt and NEO. Only one
segment of this route (Slatt-Boardman Plant) is a developed transmission
corridor. The other segments would be green-field today, but they overlap with
the proposed PGE Cascade Crossing and IPC Boardman-Hemingway projects.
Four options using these routes were considered:
• Option 1: All-AC (Attachment 6)
This option includes: (a)-a NEO-Captain Jack-Olinda--Collinsville 500 kV AC circuit, and (b) a
NEO-NEC 500 kV AC circuit using the East (1 a), PACI (1 b) and PDCI (1 c) routes.
• Option 2: New AC North of COB and COTP converted to DC (Attachment 7)
This option includes the following facilities: (a) a NEO-Captain Jack 500 kV AC circuit (brown-
field with PACI), (b) a NEO-NEC 500 kV AC circuit (green-field paralleling PACI), and (c)
COW converted from AC to DC.
1 Committee members include PNW parties (Bonneville Power Administration (BPA), Avista, BC
Hydro, Pacific Corp, and Portland General Electric (PGE)) and California parties (Western Area
Power Administration. (Western), Pacific Gas and Electric (PG&E), and the Transmission Agency of
Northern California (TANC)).
I
Staff—PR-030 Attachment A Page 5 of 63
FINAL
• Option 3: AC-DC Conversion North of COB - COTP converted to DC
(Attachment 8)
Option 3a includes: (a) NEO-Buckley bipole circuits, (b) Buckley-Captain Jack converted to
DC, and (c) COTP converted to DC using the PACt route.
Option 3b is the same as Option 3a except new DC bipole circuits would be used in Oregon
instead of an AC to DC conversion using the PACt route.
• Option 4: All DC (Attachment 9)
This option includes a NEO-Olinda-Collinsville DC considering all-routes.
Power flow studies were performed to identify thermal overloads on 230 kV (and higher
voltage) facilities.
This study utilized a Benchmark Case developed from a WECC 201 5HS2 base case that
modeled 4800 MW (n-s) on COI and 3100-MW (n-s) on PDCI. From the Benchmark Case,
four Project Cases were developed. Each case models (1) one of the four options and the
common elements in the Northwest and California 2, and (2) a total of 3000 MW scheduled
into central California: 750 MW scheduled from BC to central California: 1250 MW scheduled
from the PNWto central California, and 1000 MW from NE California to central California.
The following table summarizes the 500 kV and 230 kV facilities that are impacted (percent
over the applicable rating) for Category A, B, C and D conditions for each of the options:
2 Common elements include (1) a proposed Selkirk-NEO 500 kV AC line in British Columbia and
Washington, and (2) and proposed facilities in California consisting of a proposed Collinsville-Tracy
500 kV line, a proposed Viewland 345/230 kV substation along with a proposed 230 kV
transmission line to the NEC substation, and Western/PG&E upgrades.
2
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•••••••••••••••••••••••••••••••••••••••••South of NEO Option............................................--
IA..................... B............ç...........2A......................2B.....................................139...............
DC: AC AC AC AC AC DC I DC
Oregon' (East) Bucki (PD LL So Conv
AC
(COTP
AC AC DC: DC: DC::DC: I (COTP (COTP : • California .W . COTP COTP COTP COTP
ij Converted Converted Converted Converted k)
Category B
-LMUDTap 3% 1 3% 3% 1 3% PST
- Hilltop XFMR 1 3% 3% 3%3% 3% 3% 3%
#of Impacted I 2 2 2 2 2 2 2 2
Facilities
Category C
antia 13% 13% 13% 13% 13% 24% 21% 21%
Marcol
-Grant Pass- 1% 1%3 1% 1% Meridian
- Redmond- 25°/ Rd Butte
- Redmond- 15% Pilot Butte
-Be thel-Parish 2% 4% 4%
5% - Grizzly-JD #1 1
- Grizzly-JD #2 14%
- Maupin-Big 2°!
ES1y............................................................................................................................................................................................................
- Summer 0 16/0 Lake-Malin
#of Impacted 2 2 2 2 2 8 2 2
Facilities
Category D
- CJ-Grizzlv 4% 5% 5% 2% 1 n/a
Grizzly-JO #1 6% 8% 7% 8% n/a (PAd)
Grizzly-JD #2 .16% 17% a ..
o . •/•a
0 Transformers ........................................................................................ ..............
#of Impacted 3 3 4 0 3 3 3 Facilities
Diverged 2 4 4 Cases
1 Technology (AUgnmer
2 Aiignmentwouid meetthe WECO Separation Criteria
3 Case sdiverged Most likely due to Reactive Deficiency, resuitsMH most likely mirror those of Option 2A and 28 (Category C)
4 Casesdiverged most likety due to Reactive Deficiency, resuttswili most likely mirror those of Option IC Cateorv D)
Staff—PR-030 Attachment A Page 7 of 63
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The study results indicate:
• None of the options experienced a Category A overload.
• All of the options experienced Category B overloads of the
Hilltop 345/230 kV transformer and the proposed LMUD Tap phase shifter for a
PDCI bipole outage. A second transformer would be required at both Hilltop and
LMUD Tap, respectively.
• Category C overloads occurred for several 230 kV and 500
W facilities in Oregon. Potential mitigation for these overloads includes RAS
generation dropping, or rerates or reconductoring of the impacted facilities.
• Category D overloads occurred for several 230 kV and 500
W facilities in Oregon. Though mitigation of these overloads is not required,
potential mitigation might include RAS generation dropping,- or rerates or
reconductoring of the impacted facilities.
• Of the options investigated, the most overloads were noted
in Option 3a in which the existing Buckley-Captain Jack 500 kV line is converted
to +/-500 kV DC. However, these overloads could be mitigated as described
above.
• Of the routes considered, the East route produced
somewhat lower flows following Category C outages of the new and existing
transmission facilities on that route.
Based on these findings, any further Engineering, Land, and additional power system studies
should focus on Options 1, 2, 3b and 4 using the PACI and East Alignments in Oregon and
the COTP conversion and 230 kV alignments in California. The Engineering Study would
identify potential tower line configurations, constructability, and maintenance procedures, and
the development of cost estimates. The Land Study would consist of assessing whether
there are environmental/land constraints that might preclude a particular option or brown field
alignment (i.e., fatal flaw analysis), identifying right-of-way requirements and developing cost
estimates. Future power system study work would evaluate power flow, transient stability,
and voltage stability analyses with both north-to-south and south-to-north transfers.
4
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The Western Area Power Administration (Western), Pacific Gas & Electric Company
(PG&E) and the Transmission Agency Of Northern California (TANG), comprising the
California Parties, jointly analyzed alternative upgrades using brown-field routes in
California to increase the transfer capability between the Pacific Northwest (PNW) and
the Tesla/Tracy area and between Northeast California/Northern Nevada and the
Tesla/Tracy area. A report titled "Northern California Coordinated Transmission
Feasibility Study" was issued in July 2010. The following technical study and report is a
continuation of this effort with the emphasis now on the Northwest. These studies are
based on:
• The Canada-Northwest-California (CNC) Project sponsored by Avista, BC Hydro
(BCH), and PG&E. The project has multiple objectives including the ability to
access new renewable generation in BC and the PNW for delivery to northern
California. The project is presently in Phase 2 of the WECC Rating Process with
a 3000 MW rating and a preliminary Plan of Service consisting of a Selkirk-
Devils Gap-NEO 500 kV AC line and a NEO-Cottonwood/Olinda-Collinsvilie 500
kV DC line with a Collinsville-Tracy 500 kV AC upgrade. The Project Sponsors
are now considering a reduced rating of about 2000 MW that could lead to
changes to the Preliminary Plan of Service.
TANG investigated several new transmission facilities in Northern California. The
plans were designed to interconnect 2000 MW or more of new renewable
generation in Northern California and Northern Nevada, along with improving the
capability of the transmission grid between Round Mountain/Olinda and the
Tracy area. TANC's efforts culminated in the TANG Transmission Program
(TTP), which completed the WECC Regional Planning process and was in the
beginning stages of the environmental review process when TANG decided to
postpone its efforts due to difficulties in obtaining publically acceptable green-
field routes.
The California Parties have proposed consideration of brown-field alternatives in the Pacific
Northwest. After further discussion with Northwest Parties (Bonneville Power Administration
(BPA), PacifiCorp, and Portland General Electric (PGE), among them) and analysis by the
parties, it appeared that there may be underutilized capacity on the COI transmission that
could possibly meet a portion of the California need. The NW and California parties decided
to form the Northwest-California Steering Committee to provide direction over two analyses.
The first analysis conducted by the Transmission Utilization Group investigated the use of the
existing COI transfer capability and the ability of generation and load entities to access any
underutilized capability.3 The second analysis conducted by the Brown-field Optimization
Group (BOG) assessed potential brown-field alternatives for new transmission between the
Pacific Northwest and Northern California.
The TUG study has been completed and showed that while there is expected to be some unused
COI transmission capacity from time-to-time, it would not be sufficient to meet the needs of the
generation and load entities.
5
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This assessment report describes the approach that BOG took to assess possible brown-field
alternatives to increase the transfer capability between the Pacific Northwest and California
and the technical study results.
The assessment involved the following tasks:
• Review the existing transmission facilities between Northeast Oregon (NEO) and
Northern California.
Identify brown-field options to increase transfer capabilities by 1,500 MW or more
between NEO and Northern California. Brown-field alternatives include (1)
installing new AC facilities in a common corridor 5 or on common structures 8 with
existing or proposed facilities, (2) installing new DC facilities in a common
corridor or on common structures with existing or proposed facilities, (3)
upgrading of existing AC facilities to higher AC voltages, and (4) converting AC
facilities to DC.
• Provide an estimate of the maximum incremental transfer capability provided by
these alternatives.
Analyze the alternatives for feasibility in terms of power system impacts,
engineering, and land/environmental issues.
• Planning Study: Identify thermal overloads for Category A, B, C, and D with
respect to the NERC standards and the WECC criteria.
• Engineering Study: Determine the design, construction and maintenance
challenges of the brown-field alternatives and determined how these
challenges can be mitigated. Determine the cost of implementing the
alternatives.
• Land/Permitting Study: Determine the feasibility and cost of obtaining the
necessary rights and the regulatory permits for each of the alternatives.
• Recommend brown-field transmission alternatives to the Northwest-California
Steering Committee.
The segment between Selkirk and NEO has been evaluated by BCH and Avista.
WECC defines common corridor as follows: Contiguous right-of-way or two parallel right-of-ways
with structure centerline separation less than the longest span length of the two transmission circuits
at the point of separation or 500 feet, whichever is greater, between the transmission circuits. This
separation requirement does not apply to the last five spans of the transmission circuits entering into
a substation.
6 Facilities on common structures are (of course) in a common corridor.
Staff—PR-030 Attachment A Page 10 of 63
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The following facilities were considered for brown-field alignments
Pacific Northwest - California Upgrades
a.Selkirk - Devils Gap-NEO Segment
• Brown-field 500 kV AC (2-circuits) (evaluated by BCH and Avista)
b.NEO - Captain Jack Segment five route segments as follows: (refer to
Attachment I and Attachment 2)
• PACI: This route follows the existing 500 kV AC lines from NEO-McNary -
Coyote Springs-Slatt-Buckley-COB. DC Construction in this corridor could
be implemented by placing the Buckley-Grizzly-Malin and Buckley-Grizzly CJ
lines on common structures and installing the new DC in the then-vacant nw
• PDCI: This route follows the existing 500 kV AC line from NEO-McNary to
the Pacific DC Intertie. From there, this route follows the PDCI to a point
south of Sand Springs where a new right-of-way would be required. This
route is relatively close to COI corridor, though with greater than 1500 foot
separation. South of Sand Springs, the route veers to the southeast.
• East: This route follows the existing 138 kV, 230 kV, 500 kV lines NEO-
Quarts-Burns-Summer Lake- COB.
• West: This route follows existing 230 kV line corridors that run N-S through
Oregon east of the Cascades.
• Boardman: This route is an alternative between Slatt and NEO. Only one
segment of this route (Slatt-Boardman Plant) is a developed transmission
corridor. The other segments would be-green-field today, but they overlap
with proposed PGE Cascade Crossing and IPC 132H route alternatives.
Attachment 3 provides a preliminary review of these potential alignment options.
c.Captain Jack - Northeast California (NEC) Segment
Replace existing Malin-Round Mountain #1 500 kV line with new 500 kV
double circuit AC line
d.Captain Jack - Olinda Segment
• Co-locate new 500 kV AC (2-circuits) or DC bipole circuits on common
corridor/structure with Copco-Cottonwood 115 kV line
• Convert COTP to bipole DC
e.Olinda - Collinsville Segment
• Co-locate new 500 kV AC (2-circuits) or +1- 500 kV bipole circuits on common
corridor/structure with Cottonwood- Vaca-Dixon-Collinsville 230 kV DCTL
• Co-locate new 500 kV AC (2-circuits) or bipole circuits on common structure
with one Cottonwood- Vaca-Dixon-Collinsville 230 kV circuit
Items I d through I g and Item 2 are being considered in ongoing Western, PG&E, TANG joint
studies of possible California Arrangements.
7
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Convert COTP to bipole DC
f. Collinsviile - Tracy Segment
• Co-locate new 500 kV AC (1-circuit) on common structure with the
Collinsville-Tesla line
• Convert COTP to bipole DC
2. Northern Nevada - Northern California Upgrades
a.NW Nevada - Raven - NEC Segment
• Co-locate 230 kV AC (2-circuits) on common corridor/structure with the Hat
Creek-Westwood (LMUD) line
b.Round Mountain - Olinda - O'Banion Segment
• Convert WAPA's RM-Cottonwood 230 kV and Cottonwood - Roseville 230 kV
line to a 500 kV line and construct short 500 kV line (green-field) to O'Banion
c.O'Banion - Tracy Segment
• Co-locate new 500 kV AC (1-circuit) on common structure with TM-Tesla 500
kV
It should be noted that, after consultation with the Pacific Northwest entities, "brownfield"
options considered to be the most viable in Oregon would be those in common corridor.
The objective of this study is to determine whether various transmission options can be
aligned with existing or proposed transmission in Oregon (brown-field alignment) while
meeting the thermal loading requirements of the NERC Reliability Standards and WECC
System Performance Criteria. These transmission options would provide northern California
parties access to 2000 MW or more of new renewable resources in British Columbia (BC)
and the PNW and 1000 MW of new renewable resources in northeastern California and
northern Nevada.
Based on technical results, the better performing options will be evaluated in an Engineering
Study and Land/Permitting Study to follow this study and to determine the one (or two)
alternative(s) that would be recommended for further consideration in the WECC Path Rating
Process.
5.1 Options
Four options with several sub-options have been considered for this study. These
alternatives combine three of the California alternatives 6 with potential brown-field alignments
8 Six alternatives were evaluated in California involving new AC or DC facilities from Captain Jack
substation to Tracy/Tesla substations together with upgrades of the Western AC transmission in
Northern California. Each alternative models new AC or DC facilities from Selkirk to Devils Gap
substation to NEO substation and then to Captain Jack using green-field alignments to support up to
2000 MW from BC and the PNW.
8
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between NEO and Captain Jack.
There are a number of common elements to the four options, as follows:
Common elements in the Pacific Northwest
• Selkirk-Devils Gap-NEO 500 kV AC circuit
• Devils Gap Project
o 500/230 kV transformer
o 230 kV phase shifters
o 230 kV interconnection with existing facilities in Spokane
Common elements in California
• Installation of the proposed Viewland 345/230 kV Substation looped off Reno-
Alturas 345 kV line
• Viewland-Westwood-NEC 230 kV transmission
• NEC 500/230 kV Substation looped off the Malin-Round Mountain No.1 500 kV
• Western Upgrades
• NEC-Olinda 500 kV AC circuit (Convert RM-Cottonwood line to 500 kV)
• Olinda-O'Banion 500 kV AC circuit (convert Cottonwood-Roseville to 500 kV)
• O'Banion-Tracy 500 kV AC circuits
• Collinsville-Tracy 500 kV AC circuit
Those elements that are unique to each of the options are summarized below:
• Option 1: All AC (Attachment 6)
Includes the following facilities: (a) a NEO-Captain Jack-Olinda—Collinsville 500 kV AC circuit,
and (b) a NEO-NEC 500 kV AC circuit using the East (1 a), PACI (I b) and PDCI (1 c) routes
• Option 2: New AC North of COB and COTP converted to DC (Attachment 7)
Includes the following facilities: (a) a NEO-Captain Jack 500 kV AC circuit Hybrid with COTP,
(b) a N EQ-NEC 500 kV AC circuit, and (c) COTP converted from AC to DC using the PACI
route (2a) and a green-field route paralleling PACI (2b)
• Option 3: AC-DC Conversion North of COB -- COTP converted to DC
(Attachment 8)
Includes the following facilities: (a) NEO-Buckley bipole circuits, (b) Buckley-Captain Jack
converted to DC (3a) or new bipole circuits (3b), and (c) COTP converted from AC to DC
using the PACI route
• Option 4: All DC (Attachment 9)
Includes the following facilities: (a) a NEO-Olinda-Collinsville DC considering all routes
Table I describes in more detail each of the alternatives to be considered.
Staff—PR-030 Attachment A Page 13 of 63
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Table 1: Preliminary PNW-California Brown-field Planning Options
AC Elements = Lighter Green shading DU Ilements = uancer ureen snaaing
The live alignment options for this segment are described in Section 3, Item 1. These alignment options include West, Central AC, Central PDCI, East,
and Boardman
10
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52 Study Cases
This study of Northwest transmission utilized a Benchmark Case developed -from a WECC
201 5HS2 base case."
The Benchmark Case (pre-project) models the COI 4800 MW Upgrade, the West of McNary
Reinforcement, the Boardman-Hemingway projects. Transmission in Northeast Oregon
would be re-configured as shown on Attachment 4 to interconnect these projects. The
Mountain States Transmission Intertie (MSTI) and the Southwest Intertie Project (SWIP)
projects are not modeled. High flow conditions are modeled with 4800 - MW (n-s) on COI and
3100 MW (n-s) on PDCI.
From the Benchmark Case, four Project Cases were developed. Each case models (1) one
of the four options and the common elements in the Northwest and California, described
above, and (2) a total of 3000MW scheduled into central California as follows:
• 750 MW scheduled from BC to central California
• 1250 MW scheduled from the PNW to central California
• 1000 MW from NE California to central California
5.3 Study Standards and Criteria
This study was conducted using the NERC Reliability Standards and the WECC System
Performance Criteria for steady state thermal analysis only. These standards and criteria
require that under NERC Category A (n-0) conditions loadings on all facilities be less than or
equal to their respective normal ratings and under Category B (n-I) and Category C (n-2)
conditions that loadings on all facilities be less than or equal to their respective emergency
ratings. Standards and criteria requirements for voltage and transient performance were not
evaluated.
5.4 Contingencies
This study considered (I) existing critical Category B and Category C outages, (2) new
Category B outages, (3) new Category C outages involving the proposed project and existing
or proposed facilities that would be created by the various alignments and (4) selected
Category D outages.
A list of these outages is available electronically.
5.5 Study Seope
The following studies were performed to determine the proposed plan of service and
demonstrate the non-simultaneous rating of the Project.
10 The 2015 HS2 base case updates the earlier 2015 HSI case used in the California study and is a
more accurate reflection of expected renewable resources and transmission projects in the
Western Interconnection for 2015.
Each of the options assumed the installation of SVCs at all AC stations to which the planned
facilities would interconnect Such SVCs are expected to also support transient and voltage
stability performance
11
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Power Flow or Governor Power flow analysis was performed modeling each of the four
options under the -following conditions
1.Category "A:'- Normal operating conditions.
2.Category "B/C" - Select single and multiple facility outages of the existing system and
various segments of the proposed Project using existing and proposed RAS.
3.Category "D" - S-elect outages of the new line with existing corridors were evaluated
using existing and proposed RAS.
Power flow studies were performed to determine thermal impacts on 230 kV (and higher)
facilities resulting from the increased transfers between the PNW and California for the four
options and the PACI, PDCI, East, West, and Boardman routes.
6.1 Option 1: MAC
Option I includes three sub-options: 1 a, lb and 1 c. The three options utilize the same line
configuration, line conductor and series compensation but differ in how the 500 kV AC lines
are routed between NEO and the Captain JacklMalin area.
Option I - East Alignment (Attachment 61
Option I a modeled the following elements:
• NEO-Grizzly 500 kV I & 2 Lines (with 70% series compensation)
• Grizzly-Captain Jack 500 kV (with 70% series compensation)
• Grizzly-Malin 500 kV Line (with 70% series compensation)
Option 1 a utilizes the East alignment.
Comparison of Path/Line Flows
The following table compares the flows over the major 500 kV lines across the COB transfer
path and over the major Northwestern 500 kV lines into Southern Oregon in the Option I a
Case to those in the Reference Case.
12
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Table 2: Option la--Comparison of Path and Line Flows
ggeggg _g
COB Flows (MW)
Captain Jack-Olinda #1 Line 1,723 ' 1,504 (219)
Captain Jack-Olinda #2 Line n/a 1,504 1,504 -
MaIinRound Mountain #1 Line 1,525 n/a n/a
Maim-Round Mountain #2 Line 1,547 1,257 (290)
MaIm-NEC Line n/a 1,328 1,328
Grizzly-NEC Line n/a 1,122 1,122
Total 4,795 6,715 1920
NEO South and Grizzly South
NEO-Grizzly#1 Line ' n/a 1,428 ' 1,428
N EQ-Grizzly #2 Line n/a 1,428 l-,4-2- 8
Grizzly-Captain Jack #1 Line 1,502 1,511 9
Grizzly-Captain Jack #2 Line n/a 1,080 1,080
Grizzly-NEC#3 Line n/a 1,122 1,122
- Gnzzly-Malin Line 1,434 1,428 (6)
Grizzly-Ponderosa Line 1,391 1418 27
Klamath Falls - Captain Jack Line 664 555 (109)
Summary of Option IA Results
Category A Conditions
No-Category A violations for the PNW region were noted.
Category B Conditions
The following table summarizes Tnformation on the new or increased Category B overloads
noted in studies on the Option 1 Case and compares them to those noted in studies on the
Reference Case.
13
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Table 3: Option I a--Comparison-of Category B Overloads
Loading (%)
Oregon Critical Outage Impacted Facility Rating Reference Opton
Align Case ase
Pacific DC lntertie All LMUD Tap 345-kV n /a 10 Bipole with PDCI RAS PST
(which includes 2700 Hilltop 345/230 kV IvlvvOurlNvvgen 300 <100 1033
dropping) Transformer
The following table summarizes potential methods for mitigating the impacts of the critical
Category B outages for Option I a.
Table 4: Option la-- Potential Mitigation Measures for Category B Impacts
critical Outage Potential Mitigation i
Pacific DC Intertie Bipole 1 . Install a second 345/230 kV transformer at Hilltop and second
I PST at the LMUD Tap (on the Hilltop-LMUD Tap 345-kV line) I
Category C Conditions
No Category C violations for the PNW region were noted.
Category D Conditions
The following table summarizes information on Category D overloads noted in studies on the
Option I a case. Listed overloads are for greater than emergency rating.
14
Staff—PR-030 Attachment A Page 18 of 63
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Table 5: Option I a--Comparison of Category , liOverloads
°" Loading (%)
Critical Outage Impacted Facility Rating
C CaSE
Grizzly - Captain Jack #2
Line 500 kV & Grizzly - NEC 500 kV & Grizzly - East CAPTJACK - GRIZZLY 3220 n/a 104
Malin 500 kV with no #1500 kV Line
generation dropping
Grizzly - John Day #1
Line 500 kV & NEO
Grizzly #1 & #2 Lines East GRIZZLY - JOHN DAY 3220 n/a 116
500 kV DLO with no #2500 kV Line
generation dropping
Grizzly - John Day #2
Line 500 kV & NEO
Grizzly #1 & #2 Lines East GRIZZLY -JOHN DAY 3500 n/a 106
500 kV DLO with no #1500 kV Line
generation dropping
Outages that did not solve were
• Grizzly–Captain Jack #1 and #2 and the Grizzly-NEC 500 kV
• Grizzly-Summer Lake, Grizzly-Captain Jack and Grizzly-NEC 500 kV
Though Category 0 impacts do not require mitigation, potential methods for mitigating such
impacts for Option I a are summarized in the following table.
Table 6: Option la—Potential Mitigation Measures for Category D Impacts
Critical Outage ...ptential Mitigation
Grizzly - Captain Jack #2 Line 500 • Apply up to 3000 MW of generation dropping utilizing
W & Grizzly - NEC 500 kV & Grizzly incremental generation scheduled on the new
- Malin 500 kV transmission
Grizzly - John Day #1 Line 500 kV • Apply up to 3000 MW of generation dropping utilizing
& NEO Grizzly #1 & #2 Lines 500 kV incremental generation scheduled on the new
DLO transmission
Grizzly - John Day #2 Line 500 kV • Rerate to 3500 A by decreasing the conductor sag
& NEO Grizzly #1 & #2 Lines 500 kV • Apply up to 3000 MW of generation dropping utilizing
DLO incremental generation scheduled on the new
transmission
Option lb - PACt Alignment (Attachment 6
Option lb modeled the following elements:
• NEO-Grizzly 500 kV I & 2 Lines (with 70% series compensation)
• Grizzly-Captain Jack 500 kV (with 70% series compensation)
• Grizzly-Malin 500 kV Line (with 70% series compensation)
15
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Option lb utilizes the PACI alignment.
Comparison of Path/Line Flows
The following table compares the flows over the major 500 kV lines across the COB transfer
path and over the major Northwestern 500 kV lines into Southern Oregon in the Option lb
Case to those in the Reference Case.
Table 7: Option lb—Comparison of Path and Line Flows
XFVOU RefereTej Cptionlb Change
Case i Case
COB Flows (MW)
1,723 ' 1,481 ' (244) Captain Jack-Olinda Line #1 Line I
Captain Jack-Olinda Line #2 Line n/a 1,481 1,481
Maim-Round Mountain #1 Line 1,525 n/a (1,525)
MaIm-Round Mountain #2 Line 1547
-------
1,214 (333)-
MaI-NEC Line n/a 1,154 1,154
Grizzly-NEC Line n/a 1,463 1,463
Total 4795 6,793 1,998
NEO South and Grizzly South
n/a 1,475 ' 1 1 475 NEO-Grizzly #1 Line
NEO-Grizzly #2 Line n/a 1,475 1,475
Grizzly-Captain Jack #1 Line 1,502 1,266 (236)
Grizzly-Captain Jack #2 Line n/a 1,554 1,554
Grizzly-Malin Line 1,434 1,206 (228)
Gnzziy-Ponderosa Line 1,391 1,201 (190)
Summer Lake - Maim Line _1_,6_ M35 1,374 (261)
Klamath Falls - Captain Jack Line 1 664 475 (189)
Summary of Results
Category A Conditions
No Category A violations for the PNW region were noted.
Cate-gory B Conditions
16
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The following table summarizes information on the new or increased Category B overloads
noted in studies on the Option lb Case and compares them to those noted in studies on the
Reference Case.
Table 8: Option 1 b--Comparison of Category B Overloads
Loading
Critical Outage Oregon
Align Impacted Facility Rating Reference ObOfl
Case Case
Pacific DC Intertie All LMUD Tap 345-kV 300 a 1029 Bipole with PDCI RAS PST -
(which includes 2700 Hilltop 345/230 kV MW of PNW gen 300 <100 103.3
dropping)
The following table summarizes potential methods for mitigating the impacts of the critical
Category B outages for Option lb.
Table 9: Option 1 b-- Potential Mitigation Measures for Category B Impacts
CTitica1Otage•• Potential Mitigation
Pacific DC Intertie Bipole • Install a second 345/230 kV transformer at Hilltop and second
PST at the LMUD Tap (on the Hilltop-LMUD Tap 345-kV line)_j
Category C Conditions
No Category C violations for the PNW region were noted.
Category 0 Conditions
The following table summarizes information on Category overloads noted in studies on the
Option lb case. Listed overloads are for greater than emergency rating.
17
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Table 10: Option I b--Comparison of Category D Overloads
Loading (%)
Critical Outage regon Impacted Facility Rating Align. Ref. Case lb Case
Grizzly - John Day #1
Line 500 kV & NEO
Grizzly #1 & #2 Lines PACI GRIZZLY JOHN DAY 3220 n/a 117
500 kV DLO with no #2500 kVLine
generation tripping
Grizzly - John Day #1
Line 500 kV & NEO
Grizzly #1 & #2 Lines PACI GRIZZLY -JOHN DAY 3220 n/a 101 500 kV DLO with 2355 #2 500 kV Line
MW of PNW generation
dropping
Grizzly - John Day #2
Line 500 kV & NEO
Grizzly #1 & #2 Lines PACI GRIZZLY JOHN DAY 3500 n/a 108
500 kV DLO with no #1500 kVLine
generation tripping
Outages that did not solve were:
• Grizzly–Captain Jack #1 and #2 and the Grizzly-NEC 500 kV
• Grizzly–Captain Jack, Grizzly-NEC and Grizzly-Malin 500 kV
• Grizzly-Summer Lake, Grizzly-Captain Jack and Grizzly-NEC 500 kV
• Summer Lake-Malin, Grizzly-Captain Jack and Grizzly-NEC 500 1cV
Though Category D impacts do not require mitigation, potential methods for mitigating such
impacts for Option lb are summarized in the following table.
Table II: Option lb—Potential Mitigation Measures for Category D Impacts
Critical Outage Potential Mitigation
Grizzly -John Day #1 Line 500 kV • Apply Northwest High Gen Drop of 2700 MW
& NEO Grizzly #1 & #2 Lines 500 kV • Establish emergency rating for the impacted 500 kV
DLO line
Grizzly - John Day #1 Line 500 kV • Apply Northwest High Gen Drop of 2700 MW
& NEO Grizzly #1 & #2 Lines 500 kV • Establish emergency rating for the impacted 500 kV
DLO with RAS line
Grizzly - John Day #2 Line 500 kV • Apply Northwest High Gen Drop of 2700 MW
& NEO Grizzly #1 & #2 Lines 500 kV • Establish emergency rating for the impacted 500 kV
DLO I line
Option 1 - PDCI Alignment (Attachment 6
Option 1 modeled the following elements:
18
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-. NEO-Grizzly 500 kV 1 & 2 Lines (with 70% series compensation)
• Grizzly-Captain Jack 500 kV (with 70% series compensation)
• Grizzly-Malin 500 kV Line (with 70% series compensation)
Option I c utilizes the PDCI alignment.
Comparison of Path/Line Flows
The following table compares the flows over the major 500 kV lines across the COB transfer
path and over the major Northwestern 500 kV lines into Southern Oregon in the Option 1
Case to those in the Reference Case.
Table 12: Option 1c€-Comparison of Path and Line Flows
4 Relerence Option Ic Ch
COB Flows (MW)
1,723 1,504 (219) Captain Jack-Olinda#1 Line
Captain Jack-Olinda Line #2 Line n/a 1,504 1,504
Maim-Round Mountain #1 Line 1,525 n/a 1,525
Maim-Round Mountain #2 Line 1,547 1,247 (300)
Maim-NEC Line n/a 1,299 1,299
Grizzly-NEC Line n/a 1,172 1,172
Total 4,795 6,726 (1,931)
NEO South and Grizzly South
NEO-Grizzly#1 Line n/a 1,432 ' 1,432
NEO-Grizzly #2 Line n/a 1,432 1,432
Grizzly-Captain Jack #1 Line 1,502 1,413 (89)
Grizzly-Captain Jack -AiY Line n/a 1,332 1,332
Grizzly-NEC #3 Line n/a 1,172 1,172
Grizzly-MaIm Line 1,434 1,341 (93)
Grizzly-Ponderosa Line 1,391 1,334 (57)
Summer Lake - MaIm Line 1,635 1,494 (141)
Kiamath Fails - Captain Jack Line 664 532 (132)
19
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Summary of Results
Category A Conditions
No Category A violations for the PNW region were noted.
Category B Conditions
The following table summarizes information on the new or increased Category B overloads
noted in studies on the Option I c Case and compares them to those noted in studies on the
Reference Case.
Table 13: Option lc--Comparison of Category B Overloads
Loading (%
Reference n Critical Outage Oregon Impacted Facility Rating Align Case Case
Pacific DC Intertie All LMUD Tap 345-kV 300 n a 1029
Bipole with PDCI RAS PST
(which includes 2700 Hilltop 345/230 kV MW of rI'vv gen 300 <100 103.3
dropping)
The following table summarizes potential methods for mitigating the impacts of the critical
Category B outages for Option Ic.
Table 14: Option Ic-- Potential Mitigation Measures for Category B Impacts
Pacific DC Intertie Bipole • Install a second 345/230 kV transformer at Hilltop and second
PST at the LMUD Tap (on the Hilltop-LMUD Tap 345-kV line)
Category C Conditions
No Category C violations for the PNW region were noted.
Category D Conditions
The following table summarizes information on Category D overloads noted in studies on the
Option 1 c case. Listed overloads are for greater than emergency rating.
20
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Table 15:- Option Ic--Comparison of Category D Overloads
Grizzly - Captain Jack
#2 Line 500 kV&
Grizzly - NEC 500 kV & PDCI CAPTJACK- GRIZZLY 3220 n/a 103 Grizzly - Malin 500 kV - #1500 kV Line
with no-generation
tripping
Grizzly - John Day #1
Line 500 kV &NEO
Grizzly #1 & #2 Lines PDCI GRIZZLY - JOHN DAY 3220 n/a 116 500 kV DLO with no #2 500 kV Line
gen tripping
Grizzly - John Day #2
Line 500 kV & NEO
Grizzly #1 & #2 Lines PDCI GRIZZLY -JOHN DAY 3500 n/a 107
500 kV DLO with no #1500 kV Line
generation tripping
Summer Lake - Malin
500 kV & Grizzly -
Captain Jack #2 Line PDCI CAPTJACK - GRIZZLY 3220 n/a 105
500 kV & Grizzly - NEC #1500 kV Line
500 kV with no
generation tripping
Outages that did not solve were:
• Grizzly—Captain Jack #1 and #2 and the Grizzly-NEC 500 kV
• Grizzly—Captain Jack, Grizzly-NEC and Grizzly-Malin 500 kV
• Grizzly-Summer Lake, Grizzly-Captain Jack and Grizzly-NEC 500 kV
• Summer Lake-Malin, Grizzly-Captain Jack and Grizzly-NEC 500 kV
Though Category D impacts do not require mitigation, potential methods for mitigating such
impacts for Option 1 are summarized in the following table.
21
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Table 16: Option ic—Potential Mitigation Measures for Category D Impacts
its Pot entiaI JVIltigatiibr JN
Grizzly - Captain Jack #2 Line 500 • Apply up to 3000 MW of generation dropping utilizing
kV& Grizzly - NEC 500 kV & Grizzly incremental generation scheduled on the new
- Malin 500 kV transmission
Grizzly - John Day #1 Line 500 kV • Apply up to 3000 MW of generation dropping utilizing
& NEO Grizzly #1 & #2 Lines 500 kV incremental generation scheduled on the new
DLO transmission
Grizzly - John Day #2 Line 500 kV • Apply up to 3000 MW of generation dropping utilizing
& NEO Grizzly #1 & #2 Lines 500 kV incremental generation scheduled on the new
DLO transmission
Summer Lake - Malin 500 kV & • Apply up to 3000 MW of generation dropping utilizing
Grizzly - Captain Jack #2 Line 500 incremental generation scheduled on the new
W & Grizzly - NEC 500 kV transmission
6.2 Option 2: New AC in Oregon, COTP converted to DC
Option 2 includes two sub-options: 2a and 2b. Both options convert COTP to DC and
establish the proposed 500-kV lines from NEO to COB with similar line configuration,
conductor size and line compensation. Options 2a and 2b differ in the assumed separation
between the proposed facility and the existing adjacent PACt facility. Option 2a is routed
within the existing PACI corridor (brown field) while Option 2b is routed outside but parallel to
the existing PACI corridor (green field).
Option 2a (PACt alignment - brown field) (Attachment 7
Option 2a modeled the following elements:
Northern California:
• Conversion of the COTP to a + 500 kV DC bi-pole facility
• HVDC terminals at Captain Jack, Olinda, and Tracy
Pacific Northwest:
• New NEO-Grizzly 500 kV 1 & 2 Lines (with 70% series compensation)
• New Grizzly-NEC 500 kV Line (with 70% series compensation)
• New Grizzly-Captain Jack 500 kV Line (with 70% series compensation)
Option 2a utilizes the PACI alignment as follows:
The proposed 500 kV lines from NEO to COB would be routed along the Central
PACI alternative.
Between NEO and COB the proposed 500-kV line would be routed in the same
corridor (brown field) as the existing Slatt-Buckley-Grizzly 500 kV line and the
three 500 kV lines south of Grizzly.
Between Buckley area and COB it was assumed that the new 500 kV lines would
be located within the existing corridor on either the western or eastern side of the
existing 500-kV facilities.
Comparison of Path/Line Flows
22
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The following Itable compares the flows over the major 500 kV lines across the COB transfer
path and over the major Northwestern 500 kV lines into Southern Oregon in the Option 2a
Case to those in the Reference Case.
Table 17: Option 2a--Comparison of Path and Line Flows
Reference Option 2a Change .Ca
COB Flows (MW)
Captain Jack-Olinda Line ' 1,723 ' n/a ' (1,723)
Captain Jack-Olinda DC Bipe n/a 2960 2960 - - -
iUre - id I
—
-----1,547 1,239 (308) - - -
nfa 1156 1,156 iEÔie --
-------------------------- n/a -1,463 ,463 - - -
Total 4,795
I I
6,818 2023
NEO South and Grizzly South
n/a ' 1,479 ' 1,479 NEO-Grizzly#1 Line
ri/a —1,479
---
1,479 0y2 Li ------------------------
1,502 —1,27--
—
(231) --
üe —fl/a —1 559 1,559 - - -
EãI üe i1a-----I ,463
—
1,463 -
ij-
-
44 1 211
-
(223)
-Line
—
04
—
(187) - - -
MaIne ------------------------
—
1,635 1,381 (4) -
- Heni-Sir Le line 456 395 - - - (61)
kithÔfaTrJüie --------------&c
-
664
-
-477
-
-(187) - - -
Summary of Results
Category A Conditions
There were no Category A overloads noted in the Option 2a base case.
Category B Conditions
The following table summarizes information on the new or increased Category B overloads
noted in studies on the Option 2a Case and compares them to those noted in studies on the
Reference Case.
23
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Table 18: Option 2a--Comparison of Category B Overloads
Oeqon
't Miu Case
Pacific DC Intertie PACI LMUD Tap 345-kV 300 n/a 1038
Bipole with PDCI RAS PST
(which includes 2700
MW of PNW gen Hilltop 345/230 kV 300 <100 104.0
dropping) ___________
The following table summarizes potential methods for mitigating the impacts of the critical
Category B outages for Option 2a.
Table 19: Option 2a—Potential Mitigation Measures for Category B Impacts
I Cntk'Otag .: ::
Pacific DC lntertie Bipole • Install a second 345/230 kV transformer at Hilltop and second
I PST at the LMUD Tap (on the Hilltop-LMUD Tap 345-kV line)
Category C Conditions
The following table summarizes information on the new or increased Category C overloads
noted in studies on the Option 2a Case and compares them to those noted in studies on the
Reference Case.
Table 20: Option 2a–Compa6son of Category C Overloads
Marion-Alve)t& PACI Santiam Tap-Marcola 640 <100 1128
Marion-Lane 500 kV Swt #2 230 kV
DLO with gen drop of Grant P 1700 MW ass-Mendian
RAS)
(assumed 230 kV Line 773 <100 100.6
The following table summarizes potential methods for mitigating the impacts of the critical
Category C outages for Option 2a
Table 21: Option 2a—Potential Mitigation Measures for Category C Impacts
Potential Mitigation -. .
.
Marion-Alvey & Marion Lane 500 kV • Establish emergency rating for the impacted 230 kV
DLO lines, or
Reconductoring or rerating the impacted 230 kV lines
24
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Category D Conditions
The following table summarizes information on new Category D contingency overloads noted
in studies of the Option 2a case. The Category D contingencies include a double line outage
of the proposed 500 kV facility with the addition of one parallel 500 kV facility to the studied
western or eastern PACI routings.
Table 22: Option 2a--Comparison of Category D Overloads
Load inq (%)
Critical Outage Oregon Impacted Facility Rating Reference OOfl
Grizzly-John Day #1 PACI (NEO- John Day-Grizzly 500 3,220 n/a 116.8
Line 500 kV & NEO Grizzly: kV #2 Line
Grizzly #1 & #2 Lines Western
500 kV DLO with no Routing)
RAS
Grizzly-John Day #2 PACt (NEO- John Day-Grizzly 500 3,500 n/a 107.6
Line 500 kV & NEO Grizzly: kV #1 Line
Grizzly #1 & #2 Lines Western
500 kV DLO with no Routing)
RAS
Summer Lake-Malin PACI Grizzly-Captain Jack 3,220 n/a 102.0
500 kV & Grizzly- (Grizzly- 500 kV #1 Line
Captain Jack #2 Line COB:
500 kV & Grizzly-NEC Eastern
500 kV with no RAS Routing)
Slatt-Buckley 500 kV & PACI (NEO- Bethel 230/500 kV 940 n/a 101.3
NEO-Grizzly #1 & #2 Grizzly: Transformer #1 Bank
Lines 500 kV DLO with Eastern
no RAS Routing) Bethel 230/500 kV 940 n/a 101.3
Transformer #2 Bank
Though Category D impacts do not require mitigation, potential methods for mitigating such
impacts for Option 2a are summarized in the foHowing table.
25
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Table 23: Option 2a—Potential Mitigation Measures for Category D Impacts
Critical Outage Potential Mitigation
Grizzly-John Day #1 Line 500 kV & • Apply Northwest High Gen Drop of 2700 MW, or
NEO Grizzly #1 & #2 Lines 500 kV • Apply a new alternative gen drop scheme designed to
DLO (NEO-Grizzly: Western Routing) accommodate the proposed upgrades to the
Northwest system
Grizzly-John Day #2 Line 500 kV & • Apply Northwest High Gen Drop of 2700 MW, or
F4EO Grizzly #1 & #2 Lines 500 kV • Apply a new alternative gen drop scheme designed to
DLO(NEO-Grizzly: Western Routing) accommodate the proposed upgrades to the
Northwest system
Summer Lake-Malin 500 kV & Grizzly- • Route new 500 kV facilities to the west of the existing
Captain Jack #2 Line 500 kV & Grizzly- PACI corridor between Grizzly and COB
NEC 500 kV (Grizzly-COB: Eastern
Routing)
Slatt-Buckley 500 kV & NEO-Grizzly #1 • Apply Northwest West of McNary Gen Drop of 2700
& #2 Lines 500 kV DLO (N EQ-Grizzly: MW, or
Eastern Routing) • Apply a new alternative gen drop scheme designed to
accommodate the proposed upgrades to the
Northwest system
Rerate the impacted Transformer Banks
Option 2b (PACI alignment - green field) (Attachment 71
Option 2b modeled the following elements:
Northern California:
• Conversion of the COTP to a +1- 500 kV DC bi-pole facility
• HVDC terminals at Captain Jack, Olinda, and Tracy
Pacific Northwest:
• New N EQ-Grizzly 500 kV I & 2 Lines (with 70% series compensation)
• New Grizzly-NEC 500 kV Line (with 70% series compensation)
• New Grizzly-Captain Jack 500 kV Line (with 70% series compensation)
Option 2b utilizes the PACt alignment as follows:
The proposed 500 kV lines from NEO to COB would be routed in a new corridor
parallel with the existing Slatt-Buckley-Grizzly 500 kV line and the three 500 kV
lines south of Grizzly.
Between NEO and Grizzly and between Grizzly and COB it was assumed that
the new 500 kV line would be located either to the west of the existing corridor or
to the east of the existing corridor with adequate separation such that a three line
contingency would not be determined as a credible outage.
Comparison of Path/Line Flows
The following table compares the flows over the major 500 kV lines across the COB transfer
path and over the major Northwestern 500 kV lines into Southern Oregon in the Option 2b
26
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FINAL
Case to those in the Reference Case.
Table 24: Option 2b--Comparison of Path and Line Flows
rna
COB Flows (MW)
1,723 n/a (1,723) Captain Jack-Olinda Line
Captain Jack-Olinda DC Bipole n/a 2960 2960
Maim-Round Mountain #1 Line 1,525 n/a (1,525)
Maim-Round Mountain #2 Line 1,547 1,239 (308)
Maim-NEC Une n/a 1,156 1,156
Grizzly-NEC Line - n/a 1,463 1,463
Total 1 4,795 6,818 1 2023
NEO South and Grizzly South
N EQ-Grizzly #1 Line n/a ' 1,479 ' 1,479
N EQ-Grizz fit 2 Line n-/-a 1,479 1,479
Grizzly-Captain Jack #1 Line 1,502 1,271 (231)
Grizzly-Captain Jack #2 Line n/a 1,559 1,559
Grizzly-NEC #3 Line n/a 1,463 1,463
Grizzly-Ma W Line 1,434 1,211 (223)
Grizzly-Ponderosa Line 1,391 1,204 (187)
Summer Lake — Maim Line 1,635 1,381 (254)
Hemingway-Summer Lake line 456 395 (61)
Kiamath Falls --:(5 -a ptain Jack Line 664 477 (187)
Summary of Results
Category A Conditions
There were no Category A overloads noted in the Option 2b base case.
Category B Conditions
The following table summarizes information on the new or increased Category B overloads
noted in studies on the Option 2b Case and compares them to those noted in studies on the
Reference Case.
27
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Table 25: Option 2b--Comparison of Category B Overloads
• :. :. . ._Loadin:(%).
it, Re
9fl .. . Oon Cdk.1 Outage . lifaCilitY.. e
Pacific DC Intertie PACI LMUD Tap 345-kV 300 n/a 103.8
Bipole with PDCI RAS PST
(which includes 2700
dropping) Transformer
The following table summarizes potential methods for mitigating the impacts of the critical
Category B outages for Option 2b.
Table 26: Option 2b—Potential Mitigation Measures for Category a Impacts
Critical Outage Potential Mitigation
Pacific DC Intertie Bipole • Install a second 345/230 kV transformer at Hilltop and second
PSI at the LMUD Tap (on the Hilltop-LMUD Tap 345-kV line)
Category C Conditions
The following table summarizes information on the new or increased Category C overloads
noted in studies on the Option 2b-Case and compares them to those noted in studies on the
Reference Case.
Table 27: Option 2b--Comparison of Category C Overloads
... . .•. . .. Lpading.(%)
Critical Outage 0h1 Impacted Facility Rating Refeience . OPtion
Marion-Alvey & PACI Santiam Tap-Marcola Swt #2 640 <100 112.8
Marion-Lane 500 kV 230 kV
Grant Pass-Meridian 230 kV 773 <100 100.6 1700 MW (assumed - Line
-
RAS) -
The following table summarizes potential methods for mitigating the impacts of the critical
Category C outages for Option 2b.
Table 28: Option 2b—Potential Mitigation Measures for Category C Impacts
rt:T . • Potential Mitigation ..... : ........................ 4.
Marion-Alvey & Marion-Lane 500 kV • Establish emergency rating for the impacted 230 kV
DLO lines, or
Reconductoring or rerating the impacted 230 kV lines
28
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Cateciorv D Conditions
There were no new Category D contingencies including the proposed line and an existing
adjacent 500-kV line. The assumed separation between the existing PACI corridor and the
proposed green-field was such that the risk of a Category D event of this type would be
minimized.
6.3 Option 3: Convert NED-COB to DC, COW Converted to DC
Option 3 includes two sub-options: 3a and 3b. Both options convert COTP to DC but differ in
how they establish DC in the PNW using the PACI route. Option 3a establishes a new DC
line from NEO to Buckley and converts the Buckley-Grizzly-Captain Jack line from AC to DC.
Option 3b establishes a new DC line from NEO to Captain Jack
Option 3a - New DC plus convert AC to DC (Attachment 8)
Option 3a modeled the following elements:
Northern California:
• Conversion of the COTP to a +1- 500 kV DC bi-pole facility
• HVDC terminals at Captain Jack, Olinda, and Tracy
Pacific Northwest:
• A new +1- 500 kV DC line from NEO to the Buckley area
• Conversion of the Buckley-Grizzly and -Grizzly-Captain Jack lines to a + 500 kV
DC facility.
• HVDC terminals at NEO and additional terminals at Captain Jack
Option 3a utilized the PACI alignment as follows:
• The proposed +1- 500 kV HVDC bipole from NEO-Captain Jack would be routed
along the Central PACI alternative with the existing Buckley-Grizzly and Grizzly-
Captain Jack lines being utilized as part of the Bipole upgrade.
Comparison of PathlUne Flows
The following table compares the flows over the-major 500 kV lines across the COB transfer
path and over the major Northwestern -500 kV lines into Southern Oregon in the Option 3a
Case to those in the Reference Case.
29
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FINAL
Table 29: Option 3a--Comparison of Path and Line Flows
"T JOUNI
COB Flows (MW)
Captain Jack-Olinda Line 1,723 n/a (1,723)
Captain Jack-Olinda DC Bipole n-/-a 2,916 - 2,916
Maim-Round Mountain #1 Line 1,525- n/a - (1525)
Maim-Round Mountain #2 Line 1,547 1,647 100
Maim-NEC Line n-/-a 2,253 2,253
Total 4795
I I
6816 2,021
NEO South and Grizzly South
n/a ' 3,758 ' 3,758 NEO-Captain Jack DC Bipole
Grizzly-Captain Jack #1 Line 1,502 n/a (1,502)
Grizzly-Maim Line 1,434 1,517 83
Gnzziy-Ponderosa Line 1,391 1,527 136
Summer Lake - Maim Line 1,635 1,674 39
Hemingway-Summer Lake line 456 371 (85)
Klamath Falls - Captain Jack Line 664 626 (38)
Summary of Results
Category A Conditions
There were no Category A overloads noted in the Option 3a base case.
Category B Conditions
The following table summarizes information on the new or increased Category B overloads
noted in studies on the Option 3a Case and compares them to those noted in studies on the
Reference Case.
Table 30: Option 3a--Comparison of Category B Overloads
LUUW1.U/O)
Critical Outage Oregon Align Impacted Facility Rating Reference OPtion
Pacific DC intertie PACI LMUD Tap 345-kV PST 300 n/a 105.5
RAS (which Oô""" iô
includes 2700 MW Transformer
of PNWgen
dropping)
30
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The following table summarizes potential methods for mitigating the impacts of the critical
Category B outages for Option 2b.
Table 31: Option 3a—Potential Mitigation Measures for Category B Impacts
Critical Outage Potential Mitigation
Pacific DC Intertie Bipole • Install a second 345/230 kV transformer at Hilltop and a
second 345-kV PST at the LMUD Tap
Category C Conditions
The following table summarizes information on the new or increased Category C overloads
noted in studies on the Option 3a Case and compares them to those noted in studies on the
Reference Case.
31
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Table 32: Option 3a--Comparison of Category C Overloads
Loactinq
Critical Outage Oregon Impacted Facility Rating Reference Optith
Grizzly-Malin 500 kV PACI All - <100 Diverged
& Summer Lake-Malin
500 kV DLO with gen
drop of 2700 MW
(assumed RAS)
Grizzly-Summer Lake PAC[ Redmond West-Round 1,052 <100 124.6
500 kV & Grizzly- Butte South 230 kV #1
Malin 500 kV DLOwith Line
gen drop of 2700 MW V""" dÔT"" (assumed RAS) Butte 230 kV #1 Line
John Day-Grizzly I & PACI MAUPIN-Big Eddy2 230 900 n/a 101.9
2 500 kV DLO with kV Line
gen drop of 2700 MW
(assumed RAS)
Marion-Alvey & PACI SANT TAP-MARC SW2 640 <100 123.9
Marion-Lane 500 kV 230.0 #2
DLO with gen drop of <100 102.2 1700 MW (assumed 230.0 #1 RAS)
John Day-Grizzly 500 PACI John Day-Grizzly 500 3,220 n/a 113.9
kV #1 Line & NEO- kV #2 Line
Captain Jack DC
Monopole
No RAS
John Day-Grizzly 500 PACI John Day-Grizzly 500 3,500 n/a 104.9
kV #2 Line & NEO- kV#1 Line
Captain Jack DC
Monopole
No RAS
Grizzly-Malin 500 kV PACI Summer Lake-Malin 3,600 n/a 116.2
& NEO-Captain Jack 500 kV Line
DC Monopole
No RAS
The following table summarizes potential methods for mitigating the impacts of the critical
Category C outages for Option 2b.
32
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Table 33: Option 3a—Potential Mitigation Measures for Category C Impacts
Ctftical Outage Potential MitigatlQn
Grizzly-Malin 500 kV & Summer • Fast Ramping N EQ-Captain Jack Bipote, and
Lake-Malin 500 kV DLO • Apply Northwest High Gen Drop of 2700 MW, or
• Apply a new alternative gen drop scheme designed to
accommodate the proposed upgrades to the
Northwestsystem
Grizzly-Summer Lake 500 kV & • Fast Ramping N EQ-Captain Jack Bipole, and/or
Grizzly-Malin 500 kV DLO • Rerating affected 230 kV facilities
John Day-Grizzly I & 2 500 kV DLO • Fast Ramping NEQ-Captain Jack Bipole and/or
______________________________ • Rerating affected 230 kV facilities
Marion-Alvey & Marion-Lane 500 kV • Fast Ramping N EQ-Captain Jack Bipole and/or
DLO • Reconductor or rerating affected 230 kV facility
John Day-Grizzly 500 kV #1 Line & • Apply Northwest High Gen Drop of 2700 MW, or
NEO-Captain Jack DC Monopole • Apply a new alternative gen drop scheme designed to
accommodate the proposed upgrades to the
Northwestsystem
John Day-Grizzly 500 kV #2 Line & • Apply Northwest High Gen Drop of 2700 MW, or
NEO-Captain Jack DC Monopole • Apply a new alternative gen drop scheme designed to
accommodate the proposed upgrades to the
Northwestsystem
Grizzly-Malin 500 kV & NEQ-Captain • Apply Northwest High Gen Drop of 2700 MW, or
Jack DC Monopole • Apply a new alternative gen drop scheme designed to
accommodate the proposed upgrades to the
Northwest system
Category D Conditions
The following table summarizes information on new Category D contingency overloads noted
in studies of the Option 3a case. The Category 0 contingencies include a double line outage
of the proposed 500 kV facility with the addition of one parallel 500 W.
33
Staff—PR-030 Attachment A Page 37 of 63
FINAL
Table 34: Option 3a--Comparison of Category D Overloads
NEU i.oading (%).
Reference OptIon Critical Outage imPacted FaCultY Raling
Ashe-Marion 500 PACI Bethel 230/500 kV 940 n/a 103.6
kV & NEO-Captain Transformer #1 Bank
Jack DC Bipole
No RAS Transformer #2 Bank
John Day-Grizzly #2 PACI Grizzly-John Day 500 kV 3500 n/a 132.7
Line 500 kV &NEO- #1 Line
Captain Jack DC
Bipole Transformer #1 Bank
NoRAS Bethel 230/500 kV 940 n/a 100.9
Transformer #2 Bank
John Day-Grizzly #1 PACI Grizzly-John Day 500 kV 3220 n/a 144.5
Line 500 kV &NEO- #2 Line
Captain Jack DC Bethel 'o n/a fôö9 Bipole Transformer #1 Bank
NoRAS
..................
Bethel 230/500 kV 940 n/a 100.9
Transformer #2 Bank
Grizzly-Malin 500 PACI All - n/a Diverged
kV & NEO-Captain
Jack DC Bipole
No RAS
Slatt-Buckley 500 PACI Bethel 230/500 kV 940 n/a 107.8
kV & N EQ-Captain Transformer #1 Bank
Jack DC Bipole Bethel 940 n/a 1078
No RAS Transformer #2 Bank
Though Category D impacts do not require mitigation, potential methods for mitigating such
impacts for Option 3a are summarized in the following table.
Staff—PR-030 Attachment A Page 38 of 63
FINAL
Table 35: Option 3a—Potential Mitigation Measures for Category D Impacts
Critical Outage Potential Mitigation
Ashe-Marion 500 kV & NEO-Captain • Apply Northwest West of McNary Gen Drop of 2700
Jack DC Bipole MW, or
Apply a new alternative gen drop scheme designed to
accommodate the proposed upgrades to the
Northwest system, or
• Rerate Bethel 230/500 kV Transformer #1 & #2 Banks
John Day-Grizzly #1 Line 500 kV • Apply Northwest High Gen Drop of 2700 MW, or
&NEO-Captain Jack DC Bipole • Apply a new alternative gen drop scheme designed to
accommodate the proposed upgrades to the
Northwest system, and
• Additional RAS Required
John Day-Grizzly #2 Line 500 kV • Apply Northwest High Gen Drop of 2700 MW, or
&NEO-Captain Jack DC Bipole • Apply a new alternative gen dropscheme designed to
accommodate the proposed upgrades to the
Northwest system, and
• Additional RAS Required
Grizzly-Malin 500 kV & NEO-Captain • Apply Northwest High Gen Drop of 2700 MW, or
Jack DC Bipole • Apply a new alternative gen drop scheme designed to
accommodate the proposed upgrades to the
Northwest system, and
• Additional RAS Required
Slatt-Buckley 500 kV & NEO- • Apply Northwest West of McNary Gen Drop of 2700
Captain Jack DC Bipole MW, or
• Apply a new alternative gen drop scheme designed to
accommodate the proposed upgrades to the
Northwest system, and/or
• Rerate Bethel 230/500 kV Transformer Banks #1 & #2
Option 3b - New DC (Attachment 8
Option 3b modeled the following elements:
Northern California:
• Conversion of the COTP to a +1- 500 kV DC bi-pole facility
• HVDC terminals at Captain Jack, Olinda, and Tracy
Pacific Northwest:
• A new NEO-Captain Jack +1- 500 kV DC bi-pole facility
• HVDC terminals at NEO and additional terminals at Captain Jack
Option 3b routing assumptions include:
• The proposed +1- 500 kV HVDC bipole from NEO-Captain Jack would be routed
along the Central PACI alternative.
• Between NEO and Grizzly and between Grizzly and COB it was assumed that
the new DC line would be located either on the west side of the existing corridor
or on the east side of the existing corridor
35
Staff_PR030 Attachment A Page 39 of 63
FINAL
Comparison of Path/Line Flows
The following table compares the flows over the major 500 kV lines across the COB transfer
path and over the major Northwestern 500 kV lines into Southern Oregon in the Option 3b
Case to those in the Reference Case.
Table 36: Option 3b--Comparison of Path and Line Flows
Reference
Case
Option 3b e Case
COB Flows (MW)
Captain Jack-Olinda Line ' 1,723 ' n/a ' (1,723)
Captain Jack-Olinda DC p-ole n/a 2,916 2,916
Maim-Round Mountain W1 Line 1,525 n-/-a (1,525)
Maim-Round Mountain #2 Line 1,547 1,645 98
Maim-NEC Line n/a 2,250 2,250
Total 4795 6,811 r 2,016
NEO South and Grizzly South
n/a ' 2,277 ' 2,277 NEO-Captain Jack DC Bipole
Grizzly-Captain Jack #1 Line 1,502 1,467 (35)
Gnzzly-Malmn Line 1,434 1,441 7
Gnzzly-Ponderosa Line 1,391 1,407 16
Summer Lake :__Ma_W Line 1,635 1,643 8
Hemingway-Summer Lake line 456 452 (4)
Kiamath Falls - Captain Jack Line 1 664 1 591 1 (73)
Summary of Results
Category A Conditions
There were no Category A overloads noted in the Option 3b base case.
Category B Conditions
The following table summarizes information on the new or increased Category B overloads
noted in studies on the Option 2b Case and compares them to those noted in studies on the
Reference Case.
Staff—PR-030 Attachment A Page 40 of 63
FINAL
Table- 37: Option 3b--Comparison of Category B Overloads
Critical Outage Impacted Facility Rating
Loading (%)
Refer:nce Option
Case
Pacific DC Intertie PACI LMUD Tap 345-kV PST 300 n/a 105.2
Bipole r ---/a oo 1Ô3.6 --
includes 2700 MW
--
of PNW gen
-
dropping)
The following table summarizes potential methods for mitigating the impacts of the critical
Category B outages for Option 2b.
Table 38: Option 3b—Potential Mitigation Measures for Category B Impacts
Critical Outage Potential Mitigation
Pacific DC Intertie Bipole • Install a second 345/230 kV transformer bank at Hilltop and a
second 345-kV PST at the LMUD Tap
Category C Conditions
The following table summarizes information on the new or increased Category C overloads
noted in studies on the Option 2b Case and compares them to those noted in studies on the
Reference Case.
Table 39: Option 3b--Comparison of Category C Overloads
• _________________________
Manon-Atvey & All SANT TAP-MARC SW2 640 <100 120.6
Marion-Lane 500 kV 230.0 #2
DLO with gen drop of AfliP- ------- -3 -100 - 1700 MW (assumed
RAS) 230.0
The following table summarizes potential methods for mitigating the impacts of the critical
Category C outages for Option 3b.
37
Staff_PR030 Attachment A Page 41 of 63
FINAL
Table 40: Option 3b—Potential Mitigation Measures -for Category C Impacts
icW j IA
Marion-Alvey & Marion-Lane 500 kV • Fast Ramping NEC-Captain Jack Bipole and/or
DLO • Reconductor or rerating affected 230 kV facility
Category D Conditions
The following table summarizes information on new Category D contingency overloads noted
in studies of the Option 3b case. The Category D contingencies include a double line outage
of the proposed 500 kV facility with the addition of one parallel 500 kV facility to the studied
western or eastern routings.
Table 41: Option 3b--Comparison of Category D Overloads
Cntcag j I*dediacilfty
__________
Tv
John Day-Grizzly #1 PACI Grizzly-John Day 500 kV #2 3220 n/a 111.4
Line 500 kV &NEO- (NEO- Line
Captain Jack DC Grizzly:
Bipole with no RAS Eastern
Routing)
John Day-Grizzly #2 PACI Grizzly-John Day 500 kV #1 3500 n/a 102.6
Line 500 kV &NEO- (NEC- Line
Captain Jack DC Grizzly:
Bipole with no RAS Eastern
Routing)
Slatt-Buckley 500 kV PACI Bethel 230/500 kV 940 n/a 105.4
& NEOCaptain Jack (NEC- Transformer #1 Bank
DCBipole with no - 05.4 RAS Transformer #1 Bank
. .
Routing)
Though Category D impacts do not require mitigation, potential methods for mitigating such
impacts for Option 3b are summarized in the following table.
Staff—PR-030 Attachment A Page 42 of 63
FINAL
Table 42: Option 3b—Potential Mitigation Measures for Category D Impacts
Critical Outage Potential Mitigation
John Day-Grizzly #1 Line 500 kV & • Apply Northwest High Gen Drop of 2700 MW, or
NEO-Captain Jack DC Bipole (NEO- • Apply a new alternative gen drop scheme designed to
Grizzly: Eastern Routing) accommodate the proposed upgrades to the Northwest
system
John Day-Grizzly #2 Line 500 kV • Apply Northwest Hgh Gen Drop of 2700 MW, or
&NEO-Captain Jack DC Bipole • Apply a new alternative gen drop scheme designed to
(NEO-Grizzly: Eastern Routing) accommodate the proposed upgrades to the Northwest
system
Slat-Buckley 500 kV & NEO-Captain • Apply Northwest West of McNary Gen Drop of 2700
Jack DC Bipole (NEO-Grizzly: MW, or
Eastern Routing) • Apply a new alternative gen drop scheme designed to
accommodate the proposed- upgrades to the Northwest
system and/or
• Rerate Bethel 230/500 kV Transformer Banks #1 & #2
6.4 Option 4: All DC
Option 4 modeled a +1- 500 kV DC bipole facility from NEO to Collinsville with HVDC
terminals at NEO, Olinda and Collinsville. (Attachment 9)
Option 4 tested all of the alignments.
Comparison of Path/Line Flows
The following table compares the flows over the major 500 kV lines across the COB transfer
path and over the major Northwestern 500 kV lines into Southern Oregon in the Option 4
Case to those in the Reference Case.
39
Staff_PR030 Attachment A Page 43 of 63
FINAL
Table 43: Option 4--Comparison of Path and Line Flows
•
Case
ieTerence
Case I
COB Flows
1,723 ' 1,575 1621 -148 Captain Jack-Olinda Line '
NEO-Olinda DC Bipole n/a 2,010 2016 2,010
Maim -Round Mountain FT W -1,525 1,525 n/a
MaIm-Round Mountain #2 Line 1547 1,246 1298 -301
Maim-NEC Line 1892 1,819 n/a 1,819
Grizzly-NEC Line 0 n/a n/a
Total 4,795
I
61650
I
6827
I I
1,855
NEO South
866 -739
NEO-McNary -1 -253 -1371 -118
NEO-Olinda DC Bipole n/a 2,010 2,010
Grizzly-Captain Jack Line 1,502 1481 -21
Grizzly-Maim Line -15 1,434 1419
Gnzzly-Ponderosa Line -31 1,391 1360
Summer Lake - Malin Line 1,635 1640 5
Hemingway-SummerLake line 456 497 41
Klamath Falls - Captain Jack Line 664 622 -42
Summary of Results
Category A Conditions
There were no Category A overloads noted in the Option 4 Case.
Category B Conditions
The following table summarizes information on the new or increased Category B overloads
noted in studies on the Option 4 Case and compares them to those noted in studies on the
Reference Case.
40
Staff _PR_030 Attachment A Page 44 of 63
FINAL
Table 44: Option 4--Comparisonof Category B Overloads
Re Critical Outage Oregon Align • impacted Facility Rating rnce OPtion
Pacific DC Intertie PACI LMUD Tap-345-kV PST 300 n/a 105.5
Bipole with PDCI
RAS (which Hilltop 345/230 kV 300 n/a 105.5
includes 2700 MW Transformer
of PNW gen
dropping)
The following table summarizes potential methods for mitigating the impacts of the critical
Category B outages for Option 2b.
Table 45: Option 4—Potential Mitigation Measures for Category B Impacts
tical.Outa ;. .Ptéit .Mitigaticti .. •..
Pacific DC Intertie Bipole • Install a second 345/230 kV transformer at Hilltop and a
second 345-kV PST at the LMUD Tap
Category C Conditions
The following table summarizes information on the new or increased Category C overloads
noted in studies on the Option 2b Case and compares them to those noted in studies on the
Reference Case.
Table 46: Option 4--Comparison of Category C Overloads
HIM M HIPS owl ON 'RFWI-R M.
Manon Alvey &Marion All Sant Tap-Marc Sw2 640 <100 120.6
Lane 500 kV DLO 230 kV #2
Bethel-PanshGp 230 1,283 <100 104.1
W #1
Hill Top 345/230 kV 300 n/a 102.5 South of NEO PDCI
Monopole and PDCI transformer
of LM a P1Wgendrop Phase Shifter
-----
-
(PDCI RAS)
The following table summarizes potential methods for mitigating the impacts of the critical
Category C outages for Option 4.
41
Staff—PR-030 Attachment A Page 45 of 63
FINAL
Table 47: Option 4—Potential Mitigation Measures for Category C Impacts
L
Marion-Alvey & Marion-Lane • Fast Ramping NEO-Captain Jack Bipole
500 kV DLO • Reconductor or rerating affected 230 kV facility
South of NEO Monopole plus • Install 2nd 345/230 kV at Hilltop or replace existing
PDCI Bipole transformer at Hilltop with a higher rated transformer
• Install a higher rated phase shifter at LMUD Tap
Cat&iorv D Conditions
The following table summarizes information on new Category D contingency overloads noted
in studies of the Option 4 case. The Category D contingencies include a double line outage
of the proposed 500 kV facility with the addition of one parallel 500 kV facility to the studied
western or eastern routings.
Table 48z Option 4--Comparison of Category D Overloads
kr 1àr,ton
Align Case 3b.
John Day-Grizzly PACI Grizzly-John Day 500 kV #2 3220 n/a 111.4
#1 Line 500 kV & Line
South of NEO DC
Rang___
Bipole with no RAS
John Day-Grizzly PACI Grizzly-John Day 500 kV #1 3500 n/a 102.6
#2 Line 500 kV & Line
South of NEO DC
Bipole with no RAS
Slatt-Buckley 500 PACI Bethel 230/500 kV 940 n/a 105.4
W & South of NEO Transformer #1 Bank
DCBipole with no
•i•io0 W 940 n/a 105.4 RAS Transformer #1 Bank
Though Category D impacts do not require mitigation, potential methods for mitigating such
impacts for Option 4 are summarized in the following table.
Table 49: Option 4—Potential Mitigation Measures for Category D Impacts
42
Staff_PR030 Attachment A Page 46 of 63
FINAL
Critical Outage Potential Mitigation
John Day-Grizzly #1 Line 500 kV & • Apply Northwest High Gen Drop of 2700 MW, or
NEO-Captain Jack DC Bipole • Apply a new alternative gen drop scheme designed to
accommodate the proposed upgrades to the Northwest
system
John Day-Grizzly #2 Line 500 kV • Apply Northwest High Gen Drop of 2700 MW, or
&NEO-Captain Jack DC Bipole • Apply a new alternative gen drop scheme designed to
accommodate the proposed upgrades to the Northwest
system
Slatt-Buckley 500 kV & N EQ-Captain • Apply Northwest West of McNary Gen Drop of 2700
Jack DC Bipole MW, or
• Apply a new alternative gen drop scheme designed to
accommodate the proposed upgrades to the Northwest
system and/or
• Rerate Bethel 230/500 kV Transformer Banks #1 & #2
The study results indicate the following:
There were no Category A overloads for any of the options.
2.

All of the options experienced Category B overloads of the
Hilltop 345/230 kV transformer and the proposed LMUD Tap phase shifter for a PDCI
bipole outage. A second transformer would be required at Hilltop and LMUD Tap,
respectively.
3. Option I
a.There were no Category C overloads.
b.There were several Category D overloads for Options Ia, lb and Ic.
Though not required mitigation could be provided by the use of generation
tripping or re-rating/reconductoring the overloaded 500 kV transmission facilities.
C.

Some contingencies did not converge. Analysis in future studies should
include additional reactive voltage support where needed.
4. Option 2
a.The Option 2a Category C overloads on known existing contingencies
could likely be mitigated by modifications to the existing RAS and/or establishing
emergency ratings for the effected facilities. The Category D overloads in the
Option 2a case involving both circuits of the new line and one circuit of the
existing parallel facility may be of concern when routed on the western side of the
existing PACI corridor of the NEO to Grizzly segment and on the eastern side of
the Grizzly to COB segment. These contingencies would be less of a concern if
routing of the post project could be located on the opposite side of the existing
corridor.
b.The Option 2b Category C overloads on known existing contingencies
could likely be mitigated by modifications to the existing RAS and/or establishing
emergency ratings for the effected facilities. There were no new Category D
contingencies for Option 2b. The assumed separation between the existing
PACI corridor and the proposed green-field was such that the risk of a Category
D event of this type would be minimized.
C. Option 2a and Option 2b performed similarly with the exception to the
43
Staff—PR-030 Attachment A Page 47 of 63
FINAL
potential credible contingencies. By using alternative routing options for the
Option 2a case in locations of the reported critical three line contingencies the
Option 2a case would likely be superior in economics as less land would be
required.
5. Option 3
a.The Option 3a Category C overloads on known existing contingencies
could be mitigated by modifications to the existing RAS and/or establishing
emergency ratings for the effected facilities and/or increasing the transfers on the
NEO-Captain Jack DC bipole. The Category D overloads in the Option 3a case
including the NEO-Captain Jack bipole outage and a single line outage of the
existing adjacent facility may be of concern when the existing facility includes the
John Day to Grizzly 500-kV #1 or #2 lines or the Grizzly to Malin 500-kV line.
Adequate RAS was not found to mitigate these overloads but would likely include
a new alternative generation dropping scheme designed to accommodate the
proposed upgrades to the Northwest system that may exceed the current 2=700
MW used in the "High Generation Dropping" scheme. In addition, load shed
within the Northwest and/or the Northern California region may be required as
part of the RAS necessary for mitigation.
b.The Option 3b Category B and Category C overloads on known existing
contingencies could be mitigated by modifications to the existing RAS and/or
establishing emergency ratings for the effected facilities and/or increasing the
transfers on the NEO-Captain Jack DC bipole. The Category D overloads in the
Option 3b case including the NEO-Captain Jack bipole outage and a single line
outage of the existing adjacent facility were found to be mitigated by utilizing
similar generation dropping schemes as regional Category C contingencies not
exceeding 2700 MW. A new optimized generation dropping scheme designed to
accommodate the proposed upgrades to the Northwest system would also likely
mitigate the same overloads with an overall more favorable impact on the
existing system.
C. The Option 3b overall performance was superior to Option 3a. Option 3a
and Option 3b performed very differently under both normal and contingency
conditions. Option 3a utilized existing facilities as part of the line build which
under normal conditions the NEO to Captain Jack Bipole transfers were
approximately 1500 MW greater than in Option 3b. In addition, Option 3a
Category D contingencies that included the NEO to Captain Jack Bipole and a
parallel 500 kV facility created much more stress on the remaining facilities than
Option 3b. The required mitigation for such contingencies in Option 3a would
likely lead to a reduction in overall north-to-south transfer limitations compared to
other options within this study.
6. Option 4
a.Category C overloads occur for a PDCI alignment. (The other alignments
provide better system performance.) Those overloads that occur for a PDCI
bipole outage could potentially be mitigated by additional generation dropping
and/or re-rates to facilities.
b.Though not required Category D overloads could be mitigated by the
application of up to 3000 MW of generation dropping involving generation
scheduled on the south of NEO DC.
44
Staff_PR_030 Attachment A Page 48 of 63
FINAL
To the extent the Steering Team chooses to continue work on Brownfield Opportunities, an
Engineering study and a Land study is recommended for Options 1, 2, 3b and 4 using the
PACI and East Alignments in Oregon and the COTP conversion and 230 kV alignment in
California.
The proposed Engineering Study would consist of the following tasks:
Task 1. Conceptual Tower Line Configurations: Determine possible single circuit or
double circuit tower configurations including conductor size/type.
Task 2. AC/DC Interaction Study: Any of the alternatives that involve construction
of DC in close proximity to AC should be analyzed. Such a study would
identify the level of induced AC current on DC transmission, and identify
possible mitigation if such induced current exceed acceptable levels.
Task 3. Constructability: determine the process for constructing new transmission,
including potential requirements for clearances to accomplish construction.
Task 4. Maintenance:
• Determine the preliminary procedures (including clearance requirements)
for performing maintenance.
• Determine possible modifications to work procedures.
• Determine if new tools are needed to perform maintenance.
• Identify the training requirements for maintenance crews.
Task 5. Cost Estimates: Based on the findings of the engineering assessment,
develop line and station cost estimates (decision quality, +1- 50%) for all
feasible alternatives.
Task 6. Assessment Report: Prepare draft and final reports.
The proposed Land Study would consist of the following tasks:
Task 1. Fatal Flaw Analysis: Determine whether the alternative/alignment would
involve a corridor for which a permit could not obtained-due to existing
environmental or land use constraints.
Task 2. Right-of-way Analysis:
• Determine existing land rights, including width, voltage restrictions,
number of lines/circuits restrictions, and existing mitigation.
• Determine which lines require rights-of-way perfection
• Identify affected land owners
Task 3. Determine Preliminary Permitting Requirements
Task 4. Cost Estimates: Based on the findings of the land assessment, develop
decision quality cost estimates (+/- 50%) for all feasible
alternatives/alignments.
Task 5. Assessment Report: Prepare draft and final reports.
45
Staff—PR-030 Attachment A Page 49 of 63
FINAL
Future power system study work should consider the options, noted above, evaluating
power flow, transient stability, and voltage stability analyses with both north-to-south and
south-to-north transfers.
46
Staff—PR-030 Attachment A Page 50 of 63
Attachment 1: Map of Conceptual Routing Alignments: NEO - COB
47
iru
Staff_PR_030 Attachment A Page 51 of 63
FINAL
Attachment 2: Table of Conceptual Routing Segments: NEO - COB
Route Segment Description Corridor Info Length Owners Siting Notes
West COB I Klamath I La 500 kV AC (COB - Kiam PAC, Klamath Falls (city) Pine only), 230 kV AC BPA
La Pine I Pilot Butte I - 230 kV AC Bend (city). Line needed fgr load service
Challenging due to Bend &
I - 230 kV AC, additional PAC, Redmond (cities), including
Pilot Butte I Redmond 230 kV AC (sgl) for part of BPA residential subdivisions near both
route PB and Red. Line needed for load
service
Redmond I Crossing Redmond (city). Line needed for of Grizzly - Round I - 230 kV AC BPA load service Butte 500 kV
Crossing of Grizzly - BPA, Round Butte 500 kV I 1 - 230 kV AC PGE Line needed for load service
Junction with PDCI
Crossing of Grizzly -
Round Butte 500kV/ 1-500kVAC PGE
Grizzly
Pilot Butte I I - 230 kV AC, additional BPA, Challenging due to Bend (city),
Ponderosa 230 kV AC (sgl) for part of PAC including residential subdivisions
route near PB
Existing line needed for load
La Pine I Fort Rock 1 - 115 kV AC (radial) BPA service. 500 kV series caps at Fort
Rock
Maupin - Buckley 2-500 kV AC (dbl), 1 - 230 BPA kV AC
48
Staff_PR_030 Attachment A Page 52 of 63
FINAL
Route Segment Description Corridor Info Length Owners Siting Notes
Central / BPA,
PACI COB I Summer Lake 3-500 kV AC (sgl) PAC, 500 kV series caps at Sycan
PGE
Summer Lake / Fort 3-500 kV AC (sgl)
BPA,
PAC, 500 kV series caps at Fort Rock Rock PGE
Fort Rock I Ponderosa 3-500 kV AC (sgl)
BPA,
PAC, 500 kV series caps at Fort Rock and
PGE Sand Springs
Ponderosa I Grizzly 3-500 kV AC (sgl)
BPA,
PAC, 500/230 kV transformer tap at
PGE Ponderosa
Grizzly - Buckley 3-500 kV AC (sgl) BPA 500 kV series caps at Bakeoven
(2011)
Buckley - Slatt 2- 500 kV AC (dbl), I - 230 BPA Overlap with PGE's proposed
kV AC Cascade Crossing Project
1 -500 kVAC, 1 -230 kV
Slatt - Coyote AC, 1 - 115 kV (radial), 2- BPA Boardman(town). 115 kV line
500 kV AC (dbl) for part of needed for load service.
segment
Umatilla and Hermiston (cities).
Coyote - McNary I - 500 kV AC, 2-230 kV BPA McNary sub is physically
AC (sgl) constrained. One of the 230 kV
lines serves radial load
1 - 500 kV AC (sgl) & 1 - BPA Umatilla and Hermiston (cities).
McNary - NEO 230 kVAC (sgl) for part of (part of McNary sub is physically
constrained. Some green-field route route),? needed depending on NEO site.
49
Staff—PR-030 Attachment A Page 53 of 63
FINAL
Route Segment Description Corridor Info Length Owners Siting Notes
Pacific DC NOB I Crossing of May require green-field segment to
Intertie Hemingway - Summer 00 kV DC Bipole connect to existing transmission
Lake corridors in N. CA
Crossing of
Hemingway - Summer 500 kV DC Bipole
Lake - Ponderosa
Ponderosa I Grizzly 500 kV DC Bipole BPA
Grizzly / Maupin 500 kV DC Bipole, 1 - 230 BPA W AC (partial)
East Summer Lake /
-500 kVAC PAC Renewable resource potential in SE
Wagontire Oregon.
Wagontire / Burns I - 500 kV AC PAC Renewable resource potential in SE
Oregon.
Existing line needed for load
Bums! Quartz 1 - 138 kVAC IPC service. 500 kV series caps at
Bums, 115 kV sub at Harney. Line
needed for load service
Potential overlap with IPC B2H
Quartz I La Grande ' - 230 kV AC IPC, route. Similar issues to that project.
NEO BPA La Grande (city). Line needed for
load service
Boardman Slatt - Boardman Plant 1 - 500 kV AC PGE Overlap with PGE's proposed
Cascade Crossing Project
50
Staff_PR_030 Attachment A Page 54 of 63
FINAL
Route Segment Description Corridor Info Length Owners Siting Notes
Potential overlap with proposed
Boardman Plant - No existing HV PGE CC route and IPC B2H route.
Coyote transmission lines. Boardman Naval Bombing Range.
Green-field
Boardman Plant - No existing HV - Potential overlap with IPC B2H
NEO transmission lines. route. Boardman Naval Bombing
Range. Green-field
Potential overlap with IPC B2H
Coyote - NEO No existing HV route. Boardman Naval Bombing
transmission lines. Range. Green-field. Herrninston
(city)
Staff—M_030 Attachment A Page 55 of 63
FINAL
Attachment 3: Preliminary Review of Northwest Alignments
West:
This route follows existing 230 kV line corridors that run N-S through Oregon on the east of
the Cascades. Portions of this route are expected to be challenging due to proximity to the
population centers of Bend, Redmond, and Klamath Falls. Many of these existing 230 kV
lines are critical -for load service reliability to these population centers, so it is- unlikely that
extended outages of the existing lines would be acceptable. Additional segments have been
added to the map to reconnect to the other corridors. This route would be longer than the
Central and PDCI options, but it would have the advantage of corridor separation from the
other primary transmission corridors to CA.
Central/AC:
This route follows the existing 500 kV AC lines that support COI transfers from COB to
Buckley. From Buckley, the route follows BPA's existing 500 kV network line corridors to
Slatt, Coyote Springs, and McNary. Advantages of this route include low population density
and efficiency in co-locating auxiliary facilities (series capacitors, telecommunications, access
roads, etc.). The primary disadvantage would be heavy concentration of lines in a corridor,
especially from Buckley to COB. Another issue with a DC plan in this corridor would be
interaction between AC and DC equipment.
CentraVPDCI:
This route follows the existing Pacific DC Intertie. Like the COI corridor, the population density
is low for most-of the route Between Buckley and Sand Springs, this route is relatively close
to COI corridor, though with greater than 1 -500 foot separation. South of Sand Springs, the
route veers to the southeast. A potential disadvantage of this segment of the route is that
some green-field ROW may be needed to-reconnect to the HVAC system in N CA. Following
this route up to the terminal at Big Eddy - Celilo is not advised due to proximity to the
Columbia River Gorge National Scenic Area. A preliminary review of GIS data indicates that
there may be enough space in the existing ROW for an additional circuit. However, this
would require further review, and would not eliminate the need for an EIS or the NEPA
process. Like the Central / AC corridor, there would be concerns about heavy concentration
of lines in a corridor, especially from Buckley to Sand Springs, and interaction between AC
and DC equipment.
East:
This route would follow the existing Hemingway-Summer Lake (formerly Midpoint-Summer
Lake line to Bums, and then follow 138 kV and 230 kV lines up to NEO. These existing lower
voltage lines are critical for load service reliability to local population centers, so it is unlikely
that extended outages of the existing lines would be acceptable. This route would likely be a
longer and have higher cost that the Central and PDCI options. Some of this route is similar
to Idaho Power's preferred alternative for the proposed Boardman - Hemingway (132H)
project, so it may be subject to similar siting issues that have been experienced in permitting
52
Staff—PR-030 Attachment A Page 56 of 63
FINAL
that project. SE Oregon has -been identified as a region with significant renewable resource
potential, based on interconnection queue requests from multiple developers and wind/solar
data from third party sources. However, the development of these resources has been
limited in part by lack of transmission availability.
Boardman:
This route is an alternative between Slatt and NEO. Only one segment of this route
(Slatt - Boardman Plant) is a developed transmission corridor. The other segments
would be green-field today, but they overlap with proposed PGE Cascade Crossing and
IPC B2H route alternatives. The lines would need to avoid the Boardman Naval
Bombing Range and Umatilla Weapons Depot located east of the plant.
53
Staff_PR_030 Attachment A Page 57 of 63
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Attachment 4: NEO Area Configuration
Juniper
Flat
Cedar
Spring
54
Staff_PR_030 Attachment A Page 58 of 63
'IOn
Midpoint
FINAL
Attachment 5: 2010 Existing System Diagram
500kv _______
345 -
230W
Olin
Maxwell
Vaca
Dixor
2010 Existing System
(Partial representation of the
transmission system)
GrluIy
55
Staff—PR-030 Attachment A Page 59 of 63
FINAL
Attachment 6: Option I (Ca Opt IA) -- New AC & 2n,GOTP
Option 1A— Captain Jack Olinda
Upgrades + new AC & 2nd COTP
to Collinsville To NEO
(Partial representation of the transmission
system) /
500kv
Klamath Grizzly
345 kV , /
'-.---
Midpoint
230 kv
?mer
/ To
Hilltop
Renewable
Ca pta alinGen I
/
Keswick
UpgradZ Ja /
od
LJ
- :-.------ - Round
To Fort Sage
Olinda /aordertown
_Table
Mt.
Maxwell

I --•/ Roseville
3-i I O'Banion
Vaca- / I
Dixon / Hedge
Collinsville
'------ T ---------------------- Tracy
To Pittsburg - -------- - -
Tesla
56
Staff—PR-030 Attachment A Page 60 of 63
500 kV
345 kV
230
HVDC Bipole
Converter +
transformers
Olinda
Vaca-
Dixon
Collinsville
-
To Pittsburg
o Fort Sage
Bordertown
lidpoint
To
Hilltop
MF
FINAL
Attachment 7: Option 2 (Ca Opt 2) - AC + COTP DC
Option 2— COTP DC + new AC
(Partial representation of the transmission To NEO
t*n,tarfl
57
Staff—PR-030 Attachment A Page 61 of 63
FINAL
Attachment 8: Option 3 (Ca Opt 2) - Convert/New DC + COTP DC
Option3--COTPDC+ new DCto
NEO (B2B at Ci) + new AC To KO
(Partial representation of the transmission
system)
500W
34S IN rJamath summer
L Midpoint
2U
To
HVDCVipole Hilltop
Renewable
Converter* Captn An Gen
tranOormers Jack
Pound Mt. 2
Cottonwood

1 Pound
Mt.
Olinda '•' 'Y
Table
Mt.
To
WOO-
Dixon
ColHnMh
Tela
Hedge
/7 /L
L1J Tray
58
Staff—PR-030 Attachment A Page 62 of 63
FINAL
Attachment 9: Option 4 (Ca Opt 5) -- New DC
Option 5— New DC to NEO +
500 kV
345 kV
230
HVDC Bipole
Converter+ a transformers
Keswick
-.4-.
Olinda

new AC To NEO
(Partial representation of the
transmission system) /
Klamath Grizzly Summer
Lake 7 / .' Midpoint
To
Hilltop
Captain
Renewable
Jack ann Gen
NEC
cottonwood
L!!LJ ---------------------
- Round
Mt. To Fort Sage
/Bordertown
Table
Mt.
Roseville
Vaca-
Dixon
.\
Collinsville
To Plttsburg -------

.1 O'Banlon
Hedge
•1
Tracy
Tesla
59

Staff—PR-030 Attachment A Page 63 of 63
EXECUTION VERSION
STAGE ONE PROJECT DEVELOPMENT AGREEMENT
among
PACIFIC GAS AND ELECTRIC COMPANY,
PACIFICORP,
A VISTA,
and
BRITISH COLUMBIA TRANSMISSION CORPORATION
dated as of September 25, 2008
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Table of Contents
Eg
1.Interpretation .1

1.1 Definitions ......................................................................................................................... I

1.2 Interpretation.....................................................................................................................4
2.Participation in Stage One . ............................................................................................... 5
3.Stage One Objectives ........................................................................................................ 5
4.Stage One Timetable.........................................................................................................6
5.Project Development Organization ................................................................................... 6
5.1 Project Owners Group.......................................................................................................6
5.2 Project Director................................................................................................................. 7
5.3 Voting; Meetings .............................................................................................................. 7
5.4 Project Manager ................................................................................................................ 9
5.5 Responsibilities................................................................................................................. 9
5.6 Joint Working Groups.....................................................................................................10
5.7 Limitation of Liability; Indemnities ................................................................................ 10
6. Advisors .......................................................................................................................... 11
7.Cost Sharing....................................................................................................................11

7.1 Payment of Stage One Costs...........................................................................................11

7.2 Non-Budgeted Costs ....................................................................................................... 12
8.Budget, Project Accounts and Reports...........................................................................12

8.1 Budget.............................................................................................................................12

8.2 Project Accounts and Invoicing......................................................................................12

8.3 Reports............................................................................................................................13
9.Confidentiality and Public Communications..................................................................13
10.Transfers .........................................................................................................................13

10.1 Transfers .........................................................................................................................13

10.2 Procedure for Transfers ................................................................................................... 14
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Table of Contents
(continued)
Page
10.3 Effecting Transfers .......................................................................................................... 15
10.4 Transfer Requirements.................................................................................................... 16
11. Withdrawal ....................................................................................................................... 16
11.1 Withdrawal...................................................................................................................... 16
11.2 Effecting Withdrawals .................................................................................................... 16
12. Term of Agreement ......................................................................................................... 17
13. Representations and Warranties...................................................................................... 18
14. Covenants........................................................................................................................ 19
14.1 Compliance with Laws ................................................................................................... 19
14.2 Good Faith; Exclusivity.................................................................................................. 19
14.3 Independent Appraisal . ................................................................................................... 19
14.4 Negotiations . ................................................................................................................... 19
15 . Successors; Assignments................................................................................................ 19
15.1 Successors....................................................................................................................... 19
15.2 Assignments .................................................................................................................... 19
16. Severance ........................................................................................................................ 20
17 . Waiver............................................................................................................................. 20
18. Amendment..................................................................................................................... 20
19. Entire Agreement................................................... 20
20. Counterparts.................................................................................................................... 20
21 . Notices ............................................................................................................................ 20
21.1 Giving of Notices............................................................................................................ 20
21.2 Addresses for Notices..................................................................................................... 20
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Staff_PR030 Attachment B Page 3 of 79
Table of Contents
(continued)
Page
22.No Partnership ................................................................................................................21
23.Governing Law...............................................................................................................21
24.Dispute Resolution .......................................................................................................... 21

24.1 Intent of the Parties.........................................................................................................21

24.2 Management Negotiations .............................................................................................. 21

24.3 Mediation..........................................................................22

24.4 Arbitration ...................... . ................................................................................................. 22

24.5 Former Participants.........................................................................................................23
SCHEDULES
Schedule 1 -- Payment Schedule
Schedule 2 -- Stage One Objectives and Activities
Schedule 3 -- Stage One Timetable
Schedule 4 -- Initial Representatives and Alternates to the Project Owners Group
Schedule 5 -- Advisors and Consultants
Schedule 6 -- Stage One Costs Incurred to Date
Schedule 7 -- Initial Project Budget
Schedule S -- Form of Assignment Agreement
Schedule 9 -- Notice Information
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This STAGE ONE PROJECT DEVELOPMENT AGREEMENT (this
"Agreement") is dated as of September 25, 2008 (the "Effective Date"), among (i) PACIFIC
GAS AND ELECTRIC COMPANY, a corporation incorporated in the State of California and
having its principal place of business at 77 Beale Street, San Francisco, California, 94105,
United States ("PG&E"), (ii) PACIFICORP, a corporation incorporated in the State of Oregon,
having its principal place of business at 825 NE Multnomah St, Suite 2000, Portland, Oregon,
97232, United States ("PacifiCor"), (iii) AVISTA CORPORATION, a corporation incorporated
in the State of Washington and having its principal place of business at 1411 E. Mission Avenue,
Spokane, Washington, 99202, United States ("Avista"), and (iv) BRITISH COLUMBIA
TRANSMISSION CORPORATION, a corporation incorporated in British Columbia, Canada,
and having its principal place of business at Suite 1100, Four Bentall Centre, 1055 Dunsmuir
Street, Vancouver, British Columbia, V7X I V5, Canada ("BCTC").
WHEREAS, the parties hereto desire to evaluate arrangements under which a
transmission line extending from the Selkirk substation in British Columbia, Canada, into the
State of California would be developed, designed, engineered, financed, constructed,
commissioned and operated (the "Project");
WHEREAS, the parties hereto desire to undertake activities to achieve the Stage
One Objectives, as defined herein, and to provide for the funding of such activities ("Stage
Qfl ,,);
WHEREAS, in addition to the activities specifically identified as the Stage One
Objectives, the parties hereto are presently engaging in other discussions related to the
development, design, engineering, permitting, routing (and plan of service) and capability of the
Project and intend to continue those discussions and expand them to include ownership and
allocation of usage rights in the Project (and the segments thereof);
WHEREAS, nothing in this Agreement shall affect any other existing or proposed
projects, expansions, or developments by any of the Participants that are not part of the scope of
this Agreement; and
WHEREAS, the parties hereto desire to establish the rights and responsibilities of
the Participants in Stage One;
NOW, THEREFORE, the parties hereto agree as follows:
Interpretation.
1.1 Definitions. In this Agreement:
"AAA" has the meaning set forth in Section 24.3 (Mediation).
"Additional Participant" means an Entity admitted as a Participant after the
Effective Date by unanimous vote of the Project Owners Group in accordance with Section 5.3
(Voting) and upon such other terms and conditions as agreed by unanimous consent of the
Project Owners Group and such Participant.
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"Agreement' ''has the meaning set forth in the Preamble.
"Approved Budget" means the Initial Project Budget attached as Schedule 7 or
any revised budget approved in accordance with Section 5.3 (Voting).
"Arbitration" has the meaning set forth in Section 24.3 (Mediation).
"Assignment Agreement" means an agreement between Take-Up Participant(s) or
an Additional Participant and a Participant and counter-signed by the Project Director
substantially in the form of Schedule 8 (Form of Assignment Agreement).
"Avista" has the meaning set forth in the Preamble.
"Bankrupt" means, with respect to any -entity, such entity that (a) files a petition
or otherwise commences, authorizes or acquiesces in the commencement of a proceeding or
cause of action under any bankruptcy, insolvency, reorganization or similar law, or has any such
petition filed or commenced against it, (b) makes an assignment or any general arrangement for
the benefit of creditors, (c) otherwise becomes bankrupt or insolvent (however evidenced), (d)
has a liquidator, administrator, receiver, trustee, conservator or similar official appointed with
respect to it or any substantial portion of its property or assets, or (e) is generally unable to pay
its debts as they fall due.
"BCTC" has the meaning set forth in the Preamble.
"Commitment Amount" means, for each Participant, the amount set forth next to
its name in column (5) of Schedule 1 (Payment Schedule).
"Common Interest Privilege Agreement" means the Common Interest Privilege
Agreement that has been or will be executed by each of the Participants hereto and any
Additional Participants, as may exist from time to time.
"Confidentiality Agreement" means any of one or more agreements executed by
each of -the Participants and designated therein as a Confidentiality Agreement for purposes of
this Agreement that sets forth terms and conditions for the protection, release and use of
information that is commercially sensitive -or constitutes CEll, proprietary or trade-secret data or
is not otherwise available to the public.
"Credit" has the meaning set forth in Section 2(b)- (Participants).
"Critical Energy Infrastructure Information" or "II" has the meaning set forth
at 18 C.F.R. § 388.113, as amended from time to time.
"Disputing Party" has the meaning set forth in Section 24.4 (Arbitration).
"Effective Date" has the meaning set forth in the Preamble.
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"Entity" means any firm, company, corporation, government, state, province or
agency of a state or province or any association or partnership (whether or not having separate
legal personality) of two or more of the foregoing, but does not include natural persons.
"Executives" has the meaning set forth in Section 24.2 (Management
Negotiations).
"FERC" means the Federal Energy Regulatory Commission or its successor.
"Former Participant" means a Withdrawing Participant or a Transferring
Participant after such date as the withdrawal or transfer, as applicable, becomes effective.
"Initial Negotiation End Date" has the meaning set forth in Section 24.2
(Management Negotiations).
"Interest" has the meaning set forth in Section 10.1 (Transfers).
"Manager" has the meaning set forth in Section 24.2 (Management Negotiations).
"Notice" has the meaning set forth in Section 21.1 (Giving of Notices).
"Office of the Project Manager" has the meaning set forth in Section 5.4 (Project
Manager).
4'PacifiCorp" has the meaning set forth in the Preamble.
"Participant" means an Entity that is a signatory to this Agreement as of the
Effective Date and any Additional Participants, as may exist from time to time; provided, that an
Entity shall cease to be a Participant as of the effective date on which such Entity withdraws
from this Agreement pursuant to Section 11 (Withdrawal) or transfers all of its Interest pursuant
to Section 10 (Transfers). Use of the term "Participant" in reference to a time following the
expiration or termination of this Agreement shall mean each Entity that was a Participant as of
the date of such expiration or termination.
"Participation Percentage" means, with respect to a Participant, the percentage
appearing opposite its name in column (6) of Schedule 1 (Payment Schedule), as such
Participation Percentage may be varied by transfers from Transferring Participants or
Withdrawing Participants to Participants, Take-Up Participants or Additional Participants, as the
case may be, in accordance with Section 10 (Transfers) and Section 11 (Withdrawal) from time
to time.
"PG&E" has the meaning set forth in the Preamble.
"Project" has the meaning set forth in the Recitals.
"Project Director" has the meaning set forth in Section 5.2 (Project Director).
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"Project Information" means all information contained - in this Agreement and
information, know-how, results and data generated during Stage One or generated in anticipation
of, or used in connection with, development of the Project.
"Project Manager" has the meaning set forth in Section 5.4 (Project Manager).
"Project Owners Group" has the meaning set forth in Section 5.1 (Project Owners
Group).
"Referral Date" has the meaning set forth in Section 24.2 (Management
Negotiations).
"Stage One" has the meaning set forth in the Recitals.
"Stage One Account" has the meaning set forth in Section 8.2 (Project Accounts
and Invoicing).
"Stage One Objectives" has the meaning set forth in Section 3 (Stage One
Objectives).
"Take-Up Notice" has the meaning set forth in Section 10.2 (Procedure for
Transfers).
"Take-Up Participant" has the meaning set forth in Section 10.2 (Procedure for
Transfers).
"Transfer Interest" has the meaning set forth in Section 10.1 (Transfers).
"Transfer Notice" has the meaning set forth in Section 10.2 (Procedure for
Transfers).
"Transferring Participant" has the meaning set forth in Section 10.1 (Transfers).
"Withdrawing Participant" has the meaning set forth in Section 11.1
(Withdrawal).
1.2 Interpretation. (a) In this Agreement, unless the contrary intention
appears, -a reference to:
(i) an "authorization" includes an authorization, consent, approval, resolution,
license, exemption, filing and registration;
a "regulation" includes any law, regulation, rule or official directive of any
governmental body, agency, department or regulatory, self-regulatory or other
authority or organization;
a "working day" is a day other than a North American Electric Reliability
Corporation holiday or a Saturday or Sunday; -
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(ii)a provision of law is a reference to that provision as amended or re-
enacted;
(iii)a Section or a Schedule is a reference to a section of or a schedule to this
Agreement;
(iv)an Entity includes its successors and permitted assigns;
(v)a person in the masculine shall include a person of either gender; and
(vi)a time of day is a reference to Pacific Prevailing Time.
(b) The contents page to, and the headings in, this Agreement are for
convenience only and shall not be used in construing this Agreement.
2. Participation in Stage One.
(a)Each Participant agrees to pay its respective Commitment Amount, payable in
installments on the specified dates in Schedule I (Payment Schedule), as such Schedule may be
amended from time to time pursuant to Section 5.3 (Voting), into a Stage One Account. Failure
to pay such amounts when due shall give rise to a liability to pay interest on such outstanding
amounts payable by the Participant concerned at a rate per annum equal to the "Monthly"
Federal Funds- Rate (as reset on a monthly basis based on the latest month for which such rate is
available) as reported in Federal Reserve Bank Publication H.15-519, or its successor
publication. Subject to Section 7.1(c) (Payment of Stage One Costs), withdrawal from this
Agreement in accordance with Section 11 (Withdrawal) shall not relieve the Withdrawing
Participant from its obligations to pay the total Commitment Amount set forth next to its name in
Schedule 1 (Payment Schedule), payable in the amounts and on the dates set forth therein,
irrespective of whether any such payment is due before or after the Withdrawing Participant
gives Notice of its withdrawal or such withdrawal takes effect.
(b)Each Participant, in consideration for its payment of its Commitment
Amount described in Section- 2(a) (Participation in Stage One), shall receive a credit for each
dollar contributed (such credit, the "Credit" of such Participant), which Credit shall, for purposes
of this and all future stages of the Project, represent amounts contributed by such Participant to
the Project. Subject to Sections 10 and 11, each Participant's Credit, accrued pursuant to this
Agreement or as may be accrued in connection with future stages of the Project, shall represent
its right to share in the benefits of the Project, including but not limited to future ownership and
allocation of usage rights; provided, however, that in the event this Agreement is terminated
pursuant to Sections 1 2(a)(i), (ii), (iii). or (v) (Term of Agreement), the Credit of each Participant
shall be deemed to have terminated simultaneously therewith.
3. Stage One Objectives. The objectives which the Participants desire to be
achieved during Stage One pursuant to this Agreement are those set forth in Schedule 2 (Stage
One Objectives and Activities) (the "Stage One Objectives"). The parties shall simultaneously
engage in discussions to further define the ownership and allocation of usage rights in the Project
(and the segments thereof).
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4. Stage One Timetable. It is the intention of the Participants to advance
Stage One in accordance with the timetable attached hereto as Schedule 3 (Stage One Timetable)
(together with explanatory notes thereto) and, subject to each Participant's right to transfer its
interest or withdraw, each Participant agrees to use all reasonable commercial efforts to complete
Stage One in accordance with such timetable.
Project Development Organization.
5.1 Project Owners Group. (a) A project owners' group (the "Project Owners
Group") will be established forthwith by the Participants and will comprise one representative
an alternate) of each Participant. The initial representative and alternate of each Participant
in the Project Owners Group is as set forth in Schedule 4 (Initial Representatives and Alternates
to the Project Owners Group). Representatives may be replaced at any time at the discretion of
the nominating Participant with -Notice to the Project Owners Group pursuant to Section 21
(Notices).
(b) The tasks of the Project Owners Group are to:
(i)monitor and amend (if required) the work related to Stage One;
(ii)evaluate revisions proposed by any Participant, the Project Director or the
Project Manager to Schedules 1 (Payment Schedule) and 1 (Initial Project Budget);
provided, that amendments to Schedules 1 and 7 shall be adopted only as otherwise set
forth herein;
(iii)consult with the Project Manager with respect to the progress of the
Project relative to Schedule 3 (Stage One Timetable) and, in conjunction with the advice
of the Project Manager, determine whether or not to revise Schedule 3 and the scope of
such revisions;
(iv)determine general development policy with respect to Stage One;
(v)allocate resources and-generally attend to the constituent elements of Stage
One;
(vi)decide on the terms of a fair and reasonable confidentiality undertaking
that any Entity proposing to become an Additional Participant shall give to each of the
Participants before such Entity may receive any information relating to the Project;
(vii)determine whether to admit any other Entity into the Project as an
Additional Participant;
(viii)consent to Assignment Agreements as referred to in Section 10
(Transfers), such consent not to be unreasonably withheld or delayed (provided, that
nothing herein shall require the Project Owners Group to admit any Entity as an
Additional Participant); and
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(ix)review, approve and amend or supplement, as required from time to time,
a public affairs plan for the Project;
(x)consider any other matter relating to Stage One and referred to the Project
Owners Group by a Participant or the Project Manager.
5.2 Project Director.
(a)The Participant holding the greatest Participation Percentage shall appoint
the project director (the "Project Director"). The Project Director may be the representative or
alternate of such Participant to the Project Owners Group. If the Project Director is the
representative or alternate of a Participant, he may exercise the vote of such Participant pursuant
to Section 5.3 (Voting), but the Project Director shall have no additional or independent voting
rights.
(b)The tasks of the Project Director (which he may delegate to others at his
discretion unless otherwise directed by the Project Owners Group) are to:
(i)attend and chair meetings of the Project Owners Group;
(ii)serve as the primary liaison between the Project Owners Group and the
Project Manager;
(iii)execute documents on behalf of the Participants, at the direction and with
the consent of the Project Owners Group;
(iv)monitor and evaluate the performance of the Project Manager on behalf of
the Project Owners Group and periodically report such findings to- the Project Owners
Group;
(v)consult with the Project Owners Group about strategy and tactical issues
that affect the completion of Stage One and further Project stages and, as necessary, work
with the Project Manager to effectuate the intent of the Project Owners Group;
(vi)take actions consistent with- the direction of the Project Owners Group-to
advance Stage One to successful completion;
(vii)call meetings of the Project Owners Group as necessary;
(viii)make press releases or other public statements or disclosures concerning
the Project consistent with Section 9(b) (Confidentiality and Public Communications);
and
(ix)perform such other functions as authorized or delegated to him by the
Project Owners Group.
5.3 Voting: Meetings.
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(a) The voting rights of each Participant's representative (or the alternate,- if
the representative is not in attendance) to the Project Owners Group shall be the Participation
Percentage of each Participant. However, a representative or alternate representing a Participant
who is in arrears in payments under the terms of this Agreement for a period of more than twenty
(20) working days shall not be entitled to vote. All decisions of the Project Owners Group will
be made on the basis of Participants having an aggregate Participation Percentage of at least
662,4% voting in favor; provided, that where there are more than two Participants, no single
Participant shall be able to cause a decision to be adopted by voting in favor of a decision when
each other Participant votes against it so that if one Participant holds more than the requisite
Participation Percentage votes in favor of a decision, then such decision shall only be adopted if
a further Participant votes in favor. However, unanimous consent from the Project Owners
Group is required in the case of decisions relating to:
(i)amending Schedule 1 (Payment Schedule);
(ii)amending Schedule 2 (Stage One Activities);
(iii)amending Schedule 5 (Advisors and Consultants);
(iv)amending Schedule 7 (Initial Project Budget) or any other Approved
Budget, in whole or in part;
(v)approving or amending a public affairs plan;
(vi)terminating this Agreement, except where this Agreement terminates
automatically pursuant to Sections- 12(a)(ii), (iii), or (v) (Term of Agreement); and
(vii)admitting any Additional Participant.
(b) Votes may be taken at any duly convened meeting of the Project Owners
Group. A meeting shall be deemed duly convened if (i) each Participant's representative and
alternate has been provided Notice of the meeting at least five (5) working days in advance and
provided an opportunity to participate in person or by phone and (ii) Participants representing at
least 662,4% of the Participation Percentages are represented (in person or by phone) at the
meeting. The Project Director shall appoint an attendee at each such meeting to maintain
minutes of the meeting. The outcome of all votes taken during meetings of the Project Owners
Group shall be recorded in the meeting minutes. In addition, -in the event the Project Director
determines that a matter is of such urgency that it must be acted upon prior to the next duly
convened meeting of the Project Owners Group, the Project Director may request that the Project
Owners Group act through notational votes without a meeting and such action shall- be
recognized as a vote of the Project Owners Group; provkled, that (i) each Participant's
representative and alternate is provided with Notice of the proposed matter on which the vote
will be taken and allowed at least one (1) full working day to cast his or her vote, (ii) Participants
representing at least 87% of the Participation Percentages cast votes, and (iii) each Participant
delivers its vote by Notice to all other Participants. The Project Director shall be responsible for
maintaining a record of the votes cast by notational vote based on the Participants' Notices.
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5.4 Project Manager. (a) A project manager (the "Project Manager") will
administer and oversee Stage One on behalf of the Participants. The initial Project Manager
shall be Mark Schexnayder (who is an employee of PG&E), until such time as the -Project
Manager resigns or is replaced, and then the Project Director, in consultation with the Project
Owners Group, shall nominate and appoint any replacement Project Manager. The Project
Manager shall be responsible for the day to day activities involved in advancing Stage One and
the achievement of the Stage One Objectives. The Project Manager shall report to the Project
Director and may be replaced at the discretion of the Project Director in consultation with the
Project Owners Group. The Project Manager shall have the ability to hire staff, including
consultants to serve as staff, to the extent provided in the Approved Budget (such staff, together
with the Project Manager, the "Office of the Project Manager"). PG&E shall compensate the
Project Manager if such Project Manager is an employee of PG&E.
(b) The tasks of the Office of the Project Manager are to:
(i)carry out the Stage One Objectives and activities as set forth in Schedule 2
(Stage One Objectives and Activities) consistent with the Approved Budget;
(ii)manage and monitor the advisors and consultants performing work with
respect to Stage One and notify the Project Director of the status of their work;
(iii)subject to approval by the Project Owners Group, hire advisors and
consultants (including and in addition to those identified in Schedule 5 (Advisors and
Consultants));
(iv)report monthly to the Project Owners Group regarding expenditures made
and projected, and, to the extent necessary, recommend to the Project Owners Group
adjustments to the Approved Budget in order to satisfy expected expenses to be incurred
in relation to the Stage One Objectives;
(v)prepare monthly activity and progress reports and such other reports for
distribution to the Project Owners Group and the Participants as required by Section 8.3
(Reports);
(vi)collect amounts owed by the Participants and Withdrawing Participants (if
applicable) and deposit them into the Stage One Account;
(vii)pay amounts due and owing out of the Stage One Account;
(viii)establish project controls, including without limitation a change control
board, subject to the approval of the Project Owners Group; and
(ix)perform any other task referred to the Project Manager by the Project
Owners Group or Project Director.
5.5 Responsibilities. In addition to its payment obligations set forth in Section
2 (Participation in Stage One), each Participant is expected to provide personnel, services, know-
how, intellectual property or other resources as appropriate and as determined in good faith, to
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carry out the intent of this Agreement or as otherwise agreed by the Project Owners Group and
such Participant. No Participant shall incur any expense reimbursable by the Project Owners
Group or any other Participant unless such expense is reflected in the Approved Budget and such
Participant has obtained the prior approval of the Project Manager, or such expense is set forth in
Schedule 6 (Stage One Costs Incurred to Date).
5.6 Joint Working Groups. Joint working groups may be established by the
Project Owners Group on an ad hoc basis when the need arises to advance certain specific tasks
related to Stage One or to undertake related activities such as allocation of ownership and usage
rights in the Project (and the segments thereof).
5.7 Limitation of Liability; Indemnities. (a) Without relieving any Participant
or Withdrawing Participant of any obligation otherwise required hereunder, no Participant or
Withdrawing Participant shall:
(i)have any liability to any other Participant(s) or Former Participant(s) for a
failure or delay in completing successfully Stage One, except in the case where a
Participant or Withdrawing Participant intentionally takes actions, or intentionally fails to
take actions, that in either case are not in good faith and prejudice one or more of the
other Participants to a Participant's or Withdrawing Participant's benefit;
(ii)be liable to any other Participant(s) or Former Participant(s) for any action
taken or not taken by it under or in connection with Stage One, except in the case where a
Participant or Withdrawing Participant intentionally takes actions, or intentionally fails to
take actions, that in either case are not in good faith and prejudice one or more of the
other Participants to a Participant's or Withdrawing Participant's benefit; or
(iii)be obligated to participate in any future stage of the Project.
(b) In relation to claims made by any third party, including any advisor
retained in connection with Stage One, against a Participant, Former Participant, the Project
Director, the Project Manager or any person employed by the Office of the Project Manager
arising directly and solely out of its participation in Stage One (other than those arising by reason
of its gross negligence or willful misconduct or those made against a Participant or Former
Participant by any tax authority of that Participant's or Former Participant's home state or
province) each Participant and Withdrawing Participant shall severally indemnify the affected
Participant, Withdrawing Participant, the Project Director, the Project Manager or the employee
of the Office of the Project Manager, as applicable, to the extent required to ensure that the claim
is borne by each Participant or Withdrawing Participant pLo rata to its respective Participation
Percentage as existing on the date (or dates) of the event, occurrence, act or decision giving rise
to the claim; provided, that a Withdrawing Participant shall have no liability for events,
occurrences, acts or decisions arising after the effective date of its withdrawal and provided
further, a Transferring Participant shall have no rights or obligations under this section in
connection with a Transfer Interest, as those rights and obligations shall be undertaken by each
Take-Up Participant or Additional Participant (in their capacity as Participants) with respect to
such Transfer Interest, and the pro rata rights and obligations associated with the Transfer
Interest shall be determined by reference to the respective Participation Percentage of the
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Transferring Participant as existing on the date (or dates) of the event, occurrence, act or decision
giving rise to the claim.
(c) Unless specified in a separate agreement, neither the Project Director nor
any person employed in the Office of the Project Manager, including the Project Manager, shall
(i) be liable for any action taken or omitted to be taken by such person under or in connection
with this Agreement or the transactions contemplated hereby or any activity undertaken or not
undertaken by the Project Director, the Project Manager or the Office of the Project Manager
under or in connection with Stage One (except for such person's own gross negligence or willful
misconduct), (ii) be responsible in any manner to any of the Participants or any other Entity or
person for any recital, statement, representation or warranty made by any Participant or Former
Participant, or any officer thereof, contained in this Agreement, or in any certificate, report,
statement or other document referred to or provided for in, or received by the Office of the
Project Manager or any Entity or person under or in connection with, -this Agreement, or the
validity, effectiveness, genuineness, enforceability or sufficiency of this Agreement, or for any
failure of any Participant or Withdrawing Participant to perform its obligations hereunder, or (iii)
be liable to the extent such person relies on this Agreement, any certificate, report, statement or
other document received by the Office of the Project Manager in connection with this Agreement
or Stage One.
6.Advisors. The advisors and consultants to be engaged by the Project
Manager on behalf of the Participants are those set forth in Schedule 5 (Advisors and
Consultants) and such other advisors or consultants as approved by the Project Owners Group,
both as included in an Approved Budget.
7.Cost Sharing.
7.1 Payment of Stage One Costs. (a) Subject to subsection 7.1 (c), all
obligations incurred pursuant to any Approved Budget in relation to Stage One which have been
budgeted for in any Approved Budget, including all amounts set forth in Schedule 6 (Stage One
Costs Incurred to Date), shall be shared among the Participants based on each Participant's
Participation Percentage as of the date on which such Approved Budget was adopted (and, in the
case of the Initial Project Budget, on each Participant's Participation Percentage as of the
Effective Date).
(b)If, in accordance with an- Approved Budget and with the approval of the
Project Manager, a Participant agrees to execute a contract solely in the name of such Participant
but on behalf of the Participants, payments it makes on behalf of the Participants shall be
reimbursed to it in accordance with Section 7.1(a) (Payment of Stage One Costs). Similarly, if
all Participants execute a contract for the shared benefit of all of the Participants, in accordance
with the Approved Budget and with the approval of the Project Manager, the costs shall be
shared among the Participants in accordance with Section 7.1(a) (Payment of Stage One Costs).
(c)For the avoidance of doubt, if a Participant withdraws from Stage One,
then such Withdrawing Participant shall only be liable for (i) its obligations pursuant to Section
(Participation in Stage One), including the Commitment Amount set forth next to its name,
payable in the amounts and on the dates specified in Schedule 1 (Payment Schedule) as such
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Schedule 1 is in effect as of the date of such Withdrawing Participant's Notice of withdrawal and
interest accrued, if any, on such amounts pursuant to Section 2(a) (Participation in Stage One),
but such Withdrawing Participant shall not be liable for any change in the Commitment Amount,
or any alterations to the payment dates, required pursuant to subsequent amendments to Schedule
I (Payment Schedule) and (ii) its liabilities and indemnities as determined pursuant to Section
5.7(1?) (Limitation of Liabilities; Indemnities). If a Participant transfers its Participation
Percentage in accordance with Section 10 (Transfers), then, with respect to such Transfer
Interest, it shall be liable for the amounts set forth in the preceding sentence to the extent such
obligations became due prior to the Assignment Date, and liabilities incurred on and after the
Assignment Date shall be borne by the Take-Up Participant or Additional Participant. Amounts
paid by a Withdrawing Participant pursuant to Section 2(a) (Participation in Stage One) shall be
applied, as received, to the outstanding obligations and liabilities of the Participants pursuant to
this- Agreement, prior to determining the amounts allocable to the active Participants pursuant to
Section 7.1(a) (Payment of Stage One Costs).
7.2 Non-Budgeted Costs. Except as set forth in this Section 7 (Cost Sharing),
each Participant and Former Participant shall bear its own costs incurred in relation to
discharging its individual responsibilities in Stage One which do not form part of any Approved
Budget.
8. Budget, Project Accounts and Reports.
8.1 Budget. (a) The initial budget for costs associated with the initial phase
of Stage One is attached hereto as Schedule 7 (Initial Project Budget). The Project Owners
Group shall be responsible for producing revised budgets as necessary to complete the Stage One
activities and as the Project Owners Group otherwise deems necessary. The Project Owners
Group shall not adopt an Approved Budget in which the total liabilities thereunder exceed the
sum of funds available to the Participants under this Agreement (that is, the Participants'
Commitment Amounts adjusted to reflect the portion of the Commitment Amounts available
after reduction for amounts already paid or committed, including amounts set forth in Schedule 6
(Stage One Costs Incurred to Date), and adjustment for any amounts owed under Section 2(a)
(Participation in Stage One) by a Withdrawing Participant pursuant to Section 7.1(c) (Payment of
Stage One Costs), not otherwise counted).
(b)Each revised budget is to be approved in accordance with Section 5.3
(Voting) prior to its implementation.
(c)Each Approved Budget will include a detailed estimate of fees given by
the advisors for the remainder of Stage One. Additionally, the Project Manager shall require
each advisor to provide periodic reports of its progress, including whether such advisor's actual
costs will exceed its estimate.
8.2 Project Accounts and Invoicing. (a) The Project Manager shall establish
and maintain one or more bank accounts (each a "Stage One Account") jointly in the name of the
Participants (exclusive of any Former Participant or Participant that is Bankrupt), with the
authority to close or change any Stage One Account from time to time. All amounts payable
under Section 2(a) (Participation in Stage One) shall be deposited into a Stage One Account.
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The Project Manager shall be given the necessary signing authority to, and shall, pay expenses
related to Stage One out of funds on deposit in a Stage One Account.
(b)Each of the Participants shall have the right (t its own cost) to audit each
Stage One Account. Each Former Participant shall have the right (at its own cost) to audit each
Stage One Account to the extent necessary to determine and enforce its obligations and rights (i)
during such time as it was a Participant, (ii) as a Withdrawing Participant or, (iii) in the case of a
Transferring Participant, against an Additional Participant or Take-Up Participant under an
Assignment Agreement.
(c)The Project Manager shall cause all Stage One Account statements to be
produced and distributed to the Project Owners Group members on a regular basis.
8.3 Reports. (a) The Project Manager shall be responsible for preparing and
distributing monthly reports to the Project Owners Group and the Participants within ten (10)
working days after the end of each calendar month.
(b) The Project Manager shall be responsible for preparing and distributing
reports at such other times as any material change occurs which affects the achievement of the
Stage One Objectives, including but not limited to material changes to the budget, timetable or
project work plan.
9. Confidentiality and Public Communications.
(a)No Project Information shall be required to be kept confidential, except
information that is subject to a Confidentiality Agreement or the Common Interest Privilege
Agreement, in which case the information shall be kept confidential in accordance with the terms
of such agreement.
(b)Participants shall not make any public communications concerning the
Project that are inconsistent with the public affairs plan for the Project approved by the
Participant Owners Group. The Project Director and each Participant shall provide reasonable
advance Notice to each (other) Participant of planned press releases, public statements, and
meetings with the public or governmental authorities in which discussion of the Project is
expected to be a material part. Each Participant shall consult with the Project Director prior to
making any press releases or other public statements or disclosures concerning the Project
(including details of any agreements between the Participants); provided, that nothing herein
shall prevent, limit, or delay any Participant from making any disclosure required by regulation.
Each Participant shall provide Notice to the other Participants as promptly as possible of the
nature and content of any significant unplanned communications about the Project with the
public or with governmental authorities.
10. Transfers.
10.1 Transfers.
(a) Any Participant (a "Transferring Participant") may transfer its interest in
the Project (inclusive of, and jointly with, its rights and obligations under this Agreement and in
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the Credits, its "Interest") in whole or in part (such specified portion of the Interest to be
-transferred, a "Transfer Interest") only in accordance with the provisions of this Section 10
(Transfers).
(b)Subject to the transfer procedure set out in Section 10.2 (Procedure for
Transfers), -a- Transferring Participant may at any time transfer a Transfer Interest to one or more
Take-Up Participants (as defined below), with the consent of such Take-Up Participant(s) and
subject to Section 10.2(c) (Procedure for Transfers). The Transferring Participant shall not
demand or receive a premium over costs originally paid by such Transferring -Participant but may
include a notional rate of interest determined at a rate per annum equal to the "Monthly" Federal
Funds Rate (as reset on a monthly basis based on the latest month for which such rate is
available) as reported in Federal Reserve Bank Publication H.15-519, or its successor
publication.
(c)Subject to the transfer procedure set out in Section 10.2 (Procedure for
Transfers), any Transferring Participant may transfer a Transfer Interest to any Additional
Participant only if such Additional Participant is unanimously approved by the Project Owners
Group. The Project Owners Group shall within twenty (20) working days of a request, decide on
the terms of a fair and reasonable confidentiality undertaking that the relevant potential
Additional Participant shall be required to give to each of the Participants before the Transferring
Participant may disclose any information relating to the Project to that Entity. The Transferring
Participant may not disclose any information relating to the Project to that Entity before that
Entity has given that confidentiality undertaking and unless the fifteen (15) working day period
referred to in Section 10.2(b) (Procedure for Transfers) below has expired and no other
Participant has served a Take-Up Notice.
10.2 Procedure for Transfers. (a) If a Participant wishes to transfer all or part
of its Interest pursuant to Sections 10.1(b) or 10.1(c) (Transfers), before contacting any potential
Additional Participant, such Participant shall give notice in writing to the other Participants and
to the Project -Owners Group that it wishes to make a transfer (a "Transfer Notice") of the
specified Transfer Interest.
(b) Any of the other Participants may, within fifteen (15) working days of
receipt of the Transfer Notice, by notice in writing to the other Participants and to the Project
Owners Group, state that it wishes to take up part of the Transfer Interest (a "Take-Up Notice"),
specifying the portion of such Transfer Interest it desires, at its pro rata proportion of the price
determined in accordance with Section 10.2(c) (Procedure for Transfers) below. If a Take-Up
Notice is given within the period referred to above, the Transfer Interest shall be apportioned
between the Participants who have served Take-Up Notices (the "Take-Up Participants") in the
proportions as agreed to by the Take-Up Participants, or absent such agreement, pro rata to the
proportions which their existing Participation Percentages bear to each other; provided, that no
Take-Up Participant shall be obligated to assume a greater share than designated in its Take-Up
Notice. Subject to payment to the Transferring Participant by each Take-Up Participant of its
pro rata proportion of the price determined in accordance with Section 10.2(c) (Procedure for
Transfers) below, the Transfer Interest shall be promptly transferred to those Take-Up
Participants by the Transferring Participant. If none of the Participants issues a Take-Up Notice
then, subject to Sections 5.1 (Project Owners Group), 5.3 (Voting) and 10.1(c) (Transfers) the
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Transferring Participant may offer the Transfer Interest to an Entity approved by the Project
Owners Group as an Additional Participant (after such Additional Participant has given the
confidentiality undertaking referred to in Section 10.1(c) (Transfers)), and thereafter, upon the
agreement of the Additional Participant and the Transferring Participant, the Transferring
Participant may proceed with the proposed transfer to the Additional Participant in accordance
with Section 10.3 (Effecting Transfers).
(c) The price payable as referred to in Section 10.2(b) (Procedure for
Transfers) above shall be the costs originally paid by the Transferring Participant plus a notional
rate of interest determined at a rate per annum equal to the "Monthly" Federal Funds Rate (as
reset on a monthly basis based on the latest month for which such rate is available) as reported in
Federal Reserve Bank Publication H. 15-519, or its successor publication.
10.3 Effecting Transfers. (a) A transfer is effected if-
(i)the Transferring Participant and the Take-Up Participant(s) or the
Additional Participant deliver to the Project Owners Group a duly completed and signed
Assignment Agreement in the form set forth in Schedule 8 (Form of Assignment
Agreement);
(ii)the Project Director counter-signs the Assignment Agreement (after
receipt of the consent of the Project Owners Group); and
(iii)the Additional Participant delivers to the Project Owners Group evidence
of such Additional Participant's accession to (a) the Common Interest Privilege
Agreement, by executing Exhibit A to the Common Interest Privilege Agreement, and (b)
any applicable Confidentiality Agreement(s), by executing each such agreement (in
counterparts if necessary).
(b)Subject to receipt of the Project Owners Group's consent pursuant to
Section 5. 1(b)(viii) (Project Owners Group), each Participant irrevocably authorizes the Project
Director to countersign any duly completed Assignment Agreement on its behalf in accordance
with this Section 10 (Transfers).
(c)The Transferring Participant's participation in the Project which is
specified in the Assignment Agreement shall be subject to the following:
(i)the Transferring Participant(s) and the other Participants shall each be
released from their respective obligations to each other in respect of such participation
(such obligations being referred to as "discharged obligations");
(ii)the Take-Up Participants or the Additional Participant and each other
Participant shall each assume new obligations towards each other which differ from the
discharged obligations only insofar as they are owed to or assumed by the Take-Up
Participant or the Additional Participant instead of the Transferring Participant(s);
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(iii)the rights of the Transferring Participant(s) in respect of such participation
against the other Participants and vice versa (the "discharged rights") will be cancelled;
and
(iv)the Take-Up Participants or the Additional Participant and each
Participant will acquire rights against each other which differ from the discharged rights
only insofar as they are exercisable by or against the Take-Up Participants or the
Additional Participant.
The assignments, assumptions and releases referred to in clauses (i) through (iv) above shall each
occur on the "Assignment Date" as specified in the Assignment Agreement.
10.4 Transfer Requirements. Each Take-Up Participant or the Additional
Participant shall, before the signed Assignment Agreement is delivered to the Project Owners
Group in accordance with Section 10.3(a)(i) (Effecting Transfers) deliver, in each case, to each
of the Participants, a copy of a resolution of its requisite board or governing body approving and
authorizing its entry into this Agreement as a Take-Up Participant or an Additional Participant in
respect of the Transfer Interest transferred to it.

11. Withdrawal
11.1 Withdrawal. A Participant may withdraw from this Agreement effective
ten (10) working days after delivering Notice of such withdrawal to the Project Manager. The
Project Manager shall immediately forward such Notice to the Participants. In the event that a
Participant becomes Bankrupt, it shall be deemed to have withdrawn effective as of the date on
which it becomes Bankrupt. Any Participant who withdraws from Stage One (a "Withdrawing
Participant") forfeits its Credits and any and all other Interest in Stage One and future stages of
the Project, subject to Section 11.2(b) (Effecting Withdrawals) below. The Withdrawing
Participant's Participation Percentage and Credits shall be allocated to the remaining Participants
pro rata to their Participation Percentages.
11.2 Effecting Withdrawals. The Withdrawing Participant's participation in
the Project shall be subject to the following:
(a)the Withdrawing Participant(s) shall not be released from its payment
obligations under Section 2(a) (Participation in Stage One) but its Commitment Amount under
Schedule 1 (Payment Schedule) will not increase after the withdrawal takes effect nor will its
payment dates be altered;
(b)the Withdrawing Participant shall have no interest in or rights to the
Project Information or assets or funds of the Project Owner Group after the effective date of its
withdrawal, except that the Withdrawing Participant shall have access to and copies of any draft
or final studies and other work product funded by such Withdrawing Participant;
(c)the rights of the Withdrawing Participant(s) in respect of such
participation against the other Participants (including, without limitation, the Credit of such
Withdrawing Participant(s)) will be cancelled;

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(d)the -Withdrawing Participant shall remain subject to Sections 5.7(c)
(Limitation of Liabilities; Indemnity), 9 (Confidentiality and Public Communications) and 24
(Dispute Resolution) in its capacity as a Former Participant; and
(e)the Withdrawing Participant shall execute documents as reasonably-
requested by the Project Manager or the Project Owners Group in connection with its
withdrawal, including as necessary to evidence relinquishment of its rights in any Stage One
Account.
12. Term of Agreement. (a) This Agreement shall commence on the
Effective Date and shall terminate on the earlier of the following:
(i)upon unanimous consent of the Project Owners Group in accordance with
Section 5.3 (Voting) (except as provided in Section 12(a)(iii) below); or
(ii)June 1, 2009; or
(iii)where the Project Owners Group has not approved an amended Approved
Budget within ninety (90) days of the Project Manager's report that work must be
suspended due to exhaustion of the Approved Budget; or
(iv)upon such date as each of the Participants executes a separate agreement
that by its terms supersedes this Agreement (or consents in writing to be excluded from
such agreement), addressing the continuing rights and obligations of the signatories to
that agreement in the Project; or
(v)upon withdrawal of any Participant, such that after giving effect to such
withdrawal, fewer than two Participants will remain.
(b)Upon termination, all outstanding accounts, whether external or between
the Participants (as of the date of termination), shall be settled in accordance with the principles
set out in Section 7 (Cost Sharing). In the event of termination pursuant to Sections 1 2(a)(i), Liil
or above, all funds not expended and any liabilities outstanding shall be allocated among the
Participants in proportion to each Participant's Participation Percentage (as of the date of
termination) and the Project Manager shall be responsible for winding up any remaining matters.
In the event of a termination pursuant to Section 1 2(a)(iii). the disposition of any remaining
funds and the resolution of any remaining liabilities shall be determined in accordance with the
superseding agreement.
(c)The provisions of Section 9(a) (Confidentiality) shall survive the
termination or expiration of this Agreement for a period of three years (provided that nothing
herein shall terminate, curtail or limit any confidentiality obligation arising under a separate
agreement or regulations). Termination or expiration of this Agreement shall not relieve any
Entity of any of its liabilities and obligations arising hereunder prior to the date of such
termination or expiration. Applicable provisions of this Agreement, including without limitation,
Sections 5.7 (Limitations of Liability; Indemnities), 7.1 (Payment of Stage One Costs),
(Project Accounts and Invoicing), and 24 (Dispute Resolution), shall survive the termination or
expiration of this Agreement, and each such provision of this Agreement shall continue to be
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binding on and enforceable against each Participant or Former -Participant (to the extent not
otherwise limited herein) by the Participant or Former Participant in whose favor such provision
runs, in each case (i) for a period of twelve (12) months following the termination or expiration
of the Agreement and for such longer period as necessary to enforce any claims or actions
brought against a Participant or Former Participant prior to the conclusion of such twelve (12)
month period, except in the event of fraud and third-party claims, in which case, such provisions,
rights and obligations shall survive until the applicable statute of limitations has run and (ii) to
the extent necessary to provide for final allocation and payment of liabilities and obligations and
to wind-up the affairs of the Participants under this Agreement.
13. Representations and Warranties. As of the Effective Date, each of the
Participants hereby represents and warrants to the other Participants as follows:
(a)it is duly organized, validly existing and in good standing under the
respective laws of the jurisdiction in which it is organized;
(b)it has all requisite power and authority to enter into this Agreement and to
perform the obligations contemplated hereby, and the execution and delivery of this
Agreement and the performance thereof have been duly authorized by all necessary
action on the part of such Participant;
(c)neither the execution and delivery of this Agreement nor the performance
thereof will violate, conflict with, or result in a breach of any law or provision of such
Participant's organizational documents or any agreement, document or instrument to
which it is subject or by which it or its assets are bound or require the consent or approval
(if not already obtained) of any shareholder, partner, equity holder, holder of
indebtedness or other person or entity, or contravene or result in a breach of or default
under or the creation of any lien, charge or encumbrance upon any property under any
constitutive document, indenture, mortgage, loan agreement, lease or other agreement,
document or instrument to which that Participant is a party;
(d)any required authorizations of and exemptions, actions or approvals by,
and any required notices to or filings with, any governmental authority that are required
to have been obtained or made by such Participant, in connection with the execution and
delivery of this Agreement or the performance by it of its obligations hereunder will have
been obtained or made and will be in full force and effect, and all conditions of any such
authorizations, exemptions, actions or approvals will have been satisfied;
(e)it has made its own independent investigation and assessment of Stage
One in connection with its own participation in Stage One and this Agreement and has
not relied on any information or documentation provided to it by the other Participants;
(0 it is subject to civil and commercial law with respect to its obligations
under this Agreement, and the execution, delivery and performance of this Agreement
constitute private and commercial acts rather than public or governmental acts. It is not
immune from suit, court jurisdiction, attachment prior to judgment, attachment in aid of
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execution of a judgment, set-off, execution of a judgment or from any other legal process
with respect to the obligations of such Participant under this Agreement;
(g)it is not Bankrupt and there are no proceedings pending or being
contemplated by it or, to its knowledge, threatened against it which would result in it
being or becoming Bankrupt; and
(h)it has executed and delivered the Common Interest Privilege Agreement.
14.Covenants. Each Participant covenants and agrees as follows:
14.1 Compliance with Laws. Each Participant shall conduct its business in
compliance with all applicable requirements of law, including all relevant governmental
regulations, approvals and environmental laws.
14.2 Good Faith: Exclusivity. (a) Each Participant shall use good faith in its
dealings with the other Participants.
(b) During the term of this Agreement, each Participant shall deal exclusively
with the other Participants in the development of the Project, except that, notwithstanding
anything else in this Agreement, upon the termination of this Agreement, if a Participant or
Participants desire to proceed in developing the Project, then such Participants own the Project
Information, subject to the right of each Participant and Former Participant to have access to and
copies of any studies (draft or final) or other work product funded by such Participant or Former
Participant. Nothing in this paragraph prohibits communications with other entities concerning
the --Project or its impact on other projects, consistent with the terms and conditions of this
Agreement.
14.3 Independent Appraisal. Each Participant shall continue to make its own
independent appraisal of Stage One for so long as it participates in Stage One and this
Agreement.
14.4 Negotiations. The Participants shall, in good faith -and in a commercially
reasonable manner, engage in negotiations during the period in which this Agreement is in effect
to determine a mutually acceptable plan of service and an equitable allocation of ownership and
usage rights in the Project (and the segments thereof), consistent with the allocation of Credits
made pursuant to this Agreement.
15.Successors: Assignments.
15.1 Successors. This Agreement shall be binding upon and inure to the
benefit of the Participants and their respective successors and permitted assigns.
15.2 Assignments. Except as provided in Section 10 (Transfers), Section 11
(Withdrawal) or as the Participants may agree pursuant to Section 12(a)(iii) (Term of
Agreement), no Participant may assign or transfer all or any part of its rights and obligations
hereunder. Any assignment or transfer made in violation of this Section 15.2 (Assignments)
shall be null and void.
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16.Severance. If any provision of this Agreement or part thereof is rendered
void, illegal or unenforceable in any respect under any law, the validity, legality and
enforceability of the remaining provisions hereof shall not in any way be affected or impaired
thereby.
17.Waiver. No waiver by a Participant of any provision of this Agreement
shall be binding unless made expressly and expressly confirmed by it in writing. Any such
waiver shall relate only to such matters of non-compliance or breach as it expressly relates to and
shall not apply to any subsequent or other matter of non-compliance or breach.
18.Amendment. Any amendment to this Agreement shall only be binding if
reduced to writing and signed by the duly authorized representatives of the Participants, except
amendments to the Schedules hereto that are approved by the Project Owners Group and
specifically designated by the Projects Owners Group to become effective without signature of
the Participants.
19.Entire Agreement. This Agreement, the Schedules attached hereto and the
documents referred to in it contain or expressly refer to the entire agreement between the
Participants with respect to the subject matter hereof, and expressly exclude any warranty,
condition or other undertaking implied at law or by custom and supersede all previous
agreements and understandings between the Participants with respect thereto and each of the
Participants acknowledges that it does not enter into this Agreement in reliance upon any
representation, warranty or other undertaking not fully reflected in the terms of this Agreement
or the documents referred to in it.
20.Counterparts. This Agreement may be executed in any number of
counterparts, and this has the same effect as if the signatures on the counterparts were on a single
copy of this Agreement.
21.Notices.
21.1 Giving of Notices. All notices or other communications under or in
connection with this Agreement (each, a "Notice")- shall be given in writing, by e-mail, or by
facsimile. Any such Notice will be deemed to be given as follows:
(a)if in writing, when delivered; or
(b)if by facsimile or e-mail, when received.
However, a Notice given in accordance with the -above but received on a
non-working day or after business hours in the place of receipt will only be deemed tc be given
on the next working day in that place.
21.2 Addresses for Notices. The address, facsimile number and e-mail address
of each Participant for all Notices under or in connection with this Agreement are as set forth in
Schedule 9 (Notice Information). Schedule 9 shall be deemed to include (and deemed to be
amended to include, as applicable) the address, facsimile number and e-mail address of each
Additional Participant, as set forth in the applicable Assignment Agreement, and the address,
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facsimile number and e-mail address of any Participant as it may be amended by notice by that
Participant for this purpose to the Project Owners Group by not less than five (5) working days
Notice.
22.No Partnership. None of the provisions of this Agreement shall be
deemed to constitute a partnership between the Participants and none of them shall have any
authority to bind any other Participant in any way other than as expressly provided herein.
23.Governing Law. This Agreement shall be governed by, and construed in
accordance with, the law of the State of New York without regard to the conflict of law rules
thereof (other than Section 5-1401 of the New York General Obligations Law).
24.Dispute Resolution.
24.1 Intent of the Parties. Except as provided in the next sentence, the sole
procedure to resolve any claim arising out of or relating to this Agreement or any related
agreement is the dispute resolution procedure set forth in this Section 24 (Dispute Resolution).
Any Participant may seek a preliminary injunction or other provisional judicial remedy if such
action is necessary to prevent irreparable harm or preserve the status quo, in which case the
Participants nonetheless will continue to pursue resolution of the dispute by means of this
procedure.
24.2 Management Negotiations.. (a) The Participants will attempt in good faith
to resolve any controversy or claim arising out of or relating to this Agreement or any related
agreements by prompt negotiations between each Participant's representative to the Project
Owners Group, or such other person designated in writing as a representative of the Participant
(each a "Manager"). Any Manager may request a meeting (in person or telephonically) to
initiate negotiations to be held within ten (10) working days of receipt by each Participant
involved in the dispute of such request, at a mutually agreed time and place. If the matter is not
resolved within fifteen (15) working days of their first meeting (the "Initial Negotiation End
Pate"), the Managers shall refer the matter to the designated senior officers of their respective
companies (the "Executive(s)"), who shall have authority to settle the dispute. Within five (5)
working days of the Initial Negotiation End Date (the "Referral- Date"), each Participant shall
provide one another Notice confirming the referral and identifying the name and title of the
Executive who will represent the Participant.
(b)Within five (5) working days of the Referral Date, the Executives shall
establish a mutually acceptable location and date, which date shall not be greater than thirty (30)
days from the Referral Date, to meet. In the event that the Participants cannot agree upon a
location, the location shall be Portland, Oregon. After the initial meeting date, the Executives
shall meet, as often as they reasonably deem necessary, to exchange relevant information and to
attempt to resolve the dispute.
(c)All communication and writing exchanged among the Participants in
connection with these negotiations shall be confidential and shall not be used or referred to in
any subsequent binding adjudicatory process among the Participants.
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(d) If the matter is not resolved within forty-five (45) days of the Referral
Date, or if the Participant receiving the initial request to meet, pursuant to subsection (a) above,
refuses or does not meet within the ten (10) working day period specified in subsection (a)
above, any Participant may initiate mediation of the controversy or claim according to the terms
of the following Section 24.3 (Mediation).
24.3 Mediation. If the dispute cannot be so resolved by negotiation as set forth
in Section 24.2 (Management Negotiations) above, it shall be resolved at the request of any
Participant through a two-step dispute resolution process administered by the American
Arbitration Association (the "AAA"). As the first step, the Participants agree to mediate any
controversy before a mediator from the AAA panel, pursuant to AAA's Commercial Mediation
Rules. The mediation shall be held in a location designated by agreement of the disputing
Participants, provided that if no agreement is reached, the location shall rotate among the cities
in which the main headquarters of the disputing Participants are located. Any Participant may
begin mediation by serving a written demand for mediation. The mediator shall not have the
authority to require, and no Participant may be compelled to engage in, any form of discovery
prior to or in connection with the mediation. If within sixty (60) days after service of a written
demand for mediation, the mediation does not result in resolution of the dispute, then the
controversy shall be settled by arbitration conducted by a retired judge or justice from the AAA
panel conducted in a location designated by agreement of the disputing Participant, provided that
if no agreement is reached, the location shall be Portland, Oregon, administered by and in
accordance with AAA's Commercial Arbitration Rules (the "Arbitration"). The period
commencing from the date of the written demand for mediation until the appointment of a
mediator shall be included within the sixty (60) day mediation period. Any mediator(s) and
arbitrator(s) shall have no affiliation with, financial or other interest in, or prior employment
with, any Participant and shall be knowledgeable in the field of the dispute. Any Participant may
initiate Arbitration by filing with the AAA a notice of intent to arbitrate within sixty (60) days of
service of the written demand for mediation.
24.4 Arbitration. (a) At the request of a Participant that is a voluntary or
necessary party to the dispute ("Disputing Party"), the arbitrator shall have the discretion to order
depositions of witnesses to the extent the arbitrator deems such discovery relevant and
appropriate. Depositions shall be limited to a maximum of three (3) per Participant and shall be
held within thirty (30) days of the making of a request. Additional depositions may be scheduled
only with the permission of the arbitrator, and for good cause shown. Each deposition shall be
limited to a maximum of six (6) hours duration unless otherwise permitted by the arbitrator for
good cause shown. All objections are reserved for the Arbitration hearing except for objections
based on privilege and proprietary and confidential information. The arbitrator shall also have
discretion to order the Participants to exchange relevant documents. The arbitrator shall also
have discretion to order the Participants to answer interrogatories, upon good cause shown.
(b) Each of the Disputing Participants shall submit to the arbitrator, in
accordance with a schedule set by the arbitrator, offers in the form of the award it considers the
arbitrator should make. If the arbitrator requires the Disputing Participants to submit more than
one such offer, the arbitrator shall designate a deadline by which time the Participants shall
submit their last and best offer. In such proceedings the arbitrator shall have the authority to
make monetary and/or non-monetary awards. In the case of non-monetary awards, the arbitrator
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shall be limited to awarding only one of the "last and best" offers submitted, and shall not
determine an alternative or compromise remedy. With the exception of indemnification
obligations arising under Section 5.7(b), the total monetary award that the arbitrator may require
from any single Participant is limited to the combined total Commitment Amount for all
Participants. With regard to monetary awards for indemnification under Section 53(b), the total
monetary award that the arbitrator may require from any single Participant has no monetary cap,
but shall only be awarded in accordance with and as limited by Section 53(b).
(c)The arbitrator shall have no authority to award punitive or exemplary
damages or any other damages other than direct and actual damages and the other remedies
contemplated by this Agreement.
(d)The arbitrator's award shall be made within nine (9) months of the filing
of the notice of intention to arbitrate (demand) and the arbitrator shall agree to comply with this
schedule before accepting appointment. However, this time limit may be extended by agreement
of the Participants or by the arbitrator, if necessary. The California Superior Court of the City
and County of San Francisco may enter judgment upon any award rendered by the arbitrator.
The Participants are aware of the decision in Advanced Micro Devices, Inc. v. Intel Corp., 9 Cal.
4th 362 (1994) and, except as modified by this Agreement, intend to limit the power of the
arbitrator to that of a Superior Court judge enforcing New York law. The prevailing Disputing
Participant(s) in this dispute resolution process is entitled to recover its costs and reasonable
attorneys' fees from the non-prevailing Disputing Participant(s). All the Disputing Participants
shall indemnify, pLo rata based on the Percentage Participation of such Disputing Participants at
the conclusion of the dispute, each Participant that is not a Disputing Participant for the costs and
reasonable attorneys' fees incurred by such non-Disputing Participant to respond to discovery,
provide witnesses or otherwise participate in the dispute.
(e)The arbitrator shall have the authority to grant dispositive motions prior to
the commencement of or following the completion of discovery if the arbitrator concludes that
there is no material issue of fact pending before him or her.
(f)Except as may be required by law, neither a Participant nor an arbitrator
may disclose the existence, content, or results of any Arbitration hereunder without the prior
written consent of each Participant, provided that nothing herein limits or bars a Disputing
Participant from disclosure to a Participant that is not a Disputing Participant.
24.5 Former Participants
The rights and obligations of a Participant pursuant to this Section 24 (Dispute
Resolution) shall apply equally and in all respects to a Former Participant, to the extent such
Participant is a Disputing Participant.
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IN WITNESS HEREOF this Agreement has been entered into on the Effective
Date.
Executed and agreed:
PACIFIC GAS AND ELECTRIC COMPANY
By:
Name: Edward A. Salas
Title: Senior Vice President, Engineering and Operations
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Executed and agreed:
AVISTA CORPORATION
By:
Name: Don Kopczynski
Title: Vice President, Transmission and Distribution Operations
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Executed and agreed:
BRITISH COLUMBIA TRANSMISSION CORPORATION
By:
Name: Doug Little
Title: Vice President, Customer & Strategy Development
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Executed and agreed:
PACIFICORP
By:
Name: Darrell T. Gerrard
Title: Vice President, Transmission System Planning
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SCHEDULE I
PAYMENT SCHEDULE (Assuming 12.25% shares on Initial Project Budget)
(1-) (2) (3) (4) (5)
Participant Payment I Payment 2 Payment 3 Commitment (6)
[Due 30 days [Due 10/31/08] [Due 12/19/08] Amount Participation after Agreement 2 Percentage is Signed, Est
9/30/081 1
Avista $292,359 $73,500 $58,800 $424,659 12.25
British $292,359 $73,500 $58,800 $424,659 12.25
Columbia
Transmission
Corporation
PacifiCorp $292,359 $73,500 $58,800 $424,659 12.25
Pacific Gas and $1,509,525 $379,500 $303,600 2,192,625 63.25
Electric
Company
$2,386,600 $600,000 $480,000 $3,466,600 100
Note: Payments are intended to match cash flow. Payment I assumes the non-PG&E members
of the Project Owners Group share in $576,000 of the $2,160,700 in previously-incurred CH2M
HILL costs (for mapping of routes and other tasks described in the opportunities and constraints
report). This issue was discussed with routing and permitting personnel at an April 2 d meeting.
The $576,000 is 36.75% of $1,586,000 which is the portion of the previously-incurred costs
($2,160,700) estimated be applicable to and useful for the Project going forward.
Payment I includes the Project Owners Group share of previously incurred CH2M Hill costs (see below) and
anticipated payments to agreed upon consultants listed in Schedules 2 and 5. Payments by the Participants could be
due on a certain date, or when certain conditions are met and notice is given. Parties to advise as to which option
they prefer and, if payment is due when conditions are met, specify conditions.
2 Should indicate percent of funding each Participant is providing.
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SCHEDULE 2
STAGE ONE OBJECTIVES AND ACTIVITIES
1 Objectives
The Project Owners Group plans to proceed with project development activities on the
BC/Pacific Northwest/Northern California Transmission Project under which a transmission line
extending from the Selkirk substation in British Columbia, Canada, into the state of California
would be developed. The Project also includes but is not limited to the potential development of
and interconnection to a substation hub located near Echo, Oregon, with its exact location to be
determined through further technical, land-use, and permitting studies, and other related
facilities. The-following details the arrangements PG&E proposed in support of the project
objectives as listed in Section 3 of the Stage One Project Development Agreement. The
objectives of the activities chosen are to define the project scope and begin to identify the costs,
risks, benefits and opportunities.
The estimated costs are shared costs for consulting services for the Project. Per the Stage One
Project Development Agreement only approved consulting fees will be shared among the project
Participants. Other costs incurred by Participants for employee labor, company's legal counsel
or travel expenses will not be shared.
2.Work Plan
The work plan for Stage I includes work already underway to contract with firms to perform the
electrical system studies and prepare resource mapping of possible transmission line corridors
(3.1 —3.2). Other contracts that are being considered are for project management, project
accounting, public and political relations firms, and engineering firms (3.3 - 3.4).
3.Proposed consulting arrangements
3.1. Transmission Planning activities: ABB Consulting
3.1.1. Performing-electrical system studies in support of WECC Phase 1 Project
rating activity
Work plan: The Project will hire ABB Consulting to work with PG&E and other
participants to develop WECC Phase I Project Rating including:
1.Develop a multi-terminal HVDC model for power flow and transient
stability analysis.
2.Assist in the modeling of wind farms for power flow and transient stability
analysis.
3.Run power flow and transient stability studies to demonstrate the non-
simultaneous rating of each section of the Project line.
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4-. Evaluate the technical feasibility of the proposed locations of the Project's
HVDC converter stations
Deliverables: Technical study reports for each of the tasks in section 3. 1.1 above,
summarizing the results of each task. PG&E will use the study results from- AB-B as
input to the Project's WECC Comprehensive Progress Report. This will be the basis
for obtaining a WECC approved Phase 1 project rating. The approved rating protects
the Project capacity from being adversely impacted by future projects without
mitigation.
Estimated consulting fees: $100,000
Estimated duration: Feb '08 to Dec '08.
3.1.2. Support in developing the plan of service (POS)
Work plan:
1.Perform plan of service studies.
2.Perform transmission line rating studies, evaluate proposed points of
interconnection, and identify network upgrades required.
3.Evaluate the technical feasibility of the proposed HVDC Converter locations.
Deliverables: Preliminary plan of service, participants comments on the PUS and a final
plan of service
Estimated consulting cost: $100,000
Estimated duration: Mar '08 to Aug '08 for preliminary plan that will be routed for
comments. Agreed upon POS by Sept '08.
3.2. Routing, Planning & Permitting: Initially C112M HILL (or others)
3.2.1. Preliminary environmental assessment, mapping, and pre-EIRJEIS work
Work plan: Initially hire CH2M HILL to prepare resource mapping (map natural
resources, endangered species, cultural resources, etc) of the WECC study area
previously identified as the western corridor (approximately from Lower Monumental
to Table Mountain) to supplement the resource mapping prepared for the BC
Renewables project, which followed an eastern corridor from Selkirk to Tesla.
Deliverables: Opportunities and Constraints Report and Resource maps of the WECC
western corridor from Selkirk to Tesla. CH2M HILL has already completed the
mapping work, and is nearly finished with an opportunities and constraints report for
the eastern corridor.
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Estimated consulting cost: $1,586,600 + $400,000 = $1,986,600 (assumes that the
participants will share the $1,586,600 cost of useful work products created in 2007 and
an estimated $400,000 for work in 2008).
Estimated duration: CH2M HILL started its work in June 2007 and is forecast to
complete Stage 1 work by September 2008.
3.2.2. Performing route analysis and preliminary scoping
Work plan: Using the products of Task 3.2.1, work with project participants to start
identifying project alternatives and transmission line routes, including use of existing
rights-of-way. Develop a scope of work based on these alternatives to be used in a
consultant request for proposals.
Deliverables: Alternative routes and rights-of-way assessments. (It is conceivable that
project participants could use this deliverable in development of a request for proposal
for the preparation of the PEA-type document.)
Estimated consulting cost: $0 to $600,000 for Stage I depending when this task is
started.
Estimated duration: This would last until the end of Stage 1 and continue if Stage 2 is
implemented.
33. Project development & public affairs plan: Gallatin Group (or others)
Work plan: Hire Gallatin -Group (or others) to support various political, regulatory, and
public relations objectives. (Note that PG&E, at its sole cost, is contracting with
Gallatin to perform initial research and report findings)
Deliverables: To be developed by the project participants. Work products would feed
into the plan for working with governmental and regulatory agencies and a public
relations / participation plan (also see 3.2.3).
Estimated consulting cost: $250,000 for Stage I (excludes cost of PG&E's initial
contract).
Estimated duration: This would last until the end of Stage 1 and continue if Stage 2 is
implemented.
3.4. Other contracts (consultants not yet identified)
3.4.1. Developing a schedule and overall plan for development of the Project
Work plan: The Project will hire a project management firm to assist project
participants to: develop a project management plan including the scope definition, the
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work breakdown structure (WBS), define and list activities. The project participants
will assist the project manager in developing the schedule. The Project will also hire
the project management firm or a separate accounting firm to track how costs are
allocated. (At the February 28 steering committee meeting the consensus was to
prepare to hire a project management firm but not bring them on board under Stage 2.
Accounting support should be brought in for Stage 1.)
Deliverables: Project management plan that will include a scope statement, scope
definition, WBS and schedule plan. These deliverables will be refined over time with
input from the participants.
Estimated consulting cost: $0 to $55,000 for accounting support. Cost depends on
when the firm is brought in during Stage I and how much assistance is desired.
Estimated duration: The activity will continue throughout Stage 1. If the project moves
into Stage 2 this will be an ongoing activity.
3.4.2. Preliminary transmission line engineering design
Work plan: As the plan of service is developed, a certain amount of engineering will be
needed to support related activities (for example environmental impacts cannot be
assessed without knowing what will be built and how it will be constructed).
Engineering groups from all Participant utilities will make reasonable efforts, subject to
resource availability, to participate in establishing design, operating, and maintenance
criteria. The Project will hire an engineering firm to work with Project Participants.
Deliverables:
1.Design criteria.
2.Preliminary operations and maintenance requirements.
3.Preliminary plan for new project related facilities such as permanent
maintenance yards and other ancillary facilities.
Estimated consulting cost: $0 to $100,000 depending on when this task is started
during Stage 1.
Estimated duration: This work will last until the end of Stage 1 and continue in some
form if Stage 2 is implemented.
3.4.3. Preliminary substation engineering design
Work plan: As the plan of service is developed a certain amount of engineering will be
needed to support related activities (for example determining location, costs, sizes of
DC converter stations). Engineering groups from all Participant utilities will make
reasonable efforts, subject to resource availability, to participate in establishing design,
operating and maintenance criteria. The Project will hire an engineering firm to work
with Project participants.
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Deliverables: Design criteria. Preliminary operations and maintenance requirements.
Line terminal information needed to support other Stage I work.
Estimated consulting cost: $0 to $25,000 depending on when this task is started during
Stage 1.
Estimated duration: This work will last until the end of Stage I and continue in some
form if Stage 2 is implemented.
3.4.4. Project legal support
Work plan: As the plan of service is developed it may be useful to have Project legal
counsel that can advise the participants on permitting, routing and land use issues.
Deliverables: Legal counsel to support other Stage 1 work.
Estimated consulting cost: $0 to $250,000 depending on if and when this task is started
during Stage 1.
Estimated duration: This work will last until the end of Stage I and continue in some
form if Stage 2 is implemented.
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SCHEDULE 3
STAGE ONE TIMETABLE
ID Activity Start Date Complete Date
I Perform electrical system studies in support of WECC 2/1/08 10/15/08
Phase I project rating
2 Complete WECC Phase One Rating Studies and plan 3/1/08 9/30/08
of service, including participant reviews
3 Preliminary environmental assessment, mapping and 6/1/07 10/15/08
pre-EIRJEIS work
4 Project development, political and public relations 211/08 through term of Stage One
5 Preliminary substation and transmission line 5/1/08 through term of Stage One
engineering as required to support Stage 1
6 Legal counsel to the project participants as required to 5/1/08 through term of Stage One
support Stage I
7 Project management and accounting services to support 5/1/08 through term of Stage One
Stage I
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SCHEDULE 4
INITIAL REPRESENTATIVES AND ALTERNATES TO THE PROJECT OWNERS GROUP
Company Initial Representative Alternate Representative
Avista Don Kopczynski Scott Waples
British Columbia
Transmission Corporation
Doug Little Rohan Soulsby
PacifiCorp Darrell Gerrard Brian Fritz
Pacific Gas and Electric
Company
Steve Metague Kevin Dasso
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SCHEDULE 5
ADVISORS AND CONSULTANTS
Advisor or Consultants - Tasks
ABB Consulting Perform electrical system studies
CH2M HILL Perform environmental routing & mapping tasks
(in US)
Gallatin Not under contract. Tasks to be determined
To be determined Project Accounting
SWCA, Inc Act as project owners' representative in
preparation of RFP for regulatory permitting.
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SCHEDULE 6
STAGE ONE COSTS INCURRED TO DATE
Shared Contracts Committed Costs Actual Costs to Project
ABB Consulting $100,000 $36,586
CH2M HILL (2008) $493,395 $132,506
Ch2MH1II (2007/2008) $$1,586,600 $1,586,600
SWCA, Inc. $300,000 $0
Total $2,479,995 $1,755,692
Note: Committed costs are actual contract values. The CH2M HILL (2007/2008) cost of
$1,586,600 is the estimated amount of the $2,160,700 that is applicable and useful for the
Project.
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SCHEDULE 7
INITIAL PROJECT BUDGET
Listed here are the budgeted costs of Stage I consulting work.
ID Activity Budget
1 Perform electrical system studies in support of WECC Phase 1 $100,000
project rating (included in Payment 1)
2 Development of the plan of service, including participant reviews $100,000
(included in Payment I)
3 Preliminary environmental assessment, mapping and pre-EIRJEIS $1,586,600 (see note)
work, previously performed (included in Payment 1)
4 Preliminary environmental assessment, mapping and pre-EIRJEIS $1,000,000
work, to be performed (split 50150 in Payments I and 2)
5 Project development, political and public relations (included in $250,000
Payment 3)
6 Preliminary substation and transmission line engineering as required $125,000
to support Stage I (included in Payment 3)
6 Legal counsel to the project participants as required to support Stage $250,000
I (included in Payment 3)
7 Project management and accounting services required to support $55,000
Stage 1 (included in Payment 3)
- Total $3,466,600
Note: Amount assumes the Project Owners Group concludes that $1,586,600 of the $2,160,700
in previously incurred CH2M HILL costs (for mapping of routes and opportunities and
constraint reports) is applicable to and useful for the Project going forward.
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SCHEDULE 8
FORM OF ASSIGNMENT AGREEMENT
This Assignment Agreement ("Assignment Agreement") dated as of (the
"Assignment Date") is made by _________, the Transferring Participant,
and the Project Director acting on behalf of each of the Participants.
We refer to Section 10 (Transfers) of the Stage One Project Development
Agreement (the "Agreement"). Terms defined in the Agreement shall have the same meanings
herein.
1. For an agreed consideration, the Transferring Participant (the "Assignor") hereby
irrevocably sells and assigns to the [Take-Up Participant] [and] [Additional
Participant], (the [each an] "Assignee"), and [the] [each] Assignee hereby irrevocably
purchases and assumes from the Assignor, subject to and in accordance with Section
IQ (Transfers) of the Agreement, as of the Assignment Date, an interest in and to [all
of the Assignor's Interests] [the respective percentage of Assignor's Interests
identified below] ([the] [each, a] "Transfer Interest").
Assignor Total Interest (Participation Percentage before transfer)
Transfer Interest (Participation Percentage Assigned)
Assignee [name if more than one] Transfer Interest Assumed %
[Assignee [name if more than on Transfer Interest Assumed %]
2.We, the Assignor and Assignee(s) agree and certify to the Participants that the
Assignor and the Assignee(s) are transferring by way of novation the Transferring
Participant's Transfer Interest in accordance with, and have satisfied, each provision
of Section 10 (Transfers).
3.As of the Assignment Date, (i) [the][each] Assignee shall be a party to the Agreement
and, to the extent provided in this Assignment Agreement, have the rights and
obligations of a Participant thereunder and be liable to the other Participants for
performance of the Assignor's rights and obligations thereunder in each case, to the
extent of its Transfer Interest and (ii) the Assignor shall, to the extent provided in this
Assignment Agreement, relinquish its rights and be released from its obligations as a
Participant under the Agreement [with respect to the Transfer Interest]3 by the
Assignor(s) and each other Participant.
Use parenthetical if less than 100% of Interest is transferred.
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4.Assignor. The Assignor represents and warrants that (i) it is the legal and beneficial
owner of the Transfer Interest, (ii) the Transfer Interest is free and clear of any lien,
encumbrance or other adverse claim and (iii) it has full power and authority, and has
taken all action necessary, to execute and deliver this Assignment Agreement and to
consummate the transactions contemplated hereby. Except as set forth in this
paragraph 4, the Assignor makes no representations and warranties.
5.Assignee. [The] [Each] Assignee represents and warrants to the Assignor and each of
the Participants (a) that it has full power and authority, and has taken all action
necessary, to execute and deliver this Assignment Agreement and to consummate the
transactions contemplated hereby and (b) each of the statements set forth in Section
U (Representations and Warranties) of the Agreement (as to such Assignee), as of
the Assignment Date.
6.Notice. The Additional Participant's address for notices for the purposes of Section
21 (Notices) is:
7.Governing Law. This Assignment Agreement shall be governed by the law of the
State of New York without regard to the conflict of law rules thereof (other than
Section 5-1401 of the New York General Obligations Law).
8.General Provisions. This Assignment Agreement shall be binding upon, and inure to
the benefit of, the parties hereto and their respective successors and assigns. This
Assignment Agreement may be executed in any number of counterparts, which
together shall constitute one instrument. Delivery of an executed counterpart of a
signature page of this Assignment Agreement by telecopy shall be effective as
delivery of a manually executed counterpart of the Assignment Agreement.
Transferring Participant Additional Participant Take-Up Participant(s)
EXECUTED by ) EXECUTED by ) EXECUTED by
[TRANSFERRING ) [ADDITIONAL ) [TAKE-UP
PARTICIPANT] ) PARTICIPANT] ) PARTICIPANT]
acting by: ) acting by: ) acting by:
Counter-signed by:
Project Director
on behalf of all Participants
Date: [ I
WASHJNQTON 147760 v4 (2K)
Stage One Agreement PG&E Version 942008
Staff—PR-030 Attachment B
STAGE ONE AGREEMENT
Page 44of79 1
SCHEDULE 9
NOTICE INFORMATION
Avista
Address: Avista Corporation
1411 E. Mission Avenue, MSC-23
Spokane, WA 99202
Attn: Michael G. Andrea, Staff Attorney
Phone: [phone]
Fax: [phone]
Email: [e-mail]
Addres s: Avista Corporation
1411 E. Mission Avenue, MSC-20
Spokane, WA 99202
Attn: Don Kopczynski, Vice President, Transmission and Distribution Operations
Phone: [phone]
Fax: [phone]
Email: Don.Kopczynskiavistacorp.com
BCTC
Address: British Columbia Transmission Corp.
P.O. Box 49260, Four Bentall Centre
Suite 1100 - 1055 Dunsmuir St.
Vancouver, B.C. V7X 1V5
Attn: Rohan D. Soulsby, Director, Market Operations and Development
Phone: [phone]
Fax: [phone]
Email: [e-mail]
WASHINGFON 1457760 v4 (2K) STAGE ONE AGREEMENT Stage One Agreement PG&E Version 942008
Staff_PR_030 Attachment 8 Page 45 of 79
PG&E
Address: 123 Mission St. Mail code Hi 1K
San Francisco, CA 94105
Attn: Mark T. Schexnayder
Phone: [phone]
Fax: [phone]
Email: [e-mail]
PacifiCorp
Address: 825 NE Multnomah Street
Portland, OR 97232
Attn: Darrell T. Gerrard, Vice President, Transmission System Planning
Phone: [phone]
Fax: [phone]
Email: [e-mail]
WASHINGTON 1457760 v4 (2K) STAGE ONE AGREEMENT Stage One AgTeernent PG&E Version 942008
Staff—PR-030 Attachment B Page 46 of 79
AMENDMENT NO. I
This AMENDMENT NO. I (this "Amendment"), dated as of May 28, 2009, is
entered into among PACIFIC GAS AND ELECTRIC COMPANY, a corporation incorporated in
the State of California (P0& E"), PACIFICORP, a corporation incorporated in the State of
Oregon ("PacifiCorp"), AVISTA CORPORATION, a corporation incorporated in the State of
Washington ("Avista"). and BRITISH COLUMBIA TRANSMISSION CORPORATION, a
corporation incorporated in British Columbia, Canada ("BCTC").
W I T N ES S E T H:
WHEREAS, the parties hereto entered into the Stage One Project Development
Agreement (the "Stage One Agreement"). dated as of September 25, 2008; and
WHEREAS, the parties hereto desire to enter into this Amendment to amend the
Stage One Agreement as set forth below;
NOW THEREFORE, it is agreed:
I. Amendment to the Stage On.e .Aireeinen.t. Section 1 2(a)(ii) of the Stage
One Agrement is hereby amended by replacing the date "June 1, 2009" with "August 7,2M".
2.No Waiver, Except as specifically provided above, this Amendment shall
not in any way operate as a consent, waiver or forbe4rarlce under any provision of the Stage One
Agreement, and all of the terms and provisions of the Stage One Agreement shall remain in full
force and effect.
3.Effective Date. This Amendment shall become effective as of the date
hereof (the "Effective Date") when each of the parties hereto shall have executed and delivered
(including by way of facsimile-or electronic "pdf" format) duly executed counterparts of this
Amendment.
4.Governing Law. THIS AMENDMENT AND THE RIGHTS AND
OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE CONSTRUED IN
ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF NEW
YORK WITHOUT REGARD TO THE CONFLICT OF LAW RULES THEREOF (OTHER
TI IAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW).
5.Incorporation of Provisions. Except as amended and supplemented by the
provisions set forth in this Amendment, all of the terms and conditions of the Stage One
Agreement shall remain in lull force and effect following execution of this Amendment and each
Party confirms, ratifies and approves the Stage One Agreement as amended by this Amendment
All capitalized terms used herein and not otherwise defined shall have the respective meanings
given to such terms in the Stage One Agreement (as defined below), and the principles of
Amendment No. I to the Stage One Ajoement
Staff—PR-030 Attachment B Page 47 of 79
construction and rules of interpretation set forth in Section 1.2 of the Stage One Agreement shall
apply mutatis mutandis to this Amendment as if the same were expressly set forth herein For
the avoidance of doubt, all references in the Stage One Agreement to the Stage One Agreement
shall be deemed to be references to the Stage One Agreement as amended by this Amendment
&. Counterparts. This Amendment may be executed in any number of
counterparts and by the different parties hereto on separate counterparts, each of which when so
executed and delivered shall be an original. but all of which shall together constitute one and the
same instrument.
* * *
Amendment No. I to [tic Stage One Agreement 2
Staff_PR_030 Attachment B
Page 48 of 79
IN WITNESS WHEREOF, each of the parties hereto has caused a counterpart of
this Amendment to be duly executed and delivered as of the date first above written.
PACIFIC GAS AND ELECTRIC
COMPANY
By:______________________
NaiSe: Edward A. Salas .
Title: Senior Vice President
Engineering and Operations
Amendment No. ito the Stage One Agreement 3
Staff—PR-030 Attachment B Page 49 of 79
AVISTA CORPORATION
By
Name: Don opczsi
Title: Vice President
Transmission-and Distribution
Operations
Amendment No. I to the Stage One Agreement 4
Staff—PR-030 Attachment B Page 50 of 79
BRITISH COLUMBIA TRANSMISSION
CORPORATI N
By 4 <
Name: Doug Little
Title: Vice President
Customer & Strategy Development
Amendment No. ito the Stage One Agreement 5
Staff—PR-030 Attachment B Page 51 of 79
PACIFICORP
By:___________
Name: Darrell T. Gerrard
Title: Vice President
Transmission System Planning
Amendment No. Ito the Stage One Agreement 6
Staff_PRJ)30 Attachment B Page 52 of 79
AMENDMENT NO.2
This AMENDMENT NO. 2 (this "Amendrnent", dated as of July 30, 2009, is
entered into among PACIFIC GAS AND ELECTRICAL COMPANY, a corporation
incorporated in the State of Califbrnia ("PG&E"), PAC!FICORP, a corporation incorporated in
the State of Oregon ("PacifiCorp"). AV1STA CORPORATION, a corporation incorporated in
the State of Washington ("Avista"), and BRITISH COLUMBIA TRANSMISSION
CORPORATION, a corporation incorporated in British Columbia, Canada ("BCTC").
WITNESSETII:
WH}REAS, the parties hereto entered into the Stage One Project Development
Agreement, dated as of September 25, 2008, as amended by Amendment No. I, dated May 28,
2009 (together, the "Stage One Agreement"): and
WHEREAS, the parties hereto desire to enter into this Amendment to amend the
Stage One Agreement as set forth below:
NOW THEREFORE, it is agreed:
I. Amendment to the Stage One Agreement. Section 12(a)(ii) of the Stage
One Agreement is hereby amended by replacing the date "August 7, 2009" with "September 18.
2009".
2.No Waiver. Except as specifically provided above, this Agreement shall
not in any way operate as a consent, waiver or forbearance under any provision of the Stage One
Agreement, and all of the terms and provisions of the Stage One Agreement shall remain in full
force and effect.
3.Effective Date. This Amendment shall become effective as of the date
hereof (the "Effective Date") when each of the parties hereto shall have executed and delivered
(including by way of facsimile or electronic "pdf' format) duly executed counterparts of this
Amendment.
4.Governing Law. THIS AMENDMENT AND THE RIGHTS AND
OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE CONSTRUED IN
ACCORDANCE WITH AND GOVERNED 13Y THE LAWS OF THE STATE OF NEW
YORK WITHOUT REGARD TO THE CONFLICT OF LAW RULES THEREOF (OTHER
THAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW).
5.Jcooratin of Provisions. Except as amended and supplemented by the
provisions set forth in this Amendment. all of the terms and conditions of the Stage One
Agreement shall remain in full force and etTect following execution of this Amendment and each
Party confirms, ratifies and approves the Stage One Agreement as amended by this Agreement.
All capitalized terms used herein and not otherwise defined shall have the respective meanings
given to such terms in the Stage One Agreement, and the principles of construction and rules of
interpretation set forth in Section 1.2 of the Stage One Agreement shall apply i nutatis muiwidis
OHS
Staff—PR-030 Attachment B Page 53 of 79
to this Amendment as if the same were expressly set forth herein. For the avoidance of doubt, all
references in the Stage One Agreement to the Stage One Agreement shall he deemed to be
referenced to the Stage One Agreement as amended by this Amendment.
6. Countemarts. This Amendment may be executed in any number of
counterparts and by the different parties hereto on separate counterparts each of which when so
executed and delivered shall be an original, but all of which shall together constitute one and the
same instrument.
* * *
Oils Wcci:260(050.2
Staff—PR-030 Attachment B Page 54 of 79
AVISTA CORPORATION
Name: Don
Title: Vice Presit
Transmission and Distribution
Operations
OHS 'Wi: 2(19i)2 S,n,r page' . Iimni/wtnl t, Sk.ig fgr.nr,ll
Staff—PR-030 Attachment B Page 55 of 79
BRITISH COLUMBIA TRANSMISSION
CORPORATION
B7Y: L
Nax& Doug Little
Title: Vice President
Customer & Strategy Development
OHS Wcst:26069900.2 Signature page to Amendment 210 Stage One Agreement
Staff—PR-030 Attachment B Page 56 of 79
PACIFICORP
By:
Name: Darrell T. Gerrard
Title: Vice President
Transmission System Planning
OHS Wesi:260699050.2 Signature page lo Ame,,dnwni 2 lo Stage One Agreement
Staff—PR-030 Attachment B Page 57 of 79
IN WITNESS WHEREOF, each of the parties hereto has caused a counterpart of
this Amendment to be duly executed and delivered as of the date first above written.
PACIREC GAS AND ELECTRIC
COMPANY
By: 9jArr4., tit C .4x C
Jme: Edward A 8%1A
Title: Senior Vice President
Engineering and Operations
OHS West:2606990502 Stgnawe page to A,nend,nent 210 Stage One Agreement
Staff.PR_030 Attachment B Page 58 of 79
AMENDMENT NO. 3
This AMENDMENT NO. 3 (this "Amendment"), dated as of September 11, 2009,
is entered into among PACIFIC GAS AND ELECTRICAL COMPANY, a corporation
incorporated in the State of California ("PG&E"), PAC1FICORP, a corporation incorporated in
the State of Oregon ("PacifiCorp"), AVISTA CORPORATION, a corporation incorporated in
the State of Washington ("Avista"), and BRITISH COLUMBIA TRANSMISSION
CORPORATION, a corporation incorporated in British Columbia, Canada ("BCTC").
W I TN E S S E T H:
WHEREAS, the parties hereto entered into the Stage One Project Development
Agreement, dated as of September 25, 2008, as amended by Amendment No. 1, dated May 28,
2009, and Amendment No. 2, dated July 30, 2009 (together, the "Stage One Agreement"); and
WHEREAS, the parties hereto desire to enter into this Amendment to amend the
Stage One Agreement as set forth below;
NOW THEREFORE, it is agreed:
1.Amendment to the Stage One Agreement. Section 12(a)(ii) of the Stage
One Agreement is hereby amended by replacing the date "September 18, 2009" with "September
30, 2009".
2.No Waiver. Except as specifically provided above, this Agreement shall
not in any way operate as a consent, waiver or forbearance under any provision of the Stage One
Agreement, and all of the terms and provisions of the Stage One Agreement shall remain in full
force and effect
3.Effective Date. This Amendment shall become effective as of the date
hereof (the "Effective Date") when each of the parties hereto shall have executed and delivered
(including by way of facsimile or electronic "pdf' format) duly executed counterparts of this
Amendment.
4.Governing Law. THIS AMENDMENT AND THE RIGHTS AND
OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE CONSTRUED IN
ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF NEW
YORK WITHOUT REGARD TO THE CONFLICT OF LAW RULES THEREOF (OTHER
THAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW).
5.Incorporation of Provisions. Except as amended and supplemented by the
provisions set forth in this Amendment, all of the terms and conditions of the Stage One
Agreement shall remain in full force and effect following execution of this Amendment and each
Party confirms, ratifies and approves the Stage One Agreement as amended by this Agreement.
All capitalized terms used herein and not otherwise defined shall have the respective meanings
given to such terms in the Stage One Agreement, and the principles of construction and rules of
interpretation set forth in Section 1.2 of the Stage One Agreement shall apply mutatis mutandis
OHS Wcst260723753.2
Staff—PR-030 Attachment B Page 59 of 79
to this Amendment as if the same were expressly set forth herein. For the avoidance of doubt, all
references in the Stage One Agreement to the Stage One Agreement shall be deemed to be
referenced to the Stage One Agreement as amended by this Amendment.
6. Counterparts. This Amendment may be executed in any number of
counterparts and by the different parties hereto on separate counterparts, each of which when so
executed and delivered shall be an original, but all of which shall together constitute one and the
same instrument.
* * *
OHS West260723753.2
Staff—PR-030 Attachment B Page 60 of 79
IN WITNESS WHEREOF, each of the parties hereto has caused a counterpart of
this Amendment to be duly executed and delivered as-of the date first above written.
PACIFIC GAS AND ELECTRIC
COMPANY
By: 1tMyW &.
)'ame: Edward A. S1as
Title: Senior Vice President
Engineering and Operations
Signature page to Amendment 3 to Stage One Agreement
OHS West:260723753.2
Staff.PR_030 Attachment B Page 61 of 79
AVISTA CORPORATION
,Th
By:
Nhie: Don Kpckki
Title: Vice President
Transmission and Distribution
Operations
Signaysimpage to Anwndnic,,r 3 to Stage Osn Agree,ucnf
Of Wetfl3753.2
Staff—PR-030 Attachment B Page 62 of 79
BRITISH COLUMBIA TRANSMISSION
CORPORATION
ByIL) L
Name: Doug Little
Title: Vice President
Customer & Strategy Development
Signature page to Amendment 3 to Stage One Agreement
OHS West:260723753.2
Staff—PR-030 Attachment B Page 63 of 79
PACIFICORP
By:
Name: Darrell T. Gerrard
Title: Vice President
Transmission System Planning
Signature page to Amendment 3 to Stage One Agreement
OHS West:260723753.2
Staff—PR-030 Attachment B Page 64 of 79
AMENDMENT NO.4
This AMENDMENT NO. 4 (this "Amendment"), dated as of September 30, 2009,
is entered into among PACIFIC GAS AND ELECTRIC COMPANY, a corporation incorporated
in the State of California ("PG&E"), AVISTA CORPORATION, a corporation incorporated in
the State of Washington ("Avista"), and BRITISH COLUMBIA TRANSMISSION
CORPORATION, a corporation incorporated in British Columbia, Canada ("BCTC").
W I TN B S S E T H:
WHEREAS, the parties hereto, along with PACTFICORP, a corporation
incorporated in the State of Oregon ("PacifiCorp"), entered into the Stage One Project
Development Agreement, dated as of September 25, 2008, as amended by Amendment No. 1,
dated May 28, 2009, Amendment No. 2, dated July 30, 2009, and Amendment No. 3, dated
September 11, 2009 (together, the "Stage One Agreement"); and
WHEREAS, PacifiCorp has withdrawn from the Stage One Agreement effective
as of September 29, 2009, and therefore the undersigned constitute all of the Participants as of
the date of this Amendment;
WHEREAS, the parties hereto desire to enter into this Amendment to amend the
Stage One Agreement as set forth below;
NOW THEREFORE, it is agreed:
I. Amendment to the Stage One Agreement. Section 1 2(a)(ii)of the Stage
One Agreement is hereby amended by replacing the date "September 30, 2009" with "October
30, 2009".
2.No Waiver. Except as specifically provided above, this Agreement shall
not in any way operate as a consent, waiver or forbearance under any provision of the Stage One
Agreement, and all of the terms and provisions of the Stage One Agreement shall remain in flAil
force and effect.
3.Effective Date. This Amendment shall become effective as of the date
hereof (the "Effective Date") when each of the parties hereto shall have executed and delivered
(including by way of facsimile or electronic "pdf' format) duly executed counterparts of this
Amendment.
4.Governing Law. THIS AMENDMENT AND THE RIGHTS AND
OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE CONSTRUED IN
ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF NEW
YORK WITHOUT REGARD TO THE CONFLICT OF LAW RULES THEREOF (OTHER
THAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW).
5.Incorporation of Provisions. Except as amended and supplemented by the
provisions set forth in this Amendment, all of the terms and conditions of the Stage One
OHS Vet:260736I60.2
Staff—PR-030 Attachment B Page 65 of 79
Agreement shall remain in full force and effect following execution of this Amendment and each
Party confirms, ratifies and approves the Stage One Agreement as amended by this Agreement.
All capitalized terms used herein and not otherwise defined shall have the respective meanings
given to such terms in the Stage One Agreement, and the principles of construction and rules of
interpretation set forth in Section 1.2 of the Stage One Agreement shall apply mutatis mutandis
to this Amendment as if the same were expressly set forth herein. For the avoidance of doubt, all
references in the Stage One Agreement to the Stage One Agreement shall be deemed to be
referenced to the Stage One Agreement as amended by this Amendment.
6. Counterparts. This Amendment may be executed in any number of
counterparts and by the different parties hereto on separate counterparts, each of which when so
executed and delivered shall be an original, but all of which shaH together constitute one and the
same instrument.
* * *
OHS \Vst:260736I60.2
Staff—PR-030 Attachment B Page 66 of 79
IN WITNESS WHEREOF, each of the parties hereto has caused a counterpart of
this Amendment to be duly executed and delivered as of the date first above written.
PACIFIC GAS AND ELECTRIC
COMPANY
By: 944w 4 t
N3i'ie: Edward A. Salas
Title: Senior Vice President
Engineering and Operations
Signature page to Amendment 410 Stage One Agreement
OHS \Vest:260723753.2
Staff—PR-030 Attachment B Page 67 of 79
AVLSTA CORPORATION
Title: Vice President
Transmission and Distribution
Operations
SignnrvrQ p(jS k ni/,,w'j 4 So .ch,. Oss' 4"SSS?St
01-IS W260T3532
Staff—PR-030 Attachment B Page 68 of 79
BRITISH COLUMBIA TRANSMISSION
CORPORATION
B2L
Name: Doug Litt e
Title: Vice President
Customer & Strategy Development
Signature page to Amendment 4 to Stage One Agreement
OHS West:260736 160.2
Staff—PR-030 Attachment B Page 69 of 79
AMENDMENT NO. 5
This AMENDMENT NO. 5 (this "Amendment"), dated as of October 30, 2009, is
entered into among PACIFIC GAS AND ELECTRIC COMPANY, a corporation incorporated in
the State of California -("PG&E"), AVISTA CORPORATION, a corporation incorporated in the
State of Washington ("Avista"), and BRITISH COLUMBIA TRANSMISSION
CORPORATION, a corporation incorporated in British Columbia, Canada ("BCTC").
W I T N E S S E T H:
WHEREAS, the parties hereto, along with PACIFICORP, a corporation
incorporated in the State of Oregon ("PacifiCorp"), entered into the Stage One Project
Development Agreement, dated as of September 25, 2008, as amended by Amendment No. 1,
dated May 28, 2009, Amendment No. 2, dated July 30, 2009, Amendment No. 3, dated
September 11, 2009, and Amendment No. 4 (not including PacifiCorp), dated September 30,
2009, (together, the "Stage One Agreement");
WHEREAS, PacifiCorp has withdrawn from the Stage One Agreement effective
as of September 29, 2009, and therefore the undersigned constitute all of the Participants as of
the date of this Amendment; and
WHEREAS, the parties hereto desire to enter into this Amendment to amend the
Stage One Agreement as set forth below.
NOW THEREFORE, it is agreed:
I. Extension of Expiration of Stage One Agreement. Section 1 2(a)(ii) of the
Stage One Agreement is hereby amended by replacing the date "October 30, 2009" with "May 1,
2010".
2. Additional Funding.
(a)Schedule I (Payment Schedule) of the Agreement is hereby
amended and restated in its entirety to read as set forth on Exhibit A to this Amendment. Under
such amended Schedule 1, BCTC's and PG&E's respective Commitment Amounts are increased
such that BCTC and PG&E each will make additional contributions toward the development of
Stage One at the time and in the amounts set forth as payment 7 on amended Schedule I (the
"Supplemental Commitment Amounts").
(b)The definition of "Commitment Amount" in the Agreement is
hereby amended and restated in its entirety to state:
"Commitment Amount" means, for each Participant, the amount
set forth next to its name in the "Payment Total" column of
Schedule 1 (Payment Schedule)."
OHS West:260751 168.4
Staff_PR_030 Attachment B Page 70 of 79
3.Project Budget. Schedule 7 (Project Budget) of the Agreement is hereby
amended and restated in its entirety to read as set forth on Exhibit B to this Amendment (the
"Revised Budget"). The Revised Budget, among other changes, provides for the expenditure of
the Supplemental Commitment Amounts, payment to PacifiCorp of Unused Stage One Funds (as
such term is defined in the Withdrawal and Consent Agreement, dated September 29, 2009,
among the Participants and PacifiCorp (the "Withdrawal Agreement")), and the BCTC Direct
Payments as provided in Section 4 below. Notwithstanding Section 7.1 of the Agreement, from
and after the date of this Amendment, obligations incurred pursuant to the Revised Budget
(which shall be an Approved Budget for purposes of Section 7.1) shall be shared among the
Participants based on their respective pro rata share of the aggregate amount of payments by all
Participants pursuant to payments 6 and 7 on Schedule I (as amended by Section 2 above).
4.Direct BCTC Payments. The Revised Budget provides certain payments
to be made by BCTC directly to consultants providing services in Canada (the "BCTC Direct
Payments"). As reflected in note 3 to Schedule 1 (as amended by Section 2 above), BCTC's
payment of the BCTC Direct Payments shall be deemed payment of an equal amount toward
BCTC's Commitment Amount. BCTC shall designate an employee of BCTC to administer
invoices and the budget for BCTC Direct Payments and to provide this information to the Project
Manager on a regular basis or as requested.
5.Withdrawal and Wind-Up. Notwithstanding any provision to the contrary
in the Agreement, each of BCTC and PG&E may, at any time after such Participant has made
payment 7 referenced on Schedule I (as amended by Section 2 above and taking into account the
BCTC Direct Payments), upon 30 days' notice to all Participants, cause the Agreement to be
terminated in accordance with Section 12 of the Agreement. The Participants acknowledge that
this termination right is only with respect to the term of the Stage One Agreement as extended by
this Amendment and is not intended to carry over into a superseding agreement.
Notwithstanding Section 12(b) of the Agreement, any funds that are reflected on the Revised
Budget that are not expended or otherwise committed shall be distributed 50% to each of PG&E
and BCTC after taking into account (and crediting against the distribution to BCTC) any BCTC.
Direct Payments that have not previously been made or committed by BCTC. If the Participants
agree to additional funding on a basis other than 50% by each of PG&E and BCTC, this Section
5 will be revised accordingly as agreed by the Participants.
6.Allocation of Certain PacifiCorp Rights. Notwithstanding Section 11.1,
and without limiting the termination of PacifiCorp's rights under the Withdrawal Agreement, the
Participants have not yet determined the terms of the allocation of PacifiCorp's Participation
Percentage or Credits. Such determination shall be made at a later date as unanimously agreed
by the Project Owners Group or the Participants.
7.No Waiver. Except as specifically provided above, this Agreement shall
not in any way operate as a consent, waiver or forbearance under any provision of the Stage One
Agreement, and all of the terms and provisions of the Stage One Agreement shall remain in full
force and effect.
8.Effective Date. This Amendment shall become effective as of the date
hereof (the "Effective Date") when each of the parties hereto shall have executed and delivered
OHS West: 260751 168.4
Staff—PR-030 Attachment B Page 71 of 79
(including by way of facsimile or electronic "pdf' format) duly executed counterparts of this
Amendment.
9.Governing Law. THIS AMENDMENT AND THE RIGHTS AND
OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE CONSTRUED IN
ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF NEW
YORK WITHOUT REGARD TO THE CONFLICT OF LAW RULES THEREOF (OTHER
THAN SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW).
10.Incorporation of Provisions. Except as amended and supplemented by the
provisions set forth in this Amendment, all of the terms and conditions of the Stage One
Agreement shall remain in full force and effect following execution of this Amendment and each
Party confirms, ratifies and approves the Stage One Agreement as amended by this Agreement.
All capitalized terms used herein and not otherwise defined shall have the respective meanings
given to such terms in the Stage One Agreement, and the principles of construction and rules of
interpretation set forth in Section 1.2 of the Stage One Agreement shall apply mutatis mutandis
to this Amendment as if the same were expressly set forth herein. For the avoidance of doubt, all
references in the Stage One Agreement to the Stage One Agreement shall be deemed to be
referenced to the Stage One Agreement as amended by this Amendment.
11.Counterparts. This Amendment may be executed in any number of
counterparts and by the different parties hereto on separate counterparts, each of which when so
executed and delivered shall be an original, but all of which shall together constitute one and the
same instrument.
* * *
OHS West:260751 168.4
Staff—PR-030 Attachment B Page 72 of 79
IN WITNESS WHEREOF, each of the parties hereto has caused a counterpart of
this Amendment to be duly executed and delivered as of the date first above written.
PACIF GAS AND ELECTRIC
COMA NY
Transmission Rates
Sgnoiw'e page to Amendment ito Stage One Agreement
OHS Wcst:26075 1168.4
Staff—PR-030 Attachment B Page 73 of 79
AVLSTA CORPORATION
By---J~ Name: Den Kop
Title: Vice President
Transmission and Distribution
Operations
Signature page to Amendment 5 to Stage One Agreement
OHS West 2607S1 169.4
Staff—PR-030 Attachment B Page 74 of 79
BRITISH COLUMBIA TRANSMISSION
CORPORATION
ByLt+
Name: Doug Little
Title: Vice President
Customer & Strategy Development
Signature page to Amendment 510 Stage One Agreement
OHS Wcst:260751 168.4
Staff—PR-030 Attachment B Page 750179
EXHIBIT A
AMENDED AND RESTATED SCHEDULE 1
[see attached]
Exhibit A to Amendment 5 to Stage One Agreement
OHS West:260751 168.4
Staff_PR030 Attachment B Page 76 of 79
SCHEDULE I
PAYMENT SCHEDULE
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10)
Participant Payment 1 Payment 2 Payment 3 Payment 4 Payment 5 Payment 6 Payment 7 Payment Participation
[Due [Due [Due Total Percentage
10/20/09] 11/30/091 11/30/091
See note 2 See note 3 See note 4
Avista $292,359 $73,500 $58,800 $59,638 $148,000 $32,422 $0 $664,719 12.25
British Columbia $292,359 - $73,500 $58,800 $59,638 $148,000 $32,422 $511,000 $1,175,719 12.25
Transmission
Corporation
PacifiCorp $292,359 $73,500 $58,800 $59,638 $148,000 $0 $0 [$632,297] [12.25]
See note 5 See note 5
Pacific Gas and $1,509,525 $379,500 $303,600 $307,926 $764,160 $133,657 $511,000 $3,909,366 63.25
Electric Company
Total $2,386,600 $600,000 $480,000 $486840 $1,208,160 $198,501 $1,022,000 $6,382,101 100
Note 1: Payments are intended to match cash flow. Payment 1 assumes the non-PG&E members of the Project Owners Group share in $576,000 of the $2,160,700
in previously-incurred CH2MHiII costs (for Typing of routes and other tasks described in the opportunities and constraints report). This issue was discussed with
routing and permitting personnel at an April 2 , 2008 meeting. The $576,000 is 36.75% of $1,586,000 which is the portion of the previously-incurred costs
($2,160,700) estimated be applicable to and useful for the Project going forward.
Note 2: Payment 6 was approved by the Project Owners Group On 10/5/09, but payment due date has been moved to 11/30/09.
Note 3: BCTC's payment of $511,000 is comprised of a payment to PG&E and the estimated costs of payments made directly to specifically approved consultants r
As of 10/28/09, the estimated cost of legal, public affairs and land consultants to be paid directly by BCTC totals $242,000 (see Schedule 7). If the actual costs
differ from the estimated costs there will be a true up at the conclusion of the Stage 1 Agreement.
Note 4: Payments 6 and 7 do not adjust the Participation Percentages.
Note 5: As provided in Section 6 of the Amendment, PacifiCorp's Participation Percentages and Credits will be allocated at a later date.
Exhibit A to Amendment 5 to Stage One Agreement
OHS West:260751 168.4
Staff-PR-030 Attachment B Page 77 of 79
EXHIBIT B
AMENDED AND RESTATED SCHEDULE 7
SCHEDULE 7
ID Activity Authorized Expense
1 Perform electrical system studies in support GfWECC Phase 1 $1-00,000-(complete)
project rating (ABB)
2 Development of the plan of service, including participant reviews $150,000 + $50,000
(add $50,000 for CCO#3 in Oct 09)
3 Preliminary environmental assessment, mapping and pre-EIRIEIS $1,586,600 (complete)
work, previously performed
4 Preliminary environmental assessment, mapping and pre-EIRJEIS $494,395 (complete; 08 Hill contract)
work, to be performed, including additional strategic environmental $300,000 (complete, orig. contract)
consultants $751,000 (SWCA current contract)
$1,545,395 total
T Project development, political and public relations (add 75k for $1,049,000 + $75,000
CCO #3 in Oct 09)
6 Preliminary substation and transmission line engineering as $191,000
required to support Stage I
7 Legal counsel to the project participants as required to support $500,000
Stage I
8 Project management and accounting services required to support $0
Stage 1
9 Engineering consultants to perform electrical system -studies in $275,{)00
support of WECC rating studies, evaluation of project alternative
configurations and provide expertise on direct current transmission
issues.
10 Environmental firm: Provide ongoing project support related to $95,000
routing, permitting and siting issues (SWCA is the current firm)
11, Environmental Consultants in BC & US $0
ha
12 Land access consultant to assist in property owner identification, $0
notification and record keeping. Will also consult on routing
decisions based on land values.
Exhibit B to Amendment 5 to Stage One Agreement
OHS West:26075 1168.4
Staff_PRj30 Attachment B Page 78 of 79
12a Consultants to assist BCTC with property issues (BCTC will pay $12,000
consultant directly and the estimated cost will be deductedfrom
payments to PG&E)
13 Owners' PA consultant: Continue to support project message $150,000
participate as directed in media relations, public positioning and PA
strategy (Gallatin is the current firm).
13a BCTC Environ, Properties, 1St Nation & Public Consultations $60,000
13a Consultants to assist BCTC with BC public and First Nation $150,000
consultations issues (BCTC will pay consultant directly and the
estimated cost will be deductedfrom payments to PG&E)
14 Owners' engineer: Perform preliminary substation and transmission $260,000
line engineering as required to support project planning, cost
estimating, routing and permitting.
15, Owners' legal firms: Provide legal counsel to the project $0
15a participants as required to support Stage 2.
15b Owners' legal firms: Provide legal counsel to the project $10,000
participants on British Columbia issues.
15b Owners' legal firms: Provide legal counsel to the-project $80,000
participants on British Columbia issues. (BCTC will pay consultant
directly and the estimated cost will be deductedfrom payments to
PG&E)
16 Project Management and accounting support necessary to support $0
project planning and the work scope
17 Other Shared Costs (helicopters, specialty firms, cost recovery for $0
EFSC, BLM, USFS, etc)
- Estimated refund to PAC for 12.25% of Unused Stage 1 Funds as $43,106 (est)
of 9/30/09 per Withdrawal Agreement
- Proposed Total Stage 1 Budget $6,382,101
- Total Stage 1 Budget as of 10/5/09 $5,360,101
- Additional Funding Authorized by Amendment No. 5 $1,022,000
NOTE: As indicated above, BCTC will directly pay Project Owners Group approved consultants and deduct the
estimated cost from its payment #7 (see schedule 1). If actual payments are different than estimated costs there will
be a true up at the conclusion of Stage 1.
Exhibit B to Amendment S to Stage One Agreement
OHS West: 260751 168.4
Staff—PR-030 Attachment B Page 79 of 79
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/20/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Dave DeFelice
REQUESTER: IPUC RESPONDER: Karen Schuh
TYPE: Production Request DEPARTMENT: Rates and Tariffs
REQUEST NO.: Staff-032 TELEPHONE: [phone]
REQUEST:
Please provide the entire budgeted and actual costs for each of the following projects by year:
a.Noxon Rapids Living Facility Additions;
b.Bronx-Cabinet 11 5k RebuildlReconductor;
c.Moscow City-N Lewiston 115 kV Reconductor; and
d.Burke-Thompson A&B 115 kV Reconductor
RESPONSE:
Please see the Company's response to Staffs Data request No. 45.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/27/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Elizabeth Andrews
REQUESTER: IPUC RESPONDER: Karen Schuh
TYPE: Production Request DEPARTMENT: State & Federal Reg.
REQUEST NO.: Staff-034 TELEPHONE: [phone]
REQUEST:
Please reference Witness Andrews' Exhibit No. 10, Schedule 1, page 9, adjustment No. 3.08
Workpaper Reference E-ISIT and Schedule 2 page 9 Adjustment No 3.07 Workpaper Reference
G-DS. In Witness Andrews' electronic workpapers, titled "IS & IT Costs," there is a $1,154,313
adjustment for Common Plant and a $230,029 adjustment for Generation Plant. Please provide the
backup detail for those adjustments.
RESPONSE:
Please note, these amounts represent incremental expenses that were grouped as supporting either
common plant or generation plant IS/IT projects for allocation purposes. The Company
inadvertently missed including these workpapers electronically in the original filing (copies were
provided in hard copy only). Please see Attachment A and B for support of these IS & IT Costs.
46,696 $ 30,464 $ - $ 16,232 $ - $ - $ 46,696
$ 27,610 $ - $ 14,711 I s - $ - $ 42,321
4,375 $ 2,854 $ - $ 1,521 $ - $ - $ 4,375
Maxima Generation lin
Oracle Database in
Description h (comri1On).!" TOTAL
COLA Estimated COLA increase associated with HP and other contracts $ 90,000
Non-Labor Maintenance Estimated cost for increased in software maintenance fees $ 300,000
TOTAL $ 390,000 $ 188,332 $ 52,425 $ 92,639 $ 25,142 $ 31,461 $ 390,000
$ 43,461 $ 12,098 $ 21,378 $ 5,802 $ 7,260 $ 90,000
$ 144,871 $ 40,327 $ 71,261 $19,340 $ 24,201 $ 300,000
- Descjiptlon TOTAL
CSSIWMS/Other
True-up for positions previously working on capital projects that are now in
maintenance (contract) $ 360,000
Infrastructure
True-up for positions previously working on capital projects that are now in
maintenance (contract) $ 250,000
Appi. Mgr
New postion responsible for daily delivery of applications. Previously included in
Director and other positions (unioded) $ 105,000
BTA
The salary costs (unloaded) for the new BTA positions. Actual costs is higher than
budgeted in 2012 $ 60,000
Security
New position in support of additional security activities; i.e., architecture design,
monitoring, etc. (unloaded) $ 105,000
Compass New position for supportng Maximo once it is in production $ 83,333
WA Elect WA Gas I ID Elect ID Gas OR Gas Total
$ 173,845 $ 48,393 $ 85,513 $ 23,208 $ 29,041 $ 360,000
$ 120,726 $ 33,606 $ 59,384 $ 16,117 $ 20,168 $ 250,000
$ 50,705 $ 14,114 $ 24,941 $ 6,769 $ 8,470 $ 105,000
$ 28,974 $ 8,065 $ 14,252 $ 3,868 $ 4,840 $ 60,000
$ 50,705 $ 14,114 $ 24,941 $ 6,769 $ 8,470 $ 105,000
$ 40,242 $ 11,202 $ 19,795 $ 5,372 $ 6,722 $ 83,333
$ - $ - $ - $ - $ - $ 963,333
TOTAL I $ 963,333 $ 465,197 S 129,495 5 228,827 5 64102 5 77,71Z 5 963,333
Description TOTAL
Maxima Generation in Compass writeup $ 83,333
Workplace Mainframe Anticipate increased CSS/WMS usage from customers for on-line transactions 1 $ 100,000
TOTAL $ 183,333
$ 54,366 $ - $ 28,967 $ - $ - $ 83,333
$ 65,240 $ - $ 34,760 $ - $ - $ 100,000
$ 119,606 5 - $ 63,727 5 - 5 - 5 183,333
Common Plant $ 1,154,313 $ 557,422 $ 155,167 $ 274,191 $ 74,414 $ 93,118 $ 1,154,313
Generation plant $ 230,029 $ 150,071 $ - $ 79,958 $ - $ - $ 230,029
TOTAL Total $ 1,384,342 $ 707,493 $ 155,167 74,414 $ 93,118 $ 1,384,342
2013 O&M Expected Spend
2012 Expected Spend (Ending 6/30/2012) $ 24,056,609
2013 Expected Spend $ 25,440,951
Estimated Net Increase (2012 to 2013) $ 1,384,342
Electric Factors
1 PT Ratio 100.000% 65.240% 34.760% 0.000%
7 CD AA 100.000% 72.044% 19.889% 8.067%
4 CD AN 100.000% 67.029% 32.971% 0.000%
Gas Factors
4 GO AN 100.000% 67.5871Y. 32.413%
7 GO AA 100.000% 72.044% 19.889% 8.067%
8 0.000%
10 0.000%
Staff-PR-034 Attachment A.xlsx 1 of 1
Staff PR-034 Attachment B.docx
INCREMENTAL 2013 IS/IT Costs
CSS/WMS/Other [$360,000]:
These costs represent incremental labor that supports the Customer Support System and
Work Management System. These systems manage customer activity such as; demand
management, billing, energy efficiency education, scheduling to track and account for
customer projects and numerous other customer engagement activities.
These labor resources were re-assigned from daily maintenance (O&M) of the current
Customer Information and Work Management Systems to assist in the early phases of a
capital project to implement a new Customer Information and Work Management
System. Once their role in the capital project is complete, they will be returning to a
daily maintenance role (O&M) supporting the existing Customer Information and Work
Management System until it is shut down. After the current system is shutdown, they will
continue in a support role for the new system which is anticipated to start-up in late Q4 of
2014.
Infrastructure [$250,000]:
Infrastructure is the underlying technology that is required to enable business process;
e.g. it is the networks, servers, workstations, etc. that host and transport data and
applications.
These costs represent incremental labor that supports the following infrastructure; Radio
communications for dispatching gas and electric crews in support of building and
maintaining gas and electric infrastructure; Customer Information and Work
Management Systems. These systems manage customer activity such as; demand
management, billing, energy efficiency education, scheduling to track and account for
customer projects and numerous other customer engagement activities.
These labor resources were re-assigned from daily maintenance (O&M) of the current
radio system and Customer Information and Work Management Systems to assist in the
early phases of a capital project to implement a new Radio System and Customer
Information and Work Management System. Once their role in these capital projects is
complete, they will be returning to a daily maintenance role (O&M) supporting the
existing Customer Information and Work Management System infrastructure and the new
Radio System.
Application Manager [$105,000]:
Avista did not have a fully dedicated staff to manage its day-to-day application support
environment. Previously the Director of Application Systems filled both the Director role
and the Application Management positions. As the number of applications continue to
grow in both numbers and complexity, it is necessary to dedicate a position to managing
the daily operations associated with the applications. These are the applications that are
Page,tef 3
Staff_PR_034 Attachment B.docx
required to enable customer, operations, employee and external agency interactions, i.e.,
financial, payroll, customer, outage, construction design, web, distribution and plant
automation, etc.
Business Technology Analyst (BTA) [$60,000]: [s/h/b: $144,000]
This is an adjustment to include the incremental actual annual salary cost for 2 Business
Technology Analysts that were hired in 2012. These positions serve a lead role in
enabling Avista customers, employees and outside agencies to achieve their business
objectives with Avista through the effective and appropriate use of technology. (This
item should have been an incremental $144,000 as follows: BTA 1: $87k-hired
6/21/2012 + BTA 2: $85k * 8/12 - hired 11/03/2011, partial included in test period)
Security [$105,000]:
Security of customer data and Avista's natural gas and electric infrastructure is critical.
This position is an addition to the current security staff due to an increase in workload
associated with growth in networks, data and automation of the electric transmission and
distribution systems and gas delivery system.
Compass [$83,333]:
This is a new position in 2013 that is necessary to support the new Work Management
System. The cost is a pro-rated annual amount that represents a partial year of support as
the new system will not be in production the entire year. The new Work Management
System is used to schedule, track and account for generation projects and work activity.
Work Management System - Maximo (generation) [$83,333]:
This cost represents the 2013 anticipated pro-rated amount for the hosting of the new
Work Management System for the generation and production area. The cost is a pro-
rated annual amount that represents a partial year of hosting fees in 2013 as the new
system will not be in production the entire year. The new Work Management System is
used to schedule, track and account for generation projects and work activity.
Workplace (mainframe) [$100,000]:
The current Customer Information and Work Management Systems are outsourced to
Hewlett-Packard for hosting services. The services are billed on a per MIP (millions of
instructions processed) basis. This cost represents 2013 anticipated increase in the use of
the current Customer Information and Work Management Systems. The increase is due
to growth in the number of customers using automated transactions and the number of
new types of automated transactions to conduct business with Avista.
Work Management System -Maximo Software Maintenance Fees (generation) [$42,321]:
Page 2 of 3
Staff PR_034 Attachment B.docx
This cost represents the new recurring license fee associated with the new Work
Management System. The fee is the 2013 pro-rated annual amount that represents a
partial year of license fees as the new system will not be in production the entire year.
The new Work Management System is used to schedule, track and account for generation
projects and work activity.
Oracle Database -Maximo Software Maintenance Fees (generation) [$4,375]:
This cost represents the new recurring license fee for database licenses associated with
the new Work Management System. The fee is the 2013 pro-rated annual amount that
represents a partial year of license fees as the new system will not be in production the
entire year. The new Work Management System is used to schedule, track and account
for generation projects and work activity.
COLA (cost of living adjustment [$90,000]
This estimated cost represents a contractual obligation with Hewlett-Packard for an
annual adjustment to charges. The increase is based on the Consumer Price Index and is
applied to all labor resources contracted by Avista from Hewlett-Packard. The actual
cost is computed and effective January 1st of each calendar year. The trend has been for
an increase in CPI over the past 2 years. It is anticipated that the trend will continue and
as such the applicable contracted labor charges will increase on January 1" 2013.
Non-Labor Maintenance Fees [$300,000]:
For each critical piece of technology hardware and software, Avista pays an annual
maintenance fee to ensure that we meet compliance and system availability requirements.
These fees represent an estimated total increase for existing hardware and software
maintenance agreements. The customer benefits by systems they rely on being supported
in the event of failure such as the WEB, Enterprise Voice Portal, etc.
PLS-CAD [$15,000]:
This is the new annual software license fee for the PLS-CAD software. This software is
used for the design and engineering of electric transmission lines.
New Software Contracts - Other [$175,000]:
Based on historical trends, it is anticipated that there will be new software application
purchases that will require software and database maintenance agreements. With that
growth, come increased license fees. In addition, as new staff is hired or existing staff
require access to an application, typically a license must be purchased for their use of the
application. An example is the use of Microsoft Office. Each user must have a license to
use the application software.
Page 3 of 3
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/20/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Elizabeth Andrews
REQUESTER: IPUC RESPONDER: Jennifer Smith
TYPE: Production Request DEPARTMENT: State & Federal Reg
REQUEST NO.: Staff-035 TELEPHONE: [phone]
REQUEST:
Please provide the total dollar amount paid for the "Performance Excellence Initiative" consultant
Booz and Company contract. Please identify where these amounts are included in this rate case.
Please illustrate the allocation of total system costs to each jurisdiction. Further break this amount
down to its effect on electric and natural gas operations. Include with this information the
completion date for this contract and the cost of service accounts posted.
RESPONSE:
The total cost of the Performance Excellence Initiative by year, to-date, is noted below, these
expenses have been recorded to FERC account 923000. Consulting services under contract with
Booz and Company will be completed by December 31, 2012.
Included in AVU-E-12-08 I
AVU-G-12-07 Test Year
Period System Cost WA Electric
WA Natural
Gas ID Electric
ID Natural
Gas
OR Natural
Gas ID Electric
ID Natural
Gas
2010 $ 2,979,694 $ 1,445,676 $ 392,245 $ 711,116 $ 188,110 $ 242,547
2011 $ 2,329,432 $ 1,130,185 $ 306,645 $ 555,928 $ 147,059 $ 189,616 $ 555,928 $ 147,059
01/01/2012 -
11/12/2012 $ 410,911 $ 199,364 $ 54,092 $ 98,066 $ 25,941 $ 33,448
Total $ 5,720,037 $ 2,775,225 $ 752,981 $1,365,110 $ 361_,1101 $ 465,611 $ 555,9281s 147,059
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/27/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Elizabeth Andrews
REQUESTER: IPUC RESPONDER: Ryan Finesilver
TYPE: Production Request DEPARTMENT: Rates & Tariffs
REQUEST NO.: Staff-036 TELEPHONE: [phone]
REQUEST:
In reference to Andrews, Exhibit No. 10 Adj. 3.07 Property Tax (Elec.) and 3.05 Property Tax
(Gas), please provide actual property tax payments for each year from 2005 through the present.
RESPONSE:
Please see Attachment A for the requested tax payment information.
Avista Corporation
Property Taxes Paid
Tax Years 2005 through 2011
Actual Payments for: Actual Payments for: Actual Payments for: Actual Payments for: Actual Payments for: Actual Payments for: Actual Payments for:
2006 2007 2008 2009 200
* Not Final
Electric:
Washington $7,298,696 $6,547,806 $5,923,650 $5,199,060 $4,875,209 $6,644,454 $7,748,561 *
Idaho $4,456,390 $2,804,015 $2,668,628 $2,955,202 $3,189,957 $3,829,944 $4,256,520
Montana $7,288,292 $5,955,301 $6,174,430 $6,668,794 $6,163,546 $6,614,757 $6,929,052
Oregon( fiscal year) $166,611 $156,533 $156,343 $150,933 $1,875,944 $1,850,830 $2,022,001
$19,209,989 $15,463,655 $14,923,051 $14,973,989 $16,104,656 $18,939,985 $20,956,134
Actual Payments for: Actual Payments for: Actual Payments for: Actual Payments for: Actual Payments for: Actual Payments for: Actual Payments for:
2005 2006 ZQQZ 200 200 2211
* Not Final
Natural Gas:
Washington $1,905,711 $1,745,834 $1,554,857 $1,214,283 $1,433,508 $1,842,635 $1,939,713 *
Idaho $771,090 $586,774 $608,769 $620,253 $721,738 $802,708 $934,432
Oregon( fiscal year) $1,252,806 $1,522,207 $1,572,540 $1,759,473 $1,648,675 $1,651,219 $1,843,299
3,929,607 3,854,815 3,736,166 3,594,009 3,803,921 4,296,562 4,717,444
INCLUDES CENTRAL AND LOCALLY ASSESSED PROPERTY IN WASHINGTON
Staff—PR-036 Attachment A.xlsx Page 1 of 1
JURISDICTION:
CASE NO:
REQUESTER:
TYPE:
REQUEST NO.:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
IDAHO DATE PREPARED: 11/27/2012
AVU-E-12-08 / AVU-G-12-07 WITNESS: Elizabeth Andrews
IPUC RESPONDER: Karen Schuh
Production Request DEPARTMENT: Rates and Tariffs
Staff-037 TELEPHONE: [phone]
REQUEST:
Please provide the details of any land and plant sales assigned to Idaho during 2011 and 2012.
Please include within your response the accounting treatment of those sales.
RESPONSE:
Please see the attached schedule at Staff PR 037 Attachment A for details regarding sales during
2011 the Company did not have any land sales transactions from January 1, 2012 to October 31,
2012.
All the plant values are initially recorded in the appropriate utility FERC accounts until it is
determined that it will be sold and then it is transferred to a non-utility FERC plant account 121.
for year ended December 31, 2011
OTHER PROPERTY DISPOSITIONS
BOOK
1. (a) Brief Description of Property Disposed: Devil's Gap Larson Stratford Grant Co.
(b)Permanent Record Reference 201105
(c)Date Property disposed of 201105
(d)Primary Plant Account Credited 111000
(e)Gross Sale Price 146,021
(f)Expense of Sale
(g)Original Cost: 385,000
(h)Accumulated Depreciation 238,579
(i)Location Grant Co., Washington
(j)Date of Purchase 1986
(k)Gain on Disposition of Property 400
Transmission Line
Brief Description of Property Disposed
Permanent Record Reference
Date Property disposed of
Primary Plant Account Credited
Gross Sale Price
Expense of Sale
Original Cost:
Accumulated Depreciation
Location
Date of Purchase
Gain on Disposition of Property
Brief Description of Property Disposed
Permanent Record Reference
Date Property disposed of
Primary Plant Account Credited
Gross Sale Price
Expense of Sale
Original Cost:
Accumulated Depreciation
Location
Date of Purchase
Gain on Disposition of Property
Brief Description of Property Disposed
Permanent Record Reference
Date Property disposed of
Primary Plant Account Credited
Gross Sale Price
Expense of Sale
Original Cost:
Accumulated Depreciation
Location
Date of Purchase
Gain on Disposition of Property
Beacon-Francis & Cedar Land
201105
201105
101000
73,086
198
Spokane, WA
1951
72,888
Park Smith & Market Gas Reg Stn #29
201106
201105
101000
16,300
1,000
Spokane, WA
1998
15,300
Jackson Prairie land sale
201109
201109
101000
69,678
5,969
Chehalis, WA
1974
63,709
2. (a)
(b)
(C)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
3. (a)
(b)
(C)
(d)
(e)
(f)
(g)
(Ii)
(i)
(j)
(k)
4. (a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
0)
(k)
Staff—PR-037 Attachment A.xlsx Page 1 of 1
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/21/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Mark Thies
REQUESTER: IPUC RESPONDER: Margie Stevens
TYPE: Production Request DEPARTMENT: Finance
REQUEST NO.: Staff-038 TELEPHONE: [phone]
REQUEST:
Please provide copies of the narrative monthly, quarterly and annual comparison of operating and
capital budgets to actual expenditures for Idaho for the years 2011 and 2012 to date. Please include
within your response any narrative explanations for budget variations. Your response should
include, but not be limited to, written operating and capital budget variance reports and
explanations used by Company officers and managers to monitor and control budgets under their
areas of responsibility.
RESPONSE:
Staff _PR038 Attachment A contains all the variance reports for both operating and capital
budgets for 2011 to date. Please be advised that the costs are not reported on a jurisdictional basis
and these reports are system costs.
Do to the voluminous nature of the files they are being provided in electronic form only.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/21/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Dave DeFelice
REQUESTER: IPUC RESPONDER: Karen Schuh
TYPE: Production Request DEPARTMENT: Rates and Tariffs
REQUEST NO.: Staff-041 TELEPHONE: [phone]
REQUEST:
If not included within the response to the previous request, please identify all
forms/studies/analyses required to substantiate the need for a project, including but not limited to,
cost-benefit analyses and offsetting savings/revenues.
RESPONSE:
Please see the Company's response to Staff Production Request No. 40.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/21/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Dave DeFelice
REQUESTER: IPUC RESPONDER: Karen Schuh
TYPE: Production Request DEPARTMENT: Rates and Tariffs
REQUEST NO.: Staff-043 TELEPHONE: [phone]
REQUEST:
Please provide an updated schedule of the 2011 capital additions as proposed in Case Nos.
AVU-E-1 1-01 and AVU-G-1 1-01 that includes the following by project:
a.planned dates in service as proposed in those rate cases;
b.actual dates in service;
c.budgeted capital expenditures as proposed in those rate cases; and
d.actual capital expenditures incurred.
RESPONSE:
See Staff jR_043-Attachment A for the DeFelice capital workpapers that were originally filed in
the 2011 general rate case (for 2011 capital additions). This worksheet includes (a) and (c) of this
request. Please note that as a part of AVU-E- 11-01 and AVU-G- 11-01 the Company excluded the
Noxon upgrade from Attachment A and it was included as a separate adjustment.
See Staff _PR_043-Attachment B for the DeFelice capital workpapers that were updated for actual
transfers to plant (for 2011 capital additions). This worksheet includes (b) and (d) of this request.
Please note that the Noxon upgrade is included in Attachment B and not in Attachment A as
mentioned above.
Attach A shows that the Company pro formed approximately $46.009M electric for ID and
approx. $4.475M for ID for natural gas. Attach B shows that the Company actually transferred to
plant approximately $47.066 M electric for ID and approx. $7.844 M for ID for natural gas.
Please note that only two tabs from the electronic file have been printed and the remaining
workpapers are included electronically.
2011 additions Page 1 of 11
Avista Utilities
Pro Forma Rate Base Adjustment
for 2011 Rate Case - Test Year 2010
Adjustment Factor:
Excludes Plant Additions for Customer Growth (Budget Category 1,000 's)
Ong
Plant Additions by Month in (000's) Annual

Pfl Amou Jan Eeb Mr Apr may Jun M Aug Se2 QI
Functional Plant Categories ER ST
Generation:
Thelma!
K F Minor Blanket 4001
Kettle Falls Capital Projects .4101
K F Ash Landfill 4115
Coistrip CapitalAdditions . ..16
Thermal Subtotal
Hydro
Hydro Minor Blanket 4000
YFERC Hydro Safety Minor
Blanket 4003
Spokane River License
Implementation .4004
I Cabinet Gorge Capital
.......................... Little Falls Capital Projects .410.
Long LakeCapita.Projects .4103
Nine Mile Capital Projects 4104
Noxon Capital Projects 4105
fqstfpl!~kC.api Projects 4106
System Battery Replacement 4108
Upper Falls Capital Project..41
Monroe Street Capital
•Projects 4117
Cabinet Gorge Bypa
Tunnel Project
Noxon Rapids Unit 4
mgencRew.
Noxon Rapids Unit 1
Upgrad..4136
Noxon Rapids Unit 2 Runner
Upyrade .4137
Noxon Unit #3 Upgrade-
carryover billing from 2010
T roject .........4138
Noxon Rapids Unit 4 Runner
Blanket 6001
Clark Fork
License/Compliance ................................
Env Compliance & Best
:Mgmt Practices .....
Staff_PR043-Attachment A.xlsx
Cumulative
Ending
Nov aec_ Balance
Plant Additions by Month in (000s)
2011
Functional Plant Catectones ER ST
Clark Fork Implement PME
Areement i 6103 **
Hydro Relicensing ..6104
SR License & Compliance
:SUPp0t .6105 .
Spokane River
Implementation (PM&E) 6107 **
Coeur d'Alene Tribe
Settlement 6108
Hydro Subtotal
Other
Comb Turbine MinorBlanket 4002
Rathdrum CT Capital
Projects .4197.,,
Boulder Park Generating
Station 4113
CS2 Joint Share Projects 4114
NE Combustion Turbine
apita.Pro........ 4.11 ....
Control Network 4121
Other Production Subtotal
Electric Transmission

I.
Po
.
wer Xfmr-Transm is sion
Benewah-Shawnee 230 kV
2113
NE Moscow - Subsist
petty
Ninth & Central Sub -
Increase Capacity & 1
at Whitworth •••, 2473
Moscow 230 kV Sub-Rebuild I
230 kV Yard 2484 **
System-Install
Autotransformer Diagnostic
Monitor 2492
System -
Replace/Install/Upgrade
Relays 2252
Staff-'F_043-Attachment Axlsx
Ong
Annual
mou Jan feb Mi Apr
Cumulative
Ending
Mav M0 Jul Aug SeR Oct Nov 2ec Balance
2011 additions
El
El
Page 2 of 11
Orig Cumulative
Plant Additions by Month in (000's) Annual Ending
2011 Amount Jan Feb Mar Apr May Jun Jul AuQ Sep Qg( Nov Balance
Functional Plant Cateiories ER ST
Lucky Friday Tap 11 5k
rerout 2476 0
Addy Gifford 115kv MInor
rebid 2477 0
Power Circuit Breaker 2001 1,600 800 200 600 1,600
Noxon-Pinecreek
230kV:Ready Fiber Optic 2051 1,000 195 83 83 83 83 83 83 83 1,000
.TransmissionMinorRebuild 2057 1,750 266 250 250 280 250 250 250 () 1,750
System-Rock/Fence Rest 5 50 (14) 50
System-Replace Obsolete
Reclosers .2278 262 (74) 262
System-Install Metering
Ancillary Svc 125 47 25 25 25 125
High voltage Fuse Upgrades 1 2 150 6 150
Colstrip Transmission
Capital Additions 2214 533 103 114 113 37 33 22 12 8 533
System Rplc High Voltage
:OCBs 2215 225 150 75 225
Spokane-CDA 115 kV Line
Relay Upgrades 2217 1.000 315 350 300 1,000
System 11 5k Air Switch
Upgrade 2254 275 275 275
System-Upgrade Surge
Protection 2260 50 10 50
'Beacon STYD-Oi( Contain ....2273 ** 1,020 1.020 1,020
System-Replace/Upgrade
Voltage Regulators 2493 200 2 17 17 17 17 17 17 17 200
System Replace Obsolete
Circuit Switch 2280 150 149 150
SCADA Replacement .?.?T7 400 87 100 100 100 400
SCADA Il-Add Su . ..2293 225 106 115 225
System-Batteries 2294 200 25 18 15 25 15 40 200
Tribal Permits and
Settlements .2301 325 56 81 81 81 325
Idaho Road Sub 2307 1,750 54 1.750
West Plains Transmission
Reinforce 2310 2,3013 2.300 2,300
Nez Perce 115 Sub-Inst I
Capacitor Bank .2318
Dry Creek Complete 115kv tri 2346
PineCk 23OSub-Rp16 Circuit
Switch&Re ,.. .2342
Lolo 230 - Rebuild 230 kV
rd .2360
Otis Orchards 115-Replace
PCBs&Retsys .......2390 730 730
System Transmission::
Rebuild Condition 2423 1,750 1,750 1,750
System - Replace Substation
Air Switches ..........449 . 150 33 38 38 150
Moscow-Pullman 115
Recond ...... . 2
Staff,PR_043-Attachment A.xlsx 2011 additions . . . Page 3 of 11
Orig . Cumulative
Annual Ending
mou Jan feb, Mga Apr may JunJulAug gg Dec Balance
2011 additions Page 4of 11
Plant Additions by Month in (000's)
2011
Functional Plant Cateoones ER ST
Bronx-Cabinet 115kv
Rebuild/reconductor ; Hatwai-North Lewiston
230kv Re-Insulate 2537
System-Replace/Install
SIP Sub-Replace HV Fuses
with Circuit Switcher 2482
Noxon I. GSU B Bank 4105
Divide Crk/lmnaha Use Permi 6101 **
EFMI2F2&PVW241
Feeder Tie 2517
Electnc Transmission
Subtotal
Ram Rat 2 US 95 Widening 2070 AN
Replace High Resistance
Conductor . •. 2072 AN**
Capital Distribution Feeder
........................... 2071 !AN
Feede.VAR .rnprovem... ?!.JN ....
System-Upgrade Meters 2253 AN
Sys-Dist Reliability-Improve
Worst Fdrs 2414 AN
ampliance 2469 AW .. ....
Open Wire Secondary
Elimination J 2496 ZAN
:Colbertpa l 5 v CLPL,. ... ...... 25.... 1AN
PCB Identification &
!sposal ........ ....... ... ....... .6000 LAN
Electric AN Distribution
.Sta........
Power Xfmr-Distributlon 1006 ID
PCB Identification & T
Disposa.. ........ 6 00 .ID
Staff_PR_043-Attachment A.xlsx
Electric Distribution
Power XTmr-Distribution 1006 AN
Mobile Sub 1008 AN
Electric Underground
Replacement .2054AN
Electric Distribution Minor
Blanket 2055 AN
T&D LineRelocation 2056 AN
Failed Electric

Unknown 2059 2059 AN
Orig
Plant Additions by Month in (0001s) Annual
2211 Amou0 fl Feb siosii Aug Sep Oct
Functional Plant Cateoories ST
Replace High Resistance
Conductor 2072 .1D' 615
Plummer Rebuild Add
capacity 2302
Chance Cutout replace 2009
ID 2416 ID
ID AMR optimization Comm 1 3 ..ID
OGara Upgrade Transformer
Dist 2478 ID
System Wood Substation
Rebuilds-DearyiD 204 .ID ...1.615 1.515 10 50
NMO 521 recond 7 miles 2299 ID
Appleway 316creaii ncrease
Capacity 2306 )D 4,20 3.700 100 400
Potlatch Xform..R............. 2336 ..!.°........
PineCk 230S66-RpIc Circuit
Switch&ReIays 2342
Ratttdrum 233- Construct
Feeder 2362 ID
Sys-Dist Reliability-Improve
Worst Fdrs 2414 ;ID' 925 34 15 513 118
OGara Upgrade Transformer
Dist i 2505 iD
PCB Related Distrib rbld
Spok 2535 ID 375 18
EFM12F2&PVW241
Feeder Tle 2517 :ID 360 360
Distribution -''Pullman &
Lewis Clark 2516 ID . 350
Distribution - CdA East &
615 North 2515 ID 675
Eiect,jc ID Distribution
Subtotal 5,609 15 110 1,928 486
1 5,609 15 110 1,928 486
Cumulative
Ending
Nov Leg Balance
Power Xfmr-Distribution 1006 WA
PCB Identification &
Disposal . 6000 .WA
Spokane Electric Network
WA ......
Replace High Resistance
Conductor 2072 WA
Millwood Sub-Increase
............................
NE Sub-Increase Capacity 2296 .A
Chewelah & Othello
Xformers 2336 WA
=Spirit-Northport WA 115 Sub-i
incr.XfmrCapacity . 236.5 .WA
NE Sub-increase Capacfty .......... 2P........ WA
Sys-Dist Reliability-Improve
Worst Fdrs 2414 WA **
Metro Post St Recond Phase
:1 [ 2237 WA
Staff_PR_043-Attathment A.,dsx 2011 additions Page 5 of 11
Cumulative
Ending
Nov Qg Balance
Orig
Annual
mar Apr may 3Iifl Jul Aug Q
Plant Additions by Month in (000s)
2011
tl-M1'l-'rVVV"Il
Feeder Tie 1 2517 WA
Distribution -'Spokane North
& West 2514 WA
Terre View Sub new const
dist 2264 WA
Indian Trail Substation 2391 WA
Distribution - Pullman &
Lewis Clark 1. 2516 WA
Otis Orchards 115-13kV
Sub-New Construct 2443 WA
Irvin Sub - New Construction 2446 E WA
DREE BLM WA st dist i 2466 WA
SPII2FI River Crossing
Rbld 2490 WA
Mead Construct 121`3 2525 WA.
Pullman Substation - Rebuild 1 2533 WA
PCB Related Distrib rbld
Spok 2535 WA
Weilpinit Stepdown Banks 2503 WA
Electric WA Distribution
Subtotal
General
Structures& .rnP!OV ............. 11 : **
Office Furniture . 11.1 7003
Klamath Falls OR serv center 7004
.Stores Equip
Tools Lab & Shop
EqUIpm.en....
COFHV.AC .rnpro..,... fbi
Dollar Rd land purch &
facility expansion . 11 107
WSDOT Highway Franchise
Consolidation 7108
Spok Central Oper Fac N
IcrtRaflgnnnt ....
Jacl Stewart modular
7116 Purch Modular off Spok
Airprt 7117
Purhse prop 1619 EN
Crescent 7118
Local Improvement Distr 7119
Union Pacific RR Permits to
Easements Conversion 7112
ARO General Office Bldg 7500
StaffPR_043-Attachment A.xlsx 2011 additions Page 6 of 11
Orig Cumulative
Plant Additions by Month in (000's) Annual Ending
2011 Amount 4n Feb Mr Aff Mav Jun Jul Aug Q Oct Nov Dec Balance
Functional Plant Categories ER ST
Colville Service Center 7113 5,400 5,000
General Plant Subtotal 18,003 438 438 437 437 6,992 438 439 437 17,865
1 438 438 437 437 6.992 438 439 437 17,865
Trnp9o__
ation Equ 'Iranspo 7000 9 468 748 727 710 721 1,075 731 775 701 8,230
Transportation Subtotal 9,488 748 727 710 721 1,075 731 775 701 8,230
1 748 727 710 721 1,075 731 775 701 8.230
Software
5000 0
Information Technology
Refresh Blanket 5005 8,995 639 634 639 631 619 596 652 599 8,261
Information Technology
Expansion Blanket 5006 1,180 120 120 41 39 39 39 139 40 1,163
AFM Product Development
Program 5007 640: 180 160 160 536
Nucleus Product
DevejpntPr9orn 5008 480 120 120 120 417
Web Product Development
Program 5009 960 240 240 240 930
Enterprise Business
continuity 5010 302 132 37 24 20 2 2 21 2 241
Enterprise Data Architecture 5011 200 50 50 50 164
Workplace System
Enhancements 5012 252 63 63 63 189
IT for Facutlitiesprojects 5013 415 50 70 68 83 7 3 8 20 386
Dcv Environ project 100 25 25 25 75
Au 5024 1,188 297 297 297 891
Next Generation Radio
EuCCenhancement .
5106
510w 14
Technology Projects Minor
Blanket 5111 500 42 42 42 42 42 42 42 42 576
Valumation 3
lM rade . ••Apu 5116 168
MDEIecSe 171
511 9 1.000 250 350 200 50 50 50 950
Microwave Replacement
with Fiber 5121 2,813 2,814 2,813
Electronic Records
Oracle Database Upgrade to
6
119 .
ing ...
DIMP Infrastructure
5125
26
5127 544 136 136 138 519
Oracle R12 Upgrade 5128 1,300 1,300 1,300
AFt.net Upgrade .. 129 : 2,904 171 2,904
Rates System .!!ct .......... 5130 24
Gas Solutions Rewrite 5131 250 83 63 63 188
;CIS Rep!ace............
Appren .raftTra ..n .
p138........
7200
Software Subtotal 24,072 1,240 21406 1,014 2,336 4,731 739 869 1,863 22,925
1 1,240 2,406 1,014 2,336 4,731 739 869 1,863 22,925
Miscellaneous Intangible
Staff_PR,,,043-Attachment A.xlsx 2011 additions . Page lofll
Plant Additions by Month in (000s)
2011
Functional Plant Categories ER ST
Gas UG/Producilon
Jackson Prairie Storage J.72.I
Gas UG/Pmduction Subtotal
Gas Distribution
Gas Reinforce-Minor Blanket 3000 AA
Replace Deteriorating Gas
System . 3001 . AA ........
Regulator Reliable ......... 3002 ..
Gas Replace-.St&H . 3003 ..
Cathodic Protection-Minor =
Blanket 3004 AA
Gas Distribution Non-
:Revenue Blanket 3005 AA
Overbuilt Pipe Replacement
Blanket 3006 .AA
Gas AA Distribution Subtotal;
Gas Telemetry . 3117 AN
Reinforce Gate Station Post
Falls Idaho 3246 ID
Dover Gate Station 3225 II)
Replace Gas ERIsIdaho
Reinforcement -IP Main
Southeast Coeur d'Alene ID i 3270 ID
Rebuild-Reg Station
#203(Schweitzer),Sandpoint
ID 3271 ID
Reinforce-HP Main Ext south
from CDA East Gate, ID 3279 . ID
Reinf CDA East S of Bonnell 3290 ID
Replace - Moscow/BoviII HP 3295 ID
Gas ID Ditributiofl Subtotal
99 Road Project 1 3227 OR
Staff_PR_043-Attachment A.xlsx
Cumulative
Ending
Dec Balance
Orig
Annual
fl2flt Ian fob Mr Apr may Jun Jul Aug Sep 2st Nov
2011 additions Page 8 of 11
Orig
Annual
mou Jan Feb r may Lun imil Aug Sep Oct
Cumulative
Ending
Nov 2ec Balance
123
16
90
1,000
6
4,965
4,963
(5)
6
125
2,200
Page 9 of 11 2011 additions
Plant Additions by Month in (000's)
2011
Functional Plant Cateoories gE ST
Medford Barnett Road
*Relocation Project 3232 OR
Rebuild-J St Reg Station
Grants Pass 3233 OR
Grants Pass 8-In HP
L!i'&!9 3237 OR
'Rebuild Jstregsta25o ••R
Reinforce Talent OR Gate =
Station&Piping . 3240 OR
Relocation-Rocky Point
Bridge-Hwy 234-Gold Hill
OR 3256 OR
Oakland Bridge Bore &
Relocation, Oakland OR 3257 OR
Rock Point Reg Station Gold =
Hill OR 3258 OR
Roseburg OR 3261 R
Replace Gas ERTs Oregon 3265 OR
Rebuild Winston Gate
Station, Roseburg OR 3267 OR
15 bore © Barnett Rd Medfore 3272 OR
IMP Pipe Replace, 2012
Commitment, Medford OR 3277 OR
Relocation - N Ross Ln,
Medford OR 3287 OR
S 12th St lP Replacement 3289 OR
Construct Corrector and
Telemetry Test Bench 3288 OR
Gas OR Distribution Subtotal
3102 .WA
Bridging the aey 3107 WA
Re-Rte Kettle Falls Fdr &
Gate Station 3112 WA
US2 N Spo Gas HP
Reinforce(KaiserProp 3.2.37. A
Reinforce Barker Rd Bridge
1SpOk ... 238 ..WA
Reinforce, install pipe on
Reinforcement North
Clarkston Distribution 3262 WA
Reinforce.Upgrd Reg Stn 15,
.el-I.,SpokWA . 3263 ..A
Reintorcement,Appleway to
ypkVly.WA L WA
5 Mile pipe relocation WA .
Reinforcement Appleway
Bri9pnLibUcWA . !Q. YY
Reinforcement North
Clarkston HP Main & Reg 3269 \A
Staff_PR_043-Attachment A.xlsx
Plant Additions by Month In (000s)
2011
Functional Plant Categories ER ST
Gas WA Distilbution
Subtotal
offset to budget?? 8001
Staff_PR_043Aftachment A.xlsx
Orig Cumulative
Annual Ending
Amount Jan Feb f j.r Mav Jun j Aug Sep Oct Nov 2ec Balance
2,325 2,325 2,326
2,325 2,326
157,830 18,091 10,403 7,559 13,092 20,919 12,692 10,882 27,086 155,334
18,091 10,403 7,559 13,092 20,919 12,692 10,882 27.086 155,332
2,337 195 195 195 195 195 195 195 195 195 195 195 195 2,337
2011 additions Page lOaf 11
Orig Cumulative
Plant Additions by Month in (000's) Annual Ending
2011 Amount Ian Feb mar Apr May Jun Jul Aug Sep Oct Nov Dec Balance
Functional Plant Categories ER ST
Revenue Supported ER's (Budget Category: New Revenue/Customers) All 2011 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov
Electric Revenue Blanket 1000 13,162
Gas Revenue Blanket 1001 12,053
Elec Meters Minor Blanket 1002 675
Distribution Line Transformer 1003 9,600
Street Light Minor Blanket 1004 1,000
Area Light Minor Blanket 1005 500
Network Transformers & I
Network Protectors i 1009 800
Gas Meters Minor Blanket 1050 1,525
Gas Regulators Minor Blanke 1051 160
Industrial Gas Cust Minor BIki 1052 30
Gas ERT Minor Blanket 1053 500
Spokane Smart Circuit 10,617 (94) (356) 489 623
SGDP-Pullman Smart Grid
:DemonstrationProject .2530 7,094 (26) 20 3,762 (1,166)
SGDP-Pullman Smart Grid
Demonstration P 3291 ,. 750 304 22
58,466
Productivity Capital 7050/2331 65 1
Staff_PR_043-Attachment A.xlsx 2011 additions Page 11 of 11
1 2 3 4 5
2011 Non-Revenue 2011 2011 2011 Vintage
Plant Additions in (000's) Vintage 12mos
12moEOP AMA
Functional Plant Categories Allocation Plant Plant
Washington Electric Totals
Intangible Plant
Production Plant
Transmission Plant
Distribution Plant
General Plant
Check Total
Idaho Electric Totals
Intangible Plant
Production Plant
Transmission Plant
Distribution Plant
General Plant
Check Total
Washington Gas Totals
Intangible Plant
Underground Storage Plant
Distribution Plant
General Plant
Check Total
Idaho Gas Totals
Intangible Plant
Underground Storage Plant
Distribution Plant
General Plant
Check Total
Oregon Gas Totals
Intangible Plant
Underground Storage Plant
Distribution Plant
General Plant
Check Total
89,066 35,234
11,278 5,069
19,492 8,478
15,227 4,228
31,981 12,061
11 ,089 5,399
89,066 35,234
47,066 18,654
5,709 2,566
10,422 4,533
8,141 2,260
17,180 6,562
5,614 2,733
47,066 18,654
17,690 6,939
3,134 1,408
3,785 1,936
7,690 2,094
3,081 1,500
17,690 6,939
7,844 424,133
1,440 647
1,892 968
3,096 421,829
1,416 689
7,844 424,133
17,418 6,880
1,969 885
1,892 968
11,620 4,084
Grand Total
Staff _PR_043-Attachment B.xlsx
2011 AMA Plant Allocations
Avista Utilities
Pro Forms Rate Base Adjustment
for 2011 Rate Case - Test Year 2010
Adjustment Factor:
Excludes Plant Additions for Customer Growth (Budget Category 1000's)
Ong
Plant Additions by Month in (000's) Annual
Amount Mar Apr
Functional Plant Categories ER ST
Generation:
Thermal
,K F Minor Blanket 4001 76
Kettle Falls Capital Projects 4101 731
KFGS Cap SparConveyralt 1
or2 4149
KFAsil . 4115 80
ColsrQpetAdthtions 41ii§ 6,926
Thermal Subtotal 7,812
................................
Hydro Minor Blanket . 4000
FERC Hydro Safety Minor
Blanket 4003 287
Spokane River License
Impiern Loo ............ .................. . ....
Cabinet Gorge Capital
LJc.................................................................... 1.00 800
Kittle FallçpalProjects . 4102
Long Projects . Nine Mile ......"°J ................ 41°' ........ Noxon Capital Projects 4105 1,000
SystemBattery ..P FTP! flU 4108
Prot ect.. 411W.
Cabinet Gorge Bypass
lyn .................. 41.
Noxon Rapids Unit 4
Emergency. Rewind . 4135
Noxon Rapids Unit 1 Runner
............. . .. 4136
Noxon Rapids Unit 2 Runner
Upgrade . ........
Noxon Unit #3 Upgrade-
carryover billing from 2010
project
Noxon Rapids Unit 4 Runner
Upgrade ...
Nine Mile Redevelopment 4140
Hydro Generation Minor
Blanket 6001
Clark Fork
License/Corn 6100
Staff,,PR_043-Attachment B.xlsx
Cumulative
Ending
Y tLyn !tii Aug Sep got Nov Q Balance
2011 additions Pagel of 11
Page 2 of 11 2011 additions
Plant Additions by Month in (000's)
2011
Functional Plant Categories ER ST
Env Compliance & Best
LMP PIT _ Clark Fork Implement PME
Agreement 6103
Relicensin....................... 6104
SR License & Compliance
:Sup.pot .......... 6105
Spokane River
Implementation (PM&E) 6107
Coeur d'Alene Tribe
Settlement 6108
Hydro Subtotal
Other
Comb Turbine Minor Blanket 4002
Rathdium CT Capital
Projects 4107
Boulder Park Generating
Station 4113
CS2 Joint Share Projects 4114
NE Combustion Turbine
Cap"!pj
Control Network 4121
Lancster Assts-Trf fm, AVA
Egy 4145
Non Utility Property Transfer . 416 ....
CS?.cPaI Projects . 4132
CS21Generator Step Up
Transformer Swap 4133
CS2LTSA 4142
CS2 LtSk 4143
Other Production Subtotal
Construction 2105
Noxon-Pinecreek =
230kV:ReaclFiOptic . 2113........
Noxon 230 kV
NE Moscow - Substation
roprty . 227 ........
Ninth & Central Sub -
:Increase Capacity . Rebuild 2341
Beacon-F&C 115: Relocate
at Whitworth 2473
Moscow 230 kV Sub-Rebuild
kV .Yard I
Staff_PR_043-Attachment 8.xlsx

Orig Cumulative

Annual Ending

Amou n fob Mar Aff LY 4ii (ti1 Aug Dec Balance

Orig Cumulative

Annual Ending

Amou 2Lan Feb !r Aor May Jun Jul Aug S eR Oct Nov qe_c Balance Plant Additions by Month in (000s)
2011
Functional Plant Cateoories ER ST
System-Install
Autotransformer Diagnostic
Monitor 2492
Blue Creek Sub- CDA 2252
Lucky Friday Tap 115kv
S rerout 2476
Addy Gifford 11 5k Minor
rebld 2477
Power Circuit Breaker 2001
Noxon-Pinecreek
230kV:ReadyFiberOptic .2051
Transmission Minor Rebuild . 2057
Deary rebuild add cap
transm 2204
System-Rock/Fence Restore 2275
System-Replace Obsolete
Reclosers 2278
Ancillary Svc 2397
VoltageFuseygTades
Colstiip Transmission
System Rplc High Voltage
OCBs 2215
Spokane-CDA 116 kV Line
itelayUpdes ..
System 11 5k Air Switch
Up9rade . 2.2
System-Upgrade Surge
Protection 2260
Beacon ST YD-011 Contain 2273 **
System-Replace/Upgrade
....................
System Replace Obsolete
Circuit Switch 2280
Tribal Permits and
Settlements 2301
Idaho Road Sub 2307
West Plains Transmission
Reinforce 1 2310
Nez Perce 115 Sub-Inst
............ c L
Dry Creek Complete .....vtrj 234.6
PineCk 23OSub-RpIc Circuit
Switch&Relays 2342
Lolo 230 - Rebuild 230 kV
Yard 2360
Otis Orchards 115-Replace
PCBs & Relays . 2390
1,093
962
1,245
517
183
828
698
263
574
14
388
161
49
842
438
59
202
62
323
1,803
3,606
52
233
803
Page 3 of 11
23
Staff_PR_043-Attachment B.xlsx 2011 additions
Plant Additions by Month in (000s)
2011
Functional Plant Cateoones ER ST
System Transmission::
Rebuild Condition 2423
System Replace Substation
Air Switches 2449
Moscow-Pullman 115
Recond 2455
Bronx-Cabinet 115kv
Rebuildlreconductor 2536
Hatwai-North Lewiston
230101 Re-Insulate 2537
System-Replace/Install
Capacitor Banks 248
SIP Sub-Replace NV Fuses
with Circuit Switcher 2482
Noxon GSU B Bank 4105
Divide Crkllmnaha Use Permi 6101 **
Garden Springs Property
purch 2539
Thornton 230kv Construct
Land 2545
EFM12F2&PVW24I
Feeder 2517
Elecfn it iinlssi6n
Subtotal
Electric Distribution
Power Xfmr-Distribution 1006 AN
Mobile Sub 1008 AN
Electric Underground
Replacement 2054 AN
Electric Distribution Minor
Blanket 2055 AN
T&D Line Relocation 2056 AN
Failed Electric Plant-
Unknown 2059 AN
Wood Pole Mgmt 208.. AN , ........................
Ram Rat 2 US 95 widening 2070 :AN
Replace High Resistance
Conductor 2072 AN 11
Capital Distribution Feeder
V~ork li
Feeder VA...pçynt - 2225 AN
Svstem-UDarade Meters 2253 AN
at nvutaItuIutytl.Iptwvc
Fdrs 2414 AN
open wire seconoary
Elimination 2496 AN
Staff_PR_043-Attachment B.xlsx

Orig Cumulative

Annual Ending

Amou Jan feb Mar 612—r May JunJul Aug p 2--Balance
2011 additions Page 4 of 11
Plant Additions by Month in (000s)
2011
Orig Cumulative
Annual Ending
Arnini Jan Feb hit! _Apr !Y Jun Jul Aug set)Dec Balance
PCB Identification &
Disposal 6000 .
Electric AN Distribution
Subtotalj
Power Xfmr-Distribution 1006 0 **
PCB Identification &
...................... . ....... Replace High Resistance
6000 ID
Conductor 2072 I0
• Plummer Rebuild Add
2302 ID
Chance Cutout replace 2009
ID 2416 .10
ID AMR optimization Comm 7303 ID
OGara Upgrade Transformer
Dist 2478 ID
System Wood Substation
Rebuilds-Deary ID 2204 ID **
Appleway additional property
NMO 521 recond 7 miles 11 2299 ID
.Appleway 115-13 Increase
Capacity .. 306
2336 .10
PineCk 23OSub-RpIc Circuit
Switch&Relays . 2342 ...
Rathdrum 233- Construct
Feeder 2362 ID
• Sys-Dist Reliability-Improve
Worst rs 2414 :io
OGara 0- --.1 . ..... .. .. ... . ..
pgrade Transformer
Dist 2505 10
PCB Related Distrib rbld
Spok 2535 ID
EFM 12F2&PVW241
Feeder Tie 2517 ID
Distribution - Pullman &
Lewis Clark 2516 ID
Distribution - CdA East &
North 2515 AD
Electric ID Distribution.
Power Xfmr-Distribution 1006 WA
PCB Identification &
.................................................................. 6000 ..
Spokane Electric Network
lrlci Capacity . 2058 .W.
WSDOT required Facility
reloc 2061 WA
Replace High Resistance
Conductor 2072 WA **
Staff—PR-043-Attachment B.xlsx 2011 additions Page 5 of 11
Orig
Annual
mou 3,Lan Feb Mr Apr Nov may 0 Jul Aug Sell get
Cumulative
Ending
Dec Balance
33
1,772
76
4
348
676
65
413
561
378
3,222
39
136
17
4
4,074
2,951
250
15,256
15,256
417
El
Page 6 of 11 2011 additions
Plant Additions by Month in (000's)
2011
Functional Plant Categories R ST
S Pullman Sub Pnl Else Ext 2210 WA
Miliwood Sub-Increase
Capacity, 2283 ..A
NE Capacity,
Metro 13 kv13693 teeder ad
corn 2303 WA
Downtown east-purch prope 2321 WA
Chewelah & Othello•
XformerS 2336 WA
....... Spirit-Northport WA 115 Sub-
c p y 2365 WA
NE Sub-lncre3se Capacity ... 96
Sys-Dist Reliability-Improve
Worst Fdrs 2414 WA
Opportunity sub add 12F2
comm 2418 . WA
Metro Post St Recond Phase
.1 2237 WA
EFM 12F2 & PVW 241
Feeder Tie 2517 WA
Distribution -Spokane North
& West 2514 WA
Terre View Sub new const
dist 2264 WA
Indian Trail Substation 2391 WA
Ross Park Sub landscaping 2445 WA
• Distribution - Pullman &
Lewis Clark 2516 WA
Otis Orchards 115-13kV
Sub-New Construct 2443 WA
Irvin Sub - New Construction 2446 WA
DREEBLMWAstdi5t 2466 WA
KET 12F2 Cot um...Cadar 2487 WA
.SPI12F1 River Crossing
Rbld 2490 WA
Mead Construct 12F3 2525 'WA
Pullman Substation - Rebuild i 2533 WA
PCB Related Distrib rbld
Spok 2535 WA
College Walnut Expand Yard 2538 WA
tepdownBan... 2503 ;w.
Electric WA Distribution
Subtotal
General
Securly !.n!ttIe................................4........... o
2 .
Next Generation 0"6*
System 5106
Staff_PR_043-Attachment B.xlsx
Cumulative
Ending
Nov Dec Balance
Ong
Annual
mou Jan Feb mar Apar may MB Mul AUG §!Q Oct
2011 additions
ii
Page 7 of 11
Plant Additions by Month in (000s)
2011
Functional Plant Cateoories ER ST
Structures&irnprov 2 7001
Office Furniture 7003
Kiamath Falls OR serv center 7004
Stores Equip . 700.
Tools Lab & Shop
.Equip ent 7006
F HVAC ..provmt .
Dollar Rd land purch &
facility expansion 7107
!WSDOT Highway Franchise
ConsolidatIon 7108
Spok Central Oper Fac N
Crescent Realignment . 7109
Jack Stewart modular
:.bu........._ ............................................ 7116
Pura Modular off Spok
iirprt 7117
Purhse prop 1819 EN
Crescent 7118
Local Improvement Distr 7119
Union Pacific RR Permits to
Easements Conversion 7112
ARO General Office Bldg 7500
Colville Service Center 7113
General Plant Subtotal
Transportation
Transportation Equip 7000=
Transportation Subtotal
Software
ComPo!wa........................................ 5000
Information Technology
Refresh Blanket 5005
Information Technology
Expansion Blanket . 5006
AFM Product Development .......................................................... 5007..
Nucleus Product
Development Program . 5008
Web Product Development ...................................................... . 5009
Enterprise Business
Continuity 5010
Data
Bus App Ref/Up Qrd program .
Next Generation Radio 5106
.1........ 5107
Technology Projects Minor
Blanket 5111
Staff_PR043-Aftathment B.xlsx
Plant Additions by Month in (000's)
2011
Functional Plant Categories ER..
GRC Software 5120
Microwave Replacement
with Fiber 5121
Electronic Records
Management 5123
Oracle Database Upgrade to
................................... ............................. ..i?!....
WorkPlace Replatforming .......... 5126
:nIMP Ith,t,,rn 17
Miscellaneous Intangible
Gas UG/Productlon
Jackson Prairie Storage 7201
Gas UGlProducfion Subtotal
Blanket3000 AA
Gas
3001 AA
Blanket 3004 AA
Gas Distribution Non-
Revenue Blanket 3005 M
Overbuilt Pipe Replacement
Blanket 3006 1AA
Gas M Distribution Subtotal
Gas Telemetry 3117 AN
Staff_PR_043-Attachment B.xlsx
Orig Cumulative
Annual Ending
mou Jan FebMar AprAug p Oct Nov Qg Balance
2011 additions Page 8 of 11
Plant Additions by Month in (000$)
2011
Functional Plant Categories ER
Reinforce Gate Station Post
Falls Idaho 3246 ID
Dover Gate Station 3225 ID
RepiaceGa.ERTs Ida.. 3265 ...
Reinforcement -IP Main
Southeast Coeur dAlene ID 3270 ID
Rebuild-Reg Station
4203(Sthweitzer)Sandpoint
ID 3271 AD
Reinforce-HP Main Ext south
from CDA East Gate, ID 3279 ID
Reinf CDA East S of Bonnell 3290 ID
Isolated Riser Replacement 3007 ID
Replace - Moscow/Bovill HP 3295 ID
Gas ID Distribution Subtotal
AIdyl-A pipe replacement 3008 OR
IMP Ashland Lat Reg sta
2311 3203 OR
'Altamont & Crosby Road
..............................
Tn-City 99 Road Project 3227 .OR .
Medford Barnett Road
cat.Ion Proct ....... 3232 OR
Rebuild-J St Reg Station
Grants Pass 3233 OR
Grants Pass 8-In HP
Q0J,!0ject .......
Rebuild 4st reg Ste2503 ..... . ..P..
Reinforce Talent OR Gate
Station&Piping 3240 OR
Relocation-Rocky Point
Bridge-Hwy 234-Gold Hill
OR 3256 OR
Oakland Bridge Bore &
Relocation, Oakland OR 3257 OR
Rock Point Reg Station Gold
::Hill OR 3258 OR
Brown Bridge Relocation
Roseburg OR
Replace Gas ERT5 Oregon
3261 OR
3265 P
Rebuild Winston Gate
Station, Roseburg OR 3287 OR
15 bore © Barnett Rd Medfor 3272 OR
IMP Pipe Replace, 2012
Commitment, Medford OR 3277 :0
Relocation - N Ross Ln,
Medford OR 3287 OR
Staff_PR_043-Attachment B.xlsx
Cumulative
Ending
Q Balance
OrIg
Annual
gMJan f Mr 2! y in ! Aug SOP Q
2011 additions
I]
Page 9 of 11
Orig Cumulative
Plant Additions by Month in (009s) Annual Ending
2211 AmoMfl! )#fl feb ME Aur May &I1 MI Aug SOP Dec Balance
Functional Plant Categories ER ST
Del Rio 15 Gas Relocate 3282 OR 1I 357
S 12th St IP Replacement 3289 OR
Construct Corrector and
Telemetry Test Bench 3288 OR 6
Gas OR Distribution Subtotal 4,915 6,647
1 6,647
f!YL_i9& Riser Replacement 3007 Isolated :WA 704
Aldyl-A pipe replace....390.. WA 749
Bridging the ........................... .A
Re-Rte Kettle Falls Fdr &
GateSta...on 3112 .WA (5)
US2 N Spo Gas HP
Reinforce(Kaiser Prop . 32... ....................... WA
Reinforce Barker Rd Bridge
Crossing Spok .3238 .WA
Reinforce, install pipe on
Bridge #3.9?_§pok WA 3260 ..A
Reinforcement North
Clarkston Distribution 3262 WA
Reinforce.uPgrdRe9Stn15.
Separate . 3263 .WA 6
Reinforcement,Appleway to
...........A .3264 .WA
5 Mile pipe relocation 3266 .WA
Reinforcement Appleway
..!!gWkWA 3268 .Bnd.ge WA 125 311
Reinforcement North
Clarkston HP Main & Reg 3269 WA 2,200 2.892
Gas WA Distribution
Subtotal1. 2,325 4,657
1 4,657
offset to budget'?? 8001
Staff_PR_043-Attachment B.xlsx 2011 additions . Page 10 of 11
Ong Cumulative
Plant Additions by Month in (000$) Annual Ending
2011 Am Jan m i! Aug p Nov Dec Balance
Functional Plant Categories ER ST
Revenue Supported ERs (Budget Category: New Revenue/Customers) All 2011 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov
Electric Revenue Blanket 1000 13,162
Gas Revenue Blanket 1001 12,053
Elec Meters Minor Blanket 1002 675
Distribution Line Transformer 1003 9,600
Street Light Minor Blanket 1004 1,000
Area Light Minor

Blanket 500
Network Transformers &
Network Protectors 1009 800
Gas Meters Minor Blanket 1050 1,525
Gas Regulators Minor Blanks 1051 160
Industrial Gas Cust Minor BIkI 1052 30
Gas ERT Minor Blanket 1053 500
Spokane Smart Circuit 2529I2504 10,617 (94) (356) 489 623 286 484 802 510 1,609 1,383 499
SGDP-Pullman Smart Grid
Demonstration Project .2530 = 7,094 (26) 20 3,702 (1,166) 541 (1,283) 1,504 311 501 24 63
SGDP-Pullman Smart Grid
Demonstration Project 3291 750 304 22 51 45 10 2 10 5 22
58,466
Strategic AlIgnment 7114 40
Productivity Capital 7050/2331 65 1 212 81 132 143
Staff—PR-043-Attachment B.xlsx 2011 additions Page 11 of 11
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/26/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Dave DeFelice
REQUESTER: IPUC RESPONDER: Karen Schuh
TYPE: Production Request DEPARTMENT: Rates and Tariffs
REQUEST NO.: Staff-044 TELEPHONE: [phone]
REQUEST:
Please provide copies of the contracts associated with plant additions listed on Exhibit 10,
Schedule 2, page 5 for gas pro forma capital additions 3.08 and 3.09.
RESPONSE:
Please see Avista's response 044C, which contains TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAPA 3 1.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code.
Please see Staff _PR_044C CONFIDENTIAL Attachment A for a listing of Idaho gas distribution
and underground gas storage contracts (ER's 3000 -3007, 3117, 3297 and 3298). Please note that
contracts classified as general, software and transportation have not been included in this listing.
Please also see Staff PR 044C CONFIDENTIAL Attachments B-G for 3 large Idaho contracts in
excess of $100,000. These Contracts total approximately $1.5M of the total $13M ID contracts
listed in CONFIDENTIAL Attachment A. The remaining contracts can be reviewed during
Staffs on-site visit scheduled for the week of December 10th•
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED 11/26/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Dave DeFelice
REQUESTER: IPUC RESPONDER: Karen Schuh
TYPE: Production Request DEPARTMENT: Rates and Tariffs
REQUEST NO.: Staff-045 TELEPHONE: [phone]
REQUEST:
Please provide a schedule that identifies the expected Date in Service of all 2012 and 2013 natural
gas capital projects included within the Company's case, the budgeted expenditures, and actual
expenditures to date and identify the source of this information for each project. Please consider
this an ongoing request and provide all updates to those dates in service and expenditures during
the course of this case. Please provide the printout of this information and the underlying
electronic file in Excel format with formulas activated.
RESPONSE:
Company witness Dave DeFelice's testimony and workpapers provide the requested budget
information for 2012 and 2013 for electric and natural gas projects. Pages 53 through 63 of the
workpapers list 2012, and pages 89 through 101 list 2013 projects by ER and details the expected
month the project will be completed and will be transferred to plant in service. The source of this
data is the Company's 2012 capital budget. Both hardcopies and electronic copies were provided
with the original filing.
See Staff _PR_045-Attachment A for the workpapers DeFelice used in the original filing, with
updates for actual transfers to plant in service through October 31, 2012 for electric and natural gas
projects. The actual transfers to plant are provided monthly from the plant accounting system. The
2013 capital additions budgets were updated and developed prior to filing this case, therefore, this
is the most current information available for expected transfers to plant during 2013. Please see
DeFelice workpapers (mentioned above) for details on the expected transfers to plant in 2013.
Please note that the listing of projects is being provided in hardcopy only. However, the electronic
file includes all of the workpapers that were provided in the original filing.
Cumulative
Ending Ong Revised
Avista Utilities
Pro Forma Rate Base Adjustment
for 2012 Rate Case - Test Year 2011
Excludes Plant Additions for Customer Growth (Budget Category 1,0005)
Plant Additions by Month in (000's)
201
Functional Plant Cateoories Es
Geaemt,on:
Thermal
K F Minor Blanket 4001
Kettle Falls Capital Projects 4101
KFAsh Landfill 4115
Purchase D1OTQ Caterpillar Tractor 4158
KF 0ev New River Wells 4151
Baseload Thermal 4149
Baseload Thermal 4132
Peaking Generation 4150
Colstrip Capital Additions 4116
Hydro
Hydro Minor Blanket 4000
FERC Hydro Safety Minor Blanket 4003
Spokane River Ucense Implementation 4004
Cabinet Gorge Capital Projects 4100
Uttle Falls Capital Projects 4102
Long Lake Capital Projects 4103
Nine Mile Capital Projects 4104
Noxon Capital Projects 4105
Post Falls Capital Projects 4106
System Battery Replacement 4108
Upper Falls Capital Projects 4109
Monroe Street Capital Projects 4117
Cabinet Gorge Bypass Tunnel Project 4131
Noxon Rapids Unit 4 Emergency Rewind 4135
Noxon Rapids Unit 1 Runner Upgrade 4136
Noxon Rapids Unit 2 Runner Upgrade 4137
Noxon Unit #3 Upgrade-carryover billing from 2010 project 4138
Noxon Rapids Unit 4 Runner Upgrade 4139
Nine Mile Redevelopment 4140
Base Hydro 4147
Regulating Hydro 4148
Uttle Falls Powerhouse Redevelopment 4152
Post Falls Intake Gate Replacement 4153
Hydro Generation Minor Blanket 6001
Clark Fork Ucense/Compliance 6100
Env Compliance & Best Mgmt Practices 6102
Clark Fork Implement PME Agreement 6103
Hydro Rellcensing 6104
SR Ucense & Compliance Support 6105
Spokane River Implementation (PM&E) 6107
Coeur d'Alene Tribe Settlement 6108
Hydro Subtotal
Other
Comb Turbine Minor Blanket 4002
Rathdrum cr Capital Projects 4107
Staff_PR.045 Attachment Axlsx
2012 additions-All
Adjustment Factor: 1
Page 1 of 7
1
1
*.
**
**
**
**
Oilg Revised
Anni.I Ann, ii1
Cumulative
Ending
-
In (000's)
2012
4154
4113
4114
4118
4121
7114
4145
4132
4133
4142
4143
2000
2105
2113
2211
2274
2341
2473
2484
2492
2252
2476
2477
2001
2051
2057
2275
2278
2397
2425
2559
2214
2215
2217
2254
2260
2273
2493
2280
2283
2277
2293
2294
2301
2307
2310
2318
2346
2342
2360
2390
2423
2449
2533
2536
2537
2538
Page 2of7
**
**
**
**
Plant Additions by Month
Functional Plant Cateoories
Rathdrum Cr Upgrade Unit 1 to Mark VI Control
Boulder Park Generating Station
CS2 Joint Share Projects
NE Combustion Turbine Capital Proj
Control Network
Install 15kw of solar at CEIS
Lancster Assts-Trf frm AVA Egy
Cs2 Capital Projects
CS2/Generator Step Up Transformer Swap
CS2 LISA
CS2 LTSA Cash Accrual
Other Produdilon Subtotal
Electric Transmission
Power Xfmr-Transmission
Benewah-Shawnee 230 kV Construction
Noxon-Pinecreek 230kV:Ready Fiber Optic
Noxon 230 kV Switchyard
NE Moscow - Substation Property
Ninth & Central Sub - Increase Capacity & Rebuild
Beacon-F&C 115: Relocate at Whitworth
Moscow 230 kV Sub-Rebuild 230 kV Yard
System-Install Autotransformer Diagnostic Monitor
Glenrose 115kv UP Relay Add
Lucky Friday Tap 115kv rerout
Addy Gifford 115kv Minor rabid
Power Circuit Breaker
Noxon-Pinecreek 230kV:Ready Fiber Optic
Transmission Minor Rebuild
System-Rock/Fence Restore
System-Replace Obsolete Reclosers
System-Install Metering Ancillary Svc
High Voltage Fuse Upgrades
Hatwal 230 kV Breaker Replace
Colstrip Transmission Capital Additions
System Rplc High Voltage OCBs
Spokane-CDA 115 kV Line Relay Upgrades
System 115kV Air Switch Upgrade
System-Upgrade Surge Protection
Beacon ST YD-Oil Contain
System-Replace/Upgrade Voltage Regulators
System Replace Obsolete Circuit Switch
Millwood Sub-Increase Capacity
SCADA Replacement
SCADA Il-Add Supv
System-Batteries
Tribal Permits and Settlements
Idaho Road Sub
West Plains Transmission Reinforce
Nez Perce 115 Sub-Inst Capacitor Bank
Dry Creek Complete 115kv trans
PineCk 230Sub-RpIc Circuit Swltch&Relays
Lob 230- Rebuild 230 kV Yard
Otis Orchards 115-Replace PCBs & Relays
System Transmission:: Rebuild Condition
System - Replace Substation Air Switches
Pullman Substation - Rebuild
Bronx-Cabinet 115kv Rebuld/reconductor
Hatwai-North Lewiston 230kv Re-Insulate
College Walnut Expand Yard
Staff_PR_O45 Attachment A.xlax
2012 additions-All
Cumulative
Ending OrIg Revised
Plant Additions by Month In (000's)
2212
Functional Plant Cateacries ER
morton 230kv Switching Station-Construction WIND 254$
Deary 115kv Add Property 2548
Moscow City to North Lewiston 115kv rebuild 2549
Burke-Thompson A&B 115kv Transmission Rebuild 2550
Noxon - Hot Springs #2 230kv Re-route 2.553
System-Replaceflnstall Capacitor Banks 2481
SIP Sub-Replace HV Fuses with Circuit Switcher 2482
Replace Fire Ext Trans 2483
Divide Crk/Imnaha Use Permit 6101 **
EFM 12F2 & PVW 241 Feeder lie 2517 **
Electric Transmission Subtotal
Electric DleblbuUon
Power Xfmr-Distribution 1006 AN
Mobile Sub 1008 AN
Electric Underground Replacement 2054 AN
Electric Distribution Minor Blanket 2055 AN
T&D Une Relocation 2056 AN
Failed Electric Plant-Unknown 2059 AN
Wood Pole Mgmt 2060 AN
Transformers for Wood Pole Mgmt 1003 AN
Ram Rat zUS9sWidening 2b70 AN
Replace High Resistance Conductor 2072 AN **
Capital Distribution Feeder Repair Work 2071 AN
System Wood Substation Rebuilds 2204 AN
Feeder VAR Improvement 2225 AN
System-Upgrade Meters 2253 AN
System-Replace Dist Power Xformers 2336 AN
Sys-Dist Reliability-Improve Worst Fdrs 2414 AN **
Compliance Load Study 2469 AN
Open Wire Secondary Elimination 2496 AN
PCB Related Distribution Rebuilds 2535 AN
Transformers for PCB Related Distribution Rebuilds 1003 AN
PCB Identification & Disposal 6000 AN **
Electric AN Disbibuffix Subtotal
Power Xfmr-Distribution 1006 ID **
PCB Identification & Disposal 6000 10 **
Replace High Resistance Conductor 2072 ID**
Spirit 115 Sub- Incr Xi'mr Capacity 2365 ID
Plummer Rebuild Add Capacity 2302 ID
Chance Cutout replace 2009 ID 2416 ID
ID AMR optimization Comm 7303 lb
OGara Upgrade Transformer Dist 2478 ID
System Wood Substation Rebuilds-Dewy ID 2204 ID **
NMO 521 recond 7 miles 2299 ID
Appleway 115-13 Increase Capacity 2306 ID **
Potlatch Xformer Repl 2336 ID
PineCk 230Sub-Rplc Circuit Swltch&Relays 2342 ID
Rathdrum 233- Construct Feeder 2362 ID
Sys-Dist Reliability-Improve Worst Fdrs 2414 ID
Replace Fire ExtlDDist 2483 ID
St Mertes 24kv cr replacement 2505 ID
Staff—PR-045 Attachment Axlax
2012 additions-All Page 3 of 7
Olig Revised
Plant Additions by Month in (000's) Annual Annual
2Q12 Amoun Amou
Functional Plant Cateoories ea
10th & Stewart Dx mt 2522 ID 250 250
Blue Creek 115kv Rebuild 2546 ID 1,905 1,905
Lucky Friday 115 kv rebuild 2547 ID
EFM12F2&PVW24l Feeder Tie 2517 ID
Distribution - Pullman & Lewis Clark 2516 ID 650 650
Distribution - CdA East & North 2515 ID 855 855
Electric ID Dlsttibutioi? Subtotal 4,782 5,223
Power Xfmr-Distribution 1006 WA 800
PCB Identification & Disposal
6000 WA 250
Spokane Electric Network Incr Capacity 2058 WA 1,650
WSDOT Franchise Requirements Construction 2061 W
Replace High Resistance Conductor 2072 WA
Millwood Sub-Increase Capacity 2283 WA 1,000
NE Sub-Increase Capacity 2296 WA
Downtown East - Purth Property 2321 WA
Chewelah & Othello Xformers 2336 WA
Sys-Dist Reliability-Improve Worst Fdrs 2414 WA 1,228
Metro Post St Recond Phase 1
2237 WA 502
Distribution - Spokane North & West 2514 WA 1,910
Terre View Sub new const dist 2264 WA
Indian Trail Substation 2391 WA
Replace Fire Ext WA dist
2483 WA
Pound lane Replace Bus 2 CTs 2505 WA
Distribution - Pullman & Lewis Clark 2516 WA
Spokane Smart Orcult-SGIG
2529 WA 5,400 5,
SGDP-Pullman Smart Grid Demonstration Project 2530/3291 WA 6,300 6
Smart Grid Woritforce Program 7205 WA 1,300 1,
Otis Orchards 115-13kv Sub-New Construct
2443 WA
Ross Park Sub - Landscaping 2445 WA
System Wood Substation Rebuilds 2204 WA 300
KEr 12F2 Columbia Cedar 2487 WA
System Efficiency Feeder Rebuild 2470 WA 7,371 7
SPI121`1 River Crossing Rbld
2490 WA
Pullman Substation - Rebuild 2533 WA 609
Spokane Airport Sw Gear Repi
2544 WA
Weilpinit Stepdown Banks 2503 WA
Electric WA Dlct,Ibutlon Subtotal
5002 500
5106
7001 ** 5,757
7003 520
7004
7005 450
7006 1,250
7101 ** 4,300
7107 2,500
7126 4,500
7108 250
7109
7116
7117
7118
Cumulative
Ending
Nov Qllc BalanE
150 100 250
1,805 100 1,905
463 651
448 855
2,692 1,448 5,246
2,692 1,448 5,246
800 800
83 83 250
282 282 1,650
1,000 1,000
3
272 272 1,228
502 502
650 1,910
2
17
9
2
1,464 373 5,400
3,276 1,015 6,300
1,105 1,105
6
300 300

2,168 2,168 7,371

596 100 609
134

11,346 5,445 28,628

1,346 5,445 28,628

191 170 500

833 1,836 5,757

270 270 520

99 99 450

33 33 1,250

164 300 4,298

2,500 2,500

4,500 4,500

125 125 250
Page 4 of 7
General
Security Initiative
Next Generation Radio System
Structures & Improv
Office Furniture
Klamath Falls OR serv center
Stores Equip
Tools Lab & Shop Equipment
COF HVAC Improvmt
Dollar Rd land purch & facility expansion
Long-term Campus Re-Structuring Plan
WSDOT Highway Franchise Consolidation
Spok Central Oper Fec N Crescent Realignment
Jack Stewart modular building
Porch Modular off Spok Airpit
Pur lee prop 1619 E N Crescent
Staff_PR_045 Attachment A.xlsx
2012 additions-All
Orig Revised
A.,,.,,I Ann,,l
Cumulative
Ending
Page 5 of 7
Plant Additions by Month in (000's)
ZQ2
Functional Plant Cateoorles
Local Improvement Olstr 7119
Union Pacific RR Permits to Easements Conversion 7112
Colville Service Center 7113 **
General Plant Subtotal
Transportation
Transportation Equip 7000
Transportation Subtotal
Software
Computer Software 5000 U
Information Technology Refresh Blanket 5005 U
Information Technology Expansion Blanket 5006 AA
AFM Product Development Program 5007 U
Nucleus Product Development Program 5008 U
Web Product Development Program 5009 U
Enterprise Business Continuity 5010 U
Enterprise Data Architecture 5011 AA
Workplace System Enhancements 5012 U
IT for Facitlitles projects 5013 U
Dev, Environ project 5021 U
Bus App Ref/Upgrd program 5024 U
BuCC enhancement 5107 AA
Technology Projects Minor Blanket 5111 AA
AA
Moducom Repl(RTCCS) 5119 U
Microwave Replacement with Fiber 5121 AA
Electronic Records Management 5123 U
Oracle Database Upgrade to jig 5125 AA
WorkPlace Replatformlng 5126 U
DIMP Infrastructure 5127 AA
IFRS Compliance 5128 AA
AFM.net Upgrade 5129 AA
Gas Solutions Rewrite 5131 AA
CIS Replacement 5138 U
Appren Craft Train 7200 AA
Software Subtotal
Next Generation Radio 5106 AN
High Voltage Protection Upgrade 5142 AN
Miscellaneous Intangible
Gas UG/Pivductton
)ackson Prairie Storage 7201
Gas UG/Pff,ductlon Subtotal
Gas Otstn'but'on
Gas Reinforce-Minor Blanket 3000 U
Staff PR 045 Attachment Axlsx
2012 additions-All
Orig Revised Cumulative
Annual Annual Endln
Page 6 of 7
Plant Additions by Month in (000's)
2012
Functional Plant Catecio Es Et
Replace Deteriorating Gas System 3001 M
Regulator Reliable - Blanket 3002 AA
Gas Replace-St&Hwy 3003 AA
Cathodic Protection-Minor Blanket 3004 M
Gas Distribution Non-Revenue Blanket 3005 M
Isolated Steel Replacement 3007 AA
Ald1-A Pipe Replacement 3008 M
Overbuilt Pipe Replacement Blanket 3006 AA
Gas M DLsbibudon Subtotal
Gas Telemetry 3117 AN
Reinforce Gate Station Post Falls Idaho 3246 ID
Dover Gate Station 3225 ID
Replace Gas ERT5 Idaho 3265 ID
Reinforcement -IP Main Southeast Coeur d'Alene ID 3270 ID
Rebuild-Reg Station #203(Schweitzer),Sandpoint ID 3271 ID
Non Rev Gas Meters, Rags & ERrs 105011051/1053 ID
Reinforce-HP Main Ext south from CDA East Gate, ID 3279 ID
Reinf CDA East S of Bonnell 3290 ID
Hwy 95 Relocation & Replacement w/6' PE 3297 ID
Old Hwy 95 Relocation 3298 ID
Replace - Moscow/Boviil HP 329$ ID
Gas IV Distribution Subtotal
Roseburg Reinforcement 3204 OR
East Medford Reinforcement 3203 OR
Altamont & Crosby Road Project 3213 OR
Tr-City Hwy 99 Road Project 3227 Ol
Medford Barnett Road Relocation Project 3232 OR
Rebuild-) St Rag Station Grants Pass 3233 OR
Grants Pass 8-In HP Reinforce Project 3237 OR
Rebuild )stregsla2503 3239 OR
Reinforce Talent OR Gate Station&Piphig 3240 OR
Non Rev Gas Meters, Rags & ERTS 1050/1051/1053 OR
Relocation-Rocky Point Bridge-Hwy 234-Gold Hill OR 3256 OR
Oakland Bridge Bore & Relocation, Oakland OR 3257 OR
Rock Point Rag Station Gold Hill OR 3258 OR
Brown Bridge Relocation Roseburg OR 3261 OR
Replace Gas ERT5 Oregon 3265 OR
Rebuild Winston Gate Station, Roseburg OR 3267 OR
IS bore @ Barnett Rd Medford 3272 OR
IMP Pipe Replace, 2012 Commitment, Medford OR 3277 OR
Relocation - N Ross Ln, Medford OR 3287 OR
S 12th St IP Replacement 3289 OR
Klamath Falls lateral 3293 OR
Construct Corrector and Telemetry Test Bench 3288 OR
Gas OR Disbibution Subtotal
N-S Freeway/Gas 3102 WA
Bridging the Valley 3107 WA
Re-Rte Kettle Falls Fdr & Gate Station 3112 WA
USZ N Spo Gas HP Reinforce(Kaiser Prop) 3237 WA
Reinforce Barker Rd Bridge Crossing Spok 3238 WA
Non Rev Gas Meters, Rags & ERTs 1050/105111053 WA
Staff—PR-045 Attachment Axlsx
2012 additions-All
Orig Revised Cumulative
Plant Additions by Month in (000's) Annual Annual ____________ Ending
2012 Mount &ount lLJIt Nov Qc 0Ian
Functional Plant Cateooilre ER SI
Reinforce, install pipe on Bridge #3602, Spok WA 3260 WA
Reinforcement North Clarkston Distribution 3262 WA
Reinforce,Upgrd Reg Stn 15, Separate HP,SpokWA 3263 WA
Rsinforcement,Appleway to Henry, SpokVly, WA 3264 WA
5 Mile pipe relocation 3266 WA
Reinforcement Appleway Bridge Crossing, Lib Lk, WA 3268 WA
Reinforcement North Clarkston HP Main & Reg 3269 WA 15 15
Gas WA DLcfribution 5ubtotal 291 333 146 146 333
1 146 146 333
233,702 229,811 39,742 68,932 232,514
S9,742 68,932 232,514
Staff_PR_045 Attachment A.xlsx
Page 7 of 7 2012 additions-All
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/27/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Dave DeFelice
REQUESTER: IPUC RESPONDER: Karen Schuh
TYPE: Production Request DEPARTMENT: Rates and Tariffs
REQUEST NO.: Staff-046 TELEPHONE: [phone]
REQUEST:
For the natural gas pro forma capital additions 3.08 and 3.09 listed on Exhibit 10, Schedule 2, page
5, please provide the following information for Idaho separately for each project: invoice number,
description of payment, vendor name, date posted and amount, from inception of project to date.
Please provide the printout of this information and the underlying electronic file in Excel format
with formulas activated.
RESPONSE:
Please see Staff PR 046 Attachment A for details of Idaho's share of CWIP at December 31,
2011 expected to transfer to plant during 2012 and 2013 for ER's 3000-3008, 3117, 3246, 3297
and 3298.
Also, please see Staff _PR_046 Attachment B for details of capital spend from January 1, 2012
through October 31, 2012 for the above ER's. Below is a table that summarizes Attachment A and
B.
cWIP Spend
Amount 10.31.12
ER Description (2) Total
3000 Gas Reinforce-Minor Blanket 174,168 12,681 186,849
3002 Replace Deteriorating Gas System 47,271 72,073 119,344
3003 Gas Relace St. &Hwy 4,631 66,370 71,002
3004 Cathodic Protection-Minor Blanket 59,912 1,902 61,814
3005 Gas Distribution Non-Revenue Blanket 2,764 99,981 102,744
3008 Aldyl-A Pipe Replacement 22,335 38,022 60,358
3117 Gas Telemetry 81,755 71,680 153,435
3246 Reinforce Gate Station Post Falls Idaho 11,430 37,586 49,016
3297 Hwy 95 Relocation & Replacement w/6" PE 71,246 865,129 936,374
3298 Old Hwy 95 Relocation 411,783 1,389,569 1,801,352
Total ' 887,296 F 2,654,993 3,542,288
(1)Construction Work in Progress (CWIP) at December 31, 2011 (for Transfers to Plant in 2012/2013)
(2)Spend January 1, 2012 through October 31, 2012 (for Transfers to Plant in 2012/2013)
Adjustments 3.08 and 3.09 include allocated costs from general plant and software in addition to
the ER's provided in Attachment A and B.
IFercAcct 1107000 1
Sum of Transaction Amount
Er Project Number Jurisdicl Expenditure Category Invoice Number Vendor Name Accounting Period Total
3000 93005110 ID
____________
AFUDC - - 201109
201110
201111
201112
100.66
213.65
565.93
1,020.71
Contractor 104855 LOY CLARK PIPELINE 201111 79,648.75
105549 LOY CLARK PIPELINE 201112 9,940.00
105551 LOY CLARK PIPELINE 201112 11,815.00
105578 LOY CLARK PIPELINE 201112 7,220.00
105746 LOY CLARK PIPELINE 201112 497.00
133 CHERRY ENTERPRISES IN( 111 9,033.25
72-227578 INTERSTATE CONCRETE & 201111 142.58
76070211 ASPLUNDH TREE EXPERT 111 803.38
77952 JAMES A SE WELL & ASSOC 201111 773.10
Employee Expenses - -______________________ 201109 -
1E205411 TIMOTHY J HARDING 201109 86.58
Labor - - 201109
201110
201111
507.70
119.24
153.76
Material - - 2011-09
201110
201112
21,835.96
2,953.54
805.48
Overhead - - 201109
201110
201111
201112
8,110.53
666.99
10,270.90
3,490.08
Transportation -_____________ -____________________ 201111 100.80
Voucher 28915 (3112 201112 2.12
41922 PEAK SAND & GRAVEL INC 201111 72.89
72-227006 INTERSTATE CONCRETE & 201111 352.42
2-227032 INTERSTATE CONCRETE & 201111 384.90
72-227065 INTERSTATE CONCRETE & 201111 402.56
2-227093 INTERSTATE CONCRETE & 201111 214.48
72-227202 INTERSTATE CONCRETE & 201111 79.97
72-227261 INTERSTATE CONCRETE & 201111 154.09
2-227400 INTERSTATE CONCRETE & 201111 59.69
72-227546 INTERSTATE CONCRETE & 201111 72.64
2-227641 INTERSTATE CONCRETE & 201111 1-51.15
2-227710 INTERSTATE CONCRETE & 201111 60.26
2-228085 INTERSTATE CONCRETE & 201111 180.85
2-229489 INTERSTATE CONCRETE & 201112 218.07
72-229516 INTERSTATE CONCRETE & 201112 307.28
72-229570 INTERSTATE CONCRETE & 201112 542.98
S5799297.001 CONSOLIDATED SUPPLY 11 35.84
93005110 Total 174,167.76
3000 Total 174,16776
3002 03805338
JjOverhead
lID LAFUDC -_____________ - 201112 40.08
{Contractor IWO 1094974 INORTHWEST PIPELINE C01201112 12,129.90
1- 201112 30.32
03805338 Total - 12,200.30
31005020 ID AFUDC - - 201109
201110
201111 -
201112
0.85
5.06
14.73
21.03
Employee Expenses - - 201109 -
1E169402 DAVID ROBERT SMITH 201109 27.75
Labor - - - 201109
201110
201111
124.96
- 570.69
792.98
Overhead - -
_
201109
201110
201111
105.28
450.84
706.45
Voucher 6162 CHALLENGER PIPE & STEE 201111 410.88
31005020 Total 3,231.50
31005021 i5 AFUDC - - 201109
201110
201111
201112
0.76
2.99
52.76
101.06
Employee Expenses 1E2 18408 DAVID ROBERT SMITH 201111 29.97
Labor - - 201109
201110
124.96
249.92
ff_PR,.046 Attachment AxIs - - Pagel of 7
3002 31005021 ID Labor - - 201111 93.97
Overhead - - 201109 105-28
201110 197.43
201111 2,329.45
Voucher - - 201110 11,040.00
201111 (11,040.00)
6162 ICHALLENGER PIPE & STEEI 201111 410.86
94105 ITRI PACIFIC SUPPLY INC 1201111 11,790.45
31005021 Total ___________________ _____________ 15,489.86
62005009 ID AFUDC - - 201105 0.20
201106 0.41
201107 0.41
201108 0.41
201109 0.41
201110 0.41
201111 0.41
201112 0.41
Labor - - 201105 34.15
Overhead - - 201105 27.11
62005009 Total ____________________ ______________ 64.33
62005010 ID AFUDC .. - 201107 2.46
201108 4.92
201109 . 4.92
201110 4.92
201111 4.92
201112 4.92
Labor - - 201107 409.84
Overhead - - 201107 337.10
_______________ 62005010 Total 774.00
90105225 ID Contractor 3792
_____________________
THOMPSON QUALITY FEN( 201012 771.29
Labor - - 201101 41.10
201102 82.20
201104 1,691.66
201106 123.78
201109 253.85 -
201111 82.52
Material - - 201011
201012
3,078.31
580.00
201104 (5.01)
Overhead - - 201011
201012
1,456.40
482.82
201101 31.92
201102 63.82
201104 2,028.88
201105 14.72
201106 166.49
201109 213.87
201111 88.00
Transportation - - 2-01104
201105
58-80
9.60
201111 22.75
Voucher CDR5456 OXARC INC 201105 38.17
CDR6442 OXARC INC 201106 23.88
R062868 IOXARCINC 201106 14.86
_______________ 90105225 Total _____________________ 11,414.68
90105257 ID AFUDC - 201110
201111
1.87
5.54
201112 7.34
Employee Expenses lE273403 TIMOTHY J HARDING 201111 34.41
Labor - - 201110 317.30
201111 285.57
Overhead - - 201110 250.67
201111 225.60
90105257 Total - 1,128.30
90705059 ID AFUDC - - 201110 2.97
201111 12.64
201112 19.33
Labor - - 201110 442.84
201111 1,012.60
Overhead - - 201110 459.16
201111 1,018.62
90705059 Total 2,968.16 ________
3002 Total 47,271.13
0Q3 190105252 1113IAFUDC I- I- 1201109 13.07
Staff-PR-046 Attachment AxIs Page 2 of 7
3003 90105252 ID AFUDC - - 201110 26.59
201111 27.33
201112 27.60
Labor - - 201109 6248
201110 78.10
201111 46.88
Material - - 201109 2,847.57
Overhead - - 201109 1054.54
201110 61.70
201111 37.02
90105252 Total ________________ 4,282.86
90705074 ID AFUDC - - 201112 1.14
Labor - - 201112 190.38
Overhead - - 201112 157.06
90705074 Total ________________ 348.58
3003 Total _______________ 4,631.44
3004 93205060 ID AFUDC - - 201109 2.86
201110 5.72
201111 44.68
201112 238.32
Contractor 674052-INV HANSEN DRILLING CO INC 201112 38,160.00
Employee Expenses - - 201109 -
1E207408 RANDY DANIELS 201109 121.55
Labor - - 201109 365.53
201111 1,733.87
201112 1,741.96
Material - - 201112 1,710.00
Overhead - - 201109 380.03
201111 2,091.75
201112 5,284.30
Transportation - -____________________ 201112 36.00
Voucher 246305-1 1 NORTON CORROSION LIMIJ 201111 7,995.70 9______
3205060 Total _______________________________________ 59,912.27
3004 Total
3005 90105261 ID AFUDC - - 201112 5.85
Employee Expenses lE272433 DAVID ROBERT SMITH 201112 74.37
Labor - - 201112 931.99
Overhead - - 201112 768.90
______________ 90105261 Total ___________________ 1,781.11
90705063 ID AFUDC - - 201008
201009
3.01
6.02
201010 6.02
201011 6.02
201012 5.78
201101 5.95
201102 5.95
201103 5.95
201104 5.95
201105 5.95
201106 5.95
201107 5.95
201108 5.95
201109 5.95
201110 5.95
201111 5.95
201112 5.95
Labor - - 201008 488.00
Overhead - - 201008 388.69
90705063 Total _____________________ ________________ 974.94
93301230 [ID Employee Expenses IIE167413 IGAYLE Y LARSON 1201109 7.77
93301230 Total 7.77
3005 Total _____________________ ________________ 2,763.82
3008 03802058 ID Employee Expenses lE240412 Michael Whitby 201111 16.10
Labor - - 201107 1,716.35
201108 2,019.24
201109 2,978.38
201110 2,019.24
201111 1,716.35
201112 1,817.31
Overhead - - 201107 1,411.69
201108 1,681.03
201109 2,509.30
201110 1,595.20
201111 1,355.91
Staff.PR,,46.AUachment Axis Page 3 of 7
3008 03802058 lID IOverhead I- I- 1201112 1,499.28
03802058 Total 22,335.38
3008 Total ________________ 22,335.38
3117 03805273 ID AFUDC - - 201103 70.75
201104 141.51
201105 141.51
201106 141.51
201107 141.51
201108 141.51
201109 141.51
201110 141.51
201111 141.51
201112 141.51
Labor - - 201103 498.15
Overhead - - 201103 5,877.48
Voucher 142239 IMERCURY INSTRUMENTS 1201103 15,091.64
03805273 Total _________________ 22,811.61
03805274 ID AFUDC - - 201103 28.24
201104 56.49
201105 57.94
201106 62.14
201107 64.92
201108 65.68
201109 66.77
201110 67.27
201111 67.47
201112 67.47
Contractor - - 201109 -
201110 -
25687250 VOLT MANAGEMENT CORP 201110 8.56
6428881 HP ENTERPRISE SERVICEE 201106 105.40
6433549 HP ENTERPRISE SERVICEE 201108 231.88
6436571 HP ENTERPRISE SERVICEE 201109 96.34
6438709 HP ENTERPRISE SERVICU 201110 48.17
Labor - - 201105 239.47
201106 136.84
Overhead - - 201103 954.54
201105 198.41
201106 123.58
201108 1.16
201109 0.67
201110 0.40
Transportation - - 201106 473.75
Voucher 1142192 IMERCURY INSTRUMENTS 1201103 7,615.69
03805274 Total - 10,839.25
90105236 ID AFUDC - - 201102
201103
10.48
24.24
201104 60.48
201105 101.65
201106 109.88
201107 110.13
201108 111.58
201109 118.82
201110 127.43
201111 13003
201112 130.03
Centralized Assets 142967 MERCURY INSTRUMENTS 201104 3,425.79
43047 MERCURY INSTRUMENTS 201104 2,338.03
43185 MERCURY INSTRUMENTS 201104 2,135.80
43198 MERCURY INSTRUMENTS 201104 210.88
44048 MERCURY INSTRUMENTS 201105 1,191.36
Contractor 6425531 HP ENTERPRISE SERVICES 201105 437.05
6430923 HP ENTERPRISE SERVIGEE 201107 72.26
Labor - - 201102 1,762.55
201103 506.71
201105 98.12
201108 161.32
201109 358.50
Material - - 201108 53.60
Overhead - - 201102 1,415.93
201103 398.19
201104 1,014.70
201105 246.73
201107 0.36
Staff-PR-046 Attachment A.xls Page 4 of 7
3117 90105236 lID Overhead - - 201108 152.97
201109 443.53
201110 5.45
Transportation - - 201103 93.00
Voucher 1044768 FERGUSON ENTERPRISES 201109 4.22
2496104 STONEWAY ELECTRIC SUF 201105 188.12
31579 POWER CITY ELECTRIC 201109 1,024.32
32140 POWER CITY ELECTRIC 201110 778.74
1P41187536 C B ENGINEERING PACIFIC 201104 871.75
1P51187789 C B ENGINEERING PACIFIC 201105 334.81
90105236 Total _________________ 20,759.54
3005105 ID AFUDC - - 201105 4.40
201106 8.82
201107 8.82
201108 8.82
201109 8.82
201110 8.82
201111 10.01
201112 16.44
Centralized Assets 144048 MERCURY INSTRUMENTS 201105 1,191.40
Labor - - 201112 844.48
Overhead - - 201105 145.24
201111 26.18
201112 742.88
Voucher 13189 ENGINEERED PROCESS Cq 201111 337.91
93005105 Total _______________ 3,363.04
93205055 ID AFUDC - - 201104 34.58
201105 63.07
201106 56.96
201107 56.96
201108 56.96
201109 58.21
201110 59.47
201111 59.47
201112 59.47
Centralized Assets 142969 MERCURY INSTRUMENTS 201104 3,324.68
201105 (3,324.681
143050 MERCURY INSTRUMENTS 1104 2,249.37
143576 MERCURY INSTRUMENTS 1104 3,548.97
143577 MERCURY INSTRUMENTS 1104 205.44
144048 MERCURY INSTRUMENTS 201105 1,191.40
Contractor 6425531 HP ENTERPRISE SERVICEE 201105 244.37
Labor - - 01109 206.33
Overhead - - 201104 1,166.05
201105 (240.99)
201109 173.83
Transportation - -____________________ 201105 88.40
Voucher 2496099 3TONEWAY ELECTRIC SUPI 201105 188.12
________________ 93205055 Total ______________________ 9,526.44
93305034 ID AFUDC - - 201102
201103
0.42
3.23
201104 40.20
201105 81.31
201106 87.83
201107 87.83
201108 87.83
201109 89.09
201110 90.34
201111 90.34
201112 90.34
Centralized Assets 143051 MERCURY INSTRUMENTS 201104 2,249.37
143099 MERCURY INSTRUMENTS 201104 3,325.50
143576 MERCURY INSTRUMENTS 201104 3,548.98
143577 MERCURY INSTRUMENTS 201104 205.44
144048 MERCURY INSTRUMENTS 201105 1,191.40
Contractor 6425531 HP ENTERPRISE SERVICEE 201105 432.02
Labor - - 201102 69.62
201103 405.37
201109 206.33
Overhead - - 201102 58.24
201103 318.36
201104 1,166.14
201105 167.53
201109 173.83
Staff-PR-046 Attachment AxIs Page 5 of 7
3117 1933 05034 lID iVoucher 12496100 ISTONEWAY ELECTRIC SUFI201105 188.12
93305034 Total 14,455.01
3117 Total ________________ 81,754.89
3246 90105251 ID AFUDC - - 201109 1.93
201110 33.87
201111 66.92
201112 72.07
Employee Expenses - - 201110 -
1E199398 DAVID APADON 201109 47.18
1E232402 DAVID APADON 201110 165.39
1E270445 DAVID A PADON 201111 81.04
Labor - - 201109 292.25
201110 526.04
201111 468.60
201112 352.08
Overhead - - 201109 246.22
201110 415.57
201111 370.20
201112 290.47
Voucher 201110 -
661968-INV ROBERT M CONTI AND JO1 201110 8,000.00 _ __
90105251 Total ________________________________ 11,429.83
________________ 3246 Total ______________________ 11,429.83
3298 65305001 ID AFUDC - - 201106
201107
1.12
5.65
201108 11.17
201109 16.19
201110 33.62
201111 48.13
201112 48.13
Contractor M110765-IN SHARP LINE INDUSTRIES 201109 31.96
Labor - - 201106 187.44
201107 566.01
201108 349.69
Overhead - - 201106 154.17
201107 465.54
201108 292.40
201109 209.63
201110 1,056.83
Voucher - - 201109 -
152663 PCEPACIFIC INC 201110 3,347.53
93097 TRI PACIFIC SUPPLY INC 201109 639.86
________________ 65305001 Total _____________________ 7,465.07
65305002 I5 AFUDC - - 201106
201107
3.01
7.98
201108 12.45
201109 15.08
201110 15.20
201111 15.20
201112 15.95
Contractor M110765-IN SHARP LINE INDUSTRIES 201109 31.96
Labor - - 201106 499.91
201107 329.28
201108 412.17
201112 124.96
Overhead - - 201106 411.17
201107 270.84
201108 343.84
201109 6.61
201112 103.09 ______________________
65305002 Total _________________________________________ 2,618.70
65305004 ID AFUDC - - 201108 8.07
201109 26.71
201110 39.69
201111 92.95
201112 574.85
Contractor 4290 TATE ENGINEERING INC 201112 635.00
Employee Expenses - - 201108 -
1E153403 DAVID ROBERT SMITH 201108 38.85
201110 38.85
IE169402 DAVID ROBERT SMITH 201109 119.88
E199398 DAVID APADON 201109 57.17
1E218408 DAVID ROBERT SMITH 201111 38.85
Staff-PR-046 Attachment AxIs Page 6 of
3298 65305004 ID Employee Expenses IE232402 DAVID A PADON 201110 124.88
1E242402 Seth Samsell 201111 7.42
1E270445 DAVID A PADON 201111 45.51
lE272433 DAVID ROBERT SMITH 201112 77.70
Labor - - 01108
01109
201110
01111
01112
1,312.13
1,480.99
318.74
832.09
1,402.30
Material - - 01111
01112
11,105.99
110,593.37
Overhead - - 01108
01109
01110
01111
01112
1,097.96
1,247.72
251.81
2,994.96
18,082.81
Transportation - - 01111 400.00
Voucher - - 01109
201112
-
248,352.00
655927-INV REAL ESTATE WORKING F' 201109 300.00 _____________
65305004 Total _______________________________________ 401,699.25
3298 Total _______________________________________ 411,783.02
3297 90105260 ID AFUDC - - 201111
201112
1.48
235.52
Employee Expenses 1E314404 Seth Samsell 201112 183.16
1E27441 1 Seth Samsell 201111 33.30
Labor - - 201111
201112
233.47
18,268.72
Material - - 201112 14,792.63
Overhead - - 201111
201112
184.44
21,069.14
Transportation - - 201112 11,830.50
Voucher 1-398158 HONEY BUCKET 201112 120.20
41793 CONMAT 201112 1,524.47
41774 ICONMAT 1201112 2,768.80
901___05260 Total 71,245.83
3297 Total 71,245.83
Grand Total 887,295.37
Staff—PR-046 Attachment A.xls Page 7 of 7
lFercAcct 1107000 I
Sum of Transaction Amount
Er Project Numb Junsdi Expenditure Category Invoice Number Vendor Name Accounting Period Total
3000 93005110 ID Contractor - -_________________ 01201 -
107037 LOY CLARK PIPELINE 201206 1,955.20
151 CHERRY ENTERPRISE 201201 7,046.63
1883 FAST GRASS HYDRO SI 201206 2,594.00
Overhead - - 01201 362.90
01205 41.05
01206 375.31
Voucher -______________ -___________________ 01205 -
11611 IDAHO STONE 201205 31.79
11614 IDAHO STONE 201205 63.58
72-231889 __________

INTERSTATE CONCRE 01205 210.94
93005110 Total 12,681.40
3000 Total - 12,681.40
3002 03805338 ID AFUDC - - 201201 77.48
201202 77.47
201203 77.47
201204 77.47
201205 77.47
03805338 Total 387.36
31005020 ID AFUDC - - 201201 20.52
201202 20.52
201203 24.00
Employee Expenses 71 5748-INV O'MALLEYS 201205 40.71
Labor - - 201203 495.12
201204 1,248.69
201205 141.37
201206 49.44
Material - - 201204 115.91
Overhead - - 201203 525.10
201204 1,069.79
201205 152.76
201206 48.55
Transportation - - 201203 72.00
201204 406.00
201205 14.00
Voucher 96664 TRI PACIFIC SUPPLY IN 201204 293.89
CDT3198 OXARC INC 201205 21.93
CDT3841 OXARC INC 201205 73.23
R122715 OXARC INC 201204 14.86
Ri 34564 OXARC INC 201206 59.44
31005020 Total 4,907.83
31005021 ID AFUDC - - 201201 98.35
201202 98.36
201203 101.99
Employee Expenses - - 201204 -
42403A APPLEBEES 201204 47.27
Labor - - 201203 536.38
201204 1,716.08
201205 141.37
201206 32.96
Material - - 201204 104.12
Overhead - - 201203 531.28
201204 1,041.44
201205 168.84
201206 29.08
Transportation - - 201203 75.00
201204 412.00
201205 12.00
Voucher 196672 ITRI PACIFIC SUPPLY IN 201205 290.31
31005021 Total 5,436.83
62005009 ID AFUDC - - 201201 0.41
201202 0.40
62005009 Total 0.81
62005010 ID AFUDC - - 201201 4.91 1 201202 4.91
62005010 Total 1 9.82
90105225 jID IContractor 14150 jTHOMPSON QUALITY F1201202 1 280.00
Staff-PR-046 Attachment B.xls Page 1 of 11
3002 90105225 ID Contractor 698343-INV KOOTENAI COUNTY SO 201203 180.96
Employee Expenses 1E378414 TIMOTHY J HARDING 201202 36.63
Labor - - 201201 3,923.36
201202 82.52
Overhead - - 201201 4,247.96
201202 316.75
201203 9.32
Transportation - 201201 1,245.00
Voucher - - 201201 -
13-1655338 CENTRAL PRE MIX CON 201201 111.30
70-230293 INTERSTATE CONCRET 201202 300.28
70-230310 INTERSTATE CONCRET 201202 763.68
86048 ZANETTI BROTHERS IN 201202 1,618.50
CDS8851 JOXARCINC 201202 24.84
CDS9059 JOXARCINC 1201202 50.46
90105225 Total 13,191.56
90105257 ID AFUDC - - 201201 7.16
201202 105.73
201203 204.67
201204 232.00
Contractor - - 201205 -
33836 POWER CITY ELECTRIC 201205 463.06
201210 (463.06)
Employee Expenses - - 201204 (0.00)
E529408 TIMOTHY J HARDING 201204 47.75
Labor - - 201202 63.46
201203 64.10
201204 2,487.11
Overhead - - 201202 4,836.59
201203 56.57
201204 2,349.60
201205 38.20
201210 (38.20)
Transportation - - 201204 520.00
Voucher -_____________ -__________________ 201204 (0.00)
1473583 PLATT ELECTRIC 201204 54.99
1659409 RI MILTON ROY COMPANY 201202 24,896.82
1664120 RI MILTON ROY COMPANY 1,245.50
2757659 IVALIN CORPORATION 201204 3,000.00
382123-001 NORTHWEST HOSE & F1201204 29.80
90105257 Total 40,201.85
0705059 ID AFUDC - .. 201201 18.85
201202 18.85
201203 18.85
201204 19.21
201205 22.33
201206 25.09
201207 45.99
201208 66.90
201209 66.90
201210 66.90
Labor - - 201205 411.99
201207 2,699.19
Overhead - - 201204 8.36
201205 458.79
201207 2,493.45
Transportation - - 201204 104.50
1 1 __________ 201207 1,390.50
90705059 Total 7,936.65
3002 Total 72,072.71
3003 90105252 ID AFUDC - - 201201 27.38
201202 33.65
201203 39.91
201204 40.11
201205 40.11
201206 40.11
201207 40.11
201208 121.59
Contractor 12012A22 JAPEX DIRECTIONAL DR 201208 17,400.00
2012-86 JAPEX DIRECTIONAL DR 201208 9,310.00
Labor - - 201201 31.24
Staff_ER.j46 Attachmen.Is Page 2 of 11
3003 90105252 i5 - Labor - - 201203 32.96
201208 12,852.52
Material - - 201202 1,683.87
Overhead - - 201201 28.12
201202 228.37
201203 29.09
201208 16,365.56
- Transportation - - 201208 8,025.75
90105252 Total 66,370.45
3003 Total 66,370.45
3004 93205060 ID AFUDC - - 201201 380.45
201202 380.44
201203 380.44
201204 380.44
201205 380.44
93205060 Total 1,902.21
3004 Total 1,902.21
3005 90101121 ID Contractor 107322 LOY CLARK PIPELINE 201207 488.80
107331 LOY CLARK PIPELINE 201207 244.40
2825 CDA CONCRETE CUTTI1 201205 375.00
Employee Expenses 1E541448 CHRISTINE M ROBINSO 201205 53.09
1E617448 VERNON L NEWBY 201207 52.73
Labor - - 201201 106.65
201202 708.87
201203 2,357.52
201204 914.20
201205 980.23
201206 479.22
201207 511.20
201208 671.18
201209 1,268.28
201210 634.42
Material - - 201203 742.72
201204 631.97
201210 1,432.99
Overhead - - 201201 80.02
201202 770.40
201203 2,446.80
201204 954.18
201205 978.24
201206 479.32
201207 562.08
201208 682.87
201209 1,179.31
201210 935.42
Transportation - - 201201 95.00
201202 747.50
201203 95.00
201204 167.00
201205 178.00
201206 178.40
201207 75.00
201208 169.50
201209 308.00
201210 406.00
Voucher 201201 (397.44) 1 5021056 HOME DEPOT CREDIT 4201202 15.74
90101121 Total 23,759.81
90105261 ID AFUDC - - 201201 11.31
201202 11.31
201203 12.61
201204 13.92
201205 14.31
201206 14.70
201207 14.70
201208 16.04
201209 30.93
1 _____ 1201210 __________________

44.47
Contractor 108216 LOY CLARK PIPELINE 1201210 24,575.00
Employee Expenses -_____________ -__________________ 201208 -
IE675429 I DAVID ROBERT SMITH 1201208 22.76
StaffPR_046 Attachment B.xls Page 3 of 11
3005 90105261 ID Labor - - 201203 124.96
201205 65.92
201208 197.75
201209 1,595.72
Overhead - - 201203 110.28
201205 58.18
201208 175.65
201209 1,728.81
201210 2,334.63
Transportation - - 201208 2565
201209 941.55
Voucher -_____________ -__________________ 201203 -
699610-1 W CITY OF HAUSER 201203 175.00
90105261 Total 32,316.16
90705063 ID AFUOC - - 201201 6.39
201202 6.57
201203 6.57
201204 6.57
201205 6.57
201206 6.57
201207 6.57
201208 90.80
201209 87.51
Contractor -______________ -___________________ 201208 -
101 HYDROSEEDING UNLIM 201208 31120.00
273 C & R TRAFFIC CONTR 201208 5,724.50
Labor - - 201201 31.73
201208 6,410.28
201210 32.21
Material - - 201208 956.25
Overhead - - 201201 28.56
201208 7,373.38
201210 25.36
Transportation - -___________________ 201208 2,940.95
90705063 Total 26,867.34
93301122 ID Contractor 31638 CURRY INCORPORATEI 201210 138.23
Contributions - - 201204 (375.00)
201205 (375.00)
201209 (425.00)
201210 - (249.47
Employee Expenses - -__________________ 201207 -
1E572438 GAYLE YLARSON 201206 18.32
1E612436 GAYLE Y LARSON 201207 9.44
lE667457 RAYMOND A PETERSEI 201208 28.32
1E772433 GAYLE VLARSON 201210 9.44
Labor - - 201204 512.92
201205 . 17.91
201207 1,646.49
201208 5,166.33
201209 935.81
201210 117.00
Overhead - - 201204 531.90
201205 19.94
201 206 2.57
201207 1,511.38
201208 5,367.42
201209 923.72
201210 109.32
Transportation - - 201204 7.50
201206 31.00
201207 495.00
201208 788.70
201210 42.50
93301122 Total 17,006.69
93301230 ID Employee Expenses 1E572438_ GAYLEVLARSON 201206 19.43
_________ -
1
IE772433 GAYLEY LARSON 201210 11.10
93301230Total 30.53
3005 Total - 99,980.53
3008 03802058 I Labor - - 201201 2,019.24
201202
1201203
1,514.43
2,625.01
Staff-PR-046 Attachment B.xls Page 4 of 11
ux 201204
201205
201206
201207
201208
201209
201210
201201
201202
201203
201204
201205
201206
201207
201208
201209
201210
201
2,019.24
2,019.24
1,615.39
1,-918.28
2,625.01
1,918.28
2,019.24
1,817.32
1,362.98
2,327.17
1,787.04
1,781.98
1,425.57
1,692.89
2,308.48
1,635.33
1,590.14
8,022.26
8,022.26
144.86
144.85
289.71
68.83
201201 21.35
201202 22.60
201203 23.85
201204 23.85
201205 23.85
201202 206.33
201208 41.34
201209 82.69
201202 185.70
201208 36.86
201209 71.27
739.69
201203 77.40
2012CM 101.70
201205 122.44
201206 155.11
201207 185.88
201208 198.76
201209 216.20
201210 224.53
201203 249.60
201204 (215.04)
201205 6,481.36
164.73
97.46
622.57
201203 1,425.50
201204 420.90
201205 631.35
201206 841.80
201207 631.35
201208 631.35
201209 1,287.83
201210 2,444.89
Staff-PR-046 Attachment B.xls Page 5 of 11
U
3117 93205055 ID Overhead - - 201202 589A5
201203 1,292.06
201204 602.35
201205 594.89
201206 1,144.20
201207 557.16
201208 676.70
201209 1,148.90
201210 1,984.02
Transportation - - 201210 39.00
Voucher - - 201205 -
201208 0.00
482886 BRANOM INSTRUMENT 201205 523.28
7101552448 ABB INC 201209 62.72
8035755 TRI CITIES VALVE & FIT 201208 963.83
876881 HAHN SUPPLY INC 201210 9.59
962217424 GRAYBAR 201209 66.84
962285681 GRAYBAR 201209 13.71
962697235 GRAYBAR 201210 9.14
962742735 GRAYBAR 201210 185.36
WFS201 9618 INORTHWEST FLUID S01201208 595.44
100288464.001 I STONEWAY ELECTRIC 1201209 43.01
93205055 Total 31,881.18
93305034 ID AFUDC - - 201203 109.63
201204 135.20
201205 160.29
201206 215.44
201207 274.18
201208 295.46
201209 310.57
201210 316.63
Centralized Assets - - 201203 249.60
201204 (215.04)
201205 6,481.36
201206 (6,515.92)
112136 FEENEY WIRELESS 201203 180.87
30112833 FEENEY WIRELESS 201204 271.32
96690-A TRI PACIFIC SUPPLY IN 201204 3,459.20
96769 TRI PACIFIC SUPPLY IN 201204 -
96769-A TRI PACIFIC SUPPLY IN 201205 -
96769-B TRI PACIFIC SUPPLY IN 201205 -
96769-C TRI PACIFIC SUPPLY IN 201205 35.41
97206-A TRI PACIFIC SUPPLY IN 201205 0.00
97206-AAA TRI PACIFIC SUPPLY IN 201206 6,350.99
97229-AAA TRI PACIFIC SUPPLY IN 201206 164.73
Contractor 34379 POWER CITY ELECTRIC 08 817.18
34379A POWER CITY ELECTRIC 201210 (817.18)
34542 POWER CITY ELECTRIC 201209 734.18
Labor - - 201202 698.25
201203 1,425.50
201204 626.05
201205 962.51
201206 2,387.69
201207 1,662.40
201208 1,087.98
201209 631.35
201210 1,005.92
Material - - 201206 999.56
201207 209.20
Overhead - - 201202 662.86
201203 1,292.06
201204 800.27
201205 929.80
201206 2751.44
201207 1,404.40
201208 943.00
201209 543.74
201210 797.08
Transportation - - 201206 431.00
201207 558.00
201210 265.50
StaffPR_046 Attachment B.xls Page 6 of 11
3117 93305034 ID Voucher - - 201205 -
382706-001 NORTHWEST HOSE & F 201205 272.6T-
482885 BRANOM INSTRUMENT 201205 537.24
68528 MUNDYS MACHINE ANE 201207- 22.14
8034987 TRI- CITIES VALVE & FIT 201206 1023.11
960604796 GRAYBAR 201206 153.28
NWFS20I9I90 NORTHWEST FLUID SO 201206 75.46
NWFS2019220 INORTHWEST FLUID S01201206 246.90
S100207067.001 ISTONEWAY ELECTRIC 1201206 53.69
93305034 Total 38,474.12
3117 Total 71,679.80
3246 90105251 ID AFUDC - - 201201 73.71
201202 75.80
201203 85.17
201204 93.95
201205 95.55
201206 96.82
201207 96.82
201208 109.90
201209 130.09
201210 137.19
Employee Expenses 1E468439 DAVID ROBERT SMITH 201204 37.19
IE532421 DAVID ROBERT SMITH 201205 24.42
IE721433 DAVID ROBERT SMITH 201210 31.64
Labor - - 201201 187.44
201202 158.31
201203 1,409.33
201205 197.75
201208 2,191.71
201209 1,208.75
201210 3,722.38
Overhead - - 201201 168.69
201202 142.49
201203 1,243.73
201205 174.51
201208 1927.44
201209 1,030.46
201210 6,572.39
Transportation - - 201204 120121-0
72.80
13.00
__________ Voucher 1489801-00 TYCO VALVE AND CON 201210 16,076.66
90105251 Total 37,586.09
3246 Total 37,586.09
3298 65305001 ID AFUDC - - 201201 49.63
201202 54.01
201203 56.18-
201204 56.18
Contractor 4304 THOMPSON QUALITY FI 201210 1,305.89
Employee Expenses 5142012 APPLEBEES 201206 109.22
Labor - 201202 330.08
201205 2,193.74
201206 509.88
Material - - 201201 580.09
Overhead - - 201201 87.05
201202 353.67
201205 1,448.78
201206 344.07
201210 124.06
Transportation - - 201201 32.00
201205 488.45
Voucher CDT51I7 OXARC INC 201206 40.58
65305001 Iota 8,163.56
65305002 ID AFUDC - - 201201 39.00
201202 61.43
201203 65.61
201204 71.96
201205 74.20
201206 87.25
201207 152.73
201208 205.70
201209 217.30
Staff-PR-046 Attachment B.xls Page 1 of If
3298 65305002 ID AFUDC - - 201210 114.1-8
Labor - - 201203 577.64
201204 254.94
201206 1,699.60
201207 6,898.12
201208 84.98
201209 1,560.75
Material - - 201201 6,141.02
201202 18.00
201204 129.07
Overhead - - 201201 904.11
201202 2,44
201203 613.55
201204 302.44
201206 1,932.24
201207 6,829.48
201208 92.80
201209 1,710.25
201210 1.71
Transportation - - 201203
201204
102.00
20.00
201206 480.00
201207 2,409.00
201209 206.00
201210 18.00
Voucher - - 201207 -
43880 CONMAT 201207 299.86
CDT7174 OXARC INC 201207 17.28
CDT7850 OXARC INC 201207 53.25
65305002 Total ____________________________________ 34,447.89
65305004 ID AFUDC - - 201201
201202
2,321.35
3,259.73
201203 2,891.59
201204 4,312.48
201205 7,616.90
Contractor - - 201204
201205
(0.00)
17,900.91
201206 (17,900.91)
112448 SNELSON COMPANIES 201204 182,523.48
112465 SNELSON COMPANIES 201204 107,491.67
112475 SNELSON COMPANIES 201205 127,754.91
112481 SNELSON COMPANIES 201205 145,126.95
112552 SNELSON COMPANIES 201205 221,206.13
112676 SNELSON COMPANIES 201206 149,793.81
15015923 PRAXAIR SERVICES IN 201206 18,974.96
2012-121 APEX DIRECTIONAL DR 201205 17,075.00
2012-85 APEX DIRECTIONAL DR 201204 52,420.00
205 BAR CIRCLE S WATER 201210 2,583.40
27566 ADVENTURES IN ADVEF 201205 477.63
347526 ACUREN INSPECTION 11201204 15,558.50
3635 KOOTENAI ELECTRIC C 201204 2,399.29
4391 TATE ENGINEERING IN 201202 700.00
INV#9271 ECLIPSE TRAFFIC CON 201206 614.89
Employee Expenses - - 201203 -
201204 -
5142012 APPLEBEES 201206 83.86
1 012 APPLEBEES 201206 233.54
766303-CC CORP CREDIT CARD 201206 105.68
349408 DAVID ROBERT SMITH 201203 216.04
7403 DAVID A PADON 201201 53.28
IE404409 DAVIDAPADON 201202 79.37
8439 DAVID ROBERT SMITH 201204 208.24
2421 DAVID ROBERT SMITH 201205 173.78
IE587447 DAVID ROBERT SMITH 201206 86.03
Labor - - 201201 499.84
201202 923.55
201203 3,693.86
201204 12,959.13
201205 28,080.99
201206 19,265.58
201207 794.83
Staff-PR-046 Attachment B.xls Page 8 of 11
Staff_PR_046 Attachment B.xls Page 9 of 11
3297 90105260 ID Employee Expenses - - 201201 -
201203 -
201204 -
IE592448 Seth Samsell 201206 133.20
1E520424 Seth Samsell 201204 106.90
1E444418 Seth Samsell 201203 189.60
1E347402 Seth Samsell 201201 117.68
634316-CC CORP CREDIT CARD 201203 108.98
1E643447 Seth Samsell 201208 33.30
Labor - - 201201 43,923.62
201202 44,599.82
201203 27,923.58
201204 17,817.15
201205 4,542.41
201206 9,584.23
201207 34.40
201208 (12,852.52)
Material - - 201201 67,075.15
201202 122,666.04
201203 1,756.06
201204 124.63
201205 1,489.60
201206 1,441.42
201209 (8,364.04)
Overhead - - 201201 58,151.41
201202 67,944.87
201203 32,421.89
201204 19,113.55
201205 15,885.72
201206 14,302.16
201207 880.41
201208 (16,365.56)
201209 (1,504.95)
Transportation - - 201201
201202
11,796.75
13,978.00
201203 10,194.50
201204 11,300.95
201205 839.00
201206 2,769.35
201208 (8,025.75)
Vehicle 201000407 VOLVO RENTS 201203 (291.50)
201000316 VOLVO RENTS 201202 3,855.64
693542-INV WINGFOOT COMMERC 01202 (82.21)
201000411 VOLVO RENTS 201203 (691.12)
84869-INV WINGFOOT COMMERCI 201201 82.21
201000960 VOLVO RENTS 201206 4,401.62
201000321 VOLVO RENTS 201202 3,094.16
201000223 VOLVO RENTS 201201 404.81
201000410 VOLVO RENTS 201203 (818.32)
201000669 VOLVO RENTS 201206 1,025.00
R6601 005729 WESTERN STATES EQL 201203 1,334.80
201000319 VOLVO RENTS 201202 3,662.59
R6601 005720 WESTERN STATES EQL 201203 3,185.30
201000292 VOLVO RENTS 201202 418.20
R0605501451 WESTERN STATES EQL 201206 3,443.60
201000320 VOLVO RENTS 201202 4,311.45
R6601 005719 WESTERN STATES EQL 201203 1807.30
Voucher - - 01201 -
201204 -
2970 CONMAT 201205 400.70
2826 CONMAT 201205 296.07
41797 CONMAT 201201 4,536.70
020888 HOME DEPOT CREDIT 1 201202 126.14
41754 F V MARTIN TRUCKING 201203 1,225.00
01000239 VOLVO RENTS 201201 4,125.64
43269 CONMAT 201206 972.56
41943 CONMAT 201203 13,625.65
1-419030 HONEY BUCKET 201203 85.20
470581 CDA METALS 201206 12.78
S3244732.001 FASTENERS INC 201203 8.80
MR6601005662 WESTERN STATES EQI 201203 3,980.30
Staff—PR-046 Attachment B.xls Page 10 0th
3297 90105260 ID Voucher MR6601005531 WESTERN STATES EQL 201202 4,030.30
01006381 WESTERN STATES EQL 201207 1,907.30
201000960 VOLVO RENTS 201206 650.00
201000278 VOLVO RENTS 201202 338.90
201000390 VOLVO RENTS 201203 3,094.16
201000389 VOLVO RENTS 201203 4,311.45
201000238 VOLVO RENTS 201201 3,793.16
41811 T 201201 4,166.62
42894 T 201205 150.08
41842 T 201201 6,841.59
4 954 CDA METALS 201203 47.81
22970 D OF SPOKANE INC 201206 4,037.00
01005595 WESTERN STATES EQL 201203 1,595.30
R6601006177 WESTERN STATES EQL 201206 3,086.90
201000947 VOLVO RENTS 201206 2,299.52
201000669 VOLVO RENTS 201206 576.26
201000391 VOLVO RENTS 201203 3,662.59
-406890 HONEY BUCKET 201202 85.20
201000243 VOLVO RENTS 201201 3,932.59
1897 CONMAT 201202 2,108.37
42757 CONMAT 201206 2,311.64
43517 CONMAT 201207 3,718.71
42756 CONMAT 201205 494.09
42620 CONMAT 201205 173.39
201000241 VOLVO RENTS 201201 3,364.16
60163 CENTRAL SAW WORKS 201206 724.00
42619 CONMAT 201205 199.66
42387 . CONMAT 201205 680.59
43064 CONMAT 201206 174.25
42201 CONMAT 201204 271.91
43460 CONMAT 201206 2,728.07
42462 CONMAT 201205 181.55
215258/2 ACE ON 4TH 201205 19.02
MR6601005467 WESTERN STATES EQL 201201 1,645.30
MR6601 0061 78 WESTERN STATES EQL 201206 2,132.90
MR6601 006179 WESTERN STATES EQL 201206 2,416.80
201000232 VOLVO RENTS 201201 334.96
46806839-00 [SO] STOCK BUILDING SUPP 201201 62.75
41922 CONMAT 201202 2,755.94
41909 CONMAT 201202 2,412.05
22913 CAD OF SPOKANE INC 201205 355.75
201000242 VOLVO RENTS 201201 4,581.45
41874 CONMAT 201202 9,051.90
42621 CONMAT 201205 269.37
43189 CONMAT 201206 223.41
41908 CONMAT 201202 3,930.16
470295 CDA METALS 201206 173.26
MR6601 005623 WESTERN STATES EQL 201203 4,245.30
90105260 Total 865,128.52
3297 Total 865,128.52
Grand Total 2,654,992.69
Staff—PR-046 Attachment B.xls Page 11 of 11
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO
CASE NO: AVU-E-12-08 / AVU-G-12-07
REQUESTER: IPUC
TYPE: Production Request
REQUEST NO.: Staff-048
DATE PREPARED: 11/27/2012
WITNESS: Tara Knox
RESPONDER: Tara Knox
DEPARTMENT: State & Federal Regulation
TELEPHONE: [phone]
REQUEST:
Please explain why "Intangible Plant Costs" (Tara Knox Di, line 1, Schedule 1, p. 3) are included
in the $585,254 Production and Transmission Cost used in the calculation of the LCAR. Please
provide a detailed description of each cost within the "Intangible Plant Cost" category that was
included and a justification for each.
RESPONSE:
As stated in the Knox testimony on page 11, beginning at line 19 the first step in determining the
LCAR is to compute "the proposed revenue requirement on the production and transmission costs
contained within Ms. Andrews' Idaho electric pro forma total results of operations." Certain
material production or transmission related plant in service items are recorded in the Intangible
Plant FERC Accounts 302 and 303.
There are two primary categories of production or transmission related intangible plant assets:
namely Hydro Relicensing and Transmission Agreements.
Intangible Hydro Relicensing plant costs consist of the franchises and consents recorded in FERC
Account 302 as well as the Coeur D'Alene Settlement regulatory assets recorded in FERC
Account 182 that are presented in the Results of Operations Electric Utility Plant report in the
Intangible Plant category. These items were included in the LCAR calculation because the hydro
relicensing investment was a material cost required for the Company to continue hydrological
production at the various dams.
Intangible Transmission Agreements consist of Forest Service Use Permits recorded in FERC
Account 302 and the cost of a series of agreements (most involving other party communication
equipment) associated with various transmission substations recorded in FERC Account 303 .000.
These items were included in the LCAR calculation because the investments were necessary to
utilize the transmission system.
The only items recorded in either FERC Account 302 or 303.000 that are not related to either
production or transmission include a third-party fiber agreement which is a general plant related
common allocated north asset and distribution plant related franchises or agreements directly
assigned to the Washington jurisdiction. These costs were not included in the LCAR calculation
as they are not production or transmission related items.
The accumulated amortization associated with the production or transmission related Intangible
Plant assets are discussed in the Company's response to Staff Production Request No. 49.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/27/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Tara Knox
REQUESTER: IPUC RESPONDER: Tara Knox
TYPE: Production Request DEPARTMENT: State & Federal Regulation
REQUEST NO.: Staff-049 TELEPHONE: [phone]
REQUEST:
Please describe the Production/Transmission-Franchise/Misc. Intangible Costs (LCAR-10 in Tara
Knox LCAR Workpapers) included in the Accumulated Depreciation and Amortization used to
calculate the LCAR.
RESPONSE:
The Company response to Staff Production Request No. 48 discussed the production or
transmission related intangible plant assets included in the LCAR production and transmission
costs. The referenced work paper line item contains the accumulated amortization associated with
the Hydro Relicensing and Transmission Agreement intangible assets included in the LCAR
calculation.
Staff_PR_049 Attachment A is a copy of the E-AAMT Results of Operations report previously
provided as Andrews Electric work paper page 1.00-40. This report shows the derivation of the
Production/Transmission-Franchise/Misc. Intangibles accumulated amortization referenced
above. From this report you can see that the accumulated amortization is associated with FERC
Account 302000 and 303000 excluding any distribution or general plant related intangible assets
in those accounts. There is no separate accumulated amortization with the FERC Account 182
balances as they were shown on the plant report on a net basis.
Inclusion of the Production/Transmission-Franchise/Misc. Intangibles accumulated amortization
in the LCAR calculation provides matching with the inclusion of the associated Intangible Plant
balances discussed in response to Staff Production Request No, 48. The related amortization
expense was also included in the LCAR calculation as it is part of the Production and Transmission
expense total of $226,548 on line 12 of the Andrews' Exhibit No. 10, Schedule 1, Page 5.
Electric Gus-Notch Gas-South
72.383% 19.477% L140%
0.000% 19.575% 29425%
79.075% 20.925% 0000%
Jurisdiction - Washington
I ProductlonfTrnnomlusion Ratio 65,240%
4 Jurisdictional 4-Factor Ratio 61.029%
CI,
0)
-D
co
Ref/Basis
Productlon/Trssismiialan
I Franchises (302900) ED-AN 3 I Misc Intangible Pit (303000) ED-AN
Total Productlan/Traasnstsalon
> Distribution
l'ranchlsea (302000) ED-WA
Misc intangible Pit (303000) ED-WA
Total Distribution
General Plant - 303000
9,1 CD-AN
GO-ID
GD-WA
GD-OR
Total General Plant -303000
Miscellaneous IT Intangible Plant -3031XX
1,4 CD-AA
4 ED-AN
ED-WA
8 OD-AA
GD-AN
OD-OR
Taint Miscellaneous IT Intangible Planl.30313C
Gas Underground Storage
GD-AN
Total Gas Underground Storage
General Plant - 390100, 396200
7.4 CD-AA
9 CD-ID
9 CD-WA
4 ED-AN
ED-WA
OD-WA
GD-OR
Total General Plant -390200, 396200
Total Accumulated Amortization
AllocatIon Ratios:
Service -
1 lice/Gus North/Oregon 4-Factor
8 Gas NotiWOregon 4-Factor
9 11cc/Gsa North 4-Factor
AVISTA UTILITIES
Aastgnod or Assigned or Assigned or
System Allocated Allocated Allocated aaa0000a ELECTRIC aaa.*... aa000a.a WASHINGTON .aa.a.a. IDAHO
T. .1 flfr.,• Ssh,,,.,.a r.I flt..,..• sIt....5.l ra.l
5,092,806 5,092,806 5,092,506 5,092,806 3.322.547 3,322,547 1,170,259 1,770,2$9
562,314 562,374 562,374 562.34 366,893 366,893 191.481 195,481
5,655,180 5,655,180 5,655,1811 5,655,180 3,689,440 3,689,440 1,965,740 1,965,740
36,988 36,988 36,988 36,908 36.908 36,960
18,103 18,103 101103 18,103 10.103 18,103
51,091 55,091 55,091 55,091 55,091 55,091
33.556 26,534 7,022 26,534 26,534 17,311 17,311 9,223 9,223
37,107 37,107
65,609 65,609
37,032 31,032 ___
173,304 26,534 109,738 37,032 26,534 26,934 17,311 17,511 9,223 9,223
11,183,120 13,161,488 3,541,526 1.480,106 13,161,488 13.161.408 8,822,014 8,022,014 4,39,474 4,339,474
644,630 644,630 644.630 644,630 432,089 432,089 212,541 212,541
58,254 50,254 58,254 50,254 50,254 58,254
361,267 254,964 106,303
11,527 11,521
37,901 37,901 ______
19,296,699 13,864,372 3,808,017 1,624,310 58,254 13,806,118 13,864,372 58,254 9,254,103 9,312,357 4,552,015 4,552,015
239163 239.063
239,063 239,063
118,035 85,437 22,990 9,608 85,437 85,431 57,268 57,268 20,169 20,169
4,537 3,580 949 3,588 3,508 3,588 3,588
8,332 6,539 1,743 6,589 6.539 6,589 6,509
4,118 4,718 4,718 4,710 3,162 3.162 1,556 1,556
110,678 110,678 110,678 110,670 110,670 110,678
1,863 1,863
42,431 42,437
290,600 211,010 27,545 52,045 120,855 90,155 211,016 117,101 60,430 177,697 3,588 29,725 33,313
25,709,937 19,812,187 4,184,363 1,713,307 234,200 19,577,987 19,512,187 230,612 13,021,284 13,251.896 - 3.588 6,556,703 6,560,291
ldulio
34.760%
32971%
RESULTS OF OPERATIONS J Report ID:
E-AAMT-12A ELECTRIC ACCUMULATED AMORTIZATION
For Twelve Months Ended December31, 2011
Average Of Monthly Averages Basis
-D 0) (C (0
9'
Facet all Print Date-Than 02'0I-2012 244 F!
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/21/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Clint Kalich
REQUESTER: IPUC RESPONDER: James Gall
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-50 TELEPHONE: [phone]
REQUEST:
Please identify the cause(s) of Kettle Falls' forced outages in 2007-2011. For each year, please
identify the number of hours associated with each cause. Please also state whether Avista expects
each cause to be a recurring cause or a one-time only occurrence.
RESPONSE:
Please see Avista's response 050C, which contains TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code.
Please see Staff PR 050C Confidential Attachment A for the outage information requested.
It regards to outages being recurring or only one-time, the plant staffs goal is to
minimize/eliminate outages. After each outage, the plant staff conduct root cause reviews and
develops corrective actions. However, because these generating projects have many moving parts
and operate at high temperatures and high pressure, similar outages are expected to recur.
JURISDICTION
CASE NO:
REQUESTER:
TYPE:
REQUEST NO.:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
IDAHO DATE PREPARED: 11/21/2012
AVU-E-12-08 / AVTJ-G-12-07 WITNESS: Clint Kalich
IPUC RESPONDER: James Gall
Production Request DEPARTMENT: Energy Resources
Staff-051 TELEPHONE: [phone]
REQUEST:
Please explain whether Avista used the correct formula to calculate the forced outage % for Kettle
Falls (cells C29:026 in the "Forced Outage" worksheet in "Kettle Falls FO Rate _Final.xls). If
Avista believes it used the correct formula, please explain why the formula is correct.
RESPONSE:
Please see Avista's response 051C, which contains TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAPA 3 1.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code.
The formula in the cells referred to in this PR does include an error. See Staff_PR_OS 1 C
Confidential Attachment A for a revised workpaper. This change would increase the forced
outage rate at Kettle Falls to 5.38% from 3.78%.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/21/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Clint Kalich
REQUESTER: IPUC RESPONDER: James Gall
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-052 TELEPHONE: [phone]
REQUEST:
Please explain why Avista used a six-year average for maintenance for the Coistrip units
("Coistrip Maintenance_Final.xls) while using a five-year average for all other units.
RESPONSE:
Coistrip units 3 & 4 are on a three-year maintenance cycle, a six-year average was used to reflect
two full maintenance cycles. If a five year average were used, the annual average would not be
representative of the actual maintenance that occurs over time.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/21/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Clint Kalich
REQUESTER: IPUC RESPONDER: James Gall
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-053 TELEPHONE: [phone]
REQUEST:
Please provide work papers supporting the calculation of the forced outage rate for Boulder Park.
If using historical figures, please identify the cause(s) of Boulder Park's forced outages during the
pertinent time period. For each year, please identify the number of hours associated with each
cause. Please also state whether Avista expects each cause to be a recurring cause or a one-time
only occurrence.
RESPONSE:
Please see Avista's response 053C, which contains TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code.
Up until 2010 Avista did not track outage information at Boulder Park. Staff_PR_053C
Confidential Attachment A includes the available information regarding outages provided by the
plant. This report includes the year end statistics for 2010 and 2011. The hours represented are the
hours the units were unavailable due to a forced outage, not necessarily the forced outage hours
when the unit was needed to run.
To estimate the level of forced outages when the unit was needed to run, a look at actual generation
was done, see Staff_PR_053C Confidential Attachment B. This file contains hourly generation for
Boulder Park between 1/1/2007 and 12/31/2011. The Boulder Park Gen History tab, includes the
annual generation averages, included in this is the average generation of the plant when running'
and its implied outage rate. The 2007-2011 average is 15.6%. The implied dc-rate of the plant is
from either forced outage or maintenance, but will not include any outages due to transmission.
Since Avista does not include maintenance outages for any of its peaker plants, including Boulder
Park, in the Aurora modeling, this resulting rate would represent an appropriate dc-rate for the
plant.
These generating projects have many moving parts and operate at high temperatures and high
pressure, similar outages are expected to recur.
1 The hours considered running were filtered to only include hours that generation was greater than 10 MW. This filter
was used to exclude hours the generation was either turned on/off within the hour.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/21/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Clint Kalich
REQUESTER: IPUC RESPONDER: James Gall
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-054 TELEPHONE: [phone]
REQUEST:
Please explain the forced outage rate used for: Coyote Springs 2, Kettle Falls CT, Northeast A &
B, Lancaster, Rathdrum 1 and 2.
RESPONSE:
Please see Avista's response 054C, which contains TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAPA 3 1.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code.
Avista's natural gas fired generators use an engineering estimate for forced outages. Avista does
not use historical outage rates for these plants due to several factors, such as; low run hours, forced
outage events are not representative of future outages (i.e. prolonged transformer failure at CS2),
or the plant has a guarantee (i.e. Lancaster). The forced outage rates used for Avista's operations
planning, position reporting, integrated resource planning, as well as previous Idaho State rate
proceedings and this proceeding are as follows:
Kettle Falls CT: 5%
Northeast A & B: 5%
Rathdrum 1 &2: 5%
Coyote Springs 2: 5%a
Lancaster: 3%b
a The Coyote Springs 2 historical outage information is attached as Staff _PR_054C Confidential
Attachment A, this file shows a 5 year (2007-2011) historical forced outage factor of 4.9%.
b In the Lancaster tolling agreement, if the forced outage rate exceeds 3% the seller will be
responsible for replacement power or monetary damages. Further, Avista has only received the
output from the plant since 2010.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/21/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Clint Kalich
REQUESTER: IPUC RESPONDER: James Gall
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-055 TELEPHONE: [phone]
REQUEST:
Please identify the cause(s) of Coistrip 3 and Colstrip 4's forced outages in 2007-2011. For each
year, please identify the number of hours associated with each cause. Please also state whether
Avista expects each cause to be a recurring cause or a one-time only occurrence.
RESPONSE:
Please see Avista's response 055C, which contains TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code.
The information requested is contained in Staff _PR_055C Confidential Attachment A. The files
include the plant's year-end report for planned & unplanned outages between 2007 and 2011.
Look for the "YTD Outages" tab in each excel sheet for the detail information regarding the
outage.
In regards to outages being recurring or only one-time, the plant staff's goal is to
minimize/eliminate outages. After each outage, the plant staff conduct root cause reviews and
develops corrective actions. However, because these generating projects have many moving parts
and operate at high temperatures and high pressure, similar outages are expected to recur.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/21/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Clint Kalich
REQUESTER: IPUC RESPONDER: James Gall
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-056 TELEPHONE: [phone]
REQUEST:
In calculating the capacity factor for wind projects in the Excel workbook "Wind.xls," it appears
that Avista is using a nameplate capacity of 108 MW for the Kittitas Valley Wind project. Please
verify that this is true. Please provide the source for this capacity number and explain why it
differs from the nameplate capacity listed for this project in the following BPA publication:
http://trarismission.bpa.gov/Business/Operations/Wind/W1ND_InstalledCapacity_CHART.Ddf
RESPONSE:
The Kittitas Valley project is modeled with a capacity rating of 100.80 MW or 100800 kW in the
AURORA database. The data source for this estimate is SNL Financial, it claims the plant has 48
Suzlon S88 turbines.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 11/20/2012
CASE NO: AVU-E-12-08 / AVU-G-12-07 WITNESS: Elizabeth Andrews
REQUESTER: IPUC RESPONDER: Jennifer Smith
TYPE: Production Request DEPARTMENT: State & Federal Reg.
REQUEST NO.: Staff-069 TELEPHONE: [phone]
REQUEST:
Please provide the square footage amount and proportion of floor space associated with
non-regulated business units that are being supported by the HVAC Renovation Project.
RESPONSE:
There is approximately 280 square feet of floor space allocated to support subsidiary activities,
which is identified using the relationship of labor hours charged to subsidiary activities by
employee compared to total labor hours by employee. These percentages are applied to the
employees' office space (expressed in square feet). All of this square footage would be supported
by the HVAC renovation project.