20130104Exhibits Admitted at Hearing.pdf

Thermal Resource Data
Used in 2011IRP Aurora Analysis
Nameplate Ownership Minimum Min.Load Full Load
Rating Share Load IPeo Share Heat Rate
Unit (MW)(%)(MW)(MW)(Btu/kWh)
Bridger 1 540 33%216 71 10,325
Bridger 2 540 33%216 72 10,325
Bridger 3 540 33%216 72 10,325
Bridger 4 508.5 33%203.4 68 10,325
Boardman 556 10%222.4 22 9,840
Valmy 1 254 50%101.6 51 9,721
Valmy 2 267 50%106.8 53 9,721
Danskin 1 170 100%0 0 9,766
Danskin 2 49 100%0 0 11,358
Danskin 3 49 100%0 0 11,358
Bennett Mtn 170 100%0 0 10,100
Langley Gulch **306.8 100%204 204 6,745
**-minimum load for Langley Gulch in Aurora varies by month based on ambient
temperature -annual average of the monthly values is used for this example.
Exhibit NO.7
Case No.GNR-E-11-03
K.Bokenkamp,fPC
REPLACEMENT Page 2 of6
CONFIDENTIAL
THIS PAGE CONFIDENTIAL
Exhibit No.7
Case No.GNR-E-11-03
K.Bokenkamp,fPC
REPLACEMENT Page 5 of 6
CONFIDENTIAL
THIS PAGE CONFIDENTIAL
Exhibit No.7
Case No.GNR-E-11-03
K.Bokenkamp,IPC
REPLACEMENT Page 6 of 6
$140.00
$120.00
A Comparison of 20-Yr Levelized QF Contract Pricing
IPCo's IRP Methodology (12/15/2011)vs.IPCo's Proposed HIC Methodology
Online date for QF is January 2013
Wind and .s.ala!.Avoided Cost of Energy includes a $6.50 integration•Avoided Cost of Capacity •Avoided Cost of Energy deduetion~is the surrogate avoided resource for IRP Methodology and
SCCT is the surrogate avoided resource for the proposed HIC Methodology
Wind 22 MW
$43.08
Fixed PV Solar 20 MW
$"7s:60.--------
Canal Drop 20 MW
$80.31
$44.78
Baseload 20 MW
$0.00
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",-c">">o,eo~",-c">">eO~",-c">">,eo~",-C,,>">o,eo~,,>,:>.,,>,:>.0',,>,:>.~<o<P ,,>,:>.
Qee..·~<o<i 'Vee.·'1<0"1 \)ee..·Qee..·~<o<i
$20.00
$40.00
$65.00
$80.00 I I
$60.00
$100.00
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Comparison of Proposed SAR Methodology Rates
Levelized Rates for 20-yr Contract Term,January 2013 Online Date
Using June 2012 EIA natural gas forecast
I Baseload I I Canal Drop I I Fixed PV Solar I I Wind I
$83.57 $84.75I---I-
$60.19 $65.85 $64.28$60.64
$51.32 $45.95I---I--$41.36 I-$35.97 -l-f--
$32.09 $33.93
$120
$100
~$80S
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Deductions to account for integration and for transmission costs and losses are included for all utilities.~J+l \f>1'"/3fJn
Office ofthe Secretary
Service Date
September I,2009
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATIER OF IDAHO POWER )
COMPANY'S APPLICATION FOR A )CASE NO.IPC-E-09-03
CERTIFICATE OF PUBLIC CONVENIENCE )
AND NECESSITY FOR THE LANGLEY )
GULCH POWER PLANT )ORDER NO.30892
On March 6,2009,Idaho Power Company (Idaho Power;Company)filed an
Application with the Idaho Public Utilities Corrunission (Commission;IPUC)for a Certificate of
Public Convenience and Necessity (Certificate;CPCN)authorizing construction of the Langley
Gulch Power Plant (project)and inclusion of the Project in the Company's rate base.Idaho
Code §61-526,-528;RP 112.An electrical corporation is prohibited from beginning the
construction of a generating plant without haviug first obtained from the Commission a
certificate that the present or future public convenience and necessity require or will require such
construction.Idaho Code §61-526.The Company further requests that the Commission include
in its Order issuing a Certificate cost recovery and ratemaking assmances.Idaho Code §61-541.
On March 19,2009,the Commission issued a Notice of Application,Intervention
Deadline and Prehearing Conference.Intervention was granted to the Industrial Customers of
Idaho Power (ICIP);Invenergy Thermal Development LLC;Idaho Irrigation Pumpers
Association,Inc.(III.'A);Snake River Alliance (SRA);and Idaho Conservation League (ICL).
Following the April 15,2009 prehearing conference Invenergy Thermal Development LLC
withdrew and the following additional parties were admitted as intervenors:N0l1hwest &
IntermOlmtain Power Producers Coalition (NIPPC)and Community Action Partnership
Association of Idaho (CAPAI).An evidentiary and tedmical hearing was held in Boise on July
14-16,2009.A public hearing was held the evening of July 14.The deadline for filing written
comments was July 24.The deadline for post-hearing filings by the parties was July 31,2009.
The Conmlission in this Order grants a Certificate of 'Convenience and Necessity
authorizing the construction of Langley Gulch and provides related cost recovery and ratemaking
assurances.Idaho Code §61-541.We deny Intervenors'Motion for Stay and grant intervenor
funding awards to the Community Action Partnership Association of Idaho,the Idaho
Conservation League and the Idaho Irrigation Pumpers Association,Inc.Idaho Code §61-617A.
ORDER NO.30892 I
Exhibit SOq Page 1 of 2
Sim at.Exergy.Clearwater
On Cross aminalio'IL-__~~
either cash flow or imputed debt that would impact the Company's
financial rates.Tr.p.831.
•It is incongruous that the Company would stress the need to issue its
CPCN under non-traditional ratemaking procedures in order to finance the
project and yet not to have considered financial implications in the scoring
and selection process.Tr.p.831.
•Rejects the Company's contention that imputed debt is a measure of
financial risk shifted to a utility when it enters into a PPA or TA.Citing
Standards &Poor's Opinion that a PPA is not the same thing as actual
debt;debt-like-characteristics is not the same as debt.All debt is not
created equal.Tr.pp.833-836.
NIPPC offers as an example of competitive bidding guidelines those adopted by the
Oregon Commission.Exh.702.
Commissioll Fi/ldings
Once it determined a 2012 need for a baseload resource,Idaho Power retained a third­
party consultant and issued a Request for Proposals.The RFP process was criticized by nearly-------'----------
all patties to the case,some more stridently than others.While we find that the process could,
have been more transpat'ent,that better guidelines could have been established,that evaluation (
criteria could have better explained,that the third-party consultant could have brought more
value to the process by performing all the tasks identified in the RFP,and that the total universe
of potential bidders was perhaps not realized,we find that the RFP process was nevertheless
adequate.Based on the evidence presented,we cannot conclude that a lower price and better,
project would have resulted if the RFP was better designed and implemented.What is instead
app~rent is that the RFP participants were sophisticated bidders and that the short list of projects
were all competitive.
The Company is not foreclosed from including a self-build option in an RFP.Its
obligation to provide electric service and its decision to bid a self-build alternative is a rational
basis for lining up an equipment supplier in advance of its application to the Commission.Idaho
Power in this RFP was not the only bidder to bring turbines to the table.The Company should,
however,be concerned about perception that the third-party consultant was directed by the
Company and there was a bias in the selection process.The actual and perceived flaws in the
RFP process,we find,while not fatal to the Company's resource selection,clearly demonstrate a
need for a separate proceeding to consider RFP competitive bidding rules and guidelines.We
ORDER NO.30892 30 Exhibit __Page 2 of 2
Simplot,Exergy,Cleal\\later
On Cross Examination
Chapter 2:Loads &Resources
determined by a formula that ranges from $16 to $29 per megawatt-hour in 1987-year
constant dollars.
The second provision provides SPA approximately 32 aMW of return energy at a cost
equal to the actual operating cost of the Company's highest-cost resource.A further
discussion of this obligation,and how Avista plans to account for it,is under the
Planning Margin heading of this chapter.
Table 2.5:Large Contractual Rights and Obligations
Winter Summer 2012 Est.
Capacity Capacity Annual
Contract Type End Date (MW)(MW)Energy (aMW)
Canadian Entitlement Sale nla 8 8 5
Clearwater PURPA 06/2013 75 75 52
Douqlas Settlement Purchase 09/2018 2 3 3
Lancaster Purchase 10/2026 290 249 222
Nichols Pumpinq Sale nla 7 7 7
PGE Capacity Exchange Exchange 12/2016 150 150 0
Small Power PURPA varies 2 1 2
Stateline Purchase 03/2014 0 0 9
Stimson Lumber Purchase 09/2011 4 5 4
Upriver (net load)Purchase 12/2011 8 -1 6
WNP-3 Purchase 06/2019 82 0 42
Total 628 497 352
Reserve Margins
Planning reserves accommodate situations when loads exceed and/or resource outputs
are below expectations due to adverse weather,forced outages,poor water conditions,
or other contingencies.There are disagreements within the industry on reserve margin
levels utilities should carry.Many disagreements stem from system differences,such as
resource mix,system size,and transmission interconnections
Reserve margins,on average,increase customer rates when compared to resource
portfolios without reserves,because of the cost of carrying additional generating
capacity that is rarely used.Reserve resources have the physical capability to generate
electricity,but high operating costs limit their economic dispatch and revenues to offset
purchase costs.
Avista Planning Margin
Avista retains two planning margin targets-capacity and energy.Capacity planning is a
traditional metric ensuring that utilities can meet peak loads at times of system strain,
and cover variability inherent in their generation resources with unpredictable fuel
supplies,such as wind and hydro,and varying loads.
Avista Corp 2011 Eiectric IRP EXhibil5!Q Page 1 of 10 2·20
Simplot,Exergy,Clearwater
On Cross Examination
Chapter 2:Loads &Resources
Capacity Planning
Avista plans for peak load events using the regional standard of an 18-hour peak event
covering six hours each day for three consecutive days.Further,the IRP uses a
planning margin level approximating the Northwest Power and Conservation Council's
targets of 23 percent in the winter and 24 percent in the summer.Avista first estimates
operating reserve requirements for on-system generation,load regulation,and wind
integration.It then adds a planning margin of 15 percent to summer peak load and 14
percent to winter peak load.Adjustments to the net position include market purchases
when surplus capacity exists in the Northwest,as represented by the green bars.?The
planning margin equals 233 MW in 2012.Additional detail is in Appendix A.Figure 2.14
illustrates the winter peak position and Figure 2.15 shows the summer peak position.
Figure 2.14:Winter 18·Hour Capacity Load and Resources
3,800
3,300
2,800
-Firm Contracts
Peaking Thermals
-Hydro
-Load +Reserves +Planning Margin
Avista Share of Excess NW Capacity
-Baseload Thermals
-Load Forecast
1,300
1,800
!Il 2,300
~~I:llQ)
E
800
300
·200
N M '<t '"CS>....00 '"0 ~N M '<t '"CS>....00 '"0 ~~~~~~~~~N N N N N N N N N N M M00000000000C>0 0 0 0 0 0 0 0N N N N N N N N N N N N N N N N N N N N
7 Avista relied on work by the Northwest Power and Conservation Council in its Resource Adequacy
Forum exercises to determine the level of surplus summer energy and capacity.Reliance is limited to
Avista's prorated share of regional load.See
hltp:/Iwww.nwcouncil.org/energy/resource/Adeguacy%20Assessment%2070908.xls.NPCC surplus
estimates phase out over 10 years starting in 2013 by reducing its surplus by 10 percent,the 2014
surplus by 20 percent, the 2015 surplus by 30 percent,and so on.The phase out reflects Avista's opinion
that outer-year surpluses might not be available for various reasons,including unanticipated load growth,
the retirement of existing resources,or transmission interconnections enabling the export of more
generation outside of the Northwest.
Avista Corp 2011 Electric IRP Exhibit __Page 2 of 10 2-21
Simplot,Exergy,Cleal\'1aler
On Cross Examination
Chapter 2:Loads &Resources
Figure 2.15:Summer 18·Hour Capacity Load and Resources
3,800
-Firm Contracts
3,300 Peaking Thermals
-Hydro
2,800 --Load +Reserves +Planning Margin
Avista Share of Excess NW Capacity
-Baseload Thermals
-Load Forecast
300
800
·200
1,800
1,300
I/)2,300
~C1l
til
Q)
E
Energy Planning
For energy planning,resources must be adequate to meet customer requirements even
where loads are high for extended periods or an outage limits the output of a resource.
Extreme weather conditions can change monthly energy obligations by up to 30
percent.Where generation capability is not adequate to meet these variations,
customers and the utility must rely on the volatile short-term electricity market.In
addition to load variability,a planning margin accounts for variations in hydroelectricity
generation.
As with capacity planning,there are differences in regional opinion on a proper method
for establishing resource planning margins.Many utilities in the Northwest base their
planning on the amount of energy available during the critical water period of 1936/37.8
The critical water year of 1936/37 is low on an annual basis,but it is not necessarily low
in every month.The IRP could target resource development to reach a 99 percent
confidence level on being able to deliver energy to its customers,and it would
significantly decrease the frequency of its market purchases.However,this strategy
requires investments in approximately 200 MW of generation in additional to the
margins included in Expected Case of the IRP.Such expenditure to support this high
level of reliability would put upward pressure on retail rates for a modest benefit.Avista
instead targets a 90 percent monthly energy planning margin confidence interval based
on load hydroelectricity variability.In other words,there is a 10 percent chance of
needing to purchase energy from the market in any given month over the IRP
8 The critical water year represents the lowest historical generation level in the streamflow record.
Avista Corp 2011 Electric IRP Exhibit __Page 3 of 10 2-22
Simplot,Exergy,Clearwater
On Cross Examinalion
Chapter 2:Loads &Resources
timeframe,but on average,the utility would have the ability to meet all of its energy
requirements and be selling electricity into the marketplace.
Beyond load and hydroelectricity variability,Avista's WNP-3 contract with BPA contains
supply risk.The contract includes a return energy provision in favor of BPA that can
equal 32 aMW annually.Under adverse market conditions BPA almost certainly would
exercise its rights.BPA last exercised its contract rights in 2001.To account for this
contract risk,the energy planning margin is increased by 32 aMW until the contract
expires in 2019.With the addition of WNP-3,load and hydroelectricity variability,the
total energy planning margin equals 228 aMW in 2012.Additional detail is contained in
Appendix A.See Figure 2.16 for the summary of the annual average energy load and
resource net position.
Figure 2.16:Annual Average Energy Load and Resources
3,800
-Net Market Transactions
3,300 -Baseload Thermals
-Load Forecast
2,800
~III~2,300
IIIen
Q)
E 1,800
Q)en
ll!1,300
Q)>III
800
300
·200
Peaking Thermals
-~ydro
-Load +Contingency
Loss of Load Analysis
In the Northwest,loss-of-Ioad analysis tools help address the issue of how much
planning margin is required.Typical results of these models are Loss of Load
Probability (LOLP),Loss of Load Hours (LOLH),and Loss of Load Expectation (LOLE)
measures.A reliable system has typically been defined as having no more than one
interruption event in twenty years,or 5 percent.These analyses can be helpful,but
usually have an inherent flaw due to the need to assume how much out-of-area
generation is available for the study.Avista developed a loss of load analysis model to
simulate reliability events due to poor hydro,forced outages,and extreme weather
conditions on its system,finding that forced outages are the main driver of reliability
events.Avista has robust transmission rights to the wholesale energy markets,but the
Avista Corp 2011 Electric IRP EXhibil __Page 4 of 10 2-23
Simplol,Exergy,Clearwater
On Cross Examination
Chapter 2:Loads &Resources
amount of generation actually available for purchase from third parties is difficult to
estimate in a model.To address this concern,a sophisticated regional model must
estimate required regional planning margins.Avista will continue to monitor and
contribute to such regional model development,with the intent of using the regional
model when it becomes available.
Washington State Renewable Portfolio Standard
In the November 2006 general election,Washington State voters approved Citizens
Initiative 937,now known as the Washington state Energy Independence Act.The
initiative requires utilities with more than 25,000 customers to source 3 percent of their
energy from qualified non-hydroelectric renewables by 2012,9 percent by 2016,and 15
percent by 2020.Utilities also must acquire all cost effective conservation and energy
efficiency measures.Even though Avista does not require any new generation
resources to meet forecasted energy loads through 2019,this new law requires the
Company to acquire additional qualified renewable generation,or renewable energy
certificates (RECs),to meet the initiative's renewable goals.Table 2.6 at the end of this
chapter details the forecast amount of RECs required to meet Washington state law,
and the amount of qualifying resources has already in the generation portfolio.The
sales forecast uses the current load forecast and does not include additional
conservation as detailed in the Preferred Resource Strategy chapter.It also illustrates
how the Company will maintain a REC reserve margin of approximately 10 aMW in
2016.
Resource Requirements
The resource requirements discussed in this section do not include additional energy
efficiency acquisitions beyond what is in the load forecast.The Preferred Resource
Strategy chapter discusses conservation beyond the assumptions contained in the load
forecast.The following tables present loads and resources to illustrate future resource
requirements.
During winter peak periods (Table 2.7),surplus capacity exists through 2019 after taking
into account market purchases.9 Without these purchases,a capacity deficit would exist
in 2012.Avista believes that the present market can meet these minor winter capacity
shortfalls and therefore will optimize its portfolio to postpone new resource investments
for winter capacity until 2020.
The summer peak projection (Table 2.8)has lower loads than in winter,but resource
capabilities are also lower due to lower hydroelectricity output and reduced capacity at
natural gas-fired resources due to decreased performance during high-temperature
events.The IRP shows persistent summer deficits throughout the 20-year timeframe,
but regional surpluses are adequate to fill in these gaps.Many near-term deficits are
from decreased hydroelectricity capacity during periods of planned maintenance and
9 Avista relied on work by the Northwest Power and Conservation Council in its Resource Adequacy
Forum exercises to determine the level of surplus summer energy and capacity.Reliance is limited to the
Company's prorate share of regional load.
Avista Corp 2011 Electric IRP Exhibit~_Page 5 of 10 2-24
Simplot,Exergy,Clearwater
On Cross Examination
Chapter 2:Loads &Resources
upgrades.Taking into account regional surpluses,the load and resource balance is 54
MW short only in 2016.After 2016,when the Portland General Electricity capacity sale
contract expires,the next capacity need is in 2019 at 98 MW.
The traditional measure of resource need in the region is the annual average energy
position.The energy position is in Table 2.9.There is enough energy on an annual
average basis to meet customer requirements until 2020,when the utility is short 49
aMW.Avista will require 112 aMW of new energy by 2025,and 475 aMW in 2031.
Avista Corp 2011 Electric IRP Exhibit __Page 6 of 10 2-25
Simplot,Exergy,Clearwater
On Cross Examination
~en·
iii
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~Upgrade 2010~11~~~142015201620172018201920202021~~~~~20n20282~92030~31YearEnergy
WAState Retail Sales Forecast 628 630 636 646 654 663 671 678 687 693 701 708 714 721 730 738 746 754 763 n2 782 793
RPS%0%3%3% 3%3%9%9% 9%9%15%15%15%15%15% 15%15%15% 15% 15%15%15%-l
REQUIRED RENEWABLE ENERGY •19 '19 '19 •20 •59 '60'61 '61 •104' 105'106 f 107'108 ;109 ;110 )111 •112'114 '115 •117 III0-
Renewable Resources CD
Purchased RECs 0 6 6 6 6 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 N
Long Lake 3 1999 2.2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 '"We Falls 4 2001 0.6 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 ~N Cabinet 2 2004 2.9 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 III0Cabinet320014.5 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 '"~Cabinet 4 2.0 2 2 2 2 2 2 2 2 2 2 2 2 :::r~2007 2 2 2 2 2 2 2 2 2
m Noxon 1 2009 2.3 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 :::l
CD Noxon 3 2010 1.9 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 Cl:l-g.Noxon 2 2011 1.0 0 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 0
o·Noxon 4 2012 0.9 0 0 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 :::l
Nine Mle 2012 3.7 0 0 2 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 CII
;;U -Total Qualifying Resources 17 23 26 28 28 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 III"-INET REC POSITION 8 8 (37)(38)(39)(39)(82) (83) (84)1851 (86)(87)(88)(9511 '"17 5 7 (69)(90)(92) (93);U
RECBank "tl
Previous Year Balance 0 17 21 26 28 28 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 CII
REC's Required 0 (19) (19) (19) (20)(59)(60)(61 )(61)(104)(105) (106)(107) (108) (109) (110) (111)(112)(114) (115)(117)C
REC's Generaled/Purchased 17 23 26 28 28 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 22 '"-ked/Sold RECs 0 2)7 8 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 !!!.
NET REC BANK 17 21 26 28 28 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 .,
REC ReselVe Requirement(95th PERCENTILE):s:Load 0 1 1 1 1 3 3 3 3 5 5 5 5 5 5 5 5 5 5 6 6 5O~~Existing Hydro Upgrades 0 6 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7~3 or Total REC Reserve Requirement 0 7 8 8 8 10 10 10 10 12 12 12 12 12 12 13 13 13 13 13 13 ()0"0 _.~~lg or
INET REC POSITION 199)(101) (102)(103)(10S)(106)(108i1 "17 14 21 26 28 120)(48)(49)(SO)(94)(95) (96) (97)198)~mxxro !'!"~
3 ~",...
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2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
TOTAL LOAD OBLIGAT/ONS
Native Load -1,661 -1,688 -1,704 -1,718 -1,751 -1,784 -1,814 -1,839 -1,866 -1,892 -1,919 -1,946 -1,982 -2,020 -2,062 -2,094 -2,131 -2,168 -2,208 -2,249
Firm Power Sales -242 -242 -211 -158 -158 -8 -8 -7 -7 -7 -7 -7 -6 -6 -6 -6 -6 -6 -6 -6
Total Requirements -1.903 -1.930 -1.915 -1.876 -1.909 -1.792 -1.822 -1,846 -1,873 -1.899 -1.925 -1.953 -1.988 -2.027 -2.068 -2.101 -2.137 -2.174 -2,214 -2.255
RESOURCeS
Firm PowerPurchases 175 175 175 175 175 175 174 173 90 90 90 90 90 90 90 90 90 90 90 90
Hydro Resources 880 955 965 854 854 865 861 889 881 889 889 881 889 889 881 889 889 881 889 889
Base Load Thermals 895 895 895 895 895 895 895 895 895 895 895 895 895 895 895 606 606 606 606 606NWindResources0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 00~Peaking Units 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242~
m Total Resources 2.192 2,267 2.2n 2.166 2.166 2.1n 2.172 2,199 2.108 2,116 2,116 2,108 2,116 2.116 2.108 1.826 1.826 1,818 1,826 1,826
CD
-4291~IPeak Position Before Reserves Planning 289 337 362 290 256 385 350 353 236 217 191 155 127 89 40 -275 -311 -356 -388
0"
;0 RESERVE PLANNING
lJ Required Operating Reserves ·162 -164 -163 -162 -165 -159 -161 -163 -165 -167 -173 -176 -180 -182 -186 -170 -170 -171 -172 -173
Available Operating Reserves 23 42 42 8 8 8 8 34 34 34 34 34 34 34 34 34 34 34 34 34
Planning Wargin -233 -236 -239 -240 -245 -250 -254 -258 -261 -265 -269 -272 -277 -283 -289 -293 -298 -304 -309 -315
Total Reserves Planning -372 -358 -360 -394 -402 -400 -407 -387 -392 -398 -408 -414 -423 -431 -441 -429 -434 -441 -447 -454
[Peak Position With Reserves Planning -83 -21 2 -105 -146 -15 -57 -34 ~157 -181 -216 ~259 -296 -342 -401 -704 -746 -796 -835 -3831
Planning Margin Before NWMarket 16%20%21%16%14%22% 20%21%14% 13% 12% 10%8%6%4%-11% -13% -15% -16% -18%
Avista Share of Excess NWCapacity 737 656 565 477 400 326 255 186 115 56 0 0 0 0 0 0 0 0 0 0
IPeakPosition With NWMarket 654 635 567 373 254 311 199 152 -42 ~125 -216 ·259 -296 -342 401 -704 ~746 -796 ----=835 -383)Qrnm~3'~()-o -,
iii ji:I~00 mmx
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0"",~~9..
!!.~
!!1 0
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Peak Position With NWMarket 55%54% 51%41%35%40%34%31%21%16%12% 10%8%6%4%-11% -13% -15%-16%-18%
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IPeak Position Before Reserves Planning 203 106 152 116 94 214 209 135 119 116 68 51 41 -18 -48 -304 -361 -385 -399 -4601
RESERVE PLANNING
Required Operating Reserves -153 -157 -159 -160 -162 -155 -157 -160 -161 -163 -165 -167 -169 -171 -172 -157 -156 -157 -158 -158
Available Operating Reserves 155 66 171 159 159 159 161 158 158 161 158 158 161 158 158 161 158 158 161 158
Planning I'v1argin -227 -233 -240 -247 -251 -255 -259 -262 -266 -269 -272 -276 -280 -285 -290 -295 -299 -304 -309 -314
Total Reserves Planning -227 -325 -240 -248 -255 -255 -259 -264 -269 -271 -279 -285 -289 -298 -304 -295 -299 -304 -309 -314
IPeak PositionWith Reserves Planning -24 -220 -lI7 ·132 ·161 41 -50 -129 ~150 -155 ~211 -234 -249 ·316 -352 ·599 -660 -689 -708 -n4j
Planning Margin Before NW Market 20%10%18%15%14%22"10 21%17%16%15%12%11%11%7%6%-7%-10%·11%-12%·14%
Avista Share of Excess NWCapacity 275 221 178 141 107 78 52 31 10 3 0 0 0 0 0 0 0 0 0 0
IPeak Position With NW Market 251 1 91 9 -54 36 2 -98 -140 -152 -211 -234--249 -316 -352 -599 -660 .:§.8!l._,I08 _-~--------
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TOTAL LOAD OBLIGATlONS
Native Load
Firm Power Sales
Total Requirements
RESOURCES
Firm Power Purchases
Hydro Resources
Base Load Thermals
Wind Resources
Peakinq Units
Total Resources
Peak Position With NWMarket
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
-1,514 -1,556 -1,597 -1,644 -1,673 -1,701 -1,727 -1,748 -1,nl -1,793 -1,815 -1,838 -1,868 -1,900 -1,937 -1,964 -1,995 -2,026 -2,059 -2,094
-243 -218 -212 -159 -159 -9 -9 -8 -8 -8 -8 -8 -8 -7 -7 -7 -7 -7 -7 -7
-1.757 -1,n4 -1.809 -1,804 -1.832 -1.710 -1,736 -1.756 -i.nS -1.800 -1,822 -1,846 -1.876 -1,908 -1.944 -1.971 -2.002 -2.033 -2.067 -2,102
85 85 85 85 85 85 85 83 83 82 82 82 82 82 82 82 82 82 82 82
900 819 902 859 866 864 885 833 840 859 833 840 859 833 840 859 833 840 859 833
799 799 799 799 799 799 799 799 799 799 799 799 799 799 799 551 551 551 551 551
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176
1.960 1.880 1.962 1,919 1.926 1.924 1,945 1,891 1,897 1.916 1,891 1.896 1,916 1.890 1.896 1.668 1.642 1.648 1,668 1.642
36%22%28%23%20%26%24%18%16%16%12%11%11%7%6%-7"/0 -10% -11% -12% -14%
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!Energy Position Before Contingency Planning 191 145 184 182 161 133 91 81 2 -14 6 -49 -71 -58 -162 -351 ..J47 -397 -421 --4211
IEnergyMargin 28% 24%27"10 26% 25% 24% 20%18% 12% 10%12%7%6%7%-1%-15% -14% -17%-19%-18%]
IEnergy Position With Contingency Planning 116 69 108 89 82 54 11 13 -49 -67 -46 -103 -126 -112 ~1~__~_a._-405 -45£-482-475)
·1,249 -1.258 -1,258 -1,223 -1.244 -1,215 -1,234 -1.249 -1,266 -1,282 -1.298 -1,316 -1,338 -1.362 -1.391 -1,411 -1,434 -1,457 -1,482 -1,507
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1.087
65
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515
1,060
65
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515
1,060
65
481
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1,087
65
481
515
1.060
65
481
684
1.229
65
481
758
1.3B4
65
481
721
1,267
65
481
721
1.266
65
481
758
1.304
66
481
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1.268
66
481
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1,268
91
481
758
1.330
111
490
724
1.325
112
495
741
1.348
163
495
746
1.404
165
495
744
1.405
163
527
751
1,442
164
525
714
1,403
163
522
755
153 153 153 138 153 154 153 147 146 145 147 146 145 147 146 145 147 146 145 147
-228 -229 -230 -231 -232 -233 -233 -216 -197 -198 -198 -199 -200 -201 -202 -203 -204 -205 -206 -200
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
1,441
~,1~~,131-1,148-1.1ffi-1.100-1,~9-1~-1~-1~-1~-1~-1,MO-1,~-1~-1~-1~~~-1~-1~-1,~
-1~-1V -1~~-~~~~~~~~~~~~~~~~
CONTWGENCYPLANNWG
Peaking Resources
Contingency
Total Resources
TOTAL LOAD OBUGATlONS
Native Load
Firm PowerSales
Total Requirements
RESOURCES
Firm PowerPurchases
Hydro
Base Load Thermals
Of:2~~3 ""0-0 a:~~I~mxxro
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Pacific Northwest Regional ResolJrce Adequacy Assessment
Energy Load/Resource Balance Assessment 2011 Bal =2584 Threshold =0
NWPCC
May 28,2008 Last Update
Summary Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Ann
Net Demand 21040 21096 22934 24769 25730 24734 23376 21858 21243 22170 22911 22793 22882
Net Resources 23599 24143 28231 28887 26262 25611 24504 22870 23440 26216 26412 25405 25466
URBalance 2559 3047 5297 4118 532 877 1128 1012 2197 4046 3501 2612 2584
W/O Plan Adiustment 1259 1747 3997 2818 -768 -423 -172 -288 897 2746 2201 1312 1284
W/0 Uncontracted 259 747 652 -561 -4149 -3780 -3054 -2703 -1487 1746 1201 312 -888
Demand Sep Oct Nov Dec Jan Feb Mar Apr Mav Jun Jul AUQ Ann
Non-DSI 19900 20300 22515 24475 25114 24074 22448 20793 20179 20965 21595 21317 21966
DSI 693 693 693 693 718 718 718 718 718 718 718 718 710
Coulee Pumping 137 65 2 2 2 2 28 158 238 255 274 238 117
Total 20730 21058 23210 25171 25834 24795 23194 21670 21135 21938 22587 22273 22793
Resources Sep Oct Nov Dec Jan Feb Mar Apr Mav Jun Jul AUQ Ann
Critical Hvdro 10579 11172 12724 13175 10482 10023 10740 10938 11487 15807 13300 12332 11905
Non-Hydro Firm 10720 10671 10862 11033 11099 10931 9582 8216 8270 8109 10812 10773 10090
PNW Uncontracted 1000 1000 3345 3379 3381 3357 2882 2415 2384 1000 1000 1000 2171
Planning Adjustment 1300 1300 1300 1300 1300 1300 1300 1300 1300 1300 1300 1300 1300
Firm Contracts Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul AUQ Ann
Exports 1169 948 909 957 950 945 972 915 786 1022 1177 1216 997
Imports 859 910 1185 1359 1054 1006 790 727 678 790 853 696 908
PNW uncontracted resources are reduced during the peak SW load months June-October.
LEGEND:I
NET DEMAND:Average annual firm load based on average temperature conditions and adjusted for firm out-of-region energy sales and purchases.
CRITICAL HYDRO:Hydro generation under current constraints for hydrologic conditions from August 1936 through July 1937.
NON-HYDRO FIRM:Annual energy capability from all non-hydro resources committed to serve PNW load accounting for maintenance and forced­
outage rates &limited by fuel-supply constraints/environmental constraints (wind assumed at 30%plant factor unless better information available)
PNW UNCONTRACTED:Merchant generation located in the PNW,but not committed to load through long-term contracts.
PLANNING ADJUSTMENT:Additional energy available to PNW from out-of-region spot market and hydro flexibility derived from 5%LOLP study.
Exhibit S II Page 1 of 15
Simplot,Exergy,Clearwater
On Cross Examination
Energy Load/Resource Balance Assessment 2011
NWPCC
May 28,2008
Resource Detail (MWa)
Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Ann
18th Street (Springfield ICs,8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8
Alden Bailey (Loki)0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Amalgamated Sugar (TASC 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Amalgamated Sugar (TASC 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Barber Dam 1.2 1.6 1.4 1.8 2.1 1.6 1.9 2.0 2.6 2.4 2.4 2.2 2
Basin Creek 1 -9 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 8
Beaver 1 -7 444.4 455.3 465.5 471.6 472.2 467.9 406.7 346.3 340.4 335.4 438.6 437.9 423
Beaver 8 21.0 21.5 22.0 22.3 22.3 22.1 19.2 16.4 16.1 15.9 20.7 20.7 20
Bennett Mountain 152.7 157.8 162.3 165.3 165.5 163.3 140.7 119.1 116.4 114.2 148.4 148.9 146
Big Sheep Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Biglow Canyon Ph I 35.4 27.5 32.0 36.1 38.7 33.9 40.3 40.3 45.5 40.3 41.8 40.3 38
Biomass One 1 &2 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21
Birch Creek 2.7 0.0 0.0 0.0 0.0 0.0 0.0 2.7 2.7 2.7 2.7 2.7 1
Blind Canyon 0.4 0.5 0.5 0.6 0.7 0.5 0.6 0.7 0.9 0.8 0.8 0.7 1
Boardman 306.0 306.0 306.0 306.0 306.0 306.0 257.2 208.3 208.3 208.3 306.0 306.0 278
Boulder Park 1-6 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21
Boundary GT 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 1
Box Canyon 0.2 0.2 0.2 0.3 0.3 0.2 0.3 0.3 0.4 0.4 0.4 0.3 a
Box Canyon 1 &2 1.0 1.3 1.1 1.5 1.7 1.3 1.5 1.6 2.1 2.0 2.0 1.8 2
Briggs Creek 0.2 0.3 0.3 0.4 0.4 0.3 0.4 0.4 0.5 0.5 0.5 0.4 0
Broadwater 0.7 0.7 0.8 0.8 0.8 0.8 0.8 0.9 1.0 1.4 1.0 0.7 1
Bypass 10.0 0.0 0.0 0.0 0.0 0.0 0.0 10.0 10.0 10.0 10.0 10.0 5
Cedar Draw Creek 1.0 1.3 1.1 1.4 1.6 1.3 1.5 1.6 2.1 1.9 1.9 1.7 2
Central Oregon Siphon 1.8 2.4 2.1 2.7 3.1 2.4 2.8 3.0 3.9 3.6 3.6 3.3 3
Centralia 1 93.0 93.0 93.0 93.0 93.0 93.0 78.1 63.3 63.3 63.3 93.0 93.0 84
Chehalis Generating Facilil)464.9 476.4 487.0 493.4 494.0 489.6 425.6 362.3 356.2 350.9 458.9 458.1 443
Clearwater Hatchery (Dwor~0.3 0.4 0.4 0.5 0.6 0.4 0.5 0.5 0.7 0.7 0.7 0.6 1
Coffin Butte 1 -5 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 5
Cogen II (D.R.Johnson)1 ~6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 7
Colstrip 1 139.9 139.9 139.9 139.9 139.9 139.9 117.6 95.2 95.2 95.2 139.9 139.9 127
Colstrip 2 139.9 139.9 139.9 139.9 139.9 139.9 117.6 95.2 95.2 95.2 139.9 139.9 127
Colstrip 3 462.7 462.7 462.7 462.7 462.7 462.7 388.9 315.0 315.0 315.0 462.7 462.7 420
Colstrip 4 387.1 387.1 387.1 387.1 387.1 387.1 325.3 263.5 263.5 263.5 387.1 387.1 351
Columbia Generating Statio 1046.5 1046.5 1046.5 1046.5 1046.5 1046.5 845.0 643.5 643.5 643.5 1046.5 1046.5 929
Exhibit __Page,"('If 15
Simplo!.Exergy,r "On Cross Examine..
~-
Combine Hills I 11.6 9.0 10.5 11.8 12.7 11.1 13.2 13.2 14.9 13.2 13.7 13.2 12
Condon 14.0 10.9 12.7 14.3 15.4 13.4 16.0 16.0 18.1 16.0 16.6 16.0 15
COPCO 1 (1 &2)7.8 10.3 9.2 11.6 13.4 10.3 12.0 13.0 17.1 15.9 15.9 14.3 13
COPCO 2 (1 &2)10.5 13.7 12.2 15.5 17.8 13.8 16.0 17.3 22.7 21.1 21.2 19.1 17
Corrette (J.E.Corette)22.9 22.9 22.9 22.9 22.9 22.9 19.3 15.6 15.6 15.6 22.9 22.9 21
Covanta Marion 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8
Cowiche Hydroelectric Proje 2.0 0.0 0.0 0.0 "0.0 0.0 0.0 2.0 2.0 2.0 2.0 2.0 1
Coyote Springs 1 216.4 223.7 230.1 234.4 234.7 231.4 199.4 168.9 165.0 161.8 210.4 211.0 207
Coyote Springs 2 231.3 239.0 245.9 250.5 250.8 247.4 213.2 180.5 176.4 173.0 224.8 225.5 221
Crystal Mountain 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 3
Danskin (Evander Andrews:145.8 150.7 155.0 157.9 158.1 155.9 134.4 113.8 111.2 109.0 141.7 142.2 140
Danskin (Evander Andrews:39.5 40.8 41.9 42.7 42.8 42.2 36.4 30.8 30.1 29.5 38.4 38.5 38
Danskin (Evander Andrews:39.5 40.8 41.9 42.7 42.8 42.2 36.4 30.8 30.1 29.5 38.4 38.5 38
Deep Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 a
Dietrich Drop 4.8 0.0 0.0 0.0 0.0 0.0 0.0 4.8 4.8 4.8 4.8 4.8 2
Don Plant (Simplot Pocatelb 5.9 5.9 5.9 5.9 5.9 5.9 5.9 5.9 5.9 5.9 5.9 5.9 6
Dry Creek 3.6 0.0 0.0 0.0 0.0 0.0 0.0 3.6 3.6 3.6 3.6 3.6 2
Dry Creek Landfill 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 3
Eastsound 4 & 5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 a
Elk Creek 0.8 1.0 0.9 1.1 1.3 1.0 1.2 1.3 1.6 1.5 1.5 1.4 1
Elkhorn 28.2 21.9 25.5 28.8 30.9 27.0 32.1 32.1 36.3 32.1 33.3 32.1 30
Eltopia Branch Canal 4.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 a
Encogen 1-4 143.1 146.6 149.9 151.8 152.0 150.6 130.9 111.5 109.6 108.0 141.2 141.0 136
Everett Cogeneration Projel 30.3 30.3 30.3 30.3 30.3 30.3 30.3 30.3 30.3 30.3 30.3 30.3 30
Evergreen Forest Products 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4
Fall Creek 1 - 3 0.7 0.9 0.8 1.0 1.1 0.9 1.0 1.1 1.4 1.3 1.3 1.2 1
Fall River 3.0 3.9 3.5 4.4 5.1 3.9 4.6 4.9 6.5 6.0 6.0 5.4 5
Falls Creek 1.3 1.7 1.5 1.9 2.2 1.7 2.0 2.2 2.8 2.6 2.6 2.4 2
Farmers Irr.Dis!.No.2 (COl 1.0 1.3 1.1 1.5 1.7 1.3 1.5 1.6 2.1 2.0 2.0 1.8 2
Farmers Irr.Dis!.NO.3 (Pet 1.8 0.0 0.0 0.0 0.0 0.0 0.0 1.8 1.8 1.8 1.8 1.8 1
Faulkner 0.9 0.0 0.0 0.0 0.0 0.0 0.0 0.9 0.9 0.9 0.9 0.9 a
Foote Creek 1 11.7 9.1 10.6 11.9 12.8 11.2 13.3 13.3 15.0 13.3 13.8 13.3 12
Foote Creek 2 0.5 0.4 0.5 0.5 0.6 0.5 0.6 0.6 0.7 0.6 0.6 0.6 1
Foote Creek 4 4.7 3.7 4.3 4.8 5.2 4.5 5.4 5.4 6.1 5.4 5.6 5.4 5
Fortix 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 a
Fossil Gulch 3.0 2.3 2.7 3.0 3.2 2.8 3.4 3.4 3.8 3.4 3.5 3.4 3
Frederickson 1 77.9 79.8 81.6 82.7 82.8 82.0 71.3 60.7 59.7 58.8 76.9 76.8 74
Frederickson 2 77.9 79.8 81.6 82.7 82.8 82.0 71.3 60.7 59.7 58.8 76.9 76.8 74
Frederickson Power 1 240.5 246.4 251.9 255.2 255.6 253.3 220.1 187.4 184.3 181.5 237.4 237.0 229
Fredonia 1 108.5 111.2 113.7 115.2 115.3 114.3 99.3 84.6 83.2 81.9 107.1 106.9 103
Exhibit __Page 30115
Simplot,Exergy,Clearwater
On Cross Examination
Fredonia 2 108.5 111.2 113.7 115.2 115.3 114.3 99.3 84.6 83.2 81.9 107.1 106.9 103
Fredonia 3 51.7 52.9 54.1 54.8 54.9 54.4 49.6 44.8 44.0 43.4 51.0 50.9 51
Fredonia 4 50.8 52.1 53.2 53.9 54.0 53.5 48.8 44.0 43.3 42.6 50.2 50.1 50
Freres Lumber 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8
Galesville 0.5 0.6 0.8 0.9 0.9 0.7 0.7 0.7 0.8 0.8 0.7 0.8 1
Geo-Bon No.2 0.3 0.5 0.4 0.5 0.6 0.5 0.5 0.6 0.8 0.7 0.7 0.6 1
Georgia-Pacific (Camas)43.7 43.7 43.7 43.7 43.7 43.7 43.7 43.7 43.7 43.7 43.7 43.7 44
Georgia-Pacific (Wauna)22.7 22.7 22.7 22.7 22.7 22.7 22.7 22.7 22.7 22.7 22.7 22.7 23
Glenns Ferry Cogeneration 8.8 9.1 9.3 9.5 9.5 9.4 8.1 6.8 6.7 6.6 8.5 8.5 8
Goldendale CC 1A&1B 217.3 224.6 231.0 235.3 235.6 232.4 200.2 169.6 165.7 162.5 211.2 211.9 208
Goodnoe Hills 26.5 20.6 24.0 27.1 29.0 25.4 30.2 30.2 34.1 30.2 31.3 30.2 28
Grant Village 1 &2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
HW.Hill (Roosevelt Biogas 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9
Hampton Lumber 6.1 6.1 6.1 6.1 6.1 6.1 6.1 6.1 6.1 6.1 6.1 6.1 6
Hazelton A 8.7 0.0 0.0 0.0 0.0 0.0 0.0 8.7 8.7 8.7 8.7 8.7 4
Hazelton B 7.6 0.0 0.0 0.0 0.0 0.0 0.0 7.6 7.6 7.6 7.6 7.6 4
Hermiston Generating Proje 206.8 213.7 219.8 223.9 224.2 221.1 190.6 161.4 157.7 154.6 201.0 201.6 198
Hermiston Generating Proje 206.8 213.7 219.8 223.9 224.2 221.1 190.6 161.4 157.7 154.6 201.0 201.6 198
Hidden Hollow 3.0 0.0 0.0 0.0 0.0 0.0 0.0 3.0 3.0 3.0 3.0 3.0 2
Hopkins Ridge 42.1 32.7 38.1 43.0 46.2 40.3 48.0 48.0 54.2 48.0 49.8 48.0 45
Hoquiam Diesels 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 9
Horseshoe Bend 2.5 2.0 2.3 2.6 2.8 2.4 2.9 2.9 3.3 2.9 3.0 2.9 3
Horseshoe Bend Hydroelec 3.1 4.1 3.6 4.6 5.3 4.1 4.8 5.1 6.8 6.3 6.3 5.7 5
Ingram Warm Springs Ranc 0.2 0.2 0.2 0.2 0.3 0.2 0.3 0.3 0.4 0.3 0.3 0.3 0
Ingram Warm Springs Ranc 0.4 0.5 0.4 0.5 0.6 0.5 0.5 0.6 0.8 0.7 0.7 0.6 1
Iron Gate 5.9 7.7 6.9 8.7 10.0 7.7 9.0 9.7 12.8 11.9 11.9 10.8 9
Jim Bridger 1 492.9 492.9 492.9 492.9 492.9 492.9 414.2 335.5 335.5 335.5 492.9 492.9 447
Jim Bridger 2 492.9 492.9 492.9 492.9 492.9 492.9 414.2 335.5 335.5 335.5 492.9 492.9 447
Jim Bridger 3 492.9 492.9 492.9 492.9 492.9 492.9 414.2 335.5 335.5 335.5 492.9 492.9 447
Jim Bridger 4 492.9 492.9 492.9 492.9 492.9 492.9 414.2 335.5 335.5 335.5 492.9 492.9 447
Jim Ford Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
John Day Creek (Cereghinc 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
John H.Koyle 0.5 0.6 0.5 0.7 0.8 0.6 0.7 0.8 1.0 0.9 0.9 0.8 1
Judith Gap 6.1 4.7 5.5 6.2 6.7 5.8 6.9 6.9 7.8 6.9 7.2 6.9 6
Kasel-Witherspoon 0.5 0.6 0.5 0.7 0.8 0.6 0.7 0.8 1.0 0.9 0.9 0.8 1
Kettle Falls Generating Stat 44.6 44.6 44.6 44.6 44.6 44.6 44.6 44.6 44.6 44.6 44.6 44.6 45
Kettle Falls GT 6.0 6.2 6.4 6.5 6.5 6.4 5.5 4.7 4.6 4.5 5.8 5.9 6
Klondike I 6.8 5.3 6.1 6.9 7.4 6.5 7.7 7.7 8.7 7.7 8.0 7.7 7
Klondike II 21.2 16.4 19.1 21.6 23.2 20.3 24.1 24.1 27.2 24.1 25.0 24.1 23
Klondike III 20.2 15.7 18.3 20.7 22.2 19.4 23.0 23.0 26.1 23.0 23.9 23.0 22
Exhibit __Page 4nf 15
Simplot Exergy.C "On Cross Examine:..
Koma Kulshan 3.9 4.4 6.0 6.5 6.3 4.7 5.0 5.1 5.6 5.6 5.3 5.5 5
Lacomb 1.0 0.0 0.0 0.0 0.0 0.0 0.0 1.0 1.0 1.0 1.0 1.0 a
Lake 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 a
Lancaster (Rathdrum CC)243.6 251.7 258.9 263.8 264.1 260.5 224.5 190.1 185.8 182.2 236.8 237.5 233
Lateral NO.1 a 2.9 0.0 0.0 0.0 0.0 0.0 0.0 2.9 2.9 2.9 2.9 2.9 1
Leaning Juniper 28.3 22.0 25.6 28.9 31.1 27.1 32.3 32.3 36.5 32.3 33.5 32.3 30
Little Wood Reservoir 0.3 0.4 0.4 0.5 0.6 0.4 0.5 0.6 0.7 0.7 0.7 0.6 1
Little Wood River Ranch 0.6 0.8 0.7 0.9 1.1 0.8 1.0 1.0 1.4 1.3 1.3 1.2 1
Lower Low Line No.2 2.8 0.0 0.0 0.0 0.0 0.0 0.0 2.8 2.8 2.8 2.8 2.8 1
LQ-LS Drains 0.6 0.8 0.7 0.8 1.0 0.8 0.9 0.9 1.2 1.2 1.2 1.0 1
Lucky Peak 1 - 3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 a
MacClaren 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 a
Magic Dam 2.9 3.9 3.4 4.4 5.0 3.9 4.5 4.9 6.4 5.9 6.0 5.4 5
Main Canal Headworks 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 a
March Point 1 - 4 125.2 128.2 131.1 132.8 133.0 131.8 114.6 97.5 95.9 94.5 123.5 123.3 119
Marengo I 39.6 30.7 35.8 40.4 43.4 37.9 45.1 45.1 51.0 45.1 46.8 45.1 42
Marengo II 19.8 15.4 17.9 20.2 21.7 19.0 22.5 22.5 25.5 22.5 23.4 22.5 21
Meyers Falls 0.3 0.4 0.4 0.5 0.6 0.4 0.5 0.5 0.7 0.7 0.7 0.6 1
Middle Fork Irrigation Distrie 0.2 0.3 0.2 0.3 0.3 0.3 0.3 0.3 0.4 0.4 0.4 0.4 a
Middle Fork Irrigation Distrie 0.2 0.3 0.2 0.3 0.3 0.3 0.3 0.3 0.4 0.4 0.4 0.4 a
Middle Fork Irrigation Distric 0.7 0.9 0.8 1.0 1.2 0.9 1.1 1.1 1.5 1.4 1.4 1.3 1
Mile 28 1.8 0.0 0.0 0.0 0.0 0.0 0.0 1.8 1.8 1.8 1.8 1.8 1
Mink Creek 1.0 1.3 1.2 1.5 1.7 1.3 1.6 1.7 2.2 2.0 2.1 1.9 2
Mirror Lake (Hutchinson Cr,1.0 0.0 0.0 0.0 0.0 0.0 0.0 1.0 1.0 1.0 1.0 1.0 1
Mitchell Butte 1.9 0.0 0.0 0.0 0.0 0.0 0.0 1.9 1.9 1.9 1.9 1.9 1
Montana One (Colstrip Enel 4.7 4.7 4.7 4.7 4.7 4.7 3.9 3.2 3.2 3.2 4.7 4.7 4
N-32 (Northside Canal)0.2 0.2 0.2 0.3 0.3 0.2 0.3 0.3 0.4 0.4 0.4 0.3 a
Nichols Gap 0.3 0.3 0.4 0.5 0.5 0.4 0.4 0.4 0.4 0.4 0.4 0.4 a
Nine Canyon 18.0 14.0 16.2 18.3 19.7 17.2 20.4 20.4 23.1 20.4 21.2 20.4 19
North Fork Sprague River 0.4 0.5 0.5 0.6 0.7 0.5 0.6 0.7 0.9 0.8 0.8 0.7 1
North Valmy 1 59.1 59.1 59.1 59.1 59.1 59.1 49.6 40.2 40.2 40.2 59.1 59.1 54
North Valmy 2 60.0 60.0 60.0 60.0 60.0 60.0 50.4 40.8 40.8 40.8 60.0 60.0 54
Northeast 1 5.4 5.6 5.7 5.8 5.8 5.7 5.2 4.7 4.6 4.6 5.4 5.3 5
Northeast 2 5.4 5.6 5.7 5.8 5.8 5.7 5.2 4.7 4.6 4.6 5.4 5.3 5
Old Faithful 1 & 2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 a
Olympic View 1 & 2 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 5
Opal Springs 1.4 1.8 1.6 2.1 2.4 1.9 2.2 2.3 3.1 2.8 2.8 2.6 2
Owyhee Dam 1.4 1.9 1.7 2.1 2.4 1.9 2.2 2.3 3.1 2.9 2.9 2.6 2
Owyhee Tunnel NO.1 8.0 0.0 0.0 0.0 0.0 0.0 0.0 8.0 8.0 8.0 8.0 8.0 4
Pasco (Franklin/Grays)GT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 a
Exhibit __Page 5 of 15
Simplot,Exergy,Ciearwater
On Cross Examination
Pasco (Franklin/Grays)GT .0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Pasco (Franklin/Grays)GT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Pasco (Franklin/Grays)GT .0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Plummer Forest Products 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5.3 5
Point Whitehorn 2 77.9 79.8 81.6 82.7 82.8 82.0 71.3 60.7 59.7 58.8 76.9 76.8 74
Point Whitehorn 3 77.9 79.8 81.6 82.7 82.8 82.0 71.3 60.7 59.7 58.8 76.9 76.8 74
Port Westward CC1A &1B 380.9 390.2 399.0 404.2 404.7 401.1 348.6 296.8 291.8 287.4 375.9 375.3 363
Portneuf River 0.3 0.4 0.3 0.4 0.5 0.4 0.5 0.5 0.6 0.6 0.6 0.5 0
Potholes East Canal 66.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Potholes East Canal Head""0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Potlatch (Lewiston)1 - 4 49.6 49.6 49.6 49.6 49.6 49.6 49.6 49.6 49.6 49.6 49.6 49.6 50
Prather Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Raft River I 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12.0 12
Rathdrum 1 75.5 78.0 80.2 81.7 81.8 80.7 69.6 58.9 57.6 56.4 73.4 73.6 72
Rathdrum 2 75.5 78.0 80.2 81.7 81.8 80.7 69.6 58.9 57.6 56.4 73.4 73.6 72
River Road Generating Plar 221.7 227.2 232.3 235.3 235.6 233.5 203.0 172.8 169.9 167.3 218.9 218.5 211
Rock Creek #1 0.8 1.1 1.0 1.2 1.4 1.1 1.3 1.4 1.8 1.7 1.7 1.5 1
Rock Creek #2 0.6 0.8 0.7 0.9 1.1 0.8 1.0 1.0 1.4 1.3 1.3 1.1 1
Rock River I 14.1 11.0 12.8 14.4 15.5 13.5 16.1 16.1 18.2 16.1 16.7 16.1 15
Ross Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.0 0
Rough &Ready Lumber 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1
Rupert Cogeneration 8.8 9.1 9.3 9.5 9.5 9.4 8.1 6.8 6.7 6.6 8.5 8.5 8
Russell D.Smith 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Salmon 1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Salmon 2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Savage Rapids Diversion 0.4 0.5 0.6 0.7 0.7 0.5 0.5 0.5 0.6 0.6 0.6 0.6 1
Shasta River 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Short Mountain 1 - 4 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2
Shoshone/Shoshone II 0.3 0.4 0.3 0.4 0.5 0.4 0.5 0.5 0.6 0.6 0.6 0.5 0
Sierra Pacific (Aberdeen)4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 5
Sierra Pacific (Fredonia)0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0
Skookumchuck 0.3 0.4 0.5 0.5 0.5 0.4 0.4 0.4 0.5 0.5 0.4 0.5 0
Slate Creek 1.4 1.8 1.6 2.0 2.3 1.8 2.1 2.3 3.0 2.8 2.8 2.5 2
South Dry Creek 0.1 0.1 0.1 0.1 0.2 0.1 0.1 0.2 0.2 0.2 0.2 0.2 0
St.Anthony 0.2 0.2 0.2 0.2 0.3 0.2 0.3 0.3 0.4 0.3 0.3 0.3 0
Stateline 84.6 65.7 76.5 86.4 92.7 81.0 96.3 96.3 108.9 96.3 99.9 96.3 90
Sumas Energy 110.0 112.7 115.2 116.7 116.9 115.8 100.7 85.7 84.3 83.0 108.5 108.4 105
Summer Falls 1 &2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Tenaska Washington Partnl 219.0 224.4 229.5 232.5 232.8 230.7 200.5 170.7 167.8 165.3 216.2 215.8 209
Tiber-Montana 1.6 2.1 1.9 2.4 2.8 2.2 2.5 2.7 3.6 3.3 3.3 3.0 3
Exhibit__Page R ('If 15
Simplol,Exergy,C "On Cross ExaminEl
Tieton 4.4 5.8 5.2 6.6 7.6 5.9 6.8 7.4 9.7 9.0 9.0 8.1 7
Tuttle Ranch (Ravenscroft)0.3 0.5 0.4 0.5 0.6 0.5 0.5 0.6 0.8 0.7 0.7 0.6 1
Twin Falls (TFHA)6.5 8.6 7.6 9.7 11.2 8.6 10.0 10.8 14.2 13.2 13.2 12.0 10
Twin Reservoirs 1.0 0.0 0.0 0.0 0.0 0.0 0.0 1.0 1.0 1.0 1.0 1.0 1
U.S.Bankcorp IC1 -IC4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Upriver 4.6 6.0 5.3 6.8 7.8 6.0 7.0 7.6 9.9 9.2 9.3 8.4 7
Vaagen Brothers Lumber 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 3
Vansycle Wind Energy Projl 7.0 5.5 6.3 7.2 7.7 6.7 8.0 8.0 9.0 8.0 8.3 8.0 7
Wapato Drop 2 (#1)3.0 0.0 0.0 0.0 0.0 0.0 0.0 3.0 3.0 3.0 3.0 3.0 2
Wapato Drop 3 (#1 -2)2.0 0.0 0.0 0.0 0.0 0.0 0.0 2.0 2.0 2.0 2.0 2.0 1
Weeks Falls 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Weyerhaeuser (Springfield)21.0 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21
Wheelabrator Spokane 19.3 19.3 19.3 19.3 19.3 19.3 19.3 19.3 19.3 19.3 19.3 19.3 19
White Creek 56.0 43.5 50.6 57.2 61.4 53.6 63.8 63.8 72.1 63.8 66.1 63.8 60
Wild Horse Wind 64.5 50.1 58.3 65.8 70.6 61.7 73.4 73.4 83.0 73.4 76.1 73.4 69
Wilson Lake 8.4 0.0 0.0 0.0 0.0 0.0 0.0 8.4 8.4 8.4 8.4 8.4 4
Wolverine Creek 18.2 14.1 16.4 18.6 19.9 17.4 20.7 20.7 23.4 20.7 21.5 20.7 19
WSU Grimes Way Central ~0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Yellowstone Energy (BGI) 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6
Total 10720 10671 10862 11033 11099 10931 9582 8216 8270 8109 10812 10773 10090
Uncommitted IPPs
Big Hanaford CC1A-1 E 221.7 227.2 232.3 235.3 235.6 233.5 203.0 172.8 169.9 167.3 218.9 218.5 211
Centralia 1 530.1 530.1 530.1 530.1 530.1 530.1 445.4 360.8 360.8 360.8 530.1 530.1 481
Centralia 2 623.1 623.1 623.1 623.1 623.1 623.1 523.6 424.1 424.1 424.1 623.1 623.1 565
Grays Harbor Energy Facilit 581.1 595.4 608.8 616.8 617.5 612.0 532.0 452.9 445.3 438.6 573.6 572.7 554
Hermiston Power Project 464.4 479.9 493.7 502.9 503.5 496.6 428.0 362.4 354.2 347.3 451.4 452.8 445
Klamath Cogeneration Proj,420.6 434.6 447.1 455.5 456.0 449.7 387.6 328.2 320.7 314.5 408.8 410.1 403
Klamath Generation Peaker 42.4 43.4 44.4 44.9 45.0 44.6 40.6 36.7 36.1 35.5 41.8 41.7 41
Klamath Generation Peaker 42.4 43.4 44.4 44.9 45.0 44.6 40.6 36.7 36.1 35.5 41.8 41.7 41
Mint Farm 285.2 292.2 298.8 302.7 303.1 300.3 261.1 222.3 218.5 215.2 281.5 281.0 272
Morrow Power 21.2 21.7 22.2 22.5 22.5 22.3 20.3 18.3 18.0 17.8 20.9 20.9 21
West Point Treatment Plant 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0
Total 3232 3291 3345 3379 3381 3357 2882 2415 2384 2357 3192 3193 3033
Exhibit __Page 7 of 15
Simplet,Exergy,ClealWater
On Cross Examination
Pacific Northwest Regional Resource Adequacy Assessment
Capacity Reserve Margin Assessment 2011 Jan RM 46%Jan Threshold 23%
NWPCC Jul RM 34%Jul Threshold 24%
May 28,2008 Last Update
Summarv Sep Oct Nov Dec Jan Feb Mar Apr Ma~Jun Jul Auc
Peak Demand 24100 24429 26243 28571 28603 27796 26496 24690 23912 25043 26313 25920
Peak Resources 32424 33175 40463 41348 41842 39911 37140 35659 37917 34106 35297 33053
Reserve Margin 35%36%54%45% 46%44%40% 44%59%36%34%28%
W/O Uncontracted 30%32%29%22%23%20%17%22%35%32%30%24%
Sust Peak Demand Sep Oct Nov Dec Jan Feb Mar Apr Ma~Jun Jul Auc
Non-DSI 22000 22825 25235 27735 27501 26701 24915 22879 22050 22786 24032 23531
DSI 693 693 693 693 718 718 718 718 718 718 718 718
Coulee Pumpinq 137 65 2 2 2 2 28 158 238 255 274 238
Total 22831 23584 25930 28430 28222 27421 25661 23756 23006 23759 25024 24488
Sust Peak Resources Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug
Hvdro 18855 19476 20071 20810 21278 19465 18857 19522 21853 23661 21760 19528
Hydro Flex 1000 1000 2000 2000 2000 2000 2000 2000 2000 1000 1000 1000
PNW Uncontracted 1000 1000 3553 3589 3592 3566 3062 2565 2532 1000 1000 1000
Out-of-PNW Uncontracted 0 0 3000 3000 3000 3000 3000 3000 3000 0 0 0
Non-Hydro 11569 11699 11839 11949 11972 11879 10221 8571 8531 8445 11537 11525
On-Peak Contracts Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul AU<:l
Exports 2328 1946 1827 1833 1827 1823 1850 1834 1809 2348 2349 2336
Imports 1059 1101 1514 1692 1446 1448 1015 900 903 1064 1060 903
Hydro flex,PNW uncontracted and out-of-PNW uncontracted resources are reduced during the SW peak months June-October.
LEGEND:I
PEAK DEMAND:Average load under normal temperatures over the peak load hours (6 hours/day over 3 weekdays).
HYDRO:Hydro capacity for sustained peaking period based on 6-hour Trap output for lowest quintile.
HYDRO FLEX:Additional hydro capacity over the sustained peaking period.
PNW UNCONTRACTED:Merchant capacity located and availble to the PNW,but not committed to load through long-term contracts.
OUT-OF-PNW UNCONTRACTED:Out-of-region resources available to PNW based on an analysis of California winter surplus capacity.
NON-HYDRO:Capacity available over sustained peaking period from all non-hydro resources accounting for
maintenance outages &limited by fuel-supply constraints/environmental constraints (wind assumed at 5%plant factor for now).
-
Exhibit __Page R of 15
Simplet,Exergy,C "
On Cross Examina.
~"-
Capacity Reserve Margin Assessment 2011
NWPCC
May 28,2008
Resource Detail (MW)
Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug
18th Street (Springfield ICs,9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1
Alden Bailey (Loki)0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Amalgamated Sugar (TASe 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Amalgamated Sugar (TASe 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Barber Dam 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Basin Creek 1 - 9 20.8 20.8 20.8 20.8 20.8 20.8 20.8 20.8 20.8 20.8 20.8 20.8
Beaver 1 - 7 467.7 479.2 490.0 496.4 497.0 492.6 428.1 364.5 358.4 353.0 461.7 460.9
Beaver 8 22.6 23.1 23.7 24.0 24.0 23.8 20.7 17.6 17.3 17.0 22.3 22.3
Bennett Mountain 164.2 169.7 174.5 177.8 178.0 175.6 151.3 128.1 125.2 122.8 159.6 160.1
Big Sheep Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Biglow Canyon Ph I 5.3 4.1 4.8 5.4 5.8 5.1 6.0 6.0 6.8 6.0 6.3 6.0
Biomass One 1 & 2 22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6
Birch Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Blind Canyon 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Boardman 438.8 438.8 438.8 438.8 438.8 438.8 368.7 298.6 298.6 298.6 438.8 438.8
Boulder Park 1-6 23.1 23.1 23.1 23.1 23.1 23.1 23.1 23.1 23.1 23.1 23.1 23.1
Boundary GT 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7
Box Canyon 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Box Canyon 1 & 2 1.0 1.3 1.1 1.5 1.7 1.3 1.5 1.6 2.1 2.0 2.0 1.8
Briggs Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Broadwater 1.7 1.8 1.9 2.0 2.0 2.0 2.0 2.2 2.5 3.4 2.5 1.8
Bypass 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Cedar Draw Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Central Oregon Siphon 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Centralia 1 100.0 100.0 100.0 100.0 100.0 100.0 84.0 68.1 68.1 68.1 100.0 100.0
Chehalis Generating Facili!)489.4 501.4 512.7 519.4 520.0 515.4 448.0 381.4 374.9 369.3 483.0 482.2
Clearwater Hatchery (Dwor~0.3 0.4 0.4 0.5 0.6 0.4 0.5 0.5 0.7 0.7 0.7 0.6
Coffin Butte 1 - 5 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0
Cogen II (DR Johnson)1 E 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2
Colstrip 1 214.9 214.9 214.9 214.9 214.9 214.9 180.6 146.3 146.3 146.3 214.9 214.9
Colstrip 2 214.9 214.9 214.9 214.9 214.9 214.9 180.6 146.3 146.3 146.3 214.9 214.9
Exhibit __Page 9 of 15
Simplot,Exergy,Clearwater
On Cross Examination
Colstrip 3 606.8 606.8 606.8 606.8 606.8 606.8 509.9 413.0 413.0 413.0 606.8 606.8
Colstrip 4 555.0 555.0 555.0 555.0 555.0 555.0 466.4 377.7 377.7 377.7 555.0 555.0
Columbia Generating Statio 1150.0 1150.0 1150.0 1150.0 1150.0 1150.0 928.6 707.1 707.1 707.1 1150.0 1150.0
Combine Hills I 1.7 1.3 1.6 1.8 1.9 1.7 2.0 2.0 2.2 2.0 2.0 2.0
Condon 2.1 1.6 1.9 2.2 2.3 2.0 2.4 2.4 2.7 2.4 2.5 2.4
COPCO 1 (1 &2)7.8 10.3 9.2 11.6 13.4 10.3 12.0 13.0 17.1 15.9 15.9 14.3
COPCO 2 (1 &2)10.5 13.7 12.2 15.5 17.8 13.8 16.0 17.3 22.7 21.1 21.2 19.1
Corrette (J.E.Corette)61.6 61.6 61.6 61.6 61.6 61.6 51.8 41.9 41.9 41.9 61.6 61.6
Covanta Marion 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0
Cowiche Hydroelectric ProjE 2.0 0.0 0.0 0.0 0.0 0.0 0.0 2.0 2.0 2.0 2.0 2.0
Coyote Springs 1 227.8 235.4 242.2 246.7 247.0 243.6 209.9 177.8 173.7 170.4 221.4 222.1
Coyote Springs 2 243.5 251.6 258.8 263.7 264.0 260.4 224.4 190.0 185.7 182.1 236.7 237.4
Crystal Mountain 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9
Danskin (Evander Andrews:156.8 162.0 166.7 169.8 170.0 167.7 144.5 122.4 119.6 117.3 152.4 152.9
Danskin (Evander Andrews:42.4 43.8 45.1 45.9 46.0 45.4 39.1 33.1 32.4 31.7 41.2 41.4
Danskin (Evander Andrews:42.4 43.8 45.1 45.9 46.0 45.4 39.1 33.1 32.4 31.7 41.2 41.4
Deep Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Dietrich Drop 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Don Plant (Simplot Pocatello 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3
Dry Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Dry Creek Landfill 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Eastsound 4 &5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Elk Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Elkhorn 4.2 3.3 3.8 4.3 4.6 4.1 4.8 4.8 5.4 4.8 5.0 4.8
Eltopia Branch Canal 4.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Encogen 1-4 150.6 154.3 157.7 159.8 160.0 158.6 137.8 117.3 115.4 113.6 148.6 148.4
Everett Cogeneration Proje<32.5 32.5 32.5 32.5 32.5 32.5 32.5 32.5 32.5 32.5 32.5 32.5
Evergreen Forest Products 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5
Fall Creek 1 - 3 0.7 0.9 0.8 1.0 1.1 0.9 1.0 1.1 1.4 1.3 1.3 1.2
Fall River 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Falls Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Farmers Irr.Dis!.NO.2 (COl 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Farmers Irr.Dis!.No.3 (Pet 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Faulkner 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Foote Creek 1 1.8 1.4 1.6 1.8 1.9 1.7 2.0 2.0 2.3 2.0 2.1 2.0
Foote Creek 2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
Foote Creek 4 0.7 0.6 0.6 0.7 0.8 0.7 0.8 0.8 0.9 0.8 0.8 0.8
Exhibit __Page 1n ('If 15
Simplol,Exergy,CI 'r
On Cross Examinal.
~
Fortix 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2
Fossil Gulch 0.4 0.3 0.4 0.5 0.5 0.4 0.5 0.5 0.6 0.5 0.5 0.5
Frederickson 1 83.8 85.8 87.7 88.9 89.0 88.2 76.7 65.3 64.2 63.2 82.7 82.5
Frederickson 2 83.8 85.8 87.7 88.9 89.0 88.2 76.7 65.3 64.2 63.2 82.7 82.5
Frederickson Power 1 253.2 259.4 265.2 268.7 269.0 266.6 231.7 197.3 194.0 191.1 249.9 249.5
Fredonia 1 116.7 119.6 122.2 123.9 124.0 122.9 106.8 90.9 89.4 88.1 115.2 115.0
Fredonia 2 116.7 119.6 122.2 123.9 124.0 122.9 106.8 90.9 89.4 88.1 115.2 115.0
Fredonia 3 57.4 58.8 60.1 60.9 61.0 60.5 55.1 49.7 48.9 48.2 56.7 56.6
Fredonia 4 56.5 57.9 59.2 59.9 60.0 59.5 54.2 48.9 48.1 47.4 55.7 55.6
Freres Lumber 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Galesville 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Geo-Bon NO.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Georgia-Pacific (Camas)47.0 47.0 47.0 47.0 47.0 47.0 47.0 47.0 47.0 47.0 47.0 47.0
Georgia-Pacific (Wauna)24.4 24.4 24.4 24.4 24.4 24.4 24.4 24.4 24.4 24.4 24.4 24.4
Glenns Ferry Cogeneration 9.2 9.5 9.8 10.0 10.0 9.9 8.5 7.2 7.0 6.9 9.0 9.0
Goldendale CC 1A & 1B 228.7 236.4 243.2 247.7 248.0 244.6 210.8 178.5 174.4 171.0 222.3 223.0
Goodnoe Hills 4.0 3.1 3.6 4.1 4.4 3.8 4.5 4.5 5.1 4.5 4.7 4.5
Grant Village 1 & 2 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
HW.Hill (Roosevelt Biogas 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1
Hampton Lumber 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5
Hazelton A 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Hazelton B 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Hermiston Generating Proje 217.7 224.9 231.4 235.7 236.0 232.8 200.6 169.9 166.0 162.8 211.6 212.2
Hermiston Generating Proje 217.7 224.9 231.4 235.7 236.0 232.8 200.6 169.9 166.0 162.8 211.6 212.2
Hidden Hollow 3.0 0.0 0.0 0.0 0.0 0.0 0.0 3.0 3.0 3.0 3.0 3.0
Hopkins Ridge 6.3 4.9 5.7 6.5 6.9 6.1 7.2 7.2 8.1 7.2 7.5 7.2
Hoquiam Diesels 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.6
Horseshoe Bend 0.4 0.3 0.3 0.4 0.4 0.4 0.4 0.4 0.5 0.4 0.4 0.4
Horseshoe Bend Hydroelec 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Ingram Warm Springs Ranc 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Ingram Warm Springs Ranc 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Iron Gate 5.9 7.7 6.9 8.7 10.0 7.7 9.0 9.7 12.8 11.9 11.9 10.8
Jim Bridger 1 530.0 530.0 530.0 530.0 530.0 530.0 445.4 360.7 360.7 360.7 530.0 530.0
Jim Bridger 2 530.0 530.0 530.0 530.0 530.0 530.0 445.4 360.7 360.7 360.7 530.0 530.0
Jim Bridger 3 530.0 530.0 530.0 530.0 530.0 530.0 445.4 360.7 360.7 360.7 530.0 530.0
Jim Bridger 4 530.0 530.0 530.0 530.0 530.0 530.0 445.4 360.7 360.7 360.7 530.0 530.0
Jim Ford Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Exhibit __Page 11 of 15
Simplot,Exergy,Clearwater
On Cross Examination
John Day Creek (Cereghinc 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
John H.Koyle 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Judith Gap 2.3 1.8 2.1 2.3 2.5 2.2 2.6 2.6 2.9 2.6 2.7 2.6
Kasel-Witherspoon 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Kettle Falls Generating Stat 47.9 47.9 47.9 47.9 47.9 47.9 47.9 47.9 47.9 47.9 47.9 47.9
Kettle Falls GT 6.5 6.7 6.9 7.0 7.0 6.9 5.9 5.0 4.9 4.8 6.3 6.3
Klondike I 1.0 0.8 0.9 1.0 1.1 1.0 1.2 1.2 1.3 1.2 1.2 1.2
Klondike II 3.2 2.5 2.9 3.2 3.5 3.0 3.6 3.6 4.1 3.6 3.7 3.6
Klondike III 5.3 4.1 4.8 5.4 5.8 5.1 6.1 6.1 6.9 6.1 6.3 6.1
Koma Kulshan 3.9 4.4 6.0 6.5 6.3 4.7 5.0 5.1 5.6 5.6 5.3 5.5
Lacomb 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Lake 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Lancaster (Rathdrum CC)256.4 265.0 272.6 277.7 278.0 274.2 236.3 200.1 195.5 191.7 249.2 250.0
Lateral NO.1 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Leaning Juniper 4.3 3.3 3.8 4.3 4.7 4.1 4.8 4.8 5.5 4.8 5.0 4.8
Little Wood Reservoir 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Little Wood River Ranch 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Lower Low Line No.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
LQ-LS Drains 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Lucky Peak 1 - 3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
MacClaren 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5
Magic Dam 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Main Canal Headworks 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
March Point 1 - 4 131.8 135.0 138.0 139.8 140.0 138.7 120.6 102.7 100.9 99.4 130.1 129.8
Marengo I 5.9 4.6 5.4 6.1 6.5 5.7 6.8 6.8 7.6 6.8 7.0 6.8
Marengo II 3.0 2.3 2.7 3.0 3.3 2.8 3.4 3.4 3.8 3.4 3.5 3.4
Meyers Falls 0.3 0.4 0.4 0.5 0.6 0.4 0.5 0.5 0.7 0.7 0.7 0.6
Middle Fork Irrigation Distric 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Middle Fork Irrigation Distric 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Middle Fork Irrigation Distric 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Mile 28 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Mink Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Mirror Lake (Hutchinson CrE 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Mitchell Butte 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Montana One (Colstrip Enel 14.0 14.0 14.0 14.0 14.0 14.0 11.8 9.6 9.6 9.6 14.0 14.0
N-32 (Northside Canal)0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Nichols Gap 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Exhibit __Page 1?nf 15
Simplo!.Exergy,C'"
On Cross Examina...
Nine Canyon 2.7 2.1 2.4 2.8 3.0 2.6 3.1 3.1 3.5 3.1 3.2 3.1
North Fork Sprague River 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
North Valmy 1 127.0 127.0 127.0 127.0 127.0 127.0 106.7 86.4 86.4 86.4 127.0 127.0
North Valmy 2 129.0 129.0 129.0 129.0 129.0 129.0 108.4 87.8 87.8 87.8 129.0 129.0
Northeast 1 31.1 31.8 32.5 33.0 33.0 32.7 29.8 26.9 26.5 26.1 30.7 30.6
Northeast 2 31.1 31.8 32.5 33.0 33.0 32.7 29.8 26.9 26.5 26.1 30.7 30.6
Old Faithful 1 &2 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8
Olympic View 1 &2 5.2 5.2 5.2 5.2 5.2 5.2 5.2 5.2 5.2 5.2 5.2 5.2
Opal Springs 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Owyhee Dam 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Owyhee Tunnel No.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Pasco (Franklin/Grays)GT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Pasco (Franklin/Grays)GT .0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Pasco (Franklin/Grays)GT 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Pasco (Franklin/Grays)GT·0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Plummer Forest Products 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Point Whitehorn 2 83.8 85.8 87.7 88.9 89.0 88.2 76.7 65.3 64.2 63.2 82.7 82.5
Point Whitehorn 3 83.8 85.8 87.7 88.9 89.0 88.2 76.7 65.3 64.2 63.2 82.7 82.5
Port Westward CC1A &1B 400.9 410.8 420.0 425.5 426.0 422.2 367.0 312.4 307.2 302.6 395.7 395.1
Portneuf River 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Potholes East Canal 66.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Potholes East Canal Head",0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Potlatch (Lewiston)1 - 4 53.3 53.3 53.3 53.3 53.3 53.3 53.3 53.3 53.3 53.3 53.3 53.3
Prather Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Raft River I 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5
Rathdrum 1 81.2 83.9 86.3 87.9 88.0 86.8 74.8 63.3 61.9 60.7 78.9 79.1
Rathdrum 2 81.2 83.9 86.3 87.9 88.0 86.8 74.8 63.3 61.9 60.7 78.9 79.1
River Road Generating Plar 233.4 239.1 244.5 247.7 248.0 245.8 213.6 181.9 178.8 176.1 230.4 230.0
Rock Creek #1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Rock Creek #2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Rock River I 2.1 1.6 1.9 2.2 2.3 2.0 2.4 2.4 2.7 2.4 2.5 2.4
Ross Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Rough &Ready Lumber 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1
Rupert Cogeneration 9.2 9.5 9.8 10.0 10.0 9.9 8.5 7.2 7.0 6.9 9.0 9.0
Russell D.Smith 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Salmon 1 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9
Salmon 2 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9
Exhibit __Page 13 of 15
Simplot,Exergy,Clearwater
On Cross Examination
Savage Rapids Diversion 0.4 0.5 0.6 0.7 0.7 0.5 0.5 0.5 0.6 0.6 0.6 0.6
Shasta River 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Short Mountain 1 -4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4
Shoshone/Shoshone II 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Sierra Pacific (Aberdeen)9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1
Sierra Pacific (Fredonia)2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8
Skookumchuck 0.3 0.4 0.5 0.5 0.5 0.4 0.4 0.4 0.5 0.5 0.4 0.5
Slate Creek 1.4 1.8 1.6 2.0 2.3 1.8 2.1 2.3 3.0 2.8 2.8 2.5
South Dry Creek 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
St.Anthony 0.2 0.2 0.2 0.2 0.3 0.2 0.3 0.3 0.4 0.3 0.3 0.3
Stateline 12.7 9.9 11.5 13.0 13.9 12.2 14.4 14.4 16.3 14.4 15.0 14.4
Sumas Energy 115.8 118.6 121.3 122.9 123.0 121.9 106.0 90.2 88.7 87.4 114.3 114.1
Summer Falls 1 &2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Tenaska Washington Partn,230.6 236.2 241.5 244.7 245.0 242.8 211.1 179.7 176.7 174.0 227.6 227.2
Tiber-Montana 1.6 2.1 1.9 2.4 2.8 2.2 2.5 2.7 3.6 3.3 3.3 3.0
Tieton 4.4 5.8 5.2 6.6 7.6 5.9 6.8 7.4 9.7 9.0 9.0 8.1
Tuttle Ranch (Ravenscroft)0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Twin Falls (TFHA)6.5 8.6 7.6 9.7 11.2 8.6 10.0 10.8 14.2 13.2 13.2 12.0
Twin Reservoirs 1.0 0.0 0.0 0.0 0.0 0.0 0.0 1.0 1.0 1.0 1.0 1.0
U.S.Bankcorp IC1 -IC4 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2
Upriver 4.6 6.0 5.3 6.8 7.8 6.0 7.0 7.6 9.9 9.2 9.3 8.4
Vaagen Brothers Lumber 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7
Vansycle Wind Energy Proj.1.1 0.8 1.0 1.1 1.2 1.0 1.2 1.2 1.4 1.2 1.2 1.2
Wapato Drop 2 (#1)3.0 0.0 0.0 0.0 0.0 0.0 0.0 3.0 3.0 3.0 3.0 3.0
Wapato Drop 3 (#1 -2)2.0 0.0 0.0 0.0 0.0 0.0 0.0 2.0 2.0 2.0 2.0 2.0
Weeks Falls 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Weyerhaeuser (Springfield)22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6
Wheeiabrator Spokane 20.8 20.8 20.8 20.8 20.8 20.8 20.8 20.8 20.8 20.8 20.8 20.8
White Creek 8.5 6.6 7.7 8.7 9.3 8.2 9.7 9.7 11.0 9.7 10.1 9.7
Wild Horse Wind 9.7 7.5 8.7 9.9 10.6 9.3 11.0 11.0 12.4 11.0 11.4 11.0
Wilson Lake 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Wolverine Creek 2.7 2.1 2.5 2.8 3.0 2.6 3.1 3.1 3.5 3.1 3.2 3.1
WSU Grimes Way Central ~2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5
Yellowstone Energy (BGI)18.6 18.6 18.6 18.6 18.6 18.6 18.6 18.6 18.6 18.6 18.6 18.6
Total 11569 11699 11839 11949 11972 11879 10221 8571 8531 8445 11537 11525
Uncommitted IPPs
Exhibit __Page 14 ,.,f 15
Simplot.Exergy.C "
On Cross Examina.
Big Hanaford CC1A-1E 233.4 239.1 244.5 247.7 248.0 245.8 213.6 181.9 178.8 176.1 230.4 230.0
Centralia 1 570.0 570.0 570.0 570.0 570.0 570.0 479.0 388.0 388.0 388.0 570.0 570.0
Centralia 2 670.0 670.0 670.0 670.0 670.0 670.0 563.0 456.0 456.0 456.0 670.0 670.0
Grays Harbor Energy Facilit 611.7 626.8 640.8 649.2 650.0 644.2 559.9 476.7 468.7 461.7 603.8 602.8
Hermiston Power Project 488.8 505.2 519.7 529.4 530.0 522.7 450.5 381.5 372.8 365.5 475.1 476.6
Klamath Cogeneration ProjE 442.7 457.5 470.6 479.4 480.0 473.4 408.0 345.5 337.6 331.1 430.3 431.7
Kiamath Generation Peaker 47.1 48.2 49.3 49.9 50.0 49.6 45.1 40.8 40.1 39.5 46.4 46.4
Klamath Generation Peaker 47.1 48.2 49.3 49.9 50.0 49.6 45.1 40.8 40.1 39.5 46.4 46.4
Mint Farm 300.2 307.6 314.5 318.6 319.0 316.1 274.8 234.0 230.0 226.6 296.3 295.8
Morrow Power 23.5 24.1 24.6 25.0 25.0 24.8 22.6 20.4 20.0 19.7 23.2 23.2
West Point Treatment Plant 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Total 3435 3497 3553 3589 3592 3566 3062 2565 2532 2504 3392 3393
Exhibit __Page 15 of 15
Simplat,Exer9Y,Clearwater
On Cross Examination
Something needs to change about the
way alternative energy is priced in Idaho.
Idahoans are already paying hundreds
of millions of dollars in excess costs
for electricity they may not even need.
Unless something is done,they could
pay millions more.That's why Idaho
Power has asked the Idaho Public
Utilities Commission (IPUC)to update
the way prices are calculated for the
energy Idahoans are required to buy
from wind,solar and other alternative
energy projects.
Federal law requires Idaho Power to buy
electricity from independent producers,
regardless of whether our customers
BY LISA GROW
IDAHO POWER
SENIOR VICE
PRESIDENT
OF POWER SUPPLY
Exhibit5JR.Page 1 of 2
Simplol,Exergy,Clearwater
On Cross Examination
need it or not.To make matters worse,prices for this
energy are set far higher than the price of electricity
read'lly available on the open market or from our own
resources,
The result?Idaho Power customers will pay an
estimated $850 million In additional costs associated
with these purchases overthe next 10 years,Contracts
already signed with alternative energy (primarily
large-scale wind)producers obligate Idaho Power
customers to $4.8 billion in payments over the life of
the contracts,
,~thing'needsto;chailgl!;
Idaho Power has aplanning process for determining
how to best meetcustomers'electricity needs now
and Into the future.We collaborate with community
members and various Interest groups on our
Integrated Resource Plan,which Is updated every two
years.The plan considers all resource options based
on cost,reliability and environmental stewardship.
The requirement to buy energy from these producers
at inflated prices circumvents this public planning
process and results In Idaho Power~customers paying
substantially more for their energy.
Idaho Power recently filed testimony with the IPUC
recommending changes to the way prices are set for
energy from these alternative energy projects.This is
an important issue to all Idaho families and business
owners.We all want reliable,responsible energy.But
we needitatafair price based on its value.
What can you do?
•Learnmore at www.idahopower.com
.•Join the conversation at www.gelpluggedln.com
•Submit your comments to the Idaho Public
Utilities Commlssibn at www.puc.ldaho.gov '
Exhibit__Page 2 of 2
Simplot,Exergy,Clearwater
On Cross Examination
Bill Connors
Ben Olto
Lane Packwood
John Chatbul'n
Representative Elaine Smith
Senator Russ Fulcher
Jim Yost/Shiriey Lindstrom
David Hawk
Ken Miller
Vince Alberdi
REQUEST FOR PRODUCTION NO.65:At page 39 of his rebuttal testimony,
Mr.Stokes makes reference to the IRP Advisory Council.Please provide all documents
relating to the selection of the current IRP Advisory Council.Are the council members
provided with independent,technical staff?
RESPONSE TO REQUEST FOR PRODUCTION NO.65:No documents exist
related to the selection of the IRP Advisory Council ("Council")with the exception of the
list of current members listed below that participated in the preparation of the 2011 IRP:
Customer Representatives
Agricultural Representative....Sid Erwin
Boise State University John Gardner
Heinz Frozen Foods Steve Munn
INL Tom Moriarty
Micron Michael Bick
Simplo!........................................Don Sturtevant
Public Interest Representatives
Boise Metro Chamber of Commerce
Idaho Conservation League ..
Idaho Department of Commerce .
Idaho Office of Energy Resources , .
Idaho State House of Representatives ..
Idaho State Senate ..
Northwest Power and Conservation Council....
Oil/Gas Industry Advisor .
Snake River Alliance .
Water Issues Advisor .
Reaulatorv Commission Representatives
Idaho Public Utilities Commission...Rick Sterling
Public Utility Commission of Oregon Erik Colville
There is routinely some turnover in Council membership between IRP cycles.
Idaho Power strives to maintain a balance on the Council between the interests of all
the different stakeholders.In the next few weeks the Company expects to finalize the
Council membership for its 2013 IRP which begins with the first Council meeting on
August 16,2012.
IDAHO POWER COMPANY'S RESPONSE TO THE SIXTH PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY - 8 Exhibit 5l3.-Page 1 of 2
Simplot,Exergy,Clearwater
On Cross Examination
No,the Council members are not provided with independent technical staff.
The response to this Request was prepared by M,Mark Stokes,Power Supply
Planning Manager,Idaho Power Company,in consultation with Donovan E.Walker,
Lead Counsel,Idaho Power Company:
IDAHO POWER COMPANY'S RESPONSE TO THE SIXTH PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -9 Exhibit __Page20f2
Simplot,Exergy,Clearwater
On Cross Examination
AGREEMENT FOR TRANSFER OF OWNERSHIP OF ENVIRONMENTAL ATTRIBUTES
This Agreement for Transfer of Ownership of Environmental Attributes ("Agreement")is
entered into this ~day of Jla.v ,2011,between Clark Canyon,LLC,an Idaho Limited,
Liability Company,("Clark Canyon")and Idaho Power Company,an Idaho corporation
("Idaho Power"or "Company"),hereinafter sometimes referred to collectively as the "Parties"or
individually as a "Party."
WITNESSETH:
WHEREAS,Clark Canyon is the owner and operator of a to-be-built 4.7 megawatt
("MW")small hydro generation project.
WHEREAS,the Parties entered into that certain Finn Energy Sales Agreement between
Clark Canyon,LLC and Idaho Power Company dated ~v 2.IJ ,2011 whereby Idaho,
Power would purchase the energy output ofthe Facility.
WHEREAS,the FESA Article 8 specifies that ownership of Environmental Attributes is
determined by a separate agreement;
WHEREAS,the Parties desire to enter into this Agreement to transfer the ownership of
the Environmental Attributes that result from electric generation at the Facility beginning in
Contract Year eleven (11)ofthe FESA.
NOW,THEREFORE,in consideration of the mutual covenants contained herein,the
Parties agree as follows:
1.Definitions.The following term as used in this Agreement shall be defined as
follows:
Exhibit 5\~Page 1 of 8
Simplo!,Exergy.Clearwater
On Cross Examination
1.1."Environmental Attributes"means any and all credits,benefits,emissions
reductions,offsets,and allowances,howsoever entitled,attributable to the generation
from the Facility,and its avoided emission of pollutants.Environmental Attributes
include but are not limited to:(1)any avoided emission of pollutants to the air,soil or
water such as sulfur oxides (SOx),nitrogen oxides (NOx),carbon monoxide (CO)and
other pollutants;(2)any avoided emissions of carbon dioxide (CO2),methane (CH4),
nitrous oxide,hydrofluorocarbons,perfluorocarbons,sulfur hexafluoride and other
greenhouse gases (GHGs)that have been determined by the United Nations
Intergovernmental Panel on Climate Change,or otherwise by law,to contribute to the
actual or potential threat of altering the Earth's climate by trapping heat in the
atmosphere;(3)the reporting rights to these avoided emissions,such as and without
limitation,REC (as that term is defined herein)reporting rights.REC reporting rights are
the right of a REC owner or purchaser to report the ownership of accumulated RECs in
compliance with federal or state law,ifapplicable,and to a federal or state agency or any
other party at the REC owner's/purchaser's discretion,and includes,without limitation,
those REe reporting rights accruing under Section 1605(b)ofThe Energy Policy Act of
1992 and any present or future federal,state,or local law,regulation or bill,and
international or foreign emissions trading program.Environmental Attributes are
accumulated on a MWh basis and one REC represents the Environmental Attributes
associated with one (I)megawatt hour ("MWh)of energy.Environmental Attributes do
not include (i)any energy,capacity,reliability or other power attributes from the Facility,
(ii)production tax credits associated with the construction or operation ofthe Facility and
other financial incentives in the form of credits,reductions,or allowances associated with
2
Exhibit ~_Page 2 of 8
Simplot,Exergy,ClealWater
On Cross Examination
the Facility that are applicable to a state or federal income taxation obligation,(iii)the
cash grant in lieu of the investment tax credit pursuant to Section 1603 of the American
Recovery and Reinvestment Act of 2009,or (iv)emission reduction credits encumbered
or used by the Facility for compliance with local,state,or federal operating and/or air
quality permits.
1.2."Contract Year"shall have the same meaning as defined in the FESA.
1.3."Facility"shall have the same meaning as defined in the FESA.
1.4."Renewable Energy Certificate" or "REC"means a certificate,renewable
energy credit or any other credit,allowance,Green Tag,or other transferable indicia,
howsoever entitled,indicating generation of all renewable energy by the Facility,as
detennined by any and all federal and/or state law or regulation, and includes all
Environmental Attributes arising as a result of the generation of electricity by the
Facility.One REC represents the Environmental Attributes associated with the
generation of one thousand (1,000)kWh of Net Energy (as that term is defined in the
FESA).
2.For good and valuable consideration receipt of which the Parties hereby
acknowledge,Clark Canyon agrees to transfer to Idaho Power ownership of all Environmental
Attributes associated with the Facility beginning with the first hour of the first day of the Il lh
Contract Year and for the remaining term ofthe FESA.
3.Environmental Attribute Accounting and Transfers.The Parties shall cooperate to
ensure that all Environmental Attribute certifications,rights and reporting requirements are
created,maintained and completed by the responsible Parties.
3
Exhibit __Page 3 of 8
Simplot,Exergy,Clear\'Iater
On Cross Examination
3.1.Accounting for Environmental Attributes.Each Party,at its sole expense,
will he responsible to establish and maintain a Western Renewable Energy Generation
Information System ("WREGIS")account or other Environmental Attribute account
and/or tracking and reporting system that enables the Environmental Attributes associated
with the Facility to be created,certified,validated,transferred and reported.
3.2.Transfer of Ownership Rights to Idaho Power,For the term ofthe FESA,
the Parties shall cooperate,provide further assurances,and take all necessary
commercially reasonable actions to document,record,create,effect and enable the
transfer of the Environmental Attributes associated with the Facility to Idaho Power's
WREGIS account or any other Environment Attribute accounting and tracking system
selected hy the Parties.
3.3.Ownership Rights.Each Party shall report under Section 1605(b)of the
Energy Policy Act of 1992 or under any applicable program only the Environmental
Attributes that such party owns,and shall at all other times refrain from reporting the
Environmental Attributes owned by the other Party.
3.4 Right of Peaceful Ownership:Neither Party will cause or suffer to be
caused any petition,litigation,action,proceeding or cause,whether before courts,
commissions,legislative bodies,tribunals,councils or any other place that would have
the effect or purpose to take away or diminish the value of the other's ownership of the
Environmental Attributes.
4.Facility Operation.Clark Canyon shall operate the Facility pursuant to
commercially reasonahle business practices and prudent utility practice so as to not jeopardize
the current or future Environmental Attributes created hy the Facility.
4
Exhibit __Page 4 of 8
Simplot,Exergy,Clearwater
On Cross Examination
5.Miscellaneous.
5.1.Several Obligations.Except where specifically stated in this Agreement
to be otherwise,the duties,obligations and liabilities of the Parties are to be several and
not joint or collective.Nothing contained in this Agreement shall ever be construed to
create an association,trust,partnership or joint venture or impose a trust or partnership
duty,obligation or liability on or with regard to either Party.Each Party shall be
individually and severally liable for its own obligations under this Agreement.
5.2.Waiver.Any waiver at any time by either Party ofits right with respect to
a default under this Agreement or with respect to any other matters arising in connection
with this Agreement shall not be deemed a waiver with respect to any subsequent default
or other matter.
5.3.Choice of Law and Venue.This Agreement shall be construed and
interPreted in accordance with the laws of the State of Idaho without reference to its
choice of law provisions.Venue for any litigation arising out of or related to this
Agreement will be in the District Court ofThe Fourth Judicial District ofIdaho in and for
the County ofAda.
5.4.Default.Tfeither Party faUs to perfonn any of the terms or conditions of
this Agreement (an "Event of Default"),the non-defaulting Party shall cause notice in
writing to be given to the defaulting Party,specifYing the manner in which such default
occurred.Ifthe defaulting Party shall fail to cure such default within sixty (60)days after
service of such notice,or if the defaulting Party reasonably demonstrates to the other
party the default can be cured within a commercially reasonable time but not within such
sixty (60)day period and then fails to diligently pursue such cure,then,the
5
Exhibit __Page 5 of 8
Simplot,Exergy,Clearwater
On Cross Examination
non-defaulting Party may,at its option,tenninate this Agreement and/or pursue its legal
or equitable remedies.
5.5.Successors and Assigns.This Agreement and all of the tenus and
provision hereof shall be binding upon and inure to the benefit of the respective
successors and assigns of the Parties hereto,except that no assignment hereof by either
party shall become effective without the written consent of both Parties being first
obtained.Such consent shall not be unreasonably withheld.Notwithstanding the
foregoing,any party which Idaho Power may consolidate,or into which it may merge,or
to which it may conveyor transfer substantially all of its electric utility assets,shall
automatically,without further act,and without need of consent or approval by Clark
Canyon, succeed to all of Idaho Power's rights,obligations and interests under this
Agreement.
5.6.Modification.No modification to this Agreement shall be valid unless it
is in writing and signed by both Parties and subsequently approved by the Commission.
5.7.Notices.All written notices under this Agreement will be directed as
follows and shall be considered delivered when faxed,ernailed and confirmed with
deposit in the U.S.Mail,first class,postageprepaid,as follows:
6
Exhibit __Page 6 of 8
Simplot,Exergy,Clearwater
On Cross Examination
To Clark Canyon:
Original document to:
Clark Canyon Hydro,LLC
CIO Symbiotics,LLC
Kim Johnson
2000 S.Ocean Blvd #103
DelRay Beach,Florida 33438
Telephone:[phone]
E-mail:vince.lamarrn@symbioticsener!!Y.com
E-mail copy:[e-mail]
To Idaho Power:
Original docwnent to:
Vice President,Power Supply
Idaho Power Company
POBox 70
Boise,Idaho 83101
Email:[e-mail]
Copy ofdocument to:
Cogeneration and Small Power Production
Idaho Power Company
PO Box 10
Boise.Idaho 83701
E-msil:[e-mail]
5.8.Severability.The invalidity or unenforceability of any tenn or provision
of this Agreement shall not affect the validity or enforceability of any other terms or
provision and this Agreement shall be construed in all other respects as if the invalid or
unenforceable term or provision were omitted.
7
Exhibit __Page 7 of 8
Simplot,Exergy,ClealWater
On Cross Examination
5.9.Counterparts.This Agreement may be executed in two or more
counterparts,each of which shall deemed an original but all of which together shall
constitutes one and the same instnnnent.
5.10.Entire Agreement.Unless otherwise provided for herein,this Agreement
constitutes the entire Agreement of the Parties concerning the subject mailer hereof and
supersedes all prior or contemporaneous oral or wrillen agreements between the Parties
concerning the subject mailer hereof.
IN WITNESS WHEREOF,The Parties hereto have caused this Agreement to be
executed in their respective names on the dates set forth below:
By
Idaho Power Compl!!!v
~iA ~(k-AJ-A )-U LiSB A Grow
Sr.Vice President,Power Supply
Clark Canyon,LLC.
Dated Dated
1;;-18-II
"Idaho Power"
8
EXhibil __Page 8 of 8
Simplot,Exergy,Clearwater
On Cross Examination
•~AtianticPowei-__..Corporation
press release
projects will become increasingly difficult without imminent passage of federal clean energy
legislation.A federal incentive backing this project,the Treasury Grant,is expiring at year's
end.Extending that program and other federal incentives would provide the long-term
certainty that investors and manufacturers such as GE need to ensure continued expansion
of renewable energy throughout the country."
Construction of the Idaho project is well under way.Workers are delivering wind turbine
blades,towers and other components;they are installing foundations and footings for the
turbine towers,building access roads,preparing interconnection lines with idaho Power's
grid and readying a site for a new power substation.The project will use GE's 1.5-megawatt
turbines,over 13,500 of which have been installed worldwide.In addition to supplying the
turbines,GE will provide operational and maintenance services.
"We have worked long and hard with our partners,including local landowners,contractors
and suppliers,to create this historic project,"said James Carkulis,president and CEO of
Exergy,which conceptualized,planned and engineered the project over the last five years.
"We wanted from the outset to make the right kind of difference in the lives of the people
who live here,and we take great pride in our corporate responsibility,sensitivity to the local
environment,and promotion of traditional Idaho and community values."
Lisa Grow,Idaho Power's senior vice president of Power Supply,stated:"Clean,renewable
energy has been Idaho Power's focus since its founding nearly 100 years ago.We started
with hydroelectric power and,through diligent planning,have expanded into the next
generation of alternative energy sources,from this new wind project to solar,geothermal
and biomass.Our balanced generation portfolio is not only the environmentally responsible
way of doing business but ensures we can offer our customers some of the lowest rates in
the nation while providing reliable energy services."
About GE Energy Financial Services
GE Energy Financial Services'experts invest globally across the capital spectrum in
essential,long-lived and capital-intensive energy assets that meet the world's energy
needs.In addition to capital,GE Energy Financial Services offers the best of GE's technical
know-how,technology innovation,financial strength and rigorous risk management.Based
in Stamford,Connecticut,the GE business unit helps its customers and GE grow through
new investments,strong partnerships and optimization of its $21 billion in assets.For more
information,visit www.geenergvfinancialservices.com.
GE
Energy Financial.5ervices
\Ifl.WJ.geenergyfinanclalservices.com
Continued:page 2of 4
2
Exhibit No.S IS Page 1 of 2
Simplot,Clearwater,Exergy
On Cross Examination
/
~AtianticPowerCa<poraUon
press release
FARMING THE WIND NEAR THE OREGON TRAIL:IDAHO'S GOVERNOR,GE AND
PARTNERS LAUNCH STATE'S LARGEST WIND POWER PROJECT
BLISS,Idaho,Aug.24,2010 -Transforming arid farmland into land yielding clean power
and jobs,Gov.C.L."Butch"Otter joined executives of GE (NYSE:GE)and its partners
today to celebrate the start of construction of the state's largest wind power project,10 miles
from the Oregon Trail where American pioneers pushed westward across the continent.
The governor -joined by project investors GE Energy Financial Services,Reunion Power,
Exergy Development Group and Atlantic Power Corp.(TSX:ATP,NYSE:AT)-signed a
turbine blade in Bliss to celebrate the new jobs and economic development this project is
bringing to the area.The 183-megawatt,122-turbine project comprises 11 wind farms,
spread across 10,000 acres of active and inactive farmland in southern Idaho's Magic
Valley.The valley was a predominant migration route as part of the Oregon Trail in the 19th
century,and is becoming a critical renewable energy corridor in the 21 Sl century.
The wind energy project,initiated by Exergy Development Group and slated for completion
by year's end,is expected to create 175 construction jobs as well as permanent
employment for operations and maintenance.In addition to the people employed directly,a
National Renewable Energy Laboratory model estimates that a wind project of this size
would typically support the equivalent of 2,200 full-time jobs in the United States for one
year-about half of which would be in-state-and create 25 permanent jobs.The project
also benefits the environment:It will produce enough power for 39,700 average Idaho
homes and-according to US Environmental Protection Agency methodology-avoid
331,000 short tons a year in greenhouse gas emissions.That's the equivalent of taking
about 57,000 cars off the road.
"The renewabie energy industry is breathing new life into the Idaho frontier,"said Gov.Oller.
"We're aggressively harnessing our abundant natural resources for growth because that
helps our economy,generating not only electricity but career opportunities right here at
home."
GE Energy Financial Services,Atlantic Power,and project developer Exergy own non­
managing member equity interests in the nearly $500 million Idaho Wind project.Reunion
Power holds the managing member equity interest and serves as the project's manager.
The wind farms will sell all of their power to Idaho Power Company under 20-year
agreements.Once completed,the portfolio is expected to qualify for the federal Treasury
Grant program designed to stimulate renewable energy projects.
"While we are delighted to embark on this new renewable energy project in Idaho,"said GE
Energy Financial Services President and CEO Alex Urquhart,"we are concerned that such
GE
Energy Financial Services
WYNI.geenergyflnClnclolservices.com
Page 1 of 4
Exhibit NO.2.1£Page 1 of 2
Simplot,Clearwater,Exergy
On Cross Examination
Idaho Power Company 3.Idaho Power Today
For the second 10 years of the agreement (2018-2027),Idaho Power is entitled to 51 percent of the total
RECs generated by the project.
Neal Hot Springs Geothermal Project
In May 2010,the IPUC approved a PPA for approximately 22 MW of nameplate generation from the
Neal Hot Springs Geothermal Project located in eastem Oregon.The Neal Hot Springs project is under
development and is expected to begin commercial operations in 2012.Under tile PPA,Idaho Power
receives all the RECs from the project.
Clatskanie Energy Exchange
In September 2009,Idaho Power and the Clatskanie People's Utility District (Clatskanie PUD)
in Oregon entered into an energy exchange agreement.Under the agreement,Idaho Power receives the
energy as It Is generated from the newly constructed 18-MW power plant at Arrowrock Dam on the
BoIse River;and in exchange,Idaho Power provides Clatskanie PUD energy of equivalent value
dellvered seasonally-primarily during months when Idaho Power expects to have surplus energy.
An energy bank account is maintained to ensure a balanced exchange between the parties where the
energy value will be determined using the Mid-Columbia market price index.The Arrowrock project
began generaling in January 2010,and the agreement term extends tllfough 2015.Idaho Power also
retains the right to renew tlle agreement tllfough 2025.The Arrowrock project is expected to produce
approximately 81,000 MWh annually.
Public Utility Regulatory Policies Act
In 1978,Congress passed PURPA requiring investor-owned electric utilities to purchase energy from
any qua!lfying facility (QF)that delivers energy to tlle utility.A QF is defined by FERC as a small
renewable-generatlon project or small cogeneration project.Individual states were tasked with
establishing the PPA terms and conditions,Including price,that each state's utilities are required to pay
as part of the PURPA agreements.Because Idaho Power operates in both Idaho and Oregon,
tlle company must adhere to both tlle IPUC rules and regulations for all PURPA facilities located In the
state of Idaho,and the OPUC rules and regulalions for all PURPA facilities located in the state of
Oregon.The rules and regulatlons are simllar,but not identical,for the two states.Because Idaho Power
cannot accurately predict tlle level of future PURPA development,only signed contracts are accounted
for in Idaho Power's resource planning process.
Generation from PURPA contracts has to be forecasted early In the IRP planning process to update the
load and resource balance.The forecast used in tlle 2011 IRP was completed in September 2010 and did
nOiinclude approximately 500 MW of wind contracts tllat were signed In late 2010.Because
Idaho Power's future resource needs are driven by capaclly requirements and not energy,the exclusion
of these new contracts does not have a material Impact on the 201 I IRP.At the 5-percent peak-hour
capacity factor used for wind resources for planning purposes,the 500 MW of PURPA wind contracts
represent oniy 25 MW of capacity for peak-hour planning.
As of March 31,2011,Idaho Power had 127 PURPA contracts with independent developers for
approximately 1,190 MW of nameplate capacity.The PURPA generation facilities consist of low-head
hydroelectric projects on various Irrigation canals,cogeneration projects at industrial facilities,wInd
projects,anaerobic digesters.landfill gas.wood-burning facilities,solar projects,and various other
small,renewable-power projects.Of the 127 contracts,91 were on line as of March 31,2011,with a
cumulative nameplate rating of apprOXimately 491 MW.Figure 3.4 shows tlle total nameplate capacity
of each resource type under contract.Figure 3.4 includes 294 MW from 13 PURPA wInd contracts that
were recently disapproved by tlle IPUC.Additional details on these contracts are presented in the
next section.
20111RP "]Page 33
Exhibit ~page 1 of 1
Simplol.Clearwater,Exergy
On Cross Examination
REQUEST FOR PRODUCTION NO.66:On page 46 of his rebuttal testimony
Mr.Stokes states that "The Commission has specifically found this [liquidated damages]
requirement to be in the public interest and a just and reasonable requirement of the
contracting process."Please provide copies of,or citations to,where the Commission
"specifically"made those findings,
RESPONSE TO REQUEST FOR PRODUCTION NO.66:Please See Idaho
Power's Legal Brief filed in this proceeding on July 20,2012,pp.27-32,
Delay liquidated damages provisions have been
included in PURPA FESA contracts approved by the
Commission since at least 2007.See,Case No.IPC-E-06­
36.In addition,one of the first Commission approved
FESAs to contain terms requiring the project to post liquid
security was the FESA for Cassia Gulch Wind Park and
Tuana Springs Energy,Case No.IPC-E-09-24.In that case
the Commission approved provisions requiring the posting of
liquid security in the amount of $20 per kW of project
capacity,
The Commission considered and approved provisions
providing for the posting of liquid security in the amount of
$20 per kW of project capacity in at least four other PURPA
FESAs.See,Case No,IPC-E-09-18,IPC-E-09-19,IPC-E­
09-20,IPC-E-09-25.The Commission has since analyzed
and approved provisions requiring the posting of liquid
security in the amount of $45 per kW of nameplate capacity
in at least twenty-seven different PURPA FESAs,See,Case
No,IPC-E-10-02,IPC-E-10-05,IPC-E-10-15,IPC-E-10-16,
IPC-E-10-17,IPC-E-10-18,IPC-E-10-19,IPC-E-10-22,IPC­
E-10-26,IPC-E-10-37,IPC-E-10-38,IPC-E-10-39,IPC-E-10­
40,IPC-E-1 0-41,IPC-E-10-42,IPC-E-10-43,IPC-E-10-44,
IPC-E-10-45,IPC-E-10-47,IPC-E-10-48,IPC-E-10-49,IPC­
E-10-50,IPC-E-11-09,IPC-E-11-10,IPC-E-11-25,IPC-E-11­
26,and IPC-E-11-27.In ap rovin the change in the
amount of delay damage secun y t 61e for sch
con rac _~rom 0 of nameplate capacity,the
Comniission specifically found such delay security to be
reasonable,necessary,and not to be punitive.Order No.
31034,p 3-4,Case No.IPC-E-10-02 (2010).
Idaho Power's Legal Brief,Case No.GNR-E-11-03,pp.27-28.
The response to this Request was prepared by Donovan E.Walker,Lead
Counsel,Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SIXTH PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -10
Exhibit~Page 1 of 1
Simplot,Clearwater,Exergy
On Cross Examination
Office of the Secretary
Service Date
April 1,2010
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR )CASE NO.IPC-E-10-02
APPROVAL OF ITS FIRM ENERGY SALES )
AGREEMENT WITH CARGILL )ORDER NO.31034
---,I:.:N.:..::C::..:O:::..:RP=..:O:::..:RA:.=T=..:E:::'D==---~)
On January 29,2010,Idaho Power Company ("Idaho Power"or "Company")filed an
Application with the Commission seeking approval,in accordance with Idaho Code §61-503,
RP 52 and the applicable provisions of the Public Utility Regulatory Policies Act of 1978,of its
Fiml Energy Sales Agreement with Cargill Incorporated ("Cargill")under which Cargill would
sell and Idaho Power would purchase electric energy generated by the Bettencourt Dry Creek
Biofactory ("Facility")located near Hansen,Idaho.Application at 1.
On Febmary 25,2010,the Commission issued a Notice of Application and Modified
Procedure with a 21-day comment period.See Order No.31014.Commission Staff was the
only party to submit comments within the established comment period.
THE APPLICATION
"On January 22,2010,Idaho Power and Cargill entered into a Firm Energy Sales
Agreement ("Agreement")...."Id.at 2,Attachment No.1.The Agreement is for a 10-year
term and utilizes "the Non Levelized Published Avoided Cost Rates as currently established by
the Commission for energy deliveries ofless than 10 average megawatts ("MW")."Id.at 3
Idaho Power states that Cargill is an existing Schedule 86 partner providing energy to
the Company and that it will utilize the "compliance data (i.e.,nameplate capacity rating,
engineering celtification,insurance certificates,etc.)previously provided under the Schedule 86
requirements"to review and use for compliance with this Agreement if applicable.Id.
"The nameplate rating of this Facility is 2.25 MW."Id."Cargill will be required to
provide data on the Facility that Idaho Power will use to confirm that under normal and/or
average conditions the Facility will not exceed 10 average MW on a monthly basis."Id.Any
energy that exceeds 10 aMW per month,and that does not exceed the Maximum Capacity
Amount,will be accepted but not purchased or paid for by Idaho Power.Id.
The Scheduled Operation Date for the Agreement is 30 days after the approval of the
Agreement by the Commission.Id.The Agreement includes a fOlmula for the assessment and
ORDER NO.31034 1 Exhibit -.51.91 of 5
Simplot,Clea"vater,Exergy
On Cross Examination
calculation of Delay Liquidated Damages and associated Delay Security provisions if Cargill
fails to achieve the targeted Operation Date.Id.;see also Article V of the Agreement.The
Agreement states that it is effective once "the Commission has approved all of the Agreement's
terms and conditions and declared that all payments Idaho Power makes to Cargill for purchases
of energy will be allowed as prudently incurred expenses for ratemaking purposes."Id.at 4.
The Agreement places various conditions and requirements in order for Idaho Power
to accept energy from Cargill.Id.Idaho Power states that if the Commission approves the
Agreement the effective date of the Agreement will be January 22,2010.Id.
The Agreement includes non-Ievelized published avoided cost rates consistent with
past applicable IPUC Orders.Id.Interconnections with the Facility and applicable charges have
been completed in accordance with the parties'existing Schedule 86 agreement transacted in
2008.Id.
STAFF COMMENTS AND RECOMMENDATION
Staff reviewed the Agreement and found "that the rates contained therein are
consistent with the currently-approved non-Ievelized published avoided cost rates for projects
smaller than 10 aMW."Staff Comments at 2.Staff noted that,with one exception,the essential
terms and conditions "included in the Agreement are identical to those contained in recent
PURPA contracts approved by the Commission."Id.at 2-3.
Staff remarked that the amount of Delay Security required under the contract was the
one unique feature that distinguished this Agreement from other similar types of agreements
presented by Idaho Power to the Commission for approval.Id.at 3.The amount of Delay
Security in this Agreement is "equal to the greater of $45 per kW or the sum of three months'
estimated revenue."Id.The total Delay Security is estimated to be approximately $101,250.Id.
In previous contracts,the Company required Delay Security in the amount of $25 per kW.Id.
"Delay Liquidated Damages would be assessed if the Facility failed to come online within 90
days following the Scheduled Operation Date."Id.
Staff commented that Idaho Power's Firm Energy Sales Agreements for PURPA
projects did not include a Delay Liquidated Damages penalty until around 2006.Id.Idaho
Power has included the penalty as the result of several PURPA projects failing to achieve their
scheduled operation date.Id.
ORDER NO.31034 2 Exhibit 2 of 5
Simplot,Clearwater,Exergy
On Cross Examination
The increase in the amount of Delay Security arose from Idaho Power's estimation
that $25 pel'kW did not provide adequate damages for delay or a sufficient incentive for project
owners to actually meet the scheduled operation date.[d.Idaho Power settled upon the $45 per
kW after researching "the security levels required by ten other electric utilities throughout the
U.S.in their renewable energy procurements and contracts."[d.Only one of the utilities
sampled required security less than $25 per kW,while the other nine utilities required security of
at least $50 pel'kW.[d.Staff believes that the $45 per kW amount is reasonable because it is
"high enough to cover possible damages and to motivate owners to complete projects on time,
yet not so high as to make it too difficult for owners and developers to post the security and
obtain project financing."[d.
Staff also noted that delay security and damages for the BettencoUlt Dry Creek
project will not be an issue because the Facility is "already online and selling to Idaho Power
under a Schedule 86 agreement...."[d.Nevertheless,Staff commented on the deviation from
prior agreements because Staff believes that "Idaho Power is seeking endorsement of the higher
security requirement in this Agreement with the intent of including it in future contracts."[d.at
4.
Staff reconunended that the Commission approve Idaho Power's Firm Energy Sales
Agreement with Cargill and declare that all payments Idaho Power makes to Cargill for
purchases of energy be deemed plUdently incurred expenses for ratemaking purposes.[d.
COMMISSION DECISION AND FINDINGS
The Commission has reviewed and considered the filings in Case No.IPC-E-IO-02,
including the underlying Agreement submitted for approval and Staff comments.Idaho Power
has presented a Finn Energy Sales Agreement with Cargill for the Commission's consideration.
The Agreement stipulates that Cargill will continue to provide and Idaho Power will continue to
purchase 10 aMW or less of electric energy on a monthly basis.
The Commission acknowledges Staffs comments regarding the relative increase in
<
the amount of delay security and liquidated damages contemplated in this Agreement.The
Commission finds that the increase in the Delay Security included in this Agreement is
reasonable and necessary.Adequate Delay Security acts not only as an incentive for PURPA
project owners to complete their projects on time,but it can also mitigate any additional costs
which might arise when a utility is forced to purchase substitute power on the open market.
ORDER NO.31034 3 Exhibit ~3 of 5
Simplot.ClealWater.Exergy
On Cross Examination
However,the Commission reiterates its prior admonition that "such provisions calling for delay
security should not be punitive"and "should constitute a fair and reasonable offset of a regulated
utility's estimated increase in power supply costs attributable to the PURPA supplier's failure to
meet its contractually scheduled operation date."Order No.30608.
Accordingly,the Commission finds that Idaho Power's Agreement to purchase
electric energy from Cargi1l's Bettencourt Dry Creek Biofactory contains acceptable contract
terms,including the non-Ievelized published rates previously approved by the Commission.See
Order No.30480.The Commission also finds that payments made by Idaho Power pursuant to
the terms of the Agreement are deemed prudently incurred expenses for ratemaking purposes.
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jurisdiction over Idaho Power,an electric
utility,and the issues raised in this matter pursuant to the authority and power granted it under
Title 61 of the Idaho Code and the Public Utility Regulatory Policies Act of 1978 ("PURPA").
The Commission has authority under PURPA and the implementing regulations of
the Federal Energy Regulatory Commission ("FERC")to set avoided costs,to order electric
utilities to enter into fixed-term obligations for the purchase of energy QFs and to implement
FERC rules.
ORDER
IT IS HEREBY ORDERED that Idaho Power Company's Firm Energy Sales
Agreement with Cargill Incorporated is approved.
THIS IS A FINAL ORDER.Any person interested in this Order (or in issues finally
decided by this Order)may petition for reconsideration within twenty-one (21)days of the
service date of this Order with regard to any matter decided in this Order.Within seven (7)days
after any person has petitioned for reconsideration any other person may cross-petition for
reconsideration.See Idaho Code §61-626.
ORDER NO.31034 4 Exhibit __4 of 5
Simplot,Clearwater,Exergy
On Cross Examination
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this /st
day of April 201 O.
~v8:4L
MARSHA H.SMITH,COMMISSIONER
MACK fl..REDFO~CO
ATTEST:
O:IPC·E·IO·02_"p2
ORDER NO.31034 5 Exhibit 5 of 5
Simplot,Clearwater,Exergy
On Cross Examination
KRISTINE A.SASSER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE,IDAHO 83720-0074
[phone]
BARNO.6618
Street Address for Express Mail:
472 W.WASHINGTON
BOISE,IDAHO 83702-5918
Attorney for the Commission Staff
RECEIVED
2012 JUL 10 PH 3:S5
IDAHO PUBliCUTILITIESCOMMISSiO/l:
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR APPROVAL )
OF A FIRM ENERGY SALES AGREEMENT )
WITH YELLOWSTONE POWER,INC.FOR )
THE SALE AND PURCHASE OF ELECTRIC )
ENERGY.)
--------------)
CASE NO.IPC-E-IO~22
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staffofthe Idaho Public Utilities Commission,by and through its
attorney ofrecord,Kristine A.Sasser,Deputy Attorney General,and in response to the Notice
of Filing and Notice of Modified Procedure issued in Order No.32573 on June 19,2012,in Case
No.IPC-E-IO-22,submits the following comments.
BACKGROUND
On May 4,2004,the Commission approved a Finn Energy Sales Agreement (FESA)
between Idaho Power and"Renewable Energy of Idaho,Inc.("Renewable Energy")for a 17.5
megawatt (MW)biomass generating facility to be located at the old Boise Cascade Plant site
near Emmett,Idaho.Order No.29487.The FESA subsequently went into default and was
terminated by Idaho Power after Renewable Energy failed to meet its scheduled operation date.
Renewable Energy claimed its inability to meet the scheduled operation date was due to reasons
•beyond its control.Idaho Power determined that the project had incurred damages in the amount
STAFF COMMENTS JULY 10,2012
Exhibit 50l0page 1of 7
Simplol,Exergy,Crearwater
On Cross Examinalion
of$106,804 for Renewable Energy's non-perfonnance.Renewable Energy was unable to pay
the assessed damages.
On August 13,2010,Idaho Power filed an Application with the Commission requesting
approval ofa IS-year FESA between Idaho Power and Yellowstone Power for an 11.7 MW
biomass fueled combined heat and power generator located at the same site as the Renewable
Energy project.Richard Vinson,a principal of Yellowstone Power,was also a principal of
Renewable Energy.Mr.Vinson agreed,as part of the Yellowstone FESA negotiations,to pay
the non-performance damages of the Renewable Energy FESA as an offset to the energy
payments Yellowstone was to receive in its FESA.On November 2,20I0,the.Commission
approved the FESA between Idaho Power and Yellowstone,including the payment by
Yellowstone ofRenewable Energy's $106,804 in non-perfonnance damages.Order No.32104.
Yellowstone chose a scheduled operation date ofDecember 31,201 I.In addition,the FESA
required Yellowstone to post a delay liquidated damages deposit in the amount of$450,000.
Yellowstone timely posted this required deposit in the form of a Letter ofCredit.
Yellowstone has failed to achieve its December 31,20II,scheduled operation date.On
May 3,2012,Idaho Power sent Yellowstone a notice ofmaterial breach for failing to achieve its
scheduled operation date and stating that it would collect on the Letter of Credit by May 10,
2012,if Yellowstone failed to cure the material breach.Yellowstone responded by alleging that
aforce majeure event had occurred.Settlement discussions between the parties ensued.
On May 31,2012,Idaho Power Company and Yellowstone Power,Inc.filed amotion
requesting that the Commission accept a Settlement Stipulation ("Settlement")entered into
between the parties.The Settlement Stipulation provides for tennination ofthe FESA between
Idaho Power and Yellowstone Power and mutual release of any future claims or causes ofaction
between the parties.Yellowstone agrees to pay Idaho Power $200,000 for its material breach of
the FESA,which amount includes Renewable Energy's pre-existing debt of$106,804.If
Yellowstone fails to make the $200,000 payment then Yellowstone agreeS to allow Idaho Power
to draw on the current $450,000 Letter ofCredit.Idaho Power and Yellowstone state that the
Settlement Stipulation is in the public interest and that all ofits terms and conditions are fair,
just,and reasonable.
STAFF COMMENTS 2 JULY 10,2012
Exhibit __Page 2 of7
Simplot,Exergy,Clearwater
On Cross Examination
STAFF ANALYSIS
Staffbelieves that because the project has not achieved operation within 90 days ofthe
scheduled operation date,the project is in material breach and Idaho Power is entitled to
terminate the FESA.In addition,Article 5.3 ofthe FESA specifies that delay damages of$45
per kilowatt maximum capacity ($45 x 10,000 kW =$450,000)are due and payable to Idaho
Power as delay liquidated damages.Idaho Power provided notice to the project of the material
breach,and termination ofthe FESA,as well as the utility's request for payment ofthe $450,000
delay liquidated damages.The project responded to the notification of material breach with a
claim ofjorce majeure regarding its non-performance in the contract,as well as a draft complaint
for Idaho District Court challenging the legality of the liquidated damages in the contract.
Yellowstone,in its May 15,20121etter to Idaho Power alleges that conditions beyond its
control have made it impossible to complete the project and achieve the scheduled operation date
specified in the FESA.Yellowstone cites the following conditions that have prevented
construction ofthe facility:
•Availability of Financing -Yellowstone created an extensive financing package,
employed lending specialists,and marketed to a wide variety oflocal/national banks,
venture capitalist,private equity,and hedge funds related to this project.Despite these
efforts,the unpredictable change in lending protocols following the banking crisis and
resulting extended national economic recession restricted the availability of financing
funds for projects such as Yellowstone Power and funds became severely limited.
•1603 Grant In-Lieu Credit-The Section 1603 grant in lieu.credit adversely impacted
conventional lending for projects such as Yellowstone Power by attracting predatory
investors to the market.Combined with the unpredictable change in conventional
lending protocols,available fmancing was further reduced.
•Renewable Energy Credits -Due to the unexpected prolific installation ofwind power
experienced by many utilities,the value ofrenewable energy credits (RECs)decreased
dramatically.The revenue contemplated by Yellowstone Power from the sale ofRECs
was adversely affected by the installation ofwind generation.
•Emerald ·Forest Sawmill-Significant revenue and fuel sourcing was contemplated
from the Emerald Forest Sawmill.This facility experienced significant operating
problems during its start-up and eventually had to seek protection under Chapter II
Bankruptcy.The loss of this revenue and fuel source had a significant impact on the
ability of the project to attract financing due to its close proximity to the proposed
Yellowstone Power project.
STAFF COMMENTS 3 JULYIO,2012
Exhibit __Page 3 of 7
Simplot,Exergy,Clearwater
On Cross Examination
Yellowstone alleges that the combination ofchanged conditions are beyond its control and
constitute an event offoree majeure.
For reference,the terms ofthe FESArelating toforee majeure are repeated below.
ARTICLE XIV:FORCE MAJEURE
14.1 As used in this Agreement,"Force Majeure"or "an event ofForce Majeure"means
any cause beyond the control of the Seller or ofIdaho Power which,despite the
exercise ofdue diligence,such Party is unable to prevent or overcome.Force
Majeure includes,but is not limited to,acts of God,fire,flood,storms,wars,
hostilities,civil strife,strikes and other labor disturbances,earthquakes,fires,
lightning,epidemics,sabotage,or changes in law or regulation occurring after the
effective date,which,by the exercise of reasonable foresight such party could not
reasonably have been expected to avoid and by the exercise ofdue diligence,it shall
be unable to overcome.If either Party is rendered wholly or in part unable toperform
its obligations under this Agreement because ofan event ofForce Majeure,both
Parties shall be excused from whatever perfonnance is affected by the event ofForce
Majeure,provided that:
(1)The non-performing Party shall,as soon as is reasonably possible after the
occurrence of the Force Majeure,give the other Party written notice
describing the particulars ofthe occurrence.
(2)The suspension ofperformance shall be ofno greater scope and of no longer
duration than is required by the event of Force Majeure.
(3)No obligations ofeither Party which arose before the occurrence causing the
suspension ofperformance and which could and should have been fully
performed before such occurrence shall be excused as a result of such
occurrence.
In response to production requests,Idaho Power states that it does not believe that
Yellowstone has provided evidence that aforee majeure event has occurred that would provide
the project relieffrom perfonnance as required by the contract.Staffagrees.The inability of
Yellowstone to obtain financing,the decrease in value of RECs,and the bankruptcy of the
associated Emerald Forest Sawmill are not the types ofthings Staffbelieves are,envisioned by
theforee majeure provisions ofthe FESA.
Staff believes that Idaho Power is entitled to collection ofthe full amount of the Delay
Liquidated Damages ($450,000),in addition to the pre-existing debt of$106,804.Under the
tenns of section 5.6 ofthe contract,the parties have agreed that the damages Idaho Power would
incur due to delay in the facility achieving the scheduled operation date would be difficult or '
impossible to predict with certainty,and that the delay liquidated damages are an appropriate
approximation of such damages.
STAFF COMMENTS 4 JULY 10,2012
Exhibit_~Page 4 of 7
Simplot,Exergy,Clearwater
On Cross Examination
However,Idaho Power believes that the actual collection of those damages could require
additional legal proceedings prior to the Company being able to secure full payment for the
damages.As noted earlier,Yellowstone has threatened to file a complaint in Idaho District
Court challenging the legality ofthe liquidated damages in the contract.Yellowstone might
argue that the actual damages incurred by Idaho Power could be quantified at less than the
$450,000 delay liquidated damages amount specified in the contract.
The proposed Settlement collects $106,804 ofpreviously uncollectable damages from a
defaulted agreement and provides approximately $93,196 in damages for default of the current
agreement.Consequently,the proposed settlement amount falls $356,804 short ofthe $556,804
amount Staff believes is rightfully owed by Yellowstone to Idaho Power pursuant to the terms of
theFESA.
Nonetheless,the proposed Settlement eliminates the uncertainty and additional cost and
resources necessary to litigate the termination ofthe agreement and validity ofthe delay
liquidated damages.While Staffwould normally be reluctant to recommend approval of a
settlement that appears inconsistent with the express terms ofthe contract,Staffrecognizes that
.the current circumstances may support acceptance ofthe proposed Settlement.Currently,
electric market prices are far below the avoided cost rates specified in the contract.
Consequently,the actual damages to Idaho Power as a result ofcontract default are likely
minimal,and in fact,Idaho Power could arguably be better off because Yellowstone has
defaulted.The terms of the proposed Settlement acknowledge some liability for Yellowstone's
default while also acknowledging some uncertainty about the actual amount ofdamages to Idaho
Power.Approval ofthe proposed Settlement will also avoid litigation.Consequently,Staff
believes that the proposed Settlement is in the public interest.
RECOMMENDATIONS
Staffrecommends approval of the Settlement Stipulation between Idaho Power and
Yellowstone Power.
STAFF COMMENTS 5 JULY 10,2012
Exhibit __Page 5of 7
Simplot,Exergy,Cleal'\vater
On Cross Examination
Respectfully submitted this
Technical Staff:Rick Sterling
i:umisc:commentslipcelO.22ksrps comments
OU!I day ofJuly 2012.
Kristme A.Sasser
Deputy Attorney General
STAFF COMMENTS 6 JULY 10,2012
Exhibit __Page 6of 7
Simplot,Exergy,Clearwater
On Cross Examination
FIRM ENERGY SALES AGREBMIlNT
(Greater than 10aMW)
Project Name:DynamIs AdaCollDty Landlil1 Project
Project Number:2161S4l1ll
TInS AGRBBMBNT,tmtered IDto on this ~day ofp".",.,.....,2011 betweenDyDamIs EncrsY,
LLC,an Idaho limlted IiabWty00lIIJI8DY(Seller),8Dd IDAHO POWER COMPANY,an Idaho OOIJlO%8llon
(Idaho Power),henlInafterllOIIIIIIlmes leflluedto collectively88"PartIes"or IndMiluaIly 88 "PaIty."
WITNESSETH:
WHEREAS,Seller will de8illJl,COIIBlnIcl,own,maintain 8Dd opllI8te an olectricgenenltion fiIci1Ity;and
WHIlRBAS,Sellerwishes to se11,and IdahoPower is willing to pun:base,finiI electric llIIeIIlY produced
by the Sellor'sFacility.
TImREFORB,In consideration ofthe mutual coWllalll8 andapemenls haeInaftorset fonb,the
PartiesagJCO88 follOWll:
ARllCLB I;DHFJNl110NS
As used In this AaJeemenland the 8ppOIldJces attached hacto,the following tenIIS
sha1I baw the following mesnlnp:
1.1 "B1I"'nw Howt'-DallyhoursofS:oG AM to S:OO PM MountainTIme,Mondaythroush Friday
excludlna New YOIlI'II Day,Memorial Day,IndependenceDay,LaborDay,Tbanbglvlng,Cbriatmas
andanyotherIdaho Powerobservedholiday.
1.2 "9m!ml"IOA"-Tho Idaho PublioUliUliesCommIaaion.
1.3 "CgnJnMlt Yem"-Tho periodCOIIIIIIOIIcIngeach calendar yearon the samo calendardateas the
Oporatlon Date and andlDg 364 daya thereafter.
-1-
EXHIBIT~Page I of 5
Dynamis Energy
On Cross Examination
·Example 2 -The Hourly Energy Production amount specified in Appendix B for
181l118J)',hour81s 20 MW.IfDeclared SlI8pOIIBionofBnorgy nollveri081s InItlatod
by tho SoIIor and accepted by Idaho Power that mulls in total shutdown of tho
FacUlty,the Hourly Jlnergy Production will be reduced to 0 MW for this hour end
anyother houn in whlcbtho Declared SIIBpOII8iOD ofEnergy nollveri081s in elfecL
This acijusted Hourly Jlnergy Production amount will be used in applicable SuJpIus I!Dorgy
calClU1al1onaand porformence caIcu\atlona for only tho apecIfic hour in which Idaho Power was
excused from 8CllOpting the Sellor's Net Energy or tho Declared SU8pOIISion of Jlnergy
nollvori081s in effect.
6.3 Beglnnlng with tho fir&t day oftho seventh (7'"month after the Operation Date,IIII10ss oxcuaed by en
IMIIt of Force Ml\Ieure,a Forced Outage,or as Scheduled Msinlellance,Senor delivers hourly Net....'
~ersY to Idaho Power that oxceeda plus or minus 10%of tho Hourly &ersY Produotlon amoun~
specified in Appendix B for more then I)TeD (10)COIIlIOCUl1ve hOUl'll,or 2)Seventy two (72)hoU1'8 in
anyone calendar month tho applicable eDersY price par MWh aha1I be reduced by fifteen perceIIl (\5%)
for all Net Bnorgy and SUlPlus Jlnergy delivered to Idaho Power for all hoU1'8 beginning with tho fir&t
hourafter eitherofthoso criteria has been met and tho reduced cmergy payments I8to aha1I stay in oft'ect
a period oflIOVCD (7)daya.
6.3.\Ifduring this seven (7)day period,elthor of those criteria are again met,a DOW seven (7)day
period ofreduced cmergy payments will begln with tho firat hourafterthocriteriahas boonmet.
6.4 Unless llXGU8ed by an 0YCDt of Force Mllieure.Forced Outage,or Scheduled MaIDleIIaDce SeUor's
failure to deliver 30,000 MWh in anyContm:t Year aha1I COIIIlitute an IMIIt ofdefault.
ARTICLR \TIl;PURCHASB PRICBAND MBTHOD OF PAYMBNf
7.1 Heaw IpM """"'....Pripe For all Heavy Losd Jlnergy accepted by Idaho Power,Idaho Power will
pay tho DOD-lovoIIzod Heavy Losd Purchase Price aa specified in Appendix F.
·14-
EXHIBIT------'Page 2 of5
Dynamis Energy
On Cross Examination
7:J.HoUday !l1pnd'rd P!Irnh''''Price -For all HoUday SllmdanI Bnergy accepted by Idaho Power,Idaho
Power wllI pay tho llou·lovoUzed HoUday Stalldard Punlhase Prioo18 epecIfloclln AppondIx F.
7.3 Light I.f!!mpy Price -Tho SoUer does 1I0t inteIId to ptOduce 8IId doUver Illy LIght Load Enorgy to
Idaho Power.Any Light Load Bnergy producocI by the SoUer 8IId delivered to Idaho Power may 1)be
fCOOIltocI by Idaho Power at 110 00Il to Idaho Power,or 2)Idaho Power may cuital1 all Light Load I
Bnergy de1lYerlea with 110 1101100 provided to the Soller,or 3)tho Soller8IId Idaho Power may mutually
I
agree to lemIs IIIId llOlIdltlOllS of Light Load Bnergy deliveries anillI to tho delivery of Light Load
1lIIO!J!Y.The mUlUal BpeIIIOIIt wI1J spocIfY at minimum tho prIc!11&hours and Qll8lltlty of Light Load
JlIIergyto be delivered to Idaho Power.
7.3.1 The Party requesting Light LOad 1lII0lllY deliveries shal1 providewriltollllOtiticatlOU to tho other
Party during BusinllBS Hours.Thilllotificatioll shal1lncludo desired hoU1'8 of0II0lllY deliveries
IIId proposocl CIIetllY prIOll,tho other party shal1 thOIIlll8pOIIdwithin a Ie88OIIlIblo periodoftime
during BusinllBS H01III.
73:J.Upon mutual agreoment,tho roquostIng Party shal1 provlda a wriltell documOllt aulhorlzecl8lld
Ollec:utocl by 811 appropr!ale rcpresaIIBtiYll.ThIa documOllt must IIIclude the mutually agreed
upon prIo1ng,holD8 ofdalivery and other required lemIs and C()lIditiOllS.The other Party shal1
thOII withill a I'OI8OII8ble tlmo,review and 0lt0CIIle tho provldocl dowmeIItalIOIIIftho l:OIIditlOll8
llJIlaccoptable.
7.3.3 0II1y after tho written documOll1 baa beOII executed by both Plllties aha11 III exoeptiOll to Light
Load llIIergydelivories 18 epecIfled In JIlIIl18%llIIh 7.3 exist.
7.4 Surplus IlnmPrioo -Forall Swplus Bnergy,Idaho Powershal1 pay to tho Sollertho lowerofthe
cUmmt mOllth's MaJbt JlIIergy Roferonoo Priceor elgbty·fiYllpercOIIt (85%)ofthe Holiday Sl8IIdard
Punlhaae Price.
7.5 P"V'Pmrt Due Date -Undisputed 1lII0lllY paymOllts,IllBS my paymOllIl due to Idaho Power will be
dlabuned to tho Seller withill thirty (30)days oftho date which Idaho Power recelvea 8IId accepts tho
documOlllatiOll of the mOllth!y Not Bnergy actually deliYllfocl to Idaho Power 18 speoltiocl ill
AppendlxA.
-IS·
EXHIBIT ~Pnge 3 of 5
Dynamis Energy
On Cross Examination
APPBNDIXB
HOURLY IlNIlRGYPRODUcrION
320 320320320320320320320320320320320
aIIn fill ME eJ1r.MB .IlIn .,M &!II §Ill gg t:Im:QIQ
fM'ta {fltll ~{fltll {fltll tMWl (MllV}(MllV}tMWl tMWl tMWl (MllV}
0 0 0 0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0 0 0 0
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
20 20 20 20 20 20 20 20 20 20 20 20
0 0 0 0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0 0 0 0
Thla tabIo Is a list ofhourlyCl1eIllY lIIllOlIIII8 (mea8llnld inMWs)foresch hour ofa twenty-four (24)hourperiod
ineachIIIOIIlh that will beapplied to all cJays ofthe IIIOIIlh.
IIRJJ!
1
2
3
4
5
6
7
8
•
10
11
12
13
14
15
18
17
18
1.
20
·11
12
23
U
DIlly
EXHlB1T_,Page 4 ofS
Dynamis Energy
On Cross Examination
APPENDIXF
MONrHLYPURCHASB PRICES
MlIIaperKwh
MDnthlYW
Jen-12
Feb-12
Mar·12
Apr:12
May:12
Jun-12
Jul-12
Auo-12
8ep:12
0Ct·12
Nov-12
De0012
Jan-13
Feb-13
Mar-13
Apr::13
MaY-13
Jun-13
Jul-13
.13
S!!p=13
0Ct·13
Nov·13
De0013
Jan-14
Feb-14
Mar·14
Apr::14
M!!Y=14
Jun-14
Jul-14
Auo-14
S!!p=14
Hem'em'Pmb"'PrIM
$84.27
$85.78
$81.16
$78.70
$69.70
$71.77
$83.55
$87.83
$9Q.26
$84.62
$87.80
H8.89
$88.11
$87.76
$83.19
$78.88
$71.21
$73.83
$86.47
$89.91
$91.88
$88.88
$88.88
$87.78
$86.80
$80.92
$72.80
$78.16
$87.08
$91.89
$94.41
HgIIday!!tlmde'"Purr 7PrIce
H1.06
H1.03
$76.88
$73.32
$83.39
$84.29
$77.70
H1.28
$82.51
$81.19
$84.82
$82.30
$82.01
$83.51
$79.45
$74.02
H4.61
$87.88
$79.40
$83.38
$82.47
$80.29
$86.14
H2.98
$84.87
$81.15
$76.58
$!I8.01
$89.27
H1.11
$84.98
$88.47
.46-
EXHIBIT-'Page 5 of5
Dynamis Energy
On Cross Examination
FIRM ENERGY SALES AGREEMENT
(Greater than 10 aMW)
Project Name:Dynamis Ada County Landfill Project
Project Number:21615400
THIS AGREEMENT,entered into on this J'O day of .Nt'bJfI!tt ".-,2011 between Dynamis Energy,
LLC,an Idaho limited liability company (Seller),and IDAHO POWER COMPANY,an Idaho corpol1ltion
(Idaho Power),hereinafter sometimes referred to collectively as "Parties"or individually as "Party."
WITNESSETH:
WHEREAS,Seller will design,construct,own,maintain and operate an electric generation facility;and
WHEREAS,Seller wishes to sell,and Idaho Power is willing to purchase,firm electric energy produced
by the Seller's Facility.
THEREFORE,In consideration of the mutual covenants and agreements hereinafter set forth,the
Parties agree as follows:
ARTICLE I:DEFINITIONS
All used in this Agreement and the appendices attached hereto,the following terms
shall have the following meanings:
l.l "BusinesS Hours"-Daily hours of 8:00 AM to 5:00 PM Mountain Time,Monday througb Friday
excluding New Years Day,Memorial Day,Independence Day,Labor Day,Than1ligiving,Christmas
and any other Idaho Power observed holiday.
1.2 "Commission"•The Idaho Public Utilities Commission.
1.3 "Contract Year".The period commencing each calendar year on the same calendar date as the
Operation Date and ending 364 days thereafter.
•1-
EXHIBIT -.lJ!d3,Page I 013
Dynamis Energy
on Cross Examination
limits equal to $1,000,000,each occurrence,combined single limit.The deductible for such
insurance shall be consistent with current InsunlDce Induslry Utility practices for similar
property.
13.2.2 The above insurance coverage shall be placed with an insurance company with an A.M.Best
Company rating ofA·or better and shall include:
(a)An endorsement naming Idaho Power as an additional insured and loss payee as
applicable;and
(b)A provision stating thaI such policy shall not be canceled or the limits of liability
reduced without len (10)days'prior written notice to Idaho Power.
13.3 Seller to Provide Certificate of Insurance -As required in paragraph 4.1.5 herein and annually
thereafter,Seller shall furnish Idaho Power a certificate of insurance,together with the endorsements
required therein,evidencing the coverage as set forth above.
13.4 Seller to Notify Idaho Power of Loss of Coverage.If the insurance coverage required by paragraph
13.3 shall lapse for any reason,Seller will immediately notifY Idaho Power in writing.The notice will
advise Idaho Power of the specific reason for the lapse and the steps Seller is taking to reinstate the
coverage.Failure to provide this notice and to expeditiously reinstate or replace the coverage will
constitute a Material Breach of this Agreement.
ARTICLE XIV:FORCE MAJEURE
14.1 As used in this Agreement,"Force Majeure"or "an event of Force Majeure"means any cause beyond
the control of the Seller or of Idaho Power which,despite the exercise of due diligence,such Party is
unable to prevent or overcome.Force Majeure includes,but is not limited to,acts of God,fire,flood,
storms,wars,hostilities,civil strife,strikes and other labor disturbances,earthquakes,fires,lightning,
epidemics,sabotage,or changes in law or regulation occurring after the effective date,which,by the
exercise of reasonable foresight such party could not reasonably bave been expected to avoid and by the
exercise ofdue diligence,it shall be unable to overcome.Force Majeure does not include disruptions or
curtailment of the Facility's fuel supply that are the result ofactions or inactions by the fuel supplier or
-22-
EXHIBIT--'Page 2 of3
Dynamis Energy
on Cross Examination
cbanges in law or regulation occurring after tbe effective date.Ifeitber Party is rendered wbolly or in
part unable to perform its obligations under tbis Agreement because ofan event ofForce Majeure,botb
Parties sball be excused from wbatever performance is affected by the event of Force Majeure,provided
tbat:
(I)Tbe non-performing Party sball,as soon as is reasonably possible after tbe occurrence
of tbe Force Majeure,give tbe otber Party written notice describing tbe particulars of
tbe occurrence.
(2)Tbe suspension of performance sball be of no greater scope and of no longer duration
tban is required by tbe event ofForce Majeure.
(3)No obligations ofeitber Party wbicb arose before the occummce causing tbe suspension
of performance and wbicb could and sbould bave been fully performed before sucb
occurrence sball be excused as a result ofsucb occurrence.
ARTICLE XV:LIABILITY:DEDICATION
15.1 Limitation of Liability -Nothing in tbis Agreement shall be construed to create any duty to,any
staodard ofcare witb reference to,or any liability to any person not a Party to this Agreement.Neitber
party sball be liable to the otber for any indirect,special,consequential,nor punitive damages,except as
expressly autborized by tbis Agreement.Consequential damages will include,but not he limited to,the
value of Environmental Attributes and any adverse impact to the fuel supply or tbe fuel supply due to
tbe inability of Idaho Power to accept energy from the Facility.
15.2 Dedicatjon -No undertaking by one Party to tbe otber under any provision of tbis Agreement sball
constitute tbe dedication oftbat Party's system or any portion tbereofto tbe Party or tbe public or affect
tbe status of Idaho Power as an independent public utility corporation or Seller as an independent
individual or entity.
-23-
EXHIBIT ------'Page 3 of3
Dynamis Energy
on Cross Examination
Midway Power Production
2000000
1800000
1600000 /~
~"""'"1400000 V ""\1200000 II ~__2011
1000000 II "\___2010
800000 II \600000 I \400000 /\200000 /'\0
March April May June July August September October No\€mber
£XHIBIT 1102.,
DONALD L.HOWELL,II
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
POBOX 83720
BOISE,IDAHO 83720-0074
[phone]
IDAHO BAR NO.3366
Street Address for Express Mail:
472 W.WASHINGTON
BOISE,IDAHO 83702-5918
Attorney for the Commission Staff
RECEIVED
ZOIH1~Y 15 PM 1:59
IN THE MATIER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (PCA)RATES FOR
ELECTRIC SERVICE FROM JUNE 1,2012
THROUGH MAY 31,2013.
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
)
)CASE NO.IPC.E-12-17
)
)
)COMMENTS OF THE
)COMMISSION STAFF
--------------)
COMES NOW the Staffofthe Idaho Public Utilities Commission,by and through its
Attorney of Record,Donald L.Howell II,Deputy Attorney General,and submits the following
comments in response to Order No.32533 issued on April 25,2012.
BACKGROUND
Idaho Power Company filed its annual power cost adjustment (PCA)Application on
April 13,2012 for rates to be effective June 1,2012 through May 31,2013.The PCA is a
symmetrical rate adjustment mechanism that annually adjusts rates to recover a portion ofabove
normal power supply costs from customers,or refund a portion of below normal power supply
costs to customers.Idaho Power calculates the total PCA revenue increase in this case to be
approximately $43.0 million which would result in an average rate increase of approximately
5.1%.When the proposed PCA increase is combined with the $27.1 million rate credits from the
Company's Revenue Sharing case (Case No.1PC-E-12-13),the Company calculates an overall
STAFF COMMENTS MAY 15,2012
)'30\
average rate increase for tariff customers (Le.,non-special contract customers)of 1.71%.The
net rates are shown in the PCA Schedule No.55.The annual PCA rate is combined with the
Company's "base rates"to produce a customer's overall billing rate.
IDAHO POWER COMPANY'S FILING
PCA Mechanism
The annual PCA mechanism is comprised ofthree components:I)a "forecast"that
estimates the difference between normal power supply costs embedded in base rates and the
coming year's power supply costs;2)a "true-up"that captures the difference between the
previous year's projection and actual power supply costs;and 3)a "reconciliation"of the
previous year's true-up to capture the umecovered or under-refunded amount.Each component
is described in more detail below.
\,The Forecast.Forecasted power supply costs for the coming year are based on the
Company's most recent Operating Plan and measures the difference between forecasted and
normal power supply costs.The power supply cost difference is converted to a cents per
kilowatt-hour (¢IkWh)rate by dividing the power costs by projected jurisdictional energy sales.
In this PCA case,the Company calculates above normal power supply costs of $70.3 million
relative to power supply costs contained in current base rates.After the 95/5 sharing,this
produces PCA rates to recover the forecasted above normal power supply costs in the amount of
0.5099 ¢IkWh.
2.The True-up.The true-up amount is the difference between normal and actual power
supply costs during the previous year.The previous year's PCA amount is not precisely
recovered due to actual power supply costs being different than forecasted power supply costs.
The true-up amount is also converted to a ¢IkWh rate by dividing by projected jurisdictional
energy sales of 13,172,433 mWh'Idaho Power calculates the true-up amount and rate to be a
credit to ratepayers of$I7,646,658 and a credit to customers of 0.1340 ¢IkWh,respectively.
3.The Reconciliation.The reconciliation of the true-up tracks the recovery of the previous
year's true-up amounts.It nets the actual revenue collected from the true-up rates against the
amounts set for recovery.Any difference is carried into the following year's true-up
reconciliation along with the true-up difference.Idaho Power calculates the reconciliation of the
true-up amount and rate to be a credit to ratepayers of$5,165,169 and 0.0392 ¢IkWh'
respectively.
STAFF COMMENTS 2 MA Y 15,2012
In summary,this year the PCA rate for each class is the combination of the three PCA
rate components discussed above,and a Revenue Sharing rate (discussed below).The Company
calculates the combination ofthe three PCA components produces a 2012/2013 PCA rate
surcharge of0.3367 ¢IkWh (0.5099 -0.1340 -0.0392).
Revenue Sharing
The Idaho Power Revenue Sharing case (Case No.IPC·E·12-l3)is being processed
concurrently with this PCA case.In the Revenue Sharing case the Company proposes to credit
$27.1 million to Idaho customers.The Company proposes that the Revenue Sharing credit b.e .
used to offset the proposed PCA increase.Idaho Power proposes that the Revenue Sharing credit
be spread to customer classes on a uniform percent of base revenue basis and applied to reduced
energy rates.These energy credits differ for each customer class.This results in a different
PCAIRevenue Sharing energy rate for each customer class.These proposed rates are shown on
Company Exhibit No.2.For the four special contract customers,Idaho Power proposes that they
each receive a different,flat-monthly credit during the PCA year.The proposed credits are:
Micron -$46,803/mo.;Simplot -$I8,362/mo.;DOE -$22,906/mo.;and Hoku·$7,685/mo.
Atach 2,p.3.These rates are included in Tariff Schedule No.55 which would be effective
June 1,2012 and would remain in effect for one year.
STAFF AUDIT AND ANALYSIS
A.The peA Forecast or Projection
The Operating Plan used to forecast power supply costs is based on the most current
information available to the Company.It takes many factors into consideration such as water
conditions,gas hedges,market purchases,transmission availability,the cost of PURPA
contracts,etc.Throughout the year,the Risk Management Committee (RMC)comprised of key
Idaho Power employees reviews and updates the Company's risk management strategy.An
account by account breakdown of the Company's power supply expense forecast is shown on
Attachment A to these comments.The chart shows expenses included in Base Rates,Forecasted
Expenses and the Difference.Account 555 -PURPA Purchase Expense,is shown separately
from other Account 555 Non-PURPA Expenses because differences in PURPA Contract
Expenses are not shared.The entire difference in PURPA QF contracts is passed on to
customers.L_..STAFF COMMENTS 3 MAY 15,2012
Attachment B shows Staffs calculation ofthe PCA rate components.Lines I through 18
show the calculation of the Forecast Rate.The forecast rate is the sum ofthree rate elements.
The first element is composed ofall PCA amounts subject to 95/5 sharing.'Lines 2 through 8
show this calculation.Line 8 shows the first component ofthe forecast.rate to be 0.0005 ¢/kWh.
Lines 10 through 12 show the calculation ofthe second element ofthe forecast rate
component.The second element includes all amounts,except Demand Response Incentive
amounts,that are passed through to customers without sharing.These amounts are almost
entirely PURPA QF contract costs.This second rate element is 0.4830 ¢/kWh as shown on line
12.This is by far the largest part ofthis year's PCA rate increase.
The third forecast rate element is new this year.It is Demand Response Incentives and
the calculations are shown on lines 14 through 16.Commission Order No.32426 allows Idaho
Power to capture the difference between base and actual Demand Response Payments in the
PCA.This third PCA forecast element is shown on line 16 to be 0.0264 ¢/kWh.These three
elementscombine to produ~e the PCA forecast rate component of0.5099¢/kWh shown on line
18.This rate is almost entirely composed ofexpected increases in PURPA contract expenses.
The Staff agrees with the Company's forecast calculations.
B.The peA True-Up
The PCA true-up difference is netted against the amount collected from the application of
the previous year's true up rates.This difference represents the PCA true-.up deferral balance.
This deferral balance is divided by expected kWh jurisdictional sales to provide the true-up rate
component.
Page I,lines 4 through 90 of Company Exhibit No.I calculates a true-up deferral amount
-a credit of$17,646,658.Attachment C contains Staff's verification ofthe Company's true-up
deferral calculations.Stafffinds the Company's calculation as shown in Exhibit No.I to be
correct.
To verify revenues and costs associated with Idaho Power's true-up deferrals,Staff
conducted an audit ofactual revenues and expenses that occurred during the PCA year
(April I,2011 through March 30,2012).These revenues and costs included water lease
expenses,fuel expenses for coal,fuel expenses for natural gas,power sales and purchases,third­
party transmission expenses,Hoku First Block Energy revenues,Renewable Energy Credits
STAFF COMMENTS 4 MAY 15,2012
(RECs)sales,Emission Allowance sales,and Qualifying Facilities (QF)expenses.The Risk
Management Operating Plans and RMC minutes were also reviewed.
The following items are included in the PCA true-upcomponent:
I.Load Change Adjustment.This year's true-up ciilculation includes a negative Load
Change Adjustment of$12,621,398.Actual loads during the true-up year were below normal
loads in II of 12 months.The actual load for the PCA year was below normal by 655,506
MWh.This represents a 4.2%decline in load.The load change adjustment is the product of the
negative load growth and the load change acljustment rate (LCAR)of$19.67/MWh for the
months ofApril through December 2011,and $18.l6/MWh for January through March 2012.
The LCAR is composed ofthe energy classified fixed costs of production embedded in base
rates.When load grows,the adjustment reduces power supply costs to avoid double counting
production costs.When load declines,the adjustment reimburses the Company for a portion of
lost fixed production costs.The result is that $12,621,398 (before Jurisdictional Allocation and
PCA sharing)has been added to the deferral balance for recovery from customers in this year's
PCA.This increase due to the LCAR is a cost to customers and is subject to jurisdictional
allocation and sharing.
2.Water Leases.The Company sometimes leases water for the production ofhydro
power from several entities.The increase or decrease in the waterlease expense from base rates
is included in the PCA for recovery from or credit to customers.This year's PCA deferral
balance includes actual water lease expenses of$2,577,915 and the amount included in base rates
is $1,825,371,with the difference of$752,544 included in the deferral balance.This increase in
water lease expenses from base expenses is a cost to customers and is subject to jurisdictional
allocation and sharing.
3.Fuel Expense·Coal.Aportion ofIdaho Power's electricity comes from coal plants.
The three coal plants that Idaho Power owns an interest in are the Bridger,Valmy and Boardman
plants.The increase or decrease in the coal expense from base rates is included in the PCA for
recovery from or credit to customers.For the audit period of April 20II to March 2012,the total
coal expense for the three plants is $122,922,864.The total coal expense included in base rates
is $167,418,061.This year's PCA deferral balance includes a difference between costs currently
included in rates and actual costs of $44,495,197.This decrease in coal costs from base costs is
a benefit to customers and is subject to jurisdictional allocation and sharing.
STAFF COMMENTS 5 MAY 15,2012
4.Fuel Expense -Gas.Idaho Power currently owns and operates several gas-fired
combustion turbine generating plants at the Evander Andrews Power Complex (3 Danskin units)
and at Bennett Mountain.These plants are located at Mountain Home and currently account for
100%ofthe Company's natural gas usage.
For the audit period of April2011 through March 2012,the total variable gas and gas
transportation expense for all the gas plants was $10,877,122.The total gas and gas
transportation expense included in base rates is $6,051,627.This increase in gas expense from
base rates is included in the PCA.In this'year's PCA deferral balance,the additional gas expense
that is included for future recovery from customers is $4,825,495.This increase in natural gas
expenses from base expenses is a cost to customers and is subject to jurisdictional allocation and
sharing.
5.Power Sales and Purchases.Staffreviewed the power purchases and sales in
conjunction with the Company's Operating Plan.Staff did not find any transaction that was not
reasonable or did not follow the Risk Management Committee's recommendations.These
transactions were made with an assortment of credit-worthy partners on a timely basis,and there
were no transactions conducted with an Idaho Power affiliate.
a.Power Sales.During the PCA year ending March 31,2012,the Company sold off­
system surplus power totaling $96,750,895.The total surplus sales included in base rates is
$92,476,391.This increase in the power sales from base rates is included in the PCA.Actual
surplUS sales were more than base amounts by $4,274,504.This increase in revenues is a benefit
to customers and is subject to jurisdictional allocation and sharing.
b.Power Purchases.During the PCA year ending March 31,2012,the Company
made market power purchases,excluding its PURPA contracts.The total amount ofpower
purchases is $62,156,365.The amount of power purchases included in base rates is $66,570,302.
Actual power purchases were less than base amounts by $4,413,937.This decrease ill costs is a
benefit to customers and is subject to jurisdictional allocation and sharing.
6.Third-Party Transmission.In Order No.30715,the Commission found that third,
party transmission costs that are incurred in conjunction with market purchases and off-system
sales should be tracked through the PCA like other variable power supply costs.Including
transmission expenses in the PCA is a straightforward treatment ofpower supply costs that
fluctuate with power purchases and sales.
STAFF COMMENTS 6 MAY 15,2012
·For the audit period of April 2011 through March 2012,the actual third-party
transmission expense is $6,516,274.The third-party transmission expense included in baseJates
is $8,247,222.This year's PCA deferral balance includes the difference between actual costs and
base costs of$1 ,730,948.Because the actual costs are less than the amount included in base
rates,this amount represents a benefit to customers.This benefit to customers is subject to
jurisdictional allocation and sharing.
7.Hoku First Block Energy.In Order No.32426 (Case No.IPC-E-I I-08),the
Commission determined that the first block energy revenue from Hoku is to be included in base
rates like secondary sales revenue.The variation between what is built into base rates and the
actual Hoku revenues are tracked in the PCA.The amount ofHoku First Block Energy revenues
included in base rates is $5,773,675.The actual amount ofHoku First Block Energy revenues
during the current PCA period is $14,477,351.The actual revenues are more than the amount
included in base rates by $8,703,676.These additional revenues are a benefit to customers and
are subject to jurisdictional allocation and sharing.
8.Emission Allowance Sales.In Order No.32424,the Commission ordered that
revenues from the sale ofemission allowances,plus any applicable interest,be reflected in the .
PCAand benefit customers by reducing the Company'sPCA deferral balance,subject to
jurisdictional allocations and sharing.The amount included in the deferral balance is $25,202
and is a benefit to customers.
9.Renewable Energy Credit Sales.In Order No.30818,the Commission ordered that ..
revenues from the sale of renewable energy credits (RECs)benefit customers and be subject to
jurisdictional allocation and sharing.The amount included in the deferral balance is $5,521,597
and is a benefit to customers.
10.Actual PURPA Purchases Including Net Metering and Raft River Expenses.A
QualifYing Facility (QF)is a generating facility which meets the requirements for QF status
under the Public Utility Regulatory Policies Act of 1978 (PURPA)and FERC's 18 C.F.R.Part
292,and has obtained certification ofits QF status.
For the audit period of April 2011 through March 2012,the actual PURPA expense is
$103,846,995.The PURPA expense included in base rates is $62,739,020.The difference
between actual PURPA expense and base PURPAexpense is included in the PCA for recovery
from or credit to customers.In this year's PCA deferral balance,the actual PURPA expense was
more than the PURPA expense included in base rates by $41,I07,975.This amount is a cost to
STAFF COMMENTS 7 MAY 15,2012
customers and increases the PCA deferral balance.PURPA contracts are not currently subject to
sharing,but they are subject to jurisdictional allocation.
II.Demand Response Incentive Payments.In Order No.32426 (Case No.IPC-E-II­
08),the Commission determined that Demand Response Incentive Payments be included in base
rates and that differences between base and actual expenses be tracked through the PCA.Idaho.
Demand Response Incentive payments are directly assigned to Idaho and are not subject to
sharing.For the PCA period (April2011 to March 2012),there were no actual Demand
Response Incentive Payments.The base amount of incentive payments included in base rates
during the PCA period is $2,715,842.The difference between the actual amount and the base
limount is $2,715,842 and is a benefit to customers.
The Idaho customer tme-up Deferral Balance is composed ofthe following:
Load Change Adjustment $12,621,398
Water Leases $752,544
Fuel Expense -Coal $(44,495,197)
Fuel Expense -Gas $4,825,495
Surplus Sales $(4,274,504)
Non-Firm Purchases $(4,413,937)
Third Party Transmission $(1,730,948)
Hoku Energy $(8,703,676)
Subtotal-Change from Base $(45,418,825)
Emission Allowance Sales Credit $(25,202)
Renewable Energy Credit Sales $(5,521.597)
Subtotal-Subject to Jurisdictional Allocation &Sharing $(50,965,624)
Subtotal-After Jurisdictional Allocation and Sharing $(45,996,476)
Qualifying Facilities -After Jurisdictional Allocation
Demand Response Incentive Payments .
Total all Expense Items
Revenue from the Forecast
Deferral Balance
Interest on the Deferral Balance
Deferral Balance (Credit)
$39,052,576
$(2,715,842)
$(9,659,742)
$(7,823,682)
$(17,483,424).
$(163,234)
$(17;646,658)
The Company-proposed tme-up rate credit is 0.1340 ¢IkWh,Although Staffcalculates
the same rate,as shown on Staff Attachment B,line 23,Staff is concerned that the Company
does not use actual energy sales to calculate revenue from the previous year'sforecast rate,.The
Company uses normalized energy amounts,The methodology used by the Company has been in
use for many years and has been accepted by the Commission as it has approved past PCA rates.
STAFF COMMENTS 8 MAY 15,2012
Instead of using normalized energy sales to estimate forecast revenues in determining true-up
revenue,Staffbelieves it may be more appropriate in future PCA years for the Company to use
actual energy sales and the approved forecast rate to determine true-up revenue,Staffproposes
to immediately initiate discussions with the Company to resolve the issue on a prospective basis.
C.The Reconciliation ofthe True-Up
The reconciliation of the true-upI amount is the difference between whai was IIpproved to
be collected or refunded when the PCA rate for last year's true-up was setand what was actually
collected or refunded.The reconciliation ofthe true-up may benefit either the Company or
customers because any true-up over-collection is returned to customers,and any true-up under­
collection is recovered by the Company.
The reconciliation of the true-up included the following amounts:
2010-11 Forecast True-Up
2010-11 True-Up of the True-Up Balance
Emission Allowance (Order No.32250)
DSM Recovery (Order No.32217)
Net Amount Set for Recovery/(Refund)
CoIlection from True-Up Rates
Interest
True-Up Reconciliation (Credit)
$4,181,114
($18,152,666)
($491,989)
$10.000,000
($4,463,541)
($634,702)
($66,926)
($5,165,169)
This is the amount recommended for refund by the Company and Staff.When divided by
expected sales it produces the reconciliation ofthe true-up rate credit 0.0392 ¢IkWh.This
calculation is shown on Attachment B,line 25.
D.·Revell/Ie Sharing
Because the Company proposes to offset the proposed increase in PCA rates with
Revenue Shllring credits,Staff reviewed Idaho Power's class allocation ofthe Revenue Shllring
amount.Idaho Power allocated the credit to all customer classes on a uniform percent of
revenue basis using forecasted billing determinants and associated class base revenues.Within
each customer class the decrease was assigned to the energy rates.This creates a different
¢IkWh rate for each class.Staff accepts this reveriue allocation and rate design.
I The reconciliation of the true-up is also commonly referred to as the "true-up of the true-up."
STAFF COMMENTS 9 MAY 15,2012
PCA AND REVENUE SHARING RATES
The uniform PCA rate surcharge of0.3367 ¢/kWh is the sum ofthe three PCA
components describedabove (0.5099 -0.1340 -0.0392)..This new PCA surchargerate,shown
on Attachment B,line 28,replaces the 0.0629 ¢/kWh credit currently contained within Schedule
55 rates.In this case,the uniform PCA rate is combined with Revenue Sharing credits to arrive
at the total PCA rate for each class.Attachment D shows these rates.
Combined PCA and Revenue Sharing Recovery
Attachment E shows the percentage increase in the Combined PCA-Revenue Sharing
rates for all Idaho Power customer classes.It includes the uniform PCA increase and the
Revenue Sharing decrease.The impact is measured against all billed revenue.The total Staff­
recommended increase is $15.9 million which represents an average revenue increase of 1.89%.
Increase or decrease percentages vary by customer class.Staffagrees with the Company's
proposed combined rates in Schedule 55.
Other PCA Attachments
Staffhas included two other attachments that provide summary or historical information
concerning the PCA.StaffAttachmentF summarizes PCA expense amounts and rate
components for this case.The attachment also shows amounts allocated to other jurisdictions
and amounts shared with shareholders.Attachment G is a bar graph that shows the amount of
each PCA since its inception.
CUSTOMER NOTICE AND PRESS RELEASE
Idaho Power's PCA Application,filed on April 13,2012,contained both the Customer
Notice and Press Release.Staffreviewed both and determined they complied with requirements
of Procedural Rule 125.oI,IDAPA 31.01.01.125.01.However,the Customer Notice does not
comply with requirements of Procedural Rule 125.03,IDAPA 31.01.01.125.03.
Rule 125.03 requires that the information provided in Customer Notices should be
"clearly identified,easily understood,and pertain only to the proposed rate change."In the
notice sent in this case,five paragraphs are devoted to discussing Public Utility Regulatory
Policy Act (PURPA)costs.Although Staffrecognizes that PURPA expenses are a major cost
component in this year's PCA filing,Idaho Power's discussion ofPURPA strays into a
I STAFF COMMENTS
L_
10 MAY 15,2012
discussion of expected future PURPA costs and how those future costs will impact customers in
another generic case.Although the case number for the instant PCA case (lPC-E-12-17)is not
mentioned in the notice,the case number for the generic PURPA case (GNR-E-II-03)is given.
The Customer Notice states that the Commission is accepting public comment in GNR-E-ll -03,
but there is no statement to that effect with respect to this PCA case.
In the first paragraph under the section labeled "How PURPA Impacts the PCA",the
Company compares this year's PURPA-related power supply expenses to those same expenses In
2004..Staffbelieves a more appropriate comparison between PURPA expenses would be to
compare the current PCA case and last year's PCA case.Rule 125,01 requires that the Customer
Notice give the overall percentage change from cutTent rates.As one customer noted in his
comment,"It seems that Idaho Power is waging an all out war against PURPA projects."In
Staffs opinion,the Customer Notice violates Rule 125.03 by addressing and referring to issues
that are currently the subject ofa different case.At a minimum,the invitation for customers to
comment in a separate and distinct case is confusing and misleading.
Another issue ofconcern is the delay in mailing Notices to customers.Although the
Application was filed with the Commission on April 13,the Customer Notice was mailed with
Idaho Power's cyclical billings beginning on April 26,2012 and ending May 24,2012.Pursuant
to the Commission's Notice of Application,customers had until May 15,2012 to file comments
regarding this case.The delay is problematic,particularly in a PCA case that typically has a
much shorter timeline than that of general rate cases.More than 100,000 customers would not
have received the Customer Notice in their bills until the comment deadline passed.
In response to this concern about the delayed notice,the Company notified Staff on
May 4,2012,that it would issue a "supplemental"Customer Notice in the form ofa post card to
most of the customerswho would not have receive the original Notice in their bills before the
comment deadline ofMay 15,2012.The affected customers will receive the supplemental
Notice via direct mail by May 17,2012,and will also receive the original Notice in their monthly
bills.Staff agrees with the Companythut this will provide uffected customers with "the
opportunity...to submit comments in this case prior to a Commission decision",although the
turn-around time for some customers will be quite short.For this reason,Stuffencouruges the
Commission to consider late-filed comments from customers in its deliberations.
STAFF COMMENTS 11 MAY 15,2012
The Company indicated to Staff that there were two reasons for the delay in sending the
Customer Notice in this case.First,the Company did not want to include more than one
Customer Notice in bills;bills including the Notice regarding Case Nos.IPC-E-12-12,
IPC-E-12-13 and IPC-E-12-14 were being mailed until April 23,2012.Second,the Company
reports that it takes ten days for the Customer Notices to be printed locally and then shipped to
the billing vendor (located in Califomia)that prints,stuffs,and mails the bills.In discussions
with Staff,Idaho Power has acknowledged that the processing delay is problematic.The
Company is now exploring options on how it can decrease the time it takes to provide customer
notification,particularly with respect to cases with abbreviated comment periods such as this
one.
.Staffrecommends that the Company be reminded ofits obligation to provide timely
notice to customers and be directed to comply with Procedural Rule 125 in future cases.
STAFF RECOMMENDATION
Staff recommends that the Commission approve the Company's Application and the
combined PCAIRevenue Sharing rates filed by the Company in proposed Schedule 55.
Staff recommends that the Commission approve a total PCA rate comprised of the
uniform ¢/kWh increase of0.3367 and class-specific rates,as shown on Attachment D,to credit
customers for Revenue Sharing amounts.The Staffrecommends that these rates be effective
June 1,2012 through May 31,2013.
Staff recommends that the Company be reminded of its obligation to provide timely
notice to customers and be directed to comply with Procedural Rule 125 in future cases.
Respectfully submitted this I ~day of May 2012,
IJ~~~"".~~=::.--
Deputy Attorney General
Technical Staff:Keith Hessing
Kathy Stockton
Matt Elarn
Marilyn Parker
i:umisc:commentslipcc12.J7dhklskhmempcomments
STAFF COMMENTS 12 MAY 15,2012
300
POWER SUPPLY COST PROJECTION
2012 -2013 PCA Year
250
I I
•Base Cost-200
en
1 1 •Forecast Costt:.2
~150 I-I III Ultterence-cuent:100cua.XLl.I
>C.50a.
::JII)..cu 0:;Coal Ex!llse Water For Natural Gas·Non-p:AA PURPA Transmissions'E'lIuFirst Demand0Cl.Power Expense Purch Purchases Expense·ue lock Response
(50]
(100)
o CJ)(")->
.;::;EO g;.:::t I
'v.~c~'.!~Q~9"(150]"-----------------------------------------
:3:....g,3 "'t;I .....gQ>
s"o/!;;:;
-.I
2012·2013 peA·Twentieth Annual
IPC·E-12-17
SlaffCase
(a)(b)(c)(d)(e)----(f)(91
Line Description Unijs Base Forecast Difference Rate
1 Forecast 2012-2013:
2 PCA Expense (95%)($)133,997,217 140,832,145
3 Hoku First Block Revenue ($)(6,765,150)
4 Difference ($)134,066,995 69,778
5 Sharing.Percentage (%)0.95
6 Shared Difference ($)66,289
7 Normalized System Firm Sales (MWH)13,816,139
8 Rate for 95 %Items (¢JkWh)0.0005 0.0005
9
10 PCA Expense (100%)($)62,851,454 129,590,113 66,738,659
11 Normalized System Firm Sales (MWH)13,816,139
12 Rate for 100%Items (¢I1<Wh)0.4830 0.4830
13
14 Demand Response Incentives (100%)($)11,252,265 14,723,210 3,470,945
15 Idaho Jurisdictional sales (MWH)13,172,433
16 (¢I1<Wh)0.0264 0.0264
17
18 Total Forecast Rate (¢/kWh)0.5099
19
20
21 W (MWhl ($/MWhl WkWhl
22
23 True-Up of 2011-2012:(17,646,658)13,172,433 -1.340 (0.1340)
24
25 True-Up of the True.lJp:(5,165,169)13,172.433 -0.3921 (O.0392)
26
27 PCARates:
28 PCA Rate Adjustment From Base (¢/kWh)I 0.33671
29 PCA Rate Currently in Effect (¢/kWh)(0.0629)
'.000 (J:>i 30 Difference -Last Year to'This'Year (¢JkWh)0.3996.~'S'~:=:'
:V;~o~-31~(")Z§32 Note:Negative rates and amounts indicate benefits to ratepayers.IN 00.3'<>33 The True-Up calculatlon includes 95%sharing.3;;s.-'
gQt:tlc;rtp
';-'
-.J
TRUE·UP CALCULATION$:FOR 2011 ~2012
FOR
IDAHO POWER COMPANYpeA
CASE NO.IPC·E·12·17
(B~S8 Costs,are Redistributed)
1
.2 DESCRIPTION U,""
2011
APR
2011
MAY
2011
JUN
2011
JUL
2011
AUG
2011
SEPT
2011
OCT
o
oo
o
460,776
1.035,451
0.445 .
1,040,237
1,100,716
"(80,539)
1,190,802
7,819,052
4,603,670
3,015.382
2,864;813
(6,038,558)
133,942
12,284,817
444,057
4,884,502
605,165o
(6,765,741)
11,567,042
o
11,160,165
491,516
2,401,316
683,914
(11,818,634)
(1,692,789)
1.190.602
2,616,289
(3,707,509)
(6,038,658)
(9,746,067)
(21,278)
(23,018)
(0)
(23,(16)
(44.298)
(9,790,383)
(381.700)
(7,249,183)
ooo
(7,249,183)
(6,041)
(6,041)
(375,659)
(6,673,525)
oooo
576,607
1,295,747
0,445
1.293,353
1,225,589
67,764
(1,332,918)
8,186,389
6,163509
"2,022,880
1,921,736
179,325
16,447.224
594,515
6.639,896
610,211o
(9,084,921)
15,486,250
1,542,915
11,740,380
485,041
4.739,131
519,502
(10,016.187)
(2,5fj1,825)
(1.332,918)
5,116,640
(8,384,049)
4,676,640
(8,384,049)
(3,701,509)
(5,786)
(15,492)
(0)
(15,492)
(21.278)
(3,726,787)
(458,114)
(7,700,680)
ooo
(7,700,880)
(Mil)
(6,417)
(451,697)
(1,249,183)
o
ooo
629,361
1,414,294
0.445
1,565,233
1,594,331
(9,098)
178,958
9,677,446
7,033,693
2,643,753
2,511,665
9,029,808
1,464,305
13,870,657
3,177,032
15,265,932
660,272
(7,930,627)
(743,176)
178.956
26,143,252
3,648
(9,432)
f1I
(9,434)
(5,786)
4,670,754
(4,353,268)
9,029,8Q3
4,676,540
204,643
18,789,296
676,450
7,463,219
924,599o
(10,367,660)
17,672,647
(479,18S)
(8,173,235)
oo
o
(8,173,235)
(6,811)
(8,811)
(472,355)
(7,700,680)
o
ooo
602,552
1,354,071
0.445
1,685,331
1,685,870
(639)
10,602
7.749,022
o
10,194,091
1,577,118
14,768,259
898,300
(4,788,485)
(1,178,693)
10,602
21,481,193
190,953
17,513,694
633.064
6,963,955
862,746o
(9,674,005)
16,490,407
3,044
603o
603
3,548
(4,349,620)
11,225,589
8§ll3,163
4,662,426
4,429,305
(420,058)
(8,588,138)
oo
o
(6,588,138)
(7,155)
(7,155)
(412,903)
(8,173,235)
(12,102,290)
7,749,022
(4,353,268)
o
o
oo
496,391
1,115.486
.0.445
1,300,475
1,412,642
(112,367>
2,210,259
978,989
o
5,801,423
1,392,041
8,112,353
1,054,471
(7,210,510)
(1,692,789)
2,210,259
9,667,246
1,537,899
11,029,612
5,281.808
5,768,064
5,479,661
(7,600,815)
o
o
(7,600,616)
(6,334)
(6,334)
985,323
(8,686,138)
(13.640,189)
1,537,899.
(12,102,290)
1,416',56'o
1....
3,044
(12,099,245)
o
o
oo
960,840
1.-404
1,349;019
1,097,667
1,282,341
£184.674)
3,632,538
(514,305)
4,771,126
479,664
1,509,941
~9,423
(6,211,722)
(1,636,183)
3,632,536
2,338,463
8,096,202
4,266,186
3,812,014
3,621,413
1,526,938
(6,614,338)
(5,576,831)
o
(491,989)
(6,068,620)
(5,057)
(5,051)
1,531.996
(7,600,815)
(8,025,SS1)
(5.614,338)
(13,640,189)
(7)
1,483o
1,483
1,416
(13,636.713)
o
o
oo
955,398
1.404
1,341,379
1,011,234
1,085,384
(74.160)
1,458,531
o
6,666,551
456,072
(264,797)
337,992
(6,221,929)o
1.468,531
2,432,419
6,235,618
4.320,756
1,914,762
1,819,024
(8,025,851)
oo
(7)
(7)m
(8,025,858)
o
{8,025,65H
(8,025,851)
4,181,114o
10,000,000
(3,971,552)
(3,310)
(3,310)
1,605,278
(5,676,831)
1,&11,969
(18,152,666)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
MW!l
MW!l
MW!l
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
MWll
$!MWll
:3 PeA Revenue
4 NormalizedIdahoJurisd.SalGS
5 Forecast Rata
6 Revenue
7
a Load ChangeAdjustment
9 ActualSystem Finn load·Adjusted
10 Normalized Finn load
11 load Chaooa
12 ExpenseAdjuslment13.
t4 Non-QF peA
15 ACTUAL:
16 Water leases
17 Fuel Expense·Coal
18 FuelExpense·Gas
19 Noo-Fillll Purchases
20 Third PartyTransmission
21 Surplus Sales
22 Holru FirstBlockEnergy
23"ExpenseAdjustment
24 Sub·Tolal
25
26 BASE-
27 WaterforPower(leases)$125,711 124,705 153,090:
28 FuelExpense-coal S 11,629,868 11,437,623 '14,041,049
29 Fuel Expellse·Gas $416,768 413,433 507,539
30 Noo-FirmPurchases $4,584,612 4,547,932 5,583,131
31 ThlrdPartyTransmi$s!on $567,976 583,431 691,679
32 Hoku FIrstBIod<EnGCgY $0 0 0
~Suplus Sales $(8,368,731)(6,317,776) (7,765,627)
34 Sub-Tolal $10,856,204 10,769,346 13,221>,661
3."";;;;;;:;-.;;::;;;"';;;------,--==""';--;0:;;;;=,,--.==...-,0,;;,.;;,,-"'''"'''''-.,,;;='''''''-''''''''''''36 Change From Base $(8,423,78S)(8,430,863)(3,553,413)4,900,766 8,470,605 (10,369,610)(6,950,753)
37 EmissIonAllowance Sales Cfedit $0 0 0 (21,756)0 0 0
,J>r36 Renawable EnefYY CfeditSales $(998,372)(307,698)(2M,172)(823,014)(550,822)(410,843)(403,7.02)
?-39 Sub-Total $(9,422,157)(8,738,781)(3,817,585)4,348,015 7,919,782 (10,780,253)(9,354.455)
"41 Dererral(Sharetl<mdADoc:ated)$(8,503,496)(7,sas,732)(3,445,370)3,922,279 7,147,603 (9,729,178)(8.4-4:2,396)
42
43 DemandResponse IncenUvePmts,
44 Actual
45 Base
48 ChangeFrom Base
47 Deferral
"49 QFDeferral
50 Actual (includes NelMelering)
51 Base
52 Change From Base
63 Dereml (Allocated)
54
65 Total Deferral (-6+41+47+53)
56
57 PrlnclpalBalances
68 BeginningBallmC1l
59 Amount Deferred
60 Ending Balance.,
82 InterestBalances
83 AccrtJal thru Prior Month
64 Interes\@1%perYear
65 PriorMonth'slnterestAdI.
66 Total CurrentMonth Inlerast
87 InterestAcm!edto Date
88 Blllllnce(True·Up&Interesl)..
70 True-Upofthe True.lJp
71 True-Up Revenues(CQllections)
72
73 Beginning Balance
74 Adjustments:
75 2009-10 peA Transfer
76 Emission Allowance w ON32250
77 RiderFonds·O.N.32217
78 Sub-Tolal
79lnterest@1%perYear
80 RevenueApplied 10 Interest
81 RevenueApplied 10Balance
62 True-Up of the True.lJp Balance
Note:Negativeamounts Indicatebene~lto ratepayers Ali"chinent C
Case No.IPC·E·12-17
StaffComments
O~15/12 l'ag~19G.
TRUE-UP CALCULATIONS FOR 2011 ·20'2
FOR
IDAHOPOWER COMPANY peA
CASE NO.IPC,E-12·17
(Base Costs are Redistributed)
1
2 DESCRIPTION Units
2011.NOV 2011
DEC
2012
JAN
2012
FEB
2012
MAR TOTAlS
7,823,682
13,451,707
14,&12,905
15,516,411
(655.50&)
12,621,398
_.-------_.--
"Attachment C
Case No.IPC-E-12-17'
StaffComments
05/15/12 I'a~e.2 of2
o
2,716,642
(2.715,642)
(2,715,642)
2,577,916
122,922,664
10,811,122
62,156,365
6,616,27-4
(96,750,895)
(14,477,351)
12,621.396
106,443,691
4,161,114
(491,969)
10,000,000
(4,463,541)
(",'26)
701,628
(5.165,169)
(17,483,424)
(17.463.424)
{163.232}
(3)
(163,234)
(17,646,658)
634,702
(1B,152,666)
103,64f3:,995
62.739,020
41,107,975
39,052,676
446,792
1,004,0211
0.4-45
•620,257
(620,251)
(62O,267)
1,060,667
.1,134,875
<54,lO8)
984,417
7,068,958
-4,58f.666
2,507,272
2,361,906
(7,060,226)
86,000
7,666,020
561,096
2,648,054
319,376 .
(10,647,765)
(545,550)
984,417
992.630
(334,141)
(5,494,731)
••o
(5,494,731)
14,67')
(4,679)
(329,562)
(5,165,169)
(10.423,198)
(7,060,226)
(17,483,424)
(147,241)
(15,993)•(15,993),
(163.234)
(17,646,656)
490,011
1,101,149
0.4-45
o
907,045
(907,04~)
(907,045)
1,110,751
1,139;203
128.4511
516,779
8,155,684
5066.454
3.090,230
2,935,718
o
10,750,313
612,667
2,106,087
289,909
(6,630,414)
(5-45,650)
616,179
4,799,991
(352,411)
(5,642,279)
ooo
(5,842,279)
(4,669)
(',BS9)
(347,549)
(5,494,731)
(6,292,469)
(4,130.729)
(10,423,198)
(125,2S4)
.(21,947)o
(21,941)
(147.241>
(10.570,439)
.,(4,130,729)
624,060
755,863
..
988,540
(988,540)
(988,540)
1,246,576
1,346,312
.(91,7361-.
1,7704,886
.1,117,663
0.446
9,614,927
5,521,658
4,093,269
3,686,605
•12,745,738
443,209
3,145,179
366,159
(6,165,168)
(545,650)
1,714.666
10,307,052
(7,048,332)
155,863
(6,292,469)
(97,900)
(27,394)•(27,394)
1125,294}
(6,417,764)
(363,912)
(6,201,024)
oo•(6,201,024)
(5,168)
(5,168)
(358,744)
(5,642,279)
••o•
,461,051
1,081,014 .
0.445
1,285,108 _
1,360,116
(95,010)
1,8!i8,847
1,517,666
7,374,112
5,009.567
2,364,545
2,246,316
o
16,166,660 .
868,953
3,763,652
443,772
(7,744.097)
(1,692,769)
1,8S8,847
12.6~6,996
(8.556,196)
1,617&66
(7,046,332)
(70,608)
(27,299)•(27,292)
(97,900)
(1,146,~2)
(352,661)
(6,646,448)
•oo
(6,546,446)
(5,457)
(5,457)
(347,424)
(6,201,024)
••••
956,56&
.0.445
425,672
1;124,273
1,130,765
(6,492)
127,698
o
12,465,639
432,515
3,340,059
291,183
(7,165,338)
(1,640,458)
127,Gsa
7,651,498
9,540,246
4,326.868
5,213.378
4,952,709
1,179,870
(9,746.067)
1.179'870
(8,566,198)
(330,805)
(6,873.525)
(44,296)
(26,312)o
(26,312)
/10,6081
(6,636,606)
•••(6,673,525)
(5,726)
(6,728)
(325,077)
(6,546,448)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$.
$
$
$
$
$
S
$
MWh
MWh
,"'Ih
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
MWh
$!MWh
Note:Negative amountsindicate benefit to ratepayers
3 peARevenue
-4 ,Noonalizedk1aho Jurlsd.'sales
5-ForecastRate
6 Revenue
7
8 load Change Adjustment·
9 Actual System FIrmload·Adjusted
10 Normalized Firm Load
11 Load Change
12 ExpenseAdjuslm&flt'314 NonoQFpeA
15 ACWAl:
16 WaterLeases
17 Fual Expense·Cool
18 FuelExpense·Gas
19 Non-FirmPurchases
20 lhIrdPartyTransmission
21 SU/plus sales
22 Hoku Rl'$tBlockEnergy
23 ExpenseAdjustment
24 Sub-Total
2.
26 BASE;
27 Walllf fot Power(Lease5)$125,889 145,752 160,651 147,407 133,303 1,825,371
28 Fuel Expense-Coal $11,546,178 13,307,949 14,734,456 13,519,751 12,226,156 167,418,061
29 Fuel Expense.Gas $417,357 483,2Q9 -532,603 488,696 441,936 e.o51.627
30 Non·FirritPurcf\ases $.4,591.097 5,315A86 6.656.849 5,375,847 4,8s1,476 66,570,302
31 ThlrdParlyTransmls.slon $568,779 658.522 725,636 666,000 602,276 ~,247,222
32 Hoku FlrslBIOd;Energy $°0 (2,101,561)(1,928,309)(1,743.605)(5,773,676)
33 SurplusSaJes $(6,377,740)!7,384,028)(8,138,643)a,467.879)(6,753.338)(92,476,391)
34 Sub-Tolal $10,871,560 12,686,890 ,11,771,993 10,801,513 9,768,004 '151,882,517
:-,cna"""O"';;;.<F';;;o;;;mCiB;;";;;-.-'-------$'--C("3,0020;;;;,06""2):--.'''lO<'.,'"0"-.:-(""A;;;""""''''):-''(''',.'''01','''22'')'--'('',,''77'''''~'''7''')-'(':Co.",'''''',''826"")
37 Emission Allowance Sales Credit $°0 (3.446)0 0 (25,202)
38 Renewabl"eEnergyCreditSa!es $(688,7.11)(384,236)(328,785)(280,351)(282,891)(5.521,597)
39 Sub-Total {3,708,773}'(274,128)(1,795,171)(6,281,873)(9,058,266)'(50,965,626)••410eferral(SharedandAlI0C3led)$(3,347,167)(247,401)(1,620,142)(5,609,391)(B,175.085)(45.9930477)
42
043 Demand Re5pOOSelncenlivePmls.
44 AclLial
045 Base
046 Change From Base
47 ~f6ml1••49 QFDeferral
60 Actual (mcludesNetMelerlng)
51 Base
62 ChangeFromBase
63 Deferral (Allocated)
64
55 Total Deferral (_6-1-41+47+53)
56
57 PrfncipalBalances
58 BeginningBalance
59 AmountDeferr&d ­
60 Emling Balance
61
62 Interest Balances
63 Accrualltllu PriorMonlh
64 Interesl@1%perYear
65 PriorMonlh'slnlerestAdl.
66 Total Current MonlhInlerest
67 interestAccrued toDate
~Balance (True-Up &Interest)
.9
70 True.Up ofthe True·Up
71 True-Up Revenues (Collections)
72
73 Beg1nnlng Balanca
74 Adjustments:
75 2009-10PCATransfer
76 EmIssIonAllowance -ON32250
77 RklerFunds·O.N.32217
76 Sub-Tolal
79 Interest@ 1%per Year
80 Revenue Applled to Interest
81 Revenue AppIled to Ba!<lnce
82 True-Up olthoTrue-llp Balanca
I
i
Rote
Line Schedule
b'.Q J:;.Q.
1 ResidentiolService 1,4.5
2 MosterMetered MobUe Home Pork:3
3 Small GeneralService 7
4 Large Generalservice -Secondary 95
5 Lorge GeneralService'-Primary 9P
6 Lorge GeneralService-Transmission 9T
7 Dusk to Down Lighting 15
8 Lorge Power Service-Secondary 195
9 Large POwer Service~Primory 19P
10 Lorge Power Service-Transmission 19T
11 Agricultural Irrigation Service 24
12 Unmetered General Service 40
13 Street Lighting 41
14 Traffic Control Lighting 42
15 TotalUniformTariffs
16 Specig!Contracts·
17 Micron 26
18 J RSimplot 29
19 DOE 30
20 Hoku 32
21 Total SpecialContracts
22 Total IdahoJurisdiction
·000(.'»i~S ~::;:.....~<1l to,~('j~~'NoeSS;,.,gS."~gQO
v:tp
~...,
Idaho Power Company
Calculation of PCARate by Class
State of Idaho
Case No.IPC~E~12~17
Staff Proposal
II)(21 (31 (4](5](6]
Current Allocoted
Silled Revenue Test Year RevenueShoring Rote Uniform PCA Rote Totol Combined peA Rote
Revenue Shoring Benefit Billed kWh CentsperkWh CenUperkWh Cents perkWh
$397.700.569 ($12.600.7311 4.896.272827 (0.2574)0.3367 0.0793
$381.220 ($12062]4.942681 (0.24401 0.3367 0.0927
$14.990.300 ($474.246]144,888.296 (0.32731 0.3367 0.0094
$176.385.854 1$5.732224]3.056.964.925 (0.18751 0.3367 0.1492
$20.237.805 ($659.119)420,423.939 (0.15681 0.3367 0.1799
$130.585 ($4.253)2712$95 (0.1568]0.3367 0.1799
$1.173.934 1$37.871]6,481.376 (0.58431 0.3367 (0.24761
$319.273 ($10.399]6.678.959 (0.15571 0.3367 0.1810
$81.670.938 ($2664.599)1,930.039,445 (0.13811 0.3367 0.1986
$1.670.079 ($54.541)41.905.243 (0.1302]0.3367 0.2065
$109.785.557 ($3.563.9321 1.720.204,410 (O.20n)0.3367 0.1295
$1.096.245 ($35.5611 15,807,753 (0.2250)0.3367 0.1117
$2959.897 ($95.628]23,165.568 (0.41281 0.3367 (0.0761)
~~=.2ll2 (0.15611 0.3367 0.1806
$808,645,142 ($25.949.819)12273,469.299
$17.176.418 ($561.642]451.138,622 N/A 0.3367 0.3367
$5.727.934 1$220.347)203.558.197 N/A 0.3367 0.3367
$8.393.976 ($274.8691 244.266.665 N/A 0.3367 0.3367
$2.835760 ~Q N/A 0.3367 0.3367
$35.134.087 ($1.149.078)898.963.484
$843.779.229 ($27.098.897)13,172,.432.783
Combined Effect of All Filings
Staff Proposal
Present Billed Rates to 6/1/2012 Billed Rates (PCA &Revenue Sharing)
(1 )(2)(3)(4)(5)(6)(7) (8)
Rate Average Normalized Current Billed Proposed
Line Sch.Number of Energy Billed Revenue Billed Average Percent
J:;Q Tariff Description No.Customers (kWhl Revenue Adjustments Revenue ¢fkWh Chanae
1 Uniform Tariff Rates:
2 Residential Service 1 399.329 4.896.272.827 $397-700.569 $2.469.997 $400.170.566 8.173 0.62%
3 Master Metered Mobile Home Park 3 23 4.942,681 $381,220 $3.152 $384.372 7.777 0.83%
4 Residential Service Energy Watch .4 0 0 $0 $0 $0 0 N/A
5 Residential Service Time-of-Day 5 0 0 $0 $0 $0 0 N/A
6 Small General Service 7 28.165 144.888.296 $14.990.300 $(64.502)$14.925.798 10.302 -0.43%
7 Large General SelVice 9 31,614 3.480.101.459 $196.754.244 $5.229.661 $201.983.905 5.804 2.66%
8 Dusk to Dawn Lighting 15 0 6.481.376 $1.173.934 $(25.478)$1.148.456 17.719 -2.17%
9 Large Power Service 19 116 1,978.623.647 $83.660.290 $4.204.442 $87.864.732 4.441 5.03%
10 Agricultural Irrigation Service 24 16.642 1.720.204.410 $109.785.557 $2.031.893 $111,817.450 6.500 1.85%
11 Unmetered General Service 40 2,030 15.807.753 $1,096.245 $14.898 $1,111,143 7.029 1.36%
12 Street Lighting 41 361 23.165.568 $2.959.897 $(37.019)$2.922.878 12.617 -1.25%
13 Traffic Control Lighting 42 397 2.981.282 $142.887 $5.599 $148.486 4.981 3.92%
14 Total Uniform Tariffs 478.677 12.273.469.299 $808.645.142 $13.832.644 $822..477.786 6.701 1.71%
15
16 Special Contracts:
17 Micron 26 1 451.138.622 $17.176.418 $1,051.179 $18.227.597 4.040 6.12%
18 J RSimplot 29 1 203.558.197 $6.727.934 $512.666 $7.240.600 3.557 7.62%
19 DOE 30 1 244.266.665 $8.393.976 $605.712 $8.999.688 3.684 7.22%
20 Hoku 32 1 Q $2.835.760 $(92.2211 $2,743.539 0.000 -3.25%
21 Total Special Contracts 4 898.963.484 $35.134.087 $2,077.337 $37.211.424 4.139 5.91%
22
23
24 Total Idaho RetaH Safes 478.681 13.172..432.783 $843.779.229 $15.909.980 $859.689.210 6.526 1.89%
000('»
i 1Jl :t.:Q)::l:I;:;;.~~,~
'¢(')ZP"-003N3-,(tIa::a a"(')m"ins,
\"...,
1000(')>-~S~~,u::.~(l)<'"-(')ZEr:-::00:::1N~'<0-'"."'0.-
<0 C)."",~tp
;;:;
-.l
Description
ForecastorProjection (2012·2013)
Accl.501 -Coal
Acct 536 ~Water for Power
Acct.547 -Natural Gas
Accl.555 -Purchased Power (Non-PURPA)
Acet.565 -Transmission Wheeling
Acct.447-Opportunitysales Revenues
Acct.442 -Hoku First Block Energy Revenue
Acct.555 -Purchased Power (PURPA)
Demand Response Incentive Payments
Sub-Total
True Up (2011-2012)
Revenue from Forecast Rate
load Change Adjustment
Acct.501 -Coal
Acct.536 -Water for Power
Accl.547 -Natural Gas
Acct.555 ~Purchased Power(Non-PURPA)
Acct.565 -Transmission Wheeling
Acct.447 -Opportunity Sales Revenues
Acet.442 -Hoku First Block Energy Revenue
Accl.555 -Purchased Power (PURPA)
Emission Allowance Sales Credit
SREC Sales"1"'--~terestDuring DeferralPeriod
Demand Response Incentive Payments
Sub-Total
True Up oftheTrue Up(Reconciliation of the True Up)
Unrecovered TrueUp ofthe True UpAmount Carried Forward
Other Limited Term Adjustments:
PCATrue UpAmountTransferred
EmissionAllowances-ON 32250
OSM RiderFunds -ON 32217
Interest During Amortization
Revenuefrom True Up &True Up oftheTrue Up Rates
Sub-Total
Tolal Power Cost Adjustment (PCA]
[liilii3lAirioullt I
(18,152,666)
4,181,114
(491,989)
10,000,000
(66,926)
(634,702)
(5,165,169)o o
(18,152,666)
4,181,114
(491,989)
10,000,000
(66,926)
(634,702)
(5,165,169)(0.0392)
I 0,3367 1
!
HISTORY OF peA AMOUNTS
2012 -2013 PCA Year
300.0 1
250.0--l!!
lI$200.0"00-0 150.0III
C.2
100.0:i-~
::I 50.00
E««0.00a.
(50.0)+1------------'-------------'
'.
,~tf ~~'.1
V;~t't>~I;::,(")z"'"NOOS§."..-"-o~g·~O
.(it :E
'",
-..l
(100.0)1 1993 11994119951 1996
.PCAAmountsl 4.9 114.71 8.11(17.6)
PCAYear
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 15TH DAY OF MAY 2012,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF,IN
CASE NO.IPC-E·12·17,BY MAILING A COPY THEREOF,POSTAGE PREPAID,TO
THE FOLLOWING:
JULIA A HILTON
LISA DNORDSTROM
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
EMAIL:[e-mail]
[e-mail]
PETER J RICHARDSON
GREGORY MADAMS
RICHARDSON &O'LEARY
POBOX7218
BOISE ID 83702
EMAIL:[e-mail]
[e-mail]
SCOTT WRIGHT
GRBGSAID
IDAHO POWER COMPANY
PO.BOX70
BOISE ID 83707.0070
EMAIL:[e-mail]
[e-mail]
DR DON READING
6070 HILL ROAD
BOISE ID 83703
EMAIL:[e-mail]
-Jo~SECRETA
CERTIFICATE OF SERVICE