20220427Joint Comments-Redacted.pdf

; I ,..' i:: i !J i::.z
.. i' :, ,: j {}ii l;; 5BRose Monahan (CA 329861) (Pro Hac Yice)
Sierra Club Environmental Law Program
2l0l Webster Street, Suite 1300
Oakland, CA946l2
(4ts) 977-s704
[e-mail]
Attorneyfor Siena Club
Benjamin J. otto (lSB No. 8292)
710 N 6s Street
Boise,ID 83701
Ph: [phone] x t2
Fax: [phone]
[e-mail]
Attorneyfor the ldaho Conservation League
BEFORE IDAHO PUBLIC UTILITIES COMMISSION
ilii:i(ll
IN THE MATTER OF IDAHO POWER
COMPANY' S APPLICATION FOR
AUTHORITY TO INCREASE ITS RATES
FOR ELECTRIC SERVICE TO RECOVER
COSTS ASSOCIATED WITH THE JIM
BRIDGER POWER PLANT
)) CASE NO. rPC-E-21-17
)) JOINT COMMENTS OF rDAHO
) CONSERVATION LEAGUE AND
) SIERRA CLI.JB
)
Public Version
April27,2022
TABLE OF CONTENTS
I. Introduction................ ................... I
II. The Commission Should Not Guarantee Idaho Power Cost Recovery on its Jim Bridger
Expenditures Prior to a Firm Commitment to Exit the Plant.. ........................3
III.Idaho Power's Analysis of the Uneconomic SCR Project on Units 3 and 4 Was
Insullicient and Resulted in the Imprudent Investment of Over 100 Million Dollars into
Jim Bridger................ .................... 6
A. Idaho Power Failed to Robustly Reevaluate the Decision to Install SCR Updates at Units
3 and 4 at Decision Points that Would Have Allowed the Company to Avoid Substantial
Project Costs, As Ordered by the Commission................ .............. 8
l. The plant owners made the decision to move forward with the SCRS long before
Idaho Power performed any analysis................. ...................... 9
2. The Commission warned Idaho Power that it was obligated to reevaluate alternatives
as regulations changed and the Company was not guaranteed cost recovery.............12
B. Idaho Power Relied on Simplistic Screening Analysis in20l3 and then a Flawed Updated
Analysis in 2015 to Justiff its Decision to Move Forward with the SCR Project............ 14
1. 2013 Coal Unit Environmental [nvestment Analysis
a. 2013 SAIC Study
b. Natural Gas Forecast..................
l6
l6
t7
20c. Coal Price Forecast
d. COz Price Sensitivity
2. The 2015 IRP Study.......
C. The Limited Analyses Conducted by Idaho Power Regarding the SCRs Should Not Have
Been Relied Upon to Make Such a Consequential Decision as Investing Over $100
Million of Ratepayer Dollars into Jim Bridger, and the Commission Must Now Protect
Customers from the Company's Imprudence ...........26
IV.Idaho Power Should Consider Securitizing Prudently Incurred Coal Debt on JimBridger.... ...................27
A. Securitization Is an Appropriate Ratemaking Tool to Address the Changing Economic
Life of Bridger 28
B. [daho's Existing Securitization Legislation Provides an Optimal Ratemaking Treatment to
Recover Jim Bridger Costs.
.......21
)L
...30
C. RMI Modeled the Benefits of Recovering Idaho Power's Bridger Costs Through
Securitization and Found that Securitization Would Save Ratepayers $63.7 Million......32
D. Idaho Power Should Explain Why it Is Not Considering Securitization that Could Save
Ratepayers Tens of Millions of Dollars........... ......... 35
V. Conclusion..........36
REDACTED VERSION
LIST OF TABLES
Table 1. Regulatory timeline for SCR approval for the Jim Bridger PIant..........l0
Conlidential Table 2. SAIC's Total Overestimation, in Net Present Value, of the Cost Impact of
aCOz Price on Natural Gas Generation and Underestimation of the Impact on Coal
Generation 23
Conlidential Table 3. The total cost of the SAIC's carbon prices on Units 3 burning coal or gas
24
LIST OF FIGURES
Confidential Figure l. Natural Gas Price Forecasts from 2013 SAIC Coal Unit Environmental
Analysis vs EIA AEO Forecasts l9
Confidential Figure 2. Coal Price Forecast Used by IPC in 2013 Studies 2t
LIST OF ATTACHMENTS
Attachment I
Attachment 2
Attachment 3
Attachment 4
Attachment 5
Attachment 6
Attachment 7
Attachment 8
Attachment 9
Mine Profile: Black Butte & Leucite Hills Mines (S&P Global Market
Intelligence)
Confidential Attachments 1,2, and 3 to IPC Response to Industrial
Customer of Idaho Power Request No. 43
Confidential Attachment 2 to IPC Response to Sierra Club Request No. l8
("Confidential SAIC Study")
Attachment I to IPC Response to Sierra Club Request No. l8 ("2013 Coal
Unit Environmental Analysis")
Confidential Attachment I to IPC Response to Sierra Club Request No. 22
Confidential Attachment 3 to IPC Response to Sierra Club Request No. 28
Confidential Attachment I to IPC Response to Sierra Club Request No. 24
- Bridger Coal Price Forecast
Confidential Attachment 2 to IPC response to Sierra Club Request No. 28
- JB Coal Aurora Vectors
RMI Jim Bridger Analysis
ll
REDACTED VERSION
BEFORE IDAHO PUBLIC UTILITIES COMMISSION
TN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR
AUTHORITY TO TNCREASE ITS RATES
FOR ELECTzuC SERVICE TO RECOVER
COSTS ASSOCIATED WITH THE JIM
BRIDGER POWER PLANT
CASE NO. IPC-E-21-17
JOINT COMMENTS OF IDAHO CONSERVATION LEAGUE AND SIERRA CLUB
IPUBLTC VERSTONI
I. Introduction
Idaho Conservation League (*ICL") and Sierra Club appreciate the opportunity to submit
the following comments.l In this proceeding, Idaho Power Company ("IPC," "Idaho Power," or
"Company") seeks Commission approval to accelerate depreciation on its coal-related
investments at the Jim Bridger power plant and create a balancing account in order to track the
incremental costs associated with the cessation of coal operations at the plant.2
As discussed below, the Commission should deny Idaho Power's application for at least
three reasons. First, the Company has not secured a firm exit plan from Jim Bridger with Idaho
Power's co-owner, PacifiCorp. The Company freely acknowledges that current contractual
agreements do not permit the exit of one owner while another owner continues operations.3 As a
result, Idaho Power is seeking to guarantee its own cost recovery for prior investments in Jim
Bridger through accelerated depreciation without guaranteeing any benefit to ratepayers resulting
I These comments were prepared with the assistance of Devi Glick at Synapse Energy Economics, Inc. and Ben
Semrrier at RMI (formerly the Rocky Mountain Institute).
2 Supplemental Direct Testimony of Matthew T. Larkin on Behalf of Idaho Power Company al 5:16-6:2 (Feb. 16,
2022) [hereinafter "Larkin Supplemental"].
3 Direct Testimony of Ryan N. Adelman at 7:22-8:l (lune 2,2021) [hereinafter "Adelman Direct"].
tPc-E-2t-17
ICL/Sierra Club Joint Comments
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1
REDACTED VERSION
from early exit from the plant. Accelerated depreciation, which increases customer rates in order
to ensure full recovery under a shorter time frame, should not be approved by this Commission
until Idaho Power is able to guarantee that it will, in fact, exit the plant earlier than currently
forecasted.
Second, Idaho Power's decision to spend nearly $l l0 million on selective catalytic
reduction ("SCR") pollution control technology on Units 3 and 4 was imprudent. To put into
context the significance of this expenditure, of the total coal-related Bridger costs from 201 I
through 2020 for which Idaho Power seeks approval in this proceeding, the SCR investment
alone represents approximately 50 percent. Despite the enormity of the investment, Idaho Power
failed to keep abreast of rapidly changing economic conditions and took no action to avoid the
expenditure even when it was no longer the lowest cost option compared to other options. In
order to protect Idaho customers from the Company's imprudence, the Commission should
disallow any rate of return on the SCRs. Doing so would be in line with actions other state utility
commissions have taken to protect ratepayers from imprudent investment in these same SCRs.a
Finally, regardless of whether the SCRs are recovered, the Commission should not
approve this application because Idaho Power has not explained why it has chosen an unusual
form of rate recovery-accelerated depreciation-in place of lower cost, alternative forms of rate
recovery, such as securitization. ICL and Sierra Club's analysis, conducted by RMl,
demonstrates that securitizing these costs would save ratepayers approximately $63.7 million
compared to accelerated depreciation. This level of savings should be taken seriously by Idaho
a See, e.g., In the Matler of PacifiCorp, dba Pacific Power, Request for a General Rate Revision, Docket No. UE
374, Order No.20-473 (Ore.P.U.C Dec. 18, 2020) (denying any return on equity in PacifiCorp's "retum on" the
SCR investment at Jim Bridger Units 3 and 4); Washington Utililies and Transportation Commission v. PociJic
Power & Light Company, DocketNo. UE-152253, OrderNo. l2 (Wash.U.T.C. Sept. 1,2016) (denying any return
on investment in SCRs on Jim Bridger Units 3 and 4).
[PC-E-ZI-t7
ICllSierra Club Joint Comments 2
REDACTED VERSION
Power, as securitization will achieve all of the utility's stated goals in this proceeding but at
significantly lower cost to customers.
I The Commission Should Not Guarantee Idaho Power Cost Recovery on its Jim
Bridger Expenditures Prior to a Firm Commitment to Exit the Plant
Jim Bridger is a four unit coal-fired power plant located in Sweetwater County, Wyoming
that is co-owned by Idaho Power and PacifiCorp. The plant consists of four generating units, of
which Idaho Power owns a one-third stake (771 MW).s Although PacifiCorp operates the plant,6
the two companies "work jointly to make decisions regarding the plant, including required
investment and [future] retirement."T As noted above, no conffactual provisions exist that would
allow for one owner to end participation in a Bridger unit during a time when the other co-owner
wishes to continue operations.s
The Jim Bridger plant is relatively expensive to own and operate. For instance, of
PacifiCorp's entire coal fleet (10 plants comprising 22 units), Jim Bridger's four units are
consistently some of the highest cost, largely due to fuel expense.e The Bridger Coal Company
("BCC" or "Bridger mine") and Black Butte mines are the plant's primary suppliers. BCC is a
captive mine that is also co-owned by PacifiCorp and Idaho Power and exclusively services the
Jim Bridger plant.r0 As with the plant, Idaho Power holds a one-third share in the Bridger mine.
Although the Black Butte mine is third party owned, its primary customer is Jim Bridger. [n fact,
5 IPC Amended Application and Motion to Set Schedule at 3,'l[5 (Feb. 16,2022) [hereinafter "Amended
Application"].
6 Amended Application at 3, !f 5.
7 IPC Application at 3, ![5.8 Adelman Direct at 7:ll-19.
e See, e.g., In the Matter of PaciJiCorp, dba Pacific Power, 2022 Transition Adjustment Mechanism, Docket No. UE
390, Opening Testimony Of Ed Burgess on Behalf of Sierra Club at 16:4-8 (Ore.P.U.C. June 9, 2021), available at
httos://edocs.ouc.state.or.us/efdocs/tlTB/ue390htbl648l2.pdf (explaining that on a $/\,IWh basis, coal bum
expenses at Jim Bridger are significantly higher than costs of potential alternatives, including PacifiCorp's other
coal plants, gas plants, and the new installation ofrenewable energy resources).
t0 See, e.g., Amended Application at4,l9.
LPC-E-?I-17
ICLlSiena Club Joint Comments 3
REDACTED VERSION
in202l,Jim Bridger was Black Butte's only customer.ll Recent modeling in PacifiCorp's2021
IRP suggests that assumed minimum required coalpurchases from BCC and Black Butte are
driving uneconomic generation at the plant and that without those constraints, generation at Jim
Bridger would plummet. 12
Installation of pollution controltechnology, such as SCR controls, also increases a plant's
operating costs. This is true not only because construction and installation costs are high but also
because these controls have ongoing operational costs. SCR pollution control technology
requires large volumes of catalyst for the nitrogen oxide ("NOx") reduction reaction and these
catalysts must be replaced on a regular basis.l3 As discussed more fully below, between 2013
and20l6,Idaho Power and PacifiCorp installed SCRs on Bridger units 3 and 4.ta In combination
with high fuel costs, SCRs on units 3 and 4 help to explain why Jim Bridger is such an expensive
plant to own and operate.
rr Mine Profile: Black Butte & Leucite Hills Mine, S&P Global Market Intelligence
https://www.capitalio.spslobal.corn/web/client?auth:inherit#coalMine/mineProfile?id:2423 (provided as ICL/SC
Attachment l).
t2 In the Matter of Rocly Mountain Power's Filingfor Aclmowledgement of ils 2021 Integrated Resource Plan,Case
No. PAC-E-2l-19, Joint Comments of Siena Club and ldaho Conservation League at3l-32 (Mu. 15,2022),
ovailable at
httos://nuc.idaho.eov/Fileroom/PublicFiles/ELECtPAC/PACE2I19/Intervenor/ICL/202203lsJoinflo20CommentsTo
20and%20Attachments-Redacted.pdf (describing generation at Jim Bridger under modeling conducted by
PacifiCorp that removed minimum take requirements at Jim Bridger). See also In the Matter of PacifiCorp's 2021
Integrated Resource Plan,Docket No. 2l-035-09, Redacted Reply Comments of Western Resource Advocates at 2
(Utah.P.S.C Apr. 7, 2022), ovailable at
httes://pscdocs.utah.gov/electric/2ldocs/2103509/32338lRdctdWRARplyCmnts4-7-2022.pdf (commenting on same
"No Minimum Scenado" and concluding that "Jim Bridger Units 3 and 4 are so costly to operat€ that they would not
be dispatched beyond 2030 in a least-cost optimization without constraining the model with minimum-take fuel
requirements).
t3 EPA Air Pollution Control Cost Manual, U.S. EPA, Section 4, Chapter 2 al2-10 (June 2019), available at
https://www3.epa.eov/ttn/ecas/docs/SCRCostManualchapterTthEdition 20l6.pdf. In fact, replacement of the
catalyst for Unit 3's SCR controls is included in Idaho Power's application. Amended Application at 5, t[ 10.
14 Units I and2 similarly have federally mandated SCR requirements by the end of the202l and2022; however,
neither co-owner has taken any action to install the SCRs on either unit. Idaho Power Company, 202 I Inlegrated
Resource Plan at 102 (Dec. 2021), available at
https://docs.idahopower.com/pdfs/AboutUs/PlanningforFuture/iro/202112021%20IRP WEB.pdf[hereinafter"202l
IPC IRP"I.
IPC-E-zl-17
ICL/Siena Club Joint Comments 4
REDACTED VERSION
Due to these costs, it is unsurprising that Idaho Power's latest IRP projects exiting from
Units 3 and 4 by 2025 and 2028 and converting Units I and 2 to gas in 2024, with a 2034 exit
date for those units.rs ICL and Sierra Club support the Company's planned exit from Jim Bridger
as it will benefit both ratepayers and the environment.16 However, that exit is not yet guaranteed.
Currently, Idaho Power and PacifiCorp forecast different futures for the plant. While Idaho
Power is rightfully planning to exit Jim Bridger in the near-term, PacifiCorp's latest 2021 IRP
continues to forecast operating units 3 and 4 throu gh 2037-another l5 years.lT For the planned
gas conversions at Units I and2,Idaho Power's IRP anticipates exit from these units in2034,
whereas PacifiCorp plans to operate them until 2037.18
These differences are important. As Mr. Adelman testified, PacifiCorp and Idaho Power
"have not developed contractual terms that would be necessary to allow for the potential earlier
exit of a Bridger unit by one co-owner, and not both Co-Owners."le As a result, Idaho Power is
unable to provide any information on the terms of an exit agreement with PacifiCorp or what
costs might be borne by Idaho ratepayers to facilitate the planned early exit. Put simply, Idaho
Power is unable to ensure that it will exit from Jim Bridger in line with its most recent IRP or at
what cost.
Nevertheless, rather than first securing a firm exit from the plant, Idaho Power instead
asks this Commission to accept its anticipated exit dates as firmly set and authorize accelerated
ts Id. atls2.
16 In fact, it's possible that leaving Jim Bridger even earlier would be the most economic outcome for ratepayers.
Sierra Club and Idaho Conservation League's comments should not be construed as endorsing IPC's planned exit
from Jim Bridger. IPC should continue to evaluate exit from the plant and exit earlier if doing so would be economic
for ratepayers.
r7 PacifiCorp, 202 I Integrated Resource Plan,Yol.I at l5 (Sept. 1,2021), available at
https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2021-
irp/Vo lume%201yo20 -o/o209 . I 5 .2021 %20F inal. pdf.
t8 Id.
re Adelman Direct at 7:22-8:1.
tPc-E-zt-17
ICL/Siena Club Joint Comments 5
REDACTED VERSION
depreciation. This approach is clearly advantageous for ldaho Power: it would guarantee the
Company an accelerated recovery of its prior expenditures at the plant and fuither allow the
Company to create a balancing account to recover future expenditures. However, this approach is
less clearly advantageous for ratepayers, who would pay the costs of accelerated depreciation on
previous and future expenditures without any assurance of an early exit from the plant, the
reason used to justiff the accelerated depreciation proposal in the first place. This puts
tremendous risk on ratepayers while simultaneously removing both Idaho Power's risk and
incentive to exit the plant.
The Commission must condition any accelerated depreciation (or other financing) order
on a firm exit plan, including contractual agreements with PacifiCorp that guarantee Idaho
Power's timely exit from the plant. ICL and Sierra Club further recommend that the Commission
require regular updates to inform the Commission as to the status of a firm exit agreement with
PacifiCorp and only permit cost recovery based on accelerated depreciation once the agreement
is finalized.
III.Idaho Power's Analysis of the Uneconomic SCR Project on Units 3 and 4 Was
Insufficient and Resulted in the Imprudent Investment of Over 100 Million Dollars
into Jim Bridger.
Idaho Power's decision to spend $58.29 million and $51.65 million on SCR controls at
Units 3 and 4, respectively, were the largest expenditures made at the Jim Bridger plant since
2}ll.20 At the time the expenditures were made, Idaho Power assumed an indefinite retirement
date for these units. Now, in its current application, the Company seeks to accelerate
20 Adelman Direct at 13:14-17
LPC-E-21-17
ICllSierra Club Joint Comments 6
REDACTED VERSION
depreciation on the investment, from2034 to 2030,2t due to its plans to stop taking power from
Units 3 and 4, and thus no longer utilize the SCR equipment, by 2025 and 2028 respectively.
There is liule dispute that the decision to install SCRs at Jim Bridger Units 3 and 4 was
not economic for ratepayers. This is obvious for at least two reasons. First, while initial analysis
showed that the SCR project was economic, the next lower cost option would have been
conversion to natural gas. PacifiCorp, the majority owner and operator for the plant, forecasted
that the "breakeven" levelized average cost for gas was $4.86A4MBtu over PacifiCorp's
planning period.22 In other words, if gas prices stayed above $4.86/\rIMBtu, the SCR installation
was in ratepayers' economic interest; gas prices below this figure meant that the project would
cost ratepayers more than other viable alternatives. Since 2015 and 2016, when the SCRs were
installed on Units 3 and 4, gas prices have remained far below $4.86 per MMBtu,23 and only
recently exhibited an upturn in response to the pandemic and the Russian war in Ukraine. Recent
gas price forecasts project costs below $4.00 per MMBtu at least through 2028, notably the date
that Idaho Power now plans to exit from all coal operations.2a
2r Amended Application at 6, gfl 12-13.
2? In the Matter of PaciJiCorp, dbo Pacific Power, Requestfor a General Rate Revision, Docket No. UE 374, Direct
Testimony of Rick T. Link on Behalf of PacifiCorp (PAC/700) at 107:8-9 (Ore.P.U.C. Feb. 2020), ovailable at
hups://edocs.puc.state.or.us/ef<locsfuAA,/ue374uaal45444.pdf (Mr. Link's testimony begins on PDF p. 437).
23 U.S. Energy Information Administration @IA), Idaho Natural Gas Prices, available ot
httgs://www.eia.gov/dnav/ngy'ng pri sum dcu SID ahtm(lastaccessed Apr.26,2022).
24 U.S. EIA, ElAforecasts natural gas prices to remain near $4/MMBtu in 2022, slightly lower in 2023 (Jan. 14,
2022), available al https://www.eia.gov/toda),inenersy/detail.php?id:50898.
[PC-E-ZI-t7
ICL/Sierra Club Joint Comments 7
REDACTED VERSION
Second, when Idaho Power decided to move fonvard with the SCR project, the Company
assumed an indefinite closure date for coal operations at Jim Bridger.2s Today, Idaho Power
plans to exit from coal in 2023 (Units I and2),2025 (Unit 3), and 2028 (Unit 4). While exiting
from Jim Bridger is in ratepayers' best interest, this decision also means that the SCRS useful life
for Idaho ratepayers has been dramatically shortened.
The question for this Commission, then, is whether [PC's decisions related to the Jim
Bridger SCRs were reasonable, even though they were wrong. Due to Idaho Power's failure to
monitor rapidly changing economic conditions and change course when the SCRs were no
longer economically viable, the clear answer is no. As a remedy, the Commission should
disallow Idaho Power's return on investment in the SCRS, as other commissions have done
pertaining to these same SCRs.
A. Idaho Power Failed to Robustly Reevaluate the Decision to Install SCR
Updates at Units 3 and 4 at Decision Points that Would Have Allowed the
Company to Avoid Substantial Project Costs, As Ordered by the
Commission
As discussed above, PacifiCorp is the majority (trvo-thirds) owner of the Jim Bridger
plant and also the plant operator. Idaho Power is the co-owner and is responsible for its one-third
share of the plant costs, which it passes on to its ratepayers. Even though Idaho Power is not the
plant operator, it still has a responsibility to ensure that the plant is operated prudently and that
2s ln three analyses between 2013 and 2017, Idatro Power evaluated the useful life of Jim Bridger through2032,
2034, and 2037 . See In the Matter of ldaho Power Company's Application for a Certifrcate of Public Convenience
and Necessityfor the lrwestment in Selective Catalytic Reduction Controls on Jim Bridger Unils 3 and 4,CaseNo.
IPC-E-13-16, Ex. 5A "Coal Environmental Compliance Upgrade Investment Evaluation" to the Direct Testimony of
Tom Harvey at 3-8, 3-9("coal study" with a planning period through 2032), available at
https://puc.idaho.gov/FileroomlPublicFiles/ElECflPC/IPCEl3l6/Company/20l3O927Redactedo/o20Harvevo/o20Exh
ibi9/o20SA.pdf [hereinafter'IPC-E-13-16, Redacted SAIC 2013 Coal Study"]; Idaho Power Company,20l5
Integrated Resource Plan, App. C at l2l-130 (June 2015), available at
hftos://puc.idaho.eovlFileroomPublicFiles/ELEC/IPC/IPCE I 5 l9lCaseFiles/20 I 50630IRP%20Aeeendix%20C%20
Technicalo/o20Report.pdf (analysis through 2034) [hereinafter "App. C to 2015 IPC IRP"]; Idaho Power Company,
2017 Integrated Resource Plan at 83 (analysis through 2037).ln each ofthese, Jim Bridger operated through the end
of the planning period. Accordingly, no analysis identified a closure date for the plant.
IPC-E-21-17
ICLlSiena Club Joint Comments 8
REDACTED VERSION
its ratepayers do not incur unnecessary costs. IPC indicated that it works with PacifiCorp to
make decisions regarding operations and planning at the plant.26
The co-ownership relationship does not appear to be in the best interest of tdaho
ratepayers, particularly regarding the decision to install SCRs on Units 3 and 4. Rather, the
Company's decisions at the plant regarding the SCR installation appear to be driven by
PacifiCorp's actions, with its own analysis only conducted after-the-fact and designed to support
a decision that had already been made. As evidence that the co-ownership is not in the best
interest of Idaho Power customers, Idaho Power began seeking an exit path from the Jim Bridger
plant in!,
27
l. The plant owners made the decision to moveforwardwith the SCRs long
before ldaho Power performed any analysis.
The decision to move forward with the SCR project was made long before [daho Power
conducted any analysis. Specifically, in January 2011, PacifiCorp, in conjunction with the
Wyoming Department of Environmental Quality ("DEQ"), agreed to install SCRs on Units 3 and
4 (and, potentially Units I and? at a later date) as part of its Regional Haze Implementation Plan
("FIP';.za Less than ayear later, in August Z}l2,PacifiCorp filed a CPCN with the Wyoming
Commission for the SCRs and a voluntary request for approval with the Utah Commission. It
wasn't until nearly ayear later, in May 2013, that IPC filed a CPCN for the SCRs with the Idaho
Commission. This application was filed the same month the Wyoming and Utah Commissions
26 Amended Application at 3, ![5.
27 Confidential Attachments I , 2, and 3 to IPC Response to Industrial Customer of Idaho Power Request No. 43
(provided as ICL/SC Attachment 2).
2E IPC-E-13-16, Redacted SAIC 2013 Coal Study at 2-1.
tPc-E-21-17
ICL/Sierra Club Joint Comments
and
9
REDACTED VERSION
both approved the CPCN applications for the SCRs in their respective states. A full regulatory
timeline is listed in Table I below.
Table 1. Regulatory timeline for SCR approval for the Jim Bridger Plant
2e IPC-E-13-16, Redacted SAIC 2013 Coal Study at 2-1.
30 In the Matter of ldaho Power Company's Applicalionfor a Certificate of Public Convenience and Necessityfor
the Investment in Selective Calalytic Reduction Conlrols on Jim Bridger Unils 3 and 4, Case No. IPC-E-13-16,
Application at 4, ![ 8(June 28,2013), available at
https://puc.idaho.eov/Fileroom/PublicFiles/ELEC/lPC/IPCE I 3 l6lCaseFiles/20130701Application.pdf [hereinafter*CPCN Application"].
3t Id. at 4,n7 .
32 Id. at4,18.
13 Id.
3a Adelman Direct at 17:20-24.
[PC-E-2I-17
ICL/Sierra Club Joint Comments
Date Wvomins Utah Idaho
January,20l l Pacifi Corp, in conjunction
with the Wyoming DEQ,
agreed to install SCRs on
Units 3 and 4 as part of
Reeional Haze FIP.2e
August,2012 PacifiCorp filed a CPCN
with the Wyoming
Commission for the
SCRS.30
PacifiCorp filed a
voluntary request for
approval of the SCRs with
the Utah Commission.
February,
2013
SAIC study is completed.
April,20l3 PacifiCorp issued an internal memo recommending the awarding of an Engineer,
Procurement, and Construction ("EPC") Contract to Babcock and Wilcox Power
Generation Group and the Perry Group.
May,2013 EPA approved and
disapproved portions of
the Wyoming Regional
Haze SIP.3r
Wyoming Commission
approved CPCN for SCRs
in docket No. 200000-418
(Record No. 13314)32
Utah Commission issued
its final order approving
SCRs (Docket No. 12-
035-92).33
June 2013 IPC filed a CPCN with the
Idaho Commission
seeking authorization for
investment in SCR
controls.3a
l0
REDACTED VERSION
Securing approval from three state commissions and environmental agencies undoubtedly takes
time and coordination, but it appears that IPC waited until the decision was already made in Utah
and Wyoming before bringing its application to the Idaho Commission. By doing this, Idaho
Power was not allowing the Idaho Commission to play a major role in the review and decision-
making process for the SCR project. But even more concerning is that this timing gave the
Company a strong incentive to make sure any analysis included with its application supported
the position that installing the SCRs was the lowest cost option. Because any other result would
35 Approval, Disapproval and Promulgation of Implementation Plans; State of Wyoming; Regional Haze State
Implementation Plan; Federal Implementation Plan for Regional Hazn,79 Fed. Reg. 5032 (Jan. 30,2014).
36 ld. at 5046.
31 Id.
[PC-E-ZI-17
ICL/Siena Club Joint Comments
Date Wyominq Utah Idaho
December,
2013
Idaho Commission issued
order in Case No. IPC-E-
l3-16 (Order No. 32929)
approving the company's
application for a CPCN
for the SCRs at Units 3
and 4.
IPC gave PacifiCorp
formal notice to support
the issuance ofa full
notice to proceed
("FNTP") with the SCR
proiect.
January,2014 EPA issued final approval
for the Wyoming strategy
to install SCRs at Units 3
and 4 in 2015 and2016
respectively, and for Units
I and2in202l and2022
respectivelv.35
June, 201 5 IPC's 2015 IRP is
published with an updated
SCR study in Appendix C.
December 31,
20ts
Compliance deadline for Unit 3.36 Construction on Unit 3 SCR is completed
December 31,
2016
Compliance deadline for Unit 4.37 Construction on Unit 4 SCR is completed.
11
REDACTED VERSION
have contradicted the approvals that PacifiCorp had just received in Utah and Wyoming, it
would have complicated things immensely for itself and PacifiCorp, and it would have made it
challenging for the owners to comply with the EPA regulations by the now-required 2015 and
2016 dates.
2. The Commission warned ldoho Power that it was obligated to reevaluate
alternatives as regulations changed and the Company was not guaranteed
cost recovery.
When the Idaho Commission ruled on IPC's CPCN application in December 2013, the
Commission was clear in its final order that it was concerned about the economics of the
conversion. It also indicated in its order that it expected the Company to regularly reevaluate the
economics of the project and whether altematives were more economic. Specifically, the
Commission stated:
It is not inconceivable that, during the installation of the SCRs, a tipping point could
be reached making them uneconomic. It is in the best interest of the customers, the
Company, and the Company's shareholders for Idaho Power to be continuously
analyzingthe impact of changing environmental regulations on its upgrade project.
As the project moves toward completion over the next several years, we direct
Idaho Power to return to the Commission if viable alternatives to the Bridger Units
3 and 4 upgrades become available.3s
The Commission also expressed concern that future environmental regulations will make
the plant more costly to operate, and thus threaten the economics of the plant:
The Commission's primary concem is the possibility of more stringent
environmental regulations that could make the Bridger upgrades, and thus the
Company's investment, uneconomic.3e
38 In the Matter of ldaho Power Company's Applicationfor a Certificate of Public Corrvenience and Necessityfor
the Investment in Selective Catalytic Reduction Controls on Jim Bridger Units 3 and 4, Case No, IPC-E-I23-16,
Order No. 32929 at I I (Dec. 2,2013), ovailable at
httos://nuc.idaho.eov/Fileroom/PublicFiles/ElEC/IPCilPCEl3l6/OrdNotc/20131202fina1 order no 32929.pdf
[hereinafter "Order No. 32929"1.
3e In the Matter of ldaho Power Company's Application for a Certificote of Public Cowenience and Necessity for
the Investment in Selective Catolytic Reduction Controls on Jim Bridger Units 3 and 4,Case No, IPC-E-123-16,
Order No. 32996 al3 (Mar. 14,2014), ovailable at
httes://puc.idaho.sovffileroom/PublicFiles/ElEC/IPC/IPCEl3l6/OrdNotc/20140314final order no 32996.pdf.
tPc-E-2t-17
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REDACTED VERSION
The Commission was clear in its final order that it was not guaranteeing recovery of the
costs associated with the SCR:
Because of the uncertain future of coal-fired generation, we find it unreasonable
to prematurely commit ratepayer dollars to support Idaho Power's investment.ao
Finally, the Commission required IPC to submit quarterly reports on the status of the
project and any changes in environmental regulations that could impact the economics of the
SCR investment relative to alternatives.
We recognize that the future of coal-fired generation in the United States is
uncertain at best. We admonish the Company to stay abreast of potential future
environmental regulations that could negatively impact its investment in the
Bridger upgrade. To that end, we direct the Company, as a condition of its CPCN
(Idaho Code $ 6l-528), to submit quarterly reports updating the Commission on any
changes to environmental policy or regulations as the Bridger upgrades are installed
and placed in service.al
The Commission's direction in its CPCN order should have made clear to IPC that
continuous analysis of the SCR project was necessary. While the Commission largely focused on
the potential for new environmental regulations undermining the economics of the project, it is
clear that the Commission's ultimate objective was to avoid unnecessary and expensive
investment in an aging coal plant. The Commission's reference to "the uncertain future of coal-
fired generation" foresaw that IPC may seek to exit the plant earlier than contemporary forecasts
predicted, and, indeed, IPC now plans to exit from all coal operations at the plant by 2028. The
need to seriously scrutinize continued investment in the plant was, thus, obvious. Although the
Commission ultimately approved the CPCN, its order makes clear that IPC's diligence should
have been heightened, not relaxed.
ao Order No.32929 at 12.
4t Id. atll.
[PC-E-21-17
ICL/Sierra Club Joint Comments r3
REDACTED VERSION
Yet, in the Company's required quarterly reports, the Company outlined progress on the
project, but did not provide additional economic analysis of the project as a whole until June of
2015, ayear and a half after the full notice to proceed was issued.a2 By this time, construction
had been underway for over ayear, and the ability to avoid additional costs at that time was
much more limited than if the study had been conducted earlier. Specifically, 99 percent of Unit
3 and 60 percent of Unit 4's structural steel was in place, 70 percent of the reactor piping at Unit
3, and 30 percent of the overall electrical field work was completed. Additional equipment for
Unit 3 had been ordered and shipped, and the order for Unit 4 was in process.a3
It is unclear why the Company did not immediately begin the process of updating its
analysis upon approval of the CPCN, and why it did not otherwise provide updated analysis in
early 2014 to confirm that the project was still economic, when it still had an opportunity to
avoid sinking tens of millions of ratepayer dollars into the plant. By delaying until the project
was already underway, IPC had a strong incentive to deliver results showing the project was
economic. Finding otherwise would mean admitting that a project that was actively underway
and already incurred tens of millions of dollars, was no longer prudent.
B. Idaho Power Relied on Simplistic Screening Analysis in 2013 and then a
Flawed Updated Analysis in 2015 to Justify its Decision to Move Forward
with the SCR Project
Idaho Power relied on two different analyses to show, and then later confirm, that
installing SCRs on Units 3 and 4 was the least cost and lowest risk option. However, the inputs
and methodology used in each set of analysis undermined the final conclusions.
o'App. C to 2015 IPC IRP at l2l-130.
a3 In the Matler of ldaho Power Company's Applicationfor a Certificate of Public Convenience and Necessityfor
the Investment in Selective Catalyic Reduction Controls on Jim Bridger Units 3 and 4, Case No, IPC-E-123-16,
Idaho Power Company's 6th Quarterly Report (June 3, 2015), available at
https://puc.idaho.eov/Fileroom/PublicFileslELEC/IPC/IPCEl3l6/Compan),/20l50603Sixth%20Ouarterly%20Repor
LpSlf [hereinafter "June 3,2015 Quarterly Report"].
IPC-E-zl-17
ICL/Sierra Club Joint Comments t4
REDACTED VERSION
The first set of analysis was conducted in2013 as part ofthe Company's application for a
CPCN from the Idaho Commission for the SCRs. The analysis had trvo parts. The first part was
conducted by Science Applications International Corporation ("SAIC") and published February
8,2013 (*SAIC Study";.44 This study estimated the capital and variable costs associated with
the proposed environmental upgrades and of the replacement option of a gas "combined cycle
combustion turbine" ("CCCT") plant and also conversion to gas. The second part, which
incorporated the results of the first, was completed by tPC using economic dispatch modeling
tool Aurora (*2013 Portfolio Analysis").4s This analysis evaluated the total portfolio cost over a
twenty-year period of the options considered by SAIC. These results were combined and
reported as the 2013 Coal Unit Environmental Investment Analysis.a6
The second analysis was conducted in 2015 and was included in [PC's 2015 tRP ("2015
IRP Study").4'A. discussed above, construction had been underway for over a year at the time
the study was conducted, a8 and therefore the ability to avoid additional costs at that time was
more limited than if the study had been conducted earlier. As of June 30, 2015, the Company had
alreadyincurredactualcostsequivalentto*oundfofthetotalprojectcost.49
Each of these studies contains assumptions and shortcomings that made the installation of
SCRs and continued combustion of coal appear to be the most cost-effective option. Other data
available at the time, however, calls that conclusion into question.
a Confidential Attachment 2 to IPC Response to Sierra Club Request No. l8 (provided as ICL/SC Attachment 3)
[hereinafter "Confidential SAIC Study"]. A redacted version of this study was provided as Ex. 5A "Coal
Environmental Compliance Upgrade lnvestment Evaluation" to the Direct Testimony of Tom Harvey in IPC-E-13-
l6 and is referred to as "IPC-E-13-16, Redacted SAIC 2013 Coal Study" throughout these comments.
45 Attachment I to IPC Response to Sierra Club RequestNo. 18 at 3 (provided as ICL/SC Attachment 4) [hereinafter
"2013 Coal Unit Environmental Analysis"].
46 CPCN Application at 4-5, !f 9. The public portion of the AURORA analysis was included in an update to IPC's
201I IRP ('IRP Update")
" App.C to 2015 IPC IRP.
a8 June 3,2015 Quarterly Report.
ae Confidential Attachment I to IPC Response to Sierra Club Request No. 22 (provided as ICL/SC Attachment 5).
rPc-E-21-17
ICL/Sierra Club Joint Comments 15
REDACTED VERSION
l. 2013 Coal Unit Environmental Investment Analysis
As discussed above, SAIC and IPC prepared a two-part analysis on the economics of
installing SCRs at the Jim Bridger Plant. Each contained significant errors, particularly in
regards to gas, coal, and COz price assumptions, used in both part one and part two of the study
and discussed below.
a. 2013 SAIC Study
The SAIC Study analyzedthe SCR investments at Jim Bridger as part of a larger analysis
conducted for all four units at the Jim Bridger plant and the two units at the North Valmy plant.
In the study, SAIC evaluated the cost of three options: (l) installing environmental upgrades at
the Bridger units so they could continue operating on coal; (2) replacing the units with a CCCT
plant; and (3) converting the existing units to operate on gas.so
The most foundational issue with the SAIC study is that it's based upon a static forecast
of future generation, regardless of the scenario. This sort of assumption is useful for screening
analysis, but on its own, it is no basis for making multi-hundred-million-dollar power planning
decisions. Capacity expansion or, at the very least, production cost modeling, which takes into
account the cost of producing power in the context of other competing generators and changing
system demands, is far better suited for this type of decision making.
Further, the SAIC study failed to examine the full range of options available to IPC,
which also included closing Units 3 and 4 and either buying replacement energy in the capacity
market or building non-CCCT resource portfolios that included wind, solar, storage, and energy
efficiency. With such limited consideration of alternatives, there is no way to know whether
installing SCRs on Units 3 and 4 was the least-cost option.
50 ICL/SC Attach. 4,2013 Coal Unit Environmental Analysis at 3.
IPC-E-21-17
ICL/Siena Club Joint Comments r6
REDACTED VERSION
In the study, SAIC also assumed that Jim Bridger would operate through at least 2034,
consistent with IPC's current depreciation schedule, and conducted no evaluation of the cost and
economics of installing the SCRs assuming an earlier retirement date. This is concerning because
there was no evaluation of how an earlier retirement date for Units 3 and 4, such as IPC is
planning now, would impact the decision to install SCRs. An earlier retirement date would
decrease the number of years over which the SCRs would be depreciated and would reduce the
revenue that Company projected would cover the cost of the controls.
b. Natural Gas Forecast
The natural gas fuel cost forecasts that SAIC and Idaho Power used in the 2013 Coal Unit
Environmental Investment Analysis are unreasonably high and, surprisingly, different from one
another. As IPC itself acknowledged in the Coal Unit Environmental Analysis, the natural gas
forecast is one of the two most "influential inputs to the analysis" but also one of the least known
over the long-term, sl so this makes the inconsistency surprising and concerning (the other one
being a COz price, discussed below). The gas forecast is important in large part because the only
alternatives to the SCRs that IPC considered were gas resources. A high gas forecast will put the
gas-burning alternatives at a disadvantage and make them look relatively more expensive than
they should be, and, in this case, more costly than the coal option.
Even more concerning is that the gas price forecast that SAIC used is different from the
one that IPC used for part of the analysis conducted in Aurora. According to the 201 I IRP
Update, the IPC used the EIA Annual Energy Outlook's Henry Hub ("ElA AEO") spot price for
its "planning case" natural gas price forecast, adjusted to reflect an Idaho city gate delivery price.
Figure I below clearly shows in green that the nominal price in the IRP Update's planning case
st ICL/SC Attach. 4,2013 Coal Unit Environmental Analysis at 5
[PC-E-2I-17
ICllSierra Club Joint Comments 17
REDACTED VERSION
begins at less than $5.00 and rises to a level just below $14.00.s2 Yet as Figure I shows in blue,
the confidential SAIC Study shows
Further, as Figure I also shows, both SAIC's base-case forecast and Idaho Power's
forecast are substantially higher than the contemporaneous and previous years' EIA AEO
projections for natural gas prices in the mountain region, especially in the later years.sa It is not
clear why Idaho Power's forecast combining AEO's Henry Hub forecast with an ldaho city gate
adder and Sumas adjustment is so much higher than EIA's forecast for the Mountain Region,
where these adders come from, or how they were developed.ss But once again, this use of a high
forecast as the base case made the CCCT and gas conversion options look artificially expensive
compared to the SCR option. EIA's latest AEO forecast shows how much lower natural gas price
forecasts have fallen in the intervening years.
52ICLISC Attach. 4,2013 Coal Unit Environmental Analysis at 5.
s3 ICL/SC Attach. 3, Confidential SAIC Study at A-3.
54ICLISC Attach. 3, Confidential SAIC Study at Table A-23; EIA AEO 2012;EIAAEO 2013. The AEO products
archive is available at https://www.eia.eov/outlooks/aeo/archive.php.
55 Confidential Attachment 3 to IPC Response to Sierra Club Request No. 28 (provided as ICL/SC Attachment 6).
LPC-E-21-17
ICL/Sierra Club Joint Comments
53
18
REDACTED VERSION
Confidentiel Figure l. Neturel Ges Price Forecasts from 2013 SAIC Coal Unit
Environmentel vs EIA A.EO Forecests
Sotocc: lISF.lr,agt Adninistration @IA) Aruuol Enag Outld (IEO) Mounoin Rtgia Elaric &r.tor
Gas Fol lsrc 201 2, 2013, 2022.
As noted, gas prices had a substantial impact on the economics of the SCR project.
PacifiCorp's analysis of the economics of the SCR project puts this into sharper focus. For
insfaass, in March 2013, Paci{iCorp's analysis showed a benefit of the SCR project of
approximately $183 million.s6 However, just six months later, that value had dropped to $130
million based on September 2013 gas price forecasts.'7 Merely three months later, by Decernber
s In ,he Motterof PocifiCory, dbo Pacific Pawr, Requestfor a Generul Rate Raision. Docket No. UE 374.
Opeoing Testinrony of Jeremy Fisher. PhD on Behalf of Sierra Club at l2:13-15 (Ore.P.U.C. ftme 4. 2020).
a'ailable arhgrs://edocs.puc.state.or.us/efdocs/HTB/ue374htbl5l8.Idf [hereinafter *UE 374. Fisher Opering
Testimony"] (citing Redacted Rebuttal Testimony of Mr. Rick Link. Iz The Matter of lhe Application of Roch,
Mountain
Pawrfor Apprawl of a Cenficate of Public Corn'enience and Necessitt to Conshttct Selecth'e Catalvtic
Reduction,$slerrs on Jim bidga' Units 3 And 4 Locotecl Near Poinl of Rocks. Wyoming Docket
No.20O00-418-EA-12 at l:22. (Wyo. Pnb. Sen'. Cosur'n Mar. 2013).
51 ht lhe Matta'of PacifiCorp, dba Pacific Pover, Reqrcslfor a Generul Rnte Revision- Docket No. UE 374. Direct
Testinrony of Rick f. t int on Behalf of PacifiCorp (PACi700) at 107:13 (Ore.P.U.C. Feb. 2020). mailable at
https://edocs.Frc.state.or.us/efdocs/lJAA"/rrc374uaal45444.pdf (Mr. Link's testimolry bejrins on PDF p. a37).
IPC-E-21-17
ICUSierra Club Joint Commcnts l9
REDACTEDVERSION
z}l3,with continuing gas price forecast declines, the value dropped to just $36.7 million.s8In
other words, in just one year, nearly all the projected economic value of the SCR project to
ratepayers had vanished due to falling gas prices alone. This steep decline, which IPC would
have been aware of had it properly and consistently evaluated the economics of the project,
including communicating with its co-owner, should have caused the Company significant
concern. At a minimum, it should have caused further analysis well before 2015, when IPC
finally did reevaluate the economics of the project, because gas prices only continued to decline.
Even when IPC finally did reevaluate the economics in 2015, its analysis was fundamentally
flawed, as discussed further below in Section III(BX2).
c. Coal Price Forecast
In stark contrast, the SAIC Study's coal price forecast appears to move in the opposite
direction. The forecast used in the Study, which was later also used and extended in the IPC's
Aurora modeling, is significantly lower in most years than what the EIA's AEO projected at the
time for coal in the mountain region (as shown in Figure 3 below). Looking back now, the actual
cost paid for coal by Units 3 and 4 was even higher than both forecasts.
5E lJE374, Fisher Opening Testimony at52:12-18.
tPc-E-zl-17
ICL/Sierra Club Joint Comments 20
REDACTED VERSION
Confidential Figure 2: Coel Price Forecest Used by IPC in 2013 Studies
Foraast 2013; Corfidential Anachmant I to IPC Rc.spnsc to Sirl'ru Clfr Rqllrst No. 21 - Bridg* Cul Pria Formst
(provtuld as ICITSC Att*hnent 7); CotfidentUl Aruclmrail 2 to IK rrynse to Sfilz.ra Club R4uast No. 28 - JB Cal .Aurwa
Yatus (pwvidd as ICUSC Anachmant 8); ELl923 Pogc 5 - Frr,l Rrrzipr arrd Cosa 2015, 2016, 2017, 2016, 2019, 2020
202 l, 202 2, availaNe at https ://www.cia.gov/elatricity/hto/cia92 3/.
d. COr Price Sensitiviw
SAIC also relied sa simnlified carbon intensities for coal and gas in its study that
overstated the cost of gas and underestimated the cost of continuing to bum coal at Units 3 and 4
This was the second input that IPC identified as "inlluential" but "least known."5e Specifically,
in its calculations for future COz costs, SAIC assumd that coal generation.*i rI
and that natural gas emits ,By
multrplyrng these carbon intensities to a lower carbon price in the planning case and a higher
carbon price in the high case, SAIC developed resource-specific "carbon adders" to assess the
relative impact of the same carbon price on gas generation and coal generation.
s TCUSC Attach. 4. 2013 Coal Unit Enviroomental Aralysis at 5.e ICUSC Attach. 3. Corfidential SAIC Study at Table A-25: ICUSC Attach. 4. 2013 Coal Unit Enrironmeotal
Anatysis at 6.
IPC-E-21-17
ICUSierra Club Joint Cornrnents 2t
REDACTED VERSION
In reality, publicly available emissions measurements from the U.S. Environmental
hotection Agency ("EPA") Clean Air Markets Data ("CAMD") in the five years preceding the
SAIC study showed that SAIC's earbon intensities were inaccruate. Jim Bridger Units 3 and 4
emitted a little more than one ton of COz per MWh, and the carbon intensity for combined cycle
nahral gas resources in the U.S. in 2013 and 2014 was, on average,0.465 tons C&per MWL-
"bo*-rhan SAIC's assumed carbon intensity.
These may seem like small anormts, but they are significant ufoen considering that each
udt of Jim Bridger produces on the order of 3 million MWh per year and that SAIC's modeled
carbon prices rise over time.6t Multiplying more accurate carbon intensities by the same CG:
prices used by SAIC, and scali.g them over tire as SAIC does, yields higher COz costs for coal
and lower COz costs for gas in the planning and high-CQ scenarios.
On a net present value basis using the same discotmt rate as the SAIC study, SAIC
overestimated the total cost of a carbon price on nahral gas by orr"rI nominal dollars
in the planning case and approximat"trl nominal dollars in the high CO price case
from 2013 to 2032. The effect on coal is the opposite. SAIC's use of a simplified carbon
rntensity underestimates the cost of a carbon price on coal by o""l
I in the planning sceuario *d or"rl in the hip& co2 price scenario on a net
present value basis. While not as dramatic as the overestimate for gas, this is yet another example
of sirnplified or improper assumptions disadvantaging gas while giving advantage to coal
generation. The combined effect is large enoup& to have a serious irnpact on the perceived
6t EPA CAI\,ID &ta sbows that Units 3 and 4 together averaged 3.010.250 MWh of gross load per year from 2015 to
202t.
IPC-E-21-17
ICUSiera Club Joint Commeots 22
REDACTED VERSION
economics of investing in SCRs, which totaled $58.29 million and $51.65 million for Units 3 and
4, respectively.62
Conlidential Table 2. SAIC's Total Overestimation, in Net Present Value, of the Cost
Impact of a COz Price on Natural Gas Generation and Underestimation of the Impact on
Coal Generation
Source: EPA CAMD; ICUSC Attach. 4, 2013 Coal Unit Environmental Analysis; EPA Greenhouse Gas Reporting Program
lndustrial Profile: Power Plants Sector
Taking a wider view, the total cost of the SAIC study's carbon adders on both coal and
gas generation is so large that it begs a further question: how would the economics of the fossil-
burning alternatives have measured against those of a non-emitting replacement option? As
Table 3 shows, Applying SAIC's carbon adders to the actual coal-fired generation of Units 3 and
4 yields a total cost of between on a net present value basis in the
planning and high COz-price cases. For a replacement gas resource, the cost was between il
on a net-present value basis. If IPC thought at the time that the carbon
price scenarios examined by SAIC were realistic, reporting that continued fossil generation was
the most economic choice was a dubious conclusion at best. Limiting SAIC's analysis to fossil-
only options skewed the analysis in favor of the SCR option.
62 Adelman Direct at 13:14-17.
[PC-E-2|-17
ICL/Siena Club Joint Comments
Underestimation of Cost to
Coal (Million Nominal $)
COz Price Case Overestimation of Cost to
Gas (Million Nominal $)
Planning
High
23
REDACTEDVERSION
Conlidential Table 3. The total cost of the SAIC's carbon prices on Units 3 burning coal or
gas
Resource COr Price Case NPV of COz Cost
(Million Nominal $)
Coal
Planning
High
Gas
Planning
High
Source: EPA CAMD; ICUSC Attach. 4, 2013 Coal Unit Ewironmental Analysis; EPA Greenhouse Gas Reporting Program
Industrial Pro/ile: Power Plants Sector
2. The 2015 IRP Study
Between its 2013 analyses and2015,IPC did not evaluate the economics of installing
SCRs on Jim Bridger, despite this Commission's clear instruction to closely monitor the plant's
economics and be cognizant of any tipping points which would make further investment in the
plant uneconomic. When IPC finally did evaluate the economics of the SCR project in its Coal
Study, performed for the 2015 IRP and included in IRP Appendix C, the Company examined an
even more limited set of scenarios than the 2013 SAIC study. Specifically, it looked at (1) SCR
installation , and (2) replacement of Units 3 and 4 with a CCCT.63 This limited scope omitted the
costs and benefits of other potential alternatives including the conversion of Units 3 and 4 to run
on gas, and early retirement of either or both units and or procurement of other, non-gas
capacity-including renewable energy-to replace the capacity of Units 3 and 4. As a result, the
analysis was fundamentally flawed because it did not seriously consider alternatives to moving
forward with the SCR project.
The analysis should have also compared the economics of moving forward with the SCR
project to the economics of various early retirement dates for Units 3 and 4.ln fact, IRP
Appendix C includes the State of Oregon's Action ltems Regarding Idaho Power's 201I IRP,
u'App.C to 2015 IPC IRP atl22.
rPc-E-2r-17
ICllSierra Club Joint Comments 24
REDACTED VERSION
where the State of Oregon commented that they were concerned with the limited nature of IPC's
early retirement scenario analysis in 201l. Oregon expected IPC to model a broader range of
early shutdown scenarios for the 2015 IRP.64 ldaho Power's response pointed to the multiple
retirement scenarios they included in Chapter 8 of the 2015 IRP, but IPC only modeled early
retirement scenarios for Units I and2 in Chapter 8.65 For Units 3 and 4, IPC only considered
SCR installation versus immediate replacement of Units 3 and 4 with a CCCT. IPC did not
consider early retirement dates for Units 3 and 4.
It is possible that IPC did not conduct a thorough analysis because it was aware that the
2015 analysis was conducted too late in the proceeding to avoid substantial installation costs,
regardless of the findings. Specifically, as discussed above, it was conducted when the steel in
the ground for the SCRs at Unit 3 was essentially complete and was over half-way complete at
Unit3,ando,e.foftheprojectcostshadalreadybeenincurred.66
As a result, not only did IPC fail to evaluate a reasonable range of viable alternatives, but
the analysis also itself made multiple faulty and questionable assumptions. For instance, the Coal
Study neglected to examine any COz price sensitivities.
Most concerning, in this study, IPC included the remaining book value of the plant in the
retire and replace option. The book value consisted of costs incurred in the past to build the
plant, upgrade the plant, install environmental controls. These costs have been incurred, and
cannot be avoided, regardless of what happens going forward. The remaining book value
accounts for the majority of the cost difference IPC calculates between installing SCRs and
* App.C to 2015 IPC IP.P at2l2.
65 Idaho Power Company,20l 5 Integrated Resource Plan, Chapter 8 (June 2015), available at
https://puc.idaho.gov/Fileroom/PublicFileslElEC/IPC/tPCE l5 I 9/CaseFiles/2Ol50630lntesratedo/o20Resourseo/o20P
lano/o202015.pdf.
66 ICL/SC Attach. 5, Confidential Attachment I to IPC Response to Sierra Club Request No. 22.
tPc-E-2t-17
ICL/Sierra Club Joint Comments 25
REDACTED VERSION
continuing to operate Units 3 and 4 on coal and retiring Units 3 and 4 and building a new CCCT
gas plant.
The remaining book value should not be included in these calculations for several
reasons: (l) IPC is not guaranteed recovery ofthese costs; (2) the current balance is a sunk cost
and, absent action from the Commission, will be incurred regardless of when the plant retires or
continues to operate. The company should have considered in its analysis only costs that were
avoidable at the time of its analysis.
C. The Limited Analyses Conducted by ldaho Power Regarding the SCRs
Should Not Have Been Relied Upon to Make Such a Consequential Decision
as Investing Over $f00 Million of Ratepayer Dollars into Jim Bridger, and
the Commission Must Now Protect Customers from the Company's
Imprudence
As is evident, Idaho Power relied on two studies to support spending over $100 million of
ratepayer dollars on SCRs for Jim Bridger Units 3 and 4. Both studies were marred by significant
flaws designed to support the Company's foregone conclusion that it would install the SCRs
regardless of other viable alternatives. Despite this Commission's explicit instruction that Idaho
Power monitor the economics of the project and change course if doing so would be in the best
interest of ratepayers, Idaho Power did not seriously question the prudence of installing the
SCRs.
Idaho Power is limited to charging customers only for those investments that are 'Just
and reasonable."6T It is clear that faced with the decision to install SCRs at Jim Bridger today,
the Company would not make such an investment. This is evident from Idaho Power and
PacifiCorp's ongoing dispute with EPA regarding its federally mandated requirement to install
SCRS on Units I andZ. Regardless, this Commission must determine whether, at the time Idaho
67 IDAHo CoDE ANN. S 6l-301
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ICL/Siena Club Joint Comments 26
REDACTED VERSION
Power decided to spend hundreds of millions of dollars on SCRs for Units 3 and 4, the Company
acted as a prudent business owner, impartially evaluating costs and changing previous plans
when doing so made economic sense. The evidence demonstrates that Idaho Power did not.
Instead, Idaho Power did not seriously question PacifiCorp's plans to install SCRs on Units 3
and 4, relying on a fundamentally flawed analysis in 2013. Not until 2015 did the Company
again evaluate the SCRs, at which point it was all but too late to change course.
In order to protect Idaho customers from IPC's imprudence, this Commission should
issue a disallowance, which will signalto the Company that imprudent decision making will not
be rewarded. ICL and Sierra Club recommend that this Commission deny Idaho Power any rate
of return on its SCR investment, a remedy that other commissions have imposed on PacifiCorp
for its imprudence when investing in the same SCRs.
IV. Idaho Power Should Consider Securitizing Prudently Incurred Coal Debt on Jim
Bridger
After determining the total amount of prudently incurred costs and establishing a firm
exit date from Bridger, the next step is to adjust customer rates to reflect this new reality. ICL
and Sierra Club propose that Idaho Power use Idaho's Utility Cost Reduction Bond statute to
finance the prudently incurred debt for the Bridger plant.68 Known broadly as securitization, this
alternative to traditional utility financing can achieve Idaho Power's stated objectives-adjusting
rates to reflect a shortened economic life for Bridger-while reducing costs for customers.
At the simplest level, this proceeding is about the most appropriate ratemaking method to
finance, or refinance, utility infrastructure. As Idaho Power explained in 201 l, which was the last
time the Commission approved a general rate case settlement and rate of return, the goal of
68 ,See IDAso Cooe AlrN. $ 6l-1601, et seq.
[PC-E-Z1-17
ICL/Sierra Club Joint Comments 27
REDACTED VERSION
ratemaking is to ensure "good access to capital markets under reasonable terms in order to
finance needed investments in infrastructure."6e In traditional utility ratemaking, these terms
include the rates themselves, any mechanisms to address cost recovery uncertainty, and the level
of ongoing regulatory support for cost recovery. When considering ongoing, full-scale utility
infrastructure needs, there is inherent uncertainty about whether rates will provide for complete
cost recovery by the utility. Thus, it can be appropriate to allow for a higher return on utility
investment to ensure access to capital under reasonable terms. But there are other circumstances
when the Commission can provide a far higher level of certainty that costs will be recovered in
rates. In these circumstances, a lower return is sufficient to ensure access to capital markets.
Idaho Power's request to exit the Bridger unit early is exactly one of those circumstances: a
discrete capital need, driven by unique factors, that is outside the typical utility infrastructure
needs. Fortunately, Idaho's Utility Cost Reduction Bond law codified at Title 61, Chapter 16,
provides for a specific method to address this unique circumstance and allows the Commission to
develop an order with reasonable terms that will ensure access to capital markets at lower costs
than typical utility investments.
A. Securitization Is an Appropriate Ratemaking Tool to Address the Changing
Economic Life of Bridger
Recovery of coal-related Bridger costs is a good fit for using securitization to refinance
Idaho Power's interest in the plant.In2014, RBC Capital Markets reviewed utility securitization
history and trends, describing how utilities have used securitization to address unique situations
like stranded assets from deregulatory actions, storm recovery costs, and large pollution control
6e See In the Matter of the Application of ldaho Power Company for Authority to Increase its Rates and Charges for
Electric Seryice to its Customers in the State of ldaho. Case No. IPC-E- I l -08, Direct Testimony of Darrel Anderson
on Behalf of Idaho Power Company at 10:7-9 (June l, 20ll), ovailable at
https://euc.idaho.eov/Fileroom/PublicFiles/ELEC/IPC/IPCEI 108/Companli/2O1 l060lAnderson%20Di.pdf.
lPc-E-2r-17
ICL/Sierra Club Joint Comments 28
REDACTED VERSION
costs.70 After weighing the benefit of reduced customer costs versus the barriers of needing to
carefully structure the transaction, the analysts concluded that securitization was best used "to
finance projects associated with discrete, clearly identifiable public purposes" and that
securitization is "more politically palatable if the projects financed are outside of the usual and
customary capital improvement program of the utility."Tl
Bridger is a good fit under these criteria. First, exiting Bridger in order to save customers
money and reduce future risks is a discrete and laudable public purpose.T2 Second, Idaho
Power's proposal to accelerate Bridger depreciation is not part of a utility's customer capital
improvement program. Since the Commission is already being asked to adopt a non-traditional
ratemaking approach (accelerated depreciation), there is no reason not to explore another
nontraditional ratemaking approach, particularly when such alternatives have the potential to
maximize customer benefits.
The one missing piece to ensure securitization is the optimal ratemaking method to
address Jim Bridger costs is to establish a firm exit timeline and total amount to be recovered.
As discussed above, while Idaho Power seeks to adjust rates in this docket to address the shorter
economic life at Bridger, the utility has not committed to an exit date for any unit. Nor does it
have any agreement with PacifiCorp regarding cost allocation if the actual exit dates differ from
the proposed exit dates. ICL and Sierra Club emphasize that cost recovery-whether under
accelerated depreciation or securitization-should be contingent upon a firm and verifiable exit
plan. Such a firm commitment should be viewed as a non-negotiable prerequisite included in any
70 Chris Mauro, Municipal Securitization - A New Financing Trend in the Municipal Marlret?, RBC Capital Markets
(Nov. 6, 2014), wailable al https://www.rbccm.com/municipalfinance/file-826934.pdf.
7t Id. at 5.
72 See Direct Testimony of Matthew T. Larkin on Behalf of Idaho Power Company at6:3-7:3 (June2,202l)
[hereinafter "Larkin Direct"].
tPc-E-2l-17
ICL/Sierra Club Joint Comments 29
REDACTED VERSION
Commission order authorizing a cost recovery framework for prior and future investments in the
plant.
Nevertheless, just as Idaho Power did at the Valmy plant, the Company can seek a cost
recovery framework from the Commission, then commit to exit dates and negotiate an exit
agreement with PacifiCorp. Once done, this will provide more certainty for future capital needs
at the plant, and this information can feed into Idaho's Utility Cost Reduction Bond process
described below.
B. Idaho's Existing Securitization Legislation Provides an Optimal Ratemaking
Treatment to Recover Jim Bridger Costs.
In 2005, the legislature passed Idaho's Utility Cost Reduction Bonds declaring "this type
of securities legislation is in the public interest" because it provides "a method of . . . refinancing
costs incurred or to be incurred by electric . . .utilities that will accrue benefits to Idaho
consumers through reduced utility rates."73 Despite the potentially significant public benefits, it
does not appear that any Idaho utility has elected to use this authority to access lower cost
financing for infrastructure needs. Idaho Power's need to refinance the Bridger plant costs due to
changing economics of the plant is an excellent opportunity to put this existing authority into
use.
The process revolves around a Cost Reduction Order from the Commission "authorizing
the recovery of approved costs through the imposition and collection of a cost reduction rate."14
This Order sets forth the approved costs the utility will recover, the timeline for recovery, and the
method for determining the cost reduction rate paid by customers.Ts With the Order in hand, the
utility then goes to the capital markets to seek financing from lenders by issuing a cost reduction
73 IDAHo CoDE Al.rN. $ 6l-1601
'o rd.S 61-1603(l).,'rd.S 6l-1603(3).
lPc-E-2t-17
ICL/Sierra Club Joint Comments 30
REDACTED VERSION
instrument.76 Lenders then provide financing to the utility in exchange for a property interest in
the cost reduction order and the resulting right to receive the revenue from the cost reduction rate
applied to customer bills.77 Then, during the term of the Cost Reduction Order, the Commission
will, at least annually, "approve adjustments to the cost reduction rates" paid by customers "to
ensure timely and complete recovery of all approved costs that are the subject of the pertinent
cost reduction order."78 This structure ensures that the Commission has the authority to
determine the "public interest would be served if the approved costs were recovered through a
cost reduction rate"Te and retains ongoing supervision to ensure customers pay no more and no
less than the amounts necessary to recoup approved costs.8o
This structure achieves ldaho Power's stated goals in this docket: addressing the reduced
economic lifespan of the Jim Bridger plant, ensuring a stable stream of payments from
customers, and providing a mechanism to ensure customers pay no more or no less than needed
to recover prudently incurred Jim Bridger expenses.8l The primary difference between ldaho
Power's accelerated depreciation approach and securitization is the initial transaction costs
necessary to refinance Jim Bridger costs through bonds. Even with expected transaction costs,
securitization will be significantly more beneficial to customers than Idaho Power's proposed
accelerated depreciation due to the lower interest rate customers will pay during the recovery
period. In fact, analysis conducted by RMI, discussed below, suggests that securitization would
save ratepayers approximately $63.7 million compared to accelerated depreciation.
?6.td $ 6l-1603(6).
77 Id. S 6t-1606.,, rd.S 6t-1603(8).
7e IDaHo CoDE ANN. $ 61-1603(2).
80 1d $ 6l-1605(5) (empowering the commission to determine how to "use any surplus cost reduction rate
collections in excess ofthe amounts necessary to pay approved costs").
8r See Larkin Direct at 30:7-22.
[PC-E-21-17
ICllSierra Club Joint Comments 31
REDACTED VERSION
C. RMI Modeled the Benefits of Recovering ldaho Power's Bridger Costs
Through Securitization and Found that Securitization Would Save
Ratepayers $63.7 Million
ICL and Sierra Club worked with world-leading, independent analysts at RMI to assess
the different costs for customers between Idaho Power's accelerated depreciation proposal and a
securitization alternative. RMI has assessed securitization opportunities for over l4 different
operating utilities in both legislative and regulatory contexts.s2 When RMI applied their analysis
to Idaho Power's share of the Bridger plant they found that using Idaho's Utility Cost Reduction
Bond statute could save customers over $63.7 million in reduced borrowing costs, compared to
accelerated depreciation, as shown in ICL/SC Attachment 9.
This analysis makes a few necessary assumptions which are based on data provided by
Idaho Power. First, the net plant balance to be recovered is $241.6 million based on Mr. Larkin's
Supplemental Direct Testimony and Exhibit I as well as Mr. Adelman's Exhibit 3. This total
does not include the $105 million in expected decommissioning costs described on pages 23
through 25 of Mr. Larkin's Direct Testimony.
Second, RMI assumed the cost recovery period for accelerated depreciation to be 8 years,
from2023 through 2031. For the securitization analysis, RMI assumed a slightly longer time
period of 12 years,2023-2035, which aligns with the cunent depreciable life for Bridger. While
Idaho Power's proposal would begin cost recovery in June of 2022, we assume it will take some
extra time for Idaho Power to seek approval of the securitization approach from the Commission
E2 A good example of RMI's expertise is available in a report developed in partnership with Minnesota Power
exploring the potential to securitize the unrecovered balance for the early retiring Boswell coal plant. See Rocky
Mountain Institute, Using Ratepayer-Bqcl@d Bond Secaritizationfor Cost Recovery in Accelerated Asset Retirement
(Sept. 2020), filed in Minnesota PUC Docket EOI5/RP-15-690, qvailqble at
https://efiline.web.commerce.state.mn.us/edockets/searchDocuments.do?method=showPouo&documenfld=%o7BD0
ECE574-0000-C632-A755-ED5Cl85F08F5%7D&documentTitle=202010-167012-02. ICL and Sierra Club
encourage the Commission to review this report which describes the history and current use of rate-payer backed
securitization to refinance utility assets at lower costs for customers.
rPC-E-zt-17
ICLlSiena Club Joint Comments 32
REDACTED VERSION
and then complete the transaction with future bondholders. Both Idaho Power's proposal and the
securitization approach would extend cost recovery beyond the dates the Company intends to
exit the plant. We believe it is reasonable to allow for a l2-year period for securitization because
this aligns with current lifespan in rates and is more likely to attract bondholder interest than a
shorter term period. A longer cost recovery period also reduces annual costs for customers.
Third, RMI's analysis assumes the interest rate on the bonds is3.54% compared to ldaho
Power's weighted average cost of capital of 7.860/o. This bond interest rate assumption is based
on the US Treasury yield curve on April 11,2022, with an added risk premium to reflect AAA-
rated debt, and looks forward over the recovery period. These assumptions are reasonable
because Idaho Utility Cost Reduction Bond statute provides a level of certainty that should lead
to highly rated bonds and the recovery period matches the current depreciable life of Bridger.
Saber Partners, LLC maintains a list of 73 investor-owned utility securitization transactions from
1997 through present. That database shows that every transaction received a bond rating of
fuL{.83 As explained by former Ohio Public Utilities Commissioner Cheryl Roberto,
Ratepayer-backed bonds are extraordinarily low risk to investors because repayment of and
a return on their investment is secured by a legally enforceable surcharge on customer bills
which cannot be changed by the Commission, avoided by its customers, or diverted by the
utility. Traditional utility debt invesfinent does not enjoy this level of security because it is
always dependent upon the utility's ability to pay.8a
Given the extremely low-risk nature of securitization bonds, [CL and Sierra Club believe
the assumed interest rate is conservative and it is possible that Idaho Power could secure interest
rates below 3.54%. For instance, on March 11,2022, Empire District Electric Company in
83 Saber Partners, LLC, List of Investor-Owned Utility Securitization ROC/RRB Bond Transactions available at
https://saberpartners.com/list-of-investor-owned-utility-securitization-rocrrb-bond-transactions- I 997-presenU.u In The Matter of the Application of Arizona Public Service Companyfor a Hearing to Determine the Fair Value
of the Utility Property of the Company for Ratemaking Purposes, to Fix q Just And Reasonable Rate of Return
Thereon, to Approve Rate Schedules Designed to Develop Such Return, Docket No. E-01345A-19-0236, Direct
Testimony of Cheryl Roberto on Behalf of Sierra Club at 50: l8-5 I :3 (Ariz. Corp. Comm'n Oct. 2, 2020), available
at https://docket.images.azcc.gov/E000009335.pdfl i=165 1085493976.
tPc-E-2t-17
ICL/Sierra Club Joint Comments JJ
REDACTED VERSION
Missouri submitted testimony from Goldman Sachs that assessed a securitization offering for an
early retiring coal asset and provided an indicative bond structure of 2.47%o interest and a 13
year recovery period.8s Idaho's Utility Cost Reduction Bond statute has key elements present in
Missouri and other states with successful securitization options namely, a predictable and non-
avoidable rate paid by customers to the bond holders, Commission oversight of the annual rate
collections, protection from utility bankruptcy, and a pledge of non interference by future
legislative or regulatory decisions. If Idaho Power could secure similar interest rates as proposed
in Minnesota, IPC's customers may realize even greater savings than the already estimated $63.7
million. With this level of savings potential, the Commission should direct Idaho Power to work
with potential lenders to assess the interest rates and other lending terms available to reduce
customer costs.
Fourth, RMI's analysis includes assumptions about the transaction costs, tax
implications, and other impacts to the utility balance sheets as documented in tCLlSC
Attachment 9. One of the major questions is whether the transaction costs of the securitization
approach would exceed the savings from accessing lower cost capital. Based on RMI's expertise
in securitization transactions, they assume $4.7 million in initial costs and annual costs of about
$421,000 for the Jim Bridger securitization. Critically, the estimated $63.7 million in savings
already accounts for these transaction costs.
ICL and Sierra Club offer this analysis as an estimate of the benefits to customers from
securitization, recognizing that further investigation and refinement would be needed prior to
85 See lre the Matter of the Petition of The Empire District Electric Company d/b/a Liberty to Obtain a Financing
Order that Authorizes the Issuance of Securitized Utility Tariff Bonds for Energt Transition Costs Related to the
Asbury Plant, Case No. EO-2022-0193, Direct Testimony of Katrina Niehaus on Behalf of The Empire District
Electric Company dlblaLiberry Utilities (MO.P.S.C. Mar.2022), available at
https://efis.psc.mo.gov/mpsc/commoncomponents/view itemno details.asp?caseno:EO-2022-
0 193 &attach id=20220 I 647 l .
IPC-E-Zt-17
ICL/Siena Club Joint Comments 34
REDACTED VERSION
implementing securitization. While RMI used inputs from ldaho Power's filing in this case and
reasonable assumptions based on their expertise in this area, the specific savings for customers
will depend on the results of the Cost Reduction Order issued by the Commission upon Idaho
Power's request. Even if the exact numbers change through that process, the level of potential
savings from securitization is significant and the Commission should encourage Idaho Power to
use existing Idaho law to reduce costs for customers while facilitating the Company's exit from
Bridger coal.
D. Idaho Power Should Explain Why it Is Not Considering Securitization that
Could Save Ratepayers Tens of Millions of Dollars.
As explained above, using Idaho's Utility Cost Reduction Bonds laws to recover Bridger
coal-related expenses achieves Idaho Power's goals while reducing costs for customers.
However, Idaho's law makes clear that this approach is entirely voluntary for the utility. Only
the utility may apply to the Commission for a cost reduction order and when issued, only the
utility can choose to move forward or withdraw the request.s6 Even if the utility chooses not to
follow through with the Cost Reduction Order, the Commission cannot deem that action as
unreasonable or imprudent.87 Nevertheless, the Commission does have the authority to approve
or deny Idaho Power's request to accelerate depreciation and adjust customer rates accordingly.
The Commission also has the authority to require ldaho Power to explain why they elected to use
one non-traditional ratemaking approach-accelerated depreciation-instead of another
approach-securitization-that achieves the exact same goals at lower costs for customers. ICL
and Sierra Club recommend the Commission exercise their authority to deny ldaho Power's
86 IDaHo Cops Ar.rN. $ 6l-1603(4).,, Id.s 6l-1603(5).
[PC-E-ZI-17
ICllSierra Club Joint Comments 35
REDACTEDVERSION
request and encourage the utility to protect customer's interest while allowing for access to
capital markets on reasonable terms by utilizing Idaho's Utility Cost Reduction Bond authorities.
v.Conclusion
In conclusion, ICL and Sierra Club make the following recommendations:
l. Idaho Power should not be granted a new form of rate recovery-€ither accelerated
depreciation or securitization-prior to a firm commifrnent to exit the Jim Bridger
plant, including finalized, necessary contractual agreements with PacifiCorp;
2. This Commission should find that Idaho Power's investment in SCRs at Jim Bridger
Units 3 and 4 were imprudent. As a remedy, this Commission should deny [daho
Power any rate of return on its investment;
3. This Commission should direct Idaho Power to explain why it is not pursuing
securitization of past, prudently incurred expenditures at Jim Bridger, which would
achieve ldaho Power's same stated goals as with accelerated depreciation at lower
customer costs.
Dated: Apil2l,2022
Respectfu lly submitted,
f*ftMrl^,\^
Rose Monahan (CA BarNo. 329861)
Sierra Club
E^a
Benjamin Otto (lD BarNo. 8292)
Idaho Conservation League
lPc-E-2l-17
ICL/Sierra Club Joint Comments 36
Attachment 1
Mine Profile: Black Butte & Leucite Hills Mines (S&P Global Market Intelligence)
S&P Capitat nr
Black Butte & Leucite Hills Mines I Mine Profile
ICL/SC Attachment I
Page I of2
OWNER
Anadarko Petroleum Corp.
Lighthouse Resources Inc
Black Butte Coal Company
Mine State
Mine County
Latitude (degrees)
Longitude (degrees)
Coal Type
SNL Mine Operating
Status
Mine Type
Mine Operation Type
Mine District
Mine Producing Region
MSHA ID
ULTIi'ATE PAREilT
Occidental Petroleum Corp.
Lighthouse Resources lnc
oWNERSHTP (%)
50.00
50.00
FEMA Region
MSHA lnspection
Office
Number of Power
Plants Served (actual)
Total Operating
Capacity of Plants
(MW)
Total Spot Purchases
(1000 tons)
Total Contract
Purchases (1000 tons)
Total Coal Purchased
(1000 tons)
Coal Delivered Heat
Content (Btu/lb)
Average % Sulfur
Average % Ash
Average Delivered
Spot Price ($/ton)
Average Delivered
Contract Price ($/ton)
Average Delivered
Price ($/ton)
Average Estimated
FOB Coal Price ($/ton)
2019
2
2020 2021
2,645.0 2,il',t.o 2,119.0
NA NA NA
2,258.77 2,22'.1.88 1,713.90
2,258.77 2,22',t.88 1,713.90
9,496 9,564 9,505
vilt
Craig
WY
Sweetwater
41.57123',1
-108.693305
Subbituminous
Active
Surface
Strip
Administrative
Denver
Southem Wyoming
4801180
12
0.45
9.',t4
NA
0.45
9.31
NA
o.4
9.64
NAEXCLUSIVE Energy aector faces a barrage of
cyberattacks; MLP stocks gain on tax rullng 7l2Ol2O18
Wyo. Ql'i7 coal production up 23o/o ovat previous year
412412017
EXTRA BLM issues lnvitation for Black Butte coal
exploration in Wyoming 11912015
EXCLUSIVE Vote set for private equity firm to take over
Ambre Energy's US operations 1112812014
EXTRA Coal miner shortage prompts future productlon
cuts at Wyo. operation 1111712014
48.42 45.91 46.'t5
48.42 45.91 46.15
36.59 36.04 40.86
Operator Regulatory / Other
Site lnformation
Fuel Delivery Summary
Recent News
Summary Production Data
Licensed to [e-mail] Powered by S&P Global I Page 1 of2
S&PCapltat lQE
Black Butte & Leucite Hills Mines I Mine Profile
ICL/SC Attachment I
Page2of 2
20r0
2,307,947
2020
2,216,235
2021
1,771,4',11Clean Coal Produced
(tons)
Avg Number of
Employees (actual)
Clean Coal Produced
per Employee (tons)
Glean Coal Produced
per Employee Hour
(ton/hr)
Number of lnjuries
(ac'tual)
162 147 134
14,246.59 15,076.43 13,219.49
7.72 7.85 7.24
1 3 2
Seam Height (inches)60 60 60
Fuel deliveries are based on EIA-923 filings beginning in 2008 and FERC/EIA 423 filings tor 20O7 and earlier. The current year and,
in some cases, the most recent full year deliveries only constitute the sample filers, which is not representative of all power plants
that are required to file the annual 923. Once the annual 923 is received, the historical year will be populated with data for all power
plants that are required to submit data with the ElA.
Licensed to [e-mail] Porirrered by S&P Global lPage 2 of 2
Attachment 2
Confidential Affachments 1, 2, and 3 to IPC Response to Indusfrial
Customer of Idaho Power Request No. 43
ICL/SC Attachment 2 contains confidential information subject to the protective agreement in
Case No. IPC-E-21-17 and has been served upon the Commission and eligible parties.
Attachment 3
Confidential Attachment? to IPC Response to Sierra Club Request No.
18 (*Confidential SAIC Study")
ICL/SC Attachment 3 contains confidential information subject to the protective agreement in
Case No. IPC-E-21-17 and has been served upon the Commission and eligible parties.
Attachment 4
Attachment I to IPC Response to Sierra Club RequestNo. l8 (*2013
Coal Unit Envirorunental Analysis")
ICLISC Attachment4
Page I of30
aOLL IRP UPDATE
Coal Unit Environmental lnvestment Analysis
For The
Jim Bridger and North Valmy
Coal-Fired Power Plants
Coal Unit Environmental Analysis Page 1
ICL/SC Attachment 4
Page 2 of30
TABTE OF CONTENTS
Executive Summary....3
5
5
5
5
6
7
7
7
8
11
11
13
13
t4
t4
15
L7
L7
19
19
22
23
25
26
28
30
Financial and Economic Assu mptions..................
Description and Existing Major Environmental lnvestments in Coal Un}ts............
Recent Environmental Regulations......
Compliance Timing Alternatives.
Conclusions and Recommendations....
North Valmy Unit #1...
North Valmy Unit #2...
North Valmy Units #1 and #2..........
Jim Bridger Unit f1......
Jim Bridger Unit f2......
Review Process and Action P!an.......
Coal Unit Environmental Analysis Page2
ICLISC Attachment 4
Page 3 of30
Executive Summarv
The Coal Unit Environmental lnvestment Analysis (Study) examines future investments required for
environmental compliance in existing coal units and compares those investments to the costs of two
alternatives: (1) replace such units with Combined Cycle Combustion Turbine (CCC[) units or (2) converting
the existing coal units to natural gas. ldaho Power used a combination of third-party analysis, operating
partner input and an ldaho Power analysis to assure a complete and fair assessment of the alternatives.
This Study consists of two parts:
1. A unit specific forecasted (static) annual generation analysis performed by Science Applications
lnternational Corporation (SAIC). ldaho Power conducted a competitive procurement process to
select SAIC.
2. An economically dispatched (dynamic) total portfolio resource cost analysis performed by ldaho
Power using the SAIC study results.
The SAIC analysis included a review of ldaho Power's estimated capital costs and variable costs associated
with the proposed environmental compliance upgrades, coal unit replacement with CCCT's and naturalgas
conversion. SAIC developed the cost estimates for replacing the coal units annualgeneration, under three
naturalgas and three carbon futures. These estimates served as the foundation for SAIC's capital investment
analysis which allowed assets with different lengths of operation as well as different implementation dates to
be compared equitably. The results of the SAIC analysis served as planning recommendations regarding the
three investment alternatives to be used in the second part of the comprehensive Study.
The second part of the Study performed by ldaho Power utilized the AURORAxmp'Model (AURORA) to
determine the total portfolio cost of each investment alternative analyzed by SAIC. The total portfolio cost is
estimated over a twenty-year planning horizon (2013 through 2032).
The Key Assumptions section of this report provides additional details on the carbon adder assumptions and
natural gas price forecasts.
Analvsis Results for North Valmv
Currently, the only notable investment required at the North Valmy plant is to install a Dry Sorbent lnjection
(DSl) system for compliance with the Mercury and Air Toxic Standards (MATS) regulation on Unit #1. North
Valmy is not subject to Regional Haze (RH) Best Available Retrofit Technology (BART) regulations; therefore,
no additional controls will be required for compliance with this regulation. No other notable investments in
environmental controls at the North Valmy plant are required at this time.
lnstallation of DSI was the lowest cost result for most of the sensitivities analyzed by SAIC including the
planning case scenario (planning case naturalgas/planning case carbon). The AURORA analysis, performed
by ldaho Power, shows installing DSI as the least cost option in four of the nine sensitivities analyzed
including the planning case scenario (planning case natural gas/planning case carbon). The scenarios in which
Coal Unit Environmental Analysis Page 3
ICL/SC Attachment 4
Page 4 of30
DSt was not the preferred option are the elftreme low natural gas and high carbon cases, which have a lower
probability of occurring.
ldaho Powe/s conclusion is that installing the DSt system is a low cost approach to retain a diversified
portfolio of generation assets including the 125 MW's of Unit #1's capacity for our customers benefit. The
continued operation of Unit #1 as a coal-fired unit will provide fuel diversity that can mitigate risk associated
with high naturalgas prices.
ln the event that North Valmy requires significant additional capital or operation and maintenance costs
(O&M) expenditures for new environmental regulations, both the SAIC and the ldaho Power analyses advise
further review to justify the additional investment.
Analvsis Resuhs for Jim Brideer
Jim Bridger is currently required to installSelective Catalytic Reduction (SCR) on allfour units for RH
compliance and mercury controls for compliance with MATS. Both the SAIC and ldaho Power evaluations
identifo additional investments in environmental controls on all four Jim Bridger units as prudent decisions
that represent the lowest cost and least risk option when compared to the other investment alternatives.
ldaho Power recommends proceeding with the installation of SCR and other required controls on Units #3
and #4 and including the continued operation of all four Jim Bridger units in ldaho Power/s future resource
planning.
Comoliance Timins Alternatives
ldaho Power also evaluated the economic benefits of delaying coal unit investments required under the
emerging environmental regulations. To perform this evaluation ldaho Power assumed that it could
negotiate with state and federal entities a five-year period where no additional environmental controls are
installed in exchange for shutting the unit down at the end of the five-year period. These compliance timing
ahernative cases are strictly hypothetical. ldaho Power may not have any basis under current regulations to
negotiate this delay and the relevant regulatory authorities have not offered any such delay. These
ahernatives are included in the alternatives summary table.
Unit Ownerchip and Ooeration
It should be noted that, although a partial owner of the Jim Bridger (one-third) and the North Valmy (one-
half) coal plants, ldaho Power does not operate any of the coal-fired units and ldaho Power does not have
the sole rights to alter the compliance plan in place for these units. Any decision regarding environmental
investments, plant retirement or conversion to naturalgas must be coordinated and agreed to by the other
owners/operators of the plants and their regulators.
Coal Unit Environmental Analysis Page 4
ICUSC Attachment 4
Page 5 of30
Kev Assumptions
The undertaking of any analysis of this nature requires that assumptions be made regarding uncertain costs
and regulations that may impact the economics of the coal plants. ln fact, two of the most influential inputs
to the analysis are also among the least known over the long-run and are related to future carbon regulation
and future natural gas prices, ln order to evaluate these uncertainties ldaho Power has used low, planning
and high case natural gas and carbon adder futures. These forecasts provide a range of outcomes to assess
the impact of natural gas price and carbon adder uncertainty on the economic evaluation of the investment
alternatives.
ldaho Power is currently preparing its 2013 IRP covering the 2013-2032 planning horizon. As that process is
well underway, key assumptions for this Study are aligned with the 2013 IRP assumptions.
These key assumptions include:
Natural Gas Prlce Forecast - For the purpose of being consistent with ldaho Case No, GNR-E-11-03, Order No.
32697 (December t8,20t2l,ldaho Power is using the Energy lnformation Administration (ElA)Annual Energy
Outlook (Henry Hub spot price) for the 2013 IRP planning case natural gas price forecast. The high and low
cases are +/- 300,6 from the planning case forecast, All cases were adjusted to reflect an ldaho citygate
delivery price. These forecasts are provided in Figure 1.
Figure 1. NaturalGas Price Forecast
Natural Gas Price Forecast
=l!E
Eoc
5
!o
==oa
!o6
s18.00
S16.oo
Sra.oo
s12.00
s10.00
Sa.oo
S6.oo
54.oo
Sz.oo
So.oo
%%%%%%%%%% % "+ % "+ "., % % "%'E %
-HiBh
Gas
-Planning
Gas
-l6s
$35
Coal Unit Environnrental Analysis Page 5
ICUSC Attachment 4
Page 6 of30
Load Forecast - The 2013 IRP load forecast is ldaho Powe/s most current load forecast and was used in the
preparation of this Study.
Flnanclal and Economlc Assumptlons - The 2013 IRP financial and economic assumptions were also used for
this Study.
Carbon Adder Assumptlons - For the 2013 lRP, three carbon adder assumptions have been developed and
include a low case of no carbon tax, a planning case with a 2018 start date at 514.64 per ton of CO2 emitted
escalated at 3% and a high case with a 2018 start date at 535.00 per ton of COa emitted escalated at9%.
These forecasts are provided in Figure 2.
Figure 2. Carbon Adder Assumptions
Carbon Adder Assumptions
Srzo
Srro
3. Srool!.= Seo
Ets*j szo
: soo
-oI ssoo* srog srooo szo
S10
SO
% r%% % %%% %t+ "r+
.r+ .r+ .r+ % % .r+ % %.E .E
-fie
Carbon
-pl3nning
Carbon
-High
Carbon
Coal Unit Environmental Analysis Page 6
ICL/SC Attachment 4
Page 7 of30
Descriotion and Existing Maior Environmenta! lnvestments in Coal Units
Jim Brldger
The Jim Bridger coal-fired power plant consists of four units and is located near Rock Springs, Wyoming.
ldaho Power owns one-third of Jim Bridger with the other two-thirds owned by PacifiCorp. PacifiCorp is the
operator of the Jim Bridger plant.
These units have the following current net dependable capacity ratings
Jim Bridger unit #1 (JB1) 531 MW
Jim Bridger unit f2 (JB2) 527 MW
Jim Bridger unit #3 (JB3) 530 MW
Jim Bridger unit #4 {JB4) 523 MW
Total Plant - 2,111 MW 1703.7 MW ldaho Power Share)
The following major emission control equipment has been previously installed on each unit at the Jim Bridger
plant:
Pollutants Controls Current Emission Limits
NO, New Generation Low NO, Burners 0.25 lb/MMBtuOpacity Electrostatic Precipitators 20% OpacitySOz Wet Scrubbers 0.15 lb/MMBtu
North Valmv
The North Valmy coal-fired power plant consists of two units and is located near Winnemucca, Nevada.
ldaho Power owns one-half of North Valmy with the other one-half owned by NV Energy. NV Energy is the
operator of the North Valmy plant.
These units have the following current net dependable capacity ratings:
North Valmy unit #1 (NV1) 252 MW
North Valmv unit #2 (NV2l 272 MW
Total PIant - 524 MW (252 MW ldaho Power Share)
The following major emission contro! equipment has been previously installed at the North Valmy plant:
Pollutants Controls Current Emission LimitsNO, Early Generation Low NO, Burners 0.45 lb/MMBtu (averaged)
Opacity Baghouse 20% Opacity
SOz (Unit 2) Dry Lime Scrubber 70% removal
Coal Unit Enyironmental Analysis PageT
Recent Environmental Resulations
The new regulations that have been proposed by the Environmental Protection Agency (EPA) over the last
few years have caused treat concern among utilities that own coal-fired generation. The impact of the
proposed regulations will require extensive installation of emissions controls in a short period of time. ln
addition, these proposed regulations often override state decisions relating to control requirements. The
effectiveness of the regulations on health and visibility is controversial and highly debated.
Final Mercury ond Air Toxlc Stondords (MAIS) Rulez ln April 2010, the U.S. District Court for the District of
Columbia approved, by consent decree, a timetable that would require the EPA to finalize a standard to
control mercury emissions from coal-fired power plants by November ZOLI. ln March 2011, the EPA released
the rule to control emissions of mercury and other Hazardous Air Pollutants (HAPs) from coal- and oil-fired
Electric utility steam Generating Units (EGUsl under the federal Clean Air Act (C,AA). tn the same notice, the
EPA further proposed to revise the New Source Performance Standards (NSPS) for fossil fuel-fired EGUs.
Both the proposed HAPs regulation and the associated NSPS revisions were finalized on February 16,20L2.
The regulation imposes maximum achievable controltechnology and NSPS on all coal-fired EGUs and replaces
the former Clean Air Mercury Rule. Specifically, the regulation sets numeric emission limitations on coa!-fired
EGUs for tota! particulate matter (a surrogate for non-mercury HAPs), hydrochloric acid (HCL), and mercury.
ln addition, the regulation imposes a work practice standard for organic HAPs, including dioxins and furans.
For the revised NSPS, for EGUs commencing construction of a new source after publication of the final rule,
the EPA has established amended emission limitations for particulate matter, sulfur dioxide, and nitrogen
oxides. Utilities have three years for compliance, with a one year compliance extension for any utility or
plant that cannot feasibly installthe pollution controls during the three year compliance window. ldaho
Power does not need nor can ldaho Power qualify for the one year extension, so all controls were assumed to
be completed within the three year time frame.
Nationol Amblent Air Quoltty Standards (NAAQS): The CAA requires the EPA to set ambient air quality
standards for six "criteria" pollutants considered harmful to public health and the environment. The six
pollutants are carbon monoxide, lead, ozone, particulate matter, nitrogen dioxide, and sulfur dioxide. States
are then required to develop emission reduction strategies through State lmplementation Plans (SlP) based
on attainment of these ambient air quality standards. Recent developments related to three of the
pollutants - PMz.s, NOo and SO2 are relevant to ldaho Power.
Particulor Motter lPMu;L ln 1997, the EPA adopted NAAQS for fine particulate matter of less than
2.5 micrometers in diameter (PMr.s standard), setting an annual limit of 15 micrograms per cubic
meter (Fg/m'), calcutated as a three-year average. ln 2005, the EPA adopted a 24-hour NAAQS for
PM2.5. of 35 pg;/m3. All of the counties in Nevada, Oregon, and Wyoming have been designated as
"attainment" with these PM2 5 standards. However, on December 14, 2012, the EPA released final
revisions to the PM2.s NAAQS. The revised annual standard is L2 Wlmt, calculated as a three-year
average. The EPA retained the existing Z$-hour standard of 35 Ug/m3. Now that the PM2.5 NAAQS
has been finalized, states will make recommendations to the EPA regarding designations of
attainment or non-attainment. States also will be required to review, modify, and supplement their
SlPs, which could require the installation of additional controls and requirements for ldaho Power's
coal-fired generation plants, depending on the level ultimately finalized. The revised NAAQS would
Coal Unit Environmental Analysis Page 8
a
a
ICL/SC Attachment 4
Page 9 of30
also have an impact on the applicable air permitting requirements for new and modified facilities.
The EPA has stated that it plans to issue nonattainment designations by late 2014, with states having
until 2020 to comply with the standards.
fl(t In 201O the EPA adopted a new NAAQS for NO, at a level of 100 parts per billion averaged over
a one-hour period. ln connection with the new NAAQS, in February 2012 the EPA issued a final rule
designating allof the counties in Nevada, Oregon, and Wyoming as "unclassifiable/attainment" for
NO,. The EPA indicated it will review the designations after 2015, when three years of air quality
monitoring data are available, and may formally designate the counties as attainment or non-
attainment for NO,. A designation of non-attainment may increase the likelihood that ldaho Power
would be required to install costly pollution controltechnology at one or more of its plants.
592. ln 2010, the EPA adopted a new NAAQS for SOz at a level of 75 parts per billion averaged over a
one-hour period. ln 2011, the states of Nevada, Oregon, and Wyoming sent letters to the EPA
recommending that al! counties in these states be classified as "unclassifiable" under the new one-
hour S0z NAAQS because of a lack of definitive monitoring and modeling data.
Clean Woter Ad Sedion 316(b)z ln March 2011, the EPA issued a proposed rule that would establish
requirements under Section 316(b) of the federal Clean Water Act for all existing power generating facilities
and existing manufacturing and industrialfacilities that withdraw more than two million gallons per day
(MCD) of water from waters of the U.S. and use at least 25 percent of the water they withdraw exclusively
for cooling purposes. The proposed rules would establish national requirements applicable to the location,
design, construction, and capacity of cooling water intake structures at these facilities by setting
requirements that reflect the Best Technology Available (BTA) for minimizing adverse environmental impact.
ln June 2012, the EPA released new data, requested further public comment, and announced it plans to
finalize the cooling water intake structures rule by June 2013.
New Source Performonce Stondards (NSPS) lor Greenhouse Gas Emissions lor New EGUs: ln March 2012,
the EPA proposed NSPS limiting Carbon Dioxide (CO2) emissions from new fossil fuel-fired power plants. The
proposed requirements would require new fossil fuel-fired EGUs greater than 25 MW to meet an output-
based standard of 1,000 pounds of CO2 per MWh. The EPA did not propose standards of performance for
existing EGUs whose CO2 emissions increase as a result of installation of pollution controls for conventional
pollutants.
Clean Air Ad (CAA) - Regional Hoze Rules: ln accordance with federal regional haze rules under the CAA,
coal-fired utility boilers are subject to RH BART if they were permitted between 1952 and L977 and affect any
Class I areas. This includes all four units at the Jim Bridger plant. However, North Valmy is not subject to the
regulation as it was permitted after t977. Under the CAA, states are required to develop a SIP to meet
various air quality requirements and submit them to the EPA for approval. The CAA provides that if the EPA
deems a StP submittalto be incomplete or "unapprovable," then the EPA will promulgate a federal
implementation plan (FlP) to fillthe deemed regulatory gap. In May 20L2, the EPA proposed to partially
reject Wyoming's regional haze SlP, submitted in January 20LL,for NO, reduction at the Jim Bridger plant,
instead proposing to substitute the EPA's own RH BART determination and FlP. The EPA's primary proposal
would result in an acceleration of the installation of Selective Catalytic Reduction (SCR) additions at JB1 and
Coal Unit Environmental Analysis Page 9
ICL/SC Attachment 4
Page l0 of30
JB2 to within five years after the FlP, or a SIP revised to be consistent with the proposed FlP, is adopted by
the EPA. The EPA had stated that it planned to adopt the FlP, or approve the revised Wyoming SlP, by late
2012. However, in December 2012 the EPA announced that it would re-propose the plant-specific NO,
control provisions of its RH FIP in March 2013 and would not finalize the RH FIP until September 2013.
Coal Combustlon Reslduols (CCR): The EPA has proposed federal regulations to govern the disposal of coal
ash and other CCR's under the Resource Conservation and Recovery Act (RCRA). The agency is weighing two
options: regulating CCR's as hazardous waste under RCRA Subtitle C, or regulating them as non-hazardous
waste under RCRA Subtitle D. EPA is not expected to issue a final rule sometime in 2013.
As a result of recent environmental regulation, ldaho Powe/s coal-fired plants will require additional
investment in environmental control technology as described below:
Jim Bridger will require the installation of the following controls to meet the RH BART and MATS regulations:
Unit
JB1
tBz
J83
J84
AllUnits
Pollutants
NO,
NO,
NO,
NO,
Mercury
Pollutants
HCL
Control
DSr (201s)
Resulation
MATS
Controls Resulation
scR (2022) RH
scR (2021) RH
scR (201s) RH BART
scR (2016) RH BART
CaBr2, scrubber MATS
additive, activated
carbon injection (2015)
New Emission Limits
0.07|b/MMBtu
0.07|b/MMBtu
0.07|b/MMBtu
0.07!b/MMBtu
1.0|b/IBtu
New Emission Limits
0.0020|b/MMBtu
North Valmy will require the installation of a DSt system, for controlling HCL for acid gas compliance, to meet
MATS regulations:
Unit
NV1
Coal Unit Environmental Analysis Page 10
ICLISC Attachment 4
Page 11 of30
Investment Alternatives
Base Alternatlves
The Study analyzes three base ahernatives for each unit. Each alternative is analyzed under the three carbon
and three natural gas sensitivities.
The atternatives include:
1l lnstall environmenta! upgrade - lnstallthe required environmental controls to comply with a current,
proposed or reasonably anticipated regulation. For Jim Bridger this includes cost for compliance with
RH, MATS, CCR and the Clean Water Act Section 316(b). For North Valmy this includes the cost for
compliance with MATS
2l Retire the unit and replace with a CCfi - The capital cost estimate for the CCCT capacity used to
replace the.retired coal-fired capacity in this Study was based on the installed cost of ldaho Powe/s
Langley Gulch plant that became commercially operational in June 2012.
The CCCT's are sized to replace the capacity of ldaho Powe/s share of the coal unit being replaced.
For example, if a 100 MW coal-fired unit is retired, it is replaced with 10O MW of CCCI capacity at a
Langley Gulch cost per kW. Of course, actual costs may be different, but for this Study however, we
believe that using the Langley Gulch cost per kW is a reasonable assumption. The CCCT units are
assumed to be located within the ldaho Power service territory.
3l Conversion of the unit to burn natural gas - Natural gas for Jim Bridger is assumed to be provided by
a pipeline approximately two miles from the plant. Natural gas for North Valmy is assumed to be
provided by a pipeline located approximately 13 miles north of the plant. The natural gas conversion
capital and O&M costs used in this Study included installing a pipeline to the plant, modifications to
the boiler, and changes in heat rate or capacity due to firing with natural gas instead of coal.
The following table summarizes the base alternatives that were analyzed. lncluded are the potential
compliance deadlines for installing environmental controls and effective dates for the retirement and
replacement with CCCT and natural gas conversion alternatives:
Coal Unit Environmental Analysis Page 11
ICL/SC Attachment 4
Page 12 of30
North Valmy Unit#1
lnstallDSl
Retire/Replace with CCCT (DSI not installed)
Naturalgas conversion (DSl not installed)
Jim Bridger Unit Sl
!nstallSCR
Retire/Replace with CCgf (SCR not installed)
Naturalgas conversion (SCR not installed)
Jim Bridger Unlt #2
Install SCR
Retire/Replace with CCfi (SCR not installed)
Naturalgas conversion (SCR not installed)
Jim Bridger Unit *3
Install SCR
Retire/Replace with CCCI (SCR not installed)
Naturalgas conversion (SCR not installed)
Jim Bridger Unlt #4
lnstallSCR
Retire/Replace with CCfi (SCR not installed)
Naturalgas conversion (SCR not installed)
3l3tl20ts
L2l3L/2022
L2l3tl2O2L
t2/3LlzOLs
L2l3tl2Ot6
4ltlzo,'s
4ltlzots
LIL/2O23
Lltl2023
tlL12022
Lltl2o22
Lltl20L6
LlL|2OL6
tltl20t7
LlL|aOLT
ln addition to the base ahernatives, ldaho Power was directed in Order No. L2-L77 , issued by the Public
Utilities Commission of Oregon (OPUC or Commission) in Action item 11 as follows:
"ln its next IRP Update, ldaho Power will include an Evaluation of Environmental Compliance Costs
for Existing Coal-fired Plants. The Evaluation will investigate whether there is flexibility in the
emerging environmental regulations that would allow the Company to avoid early compliance costs
by offering to shut down individual units prior to the end of their useful lives. The Company will also
conduct further plant specific analysis to determine whether this tradeoff would be in the ratepayers'
interest."
!n accordance with the Commission's directive ldaho Power analyzed hypothetical scenarios including
compliance timing and the enhanced upgrade alternatives desoibed below.
Environmental
Compliance
Deadline
Retire/Replace VCCCT
& Natura! Gas Convercion
Effective Date
Base Alternatives
Coal Unit Environmental Analysis Paget2
ICL/SC Attachment 4
Page l3 of30
Comoliance Timins Alternatives ICTAI
ln addition to the base alternatives, ldaho Power analyzed avoiding the installation of required or reasonably
anticipated emission controls by delaying the compliance requirement by five years in exchange for shutting
the unit down at the end of the five year period. A negotiated delay is not an option that currently exists but
the Study quantifies the financial results of these alternatives.
ldaho Power co-owns all of its coal-fired generation, and ldaho Power is not the operating partner for any of
the coal-fired plants. Not being an operating partner removes flexibility that other utilities may have for
regulations allowing emission totaling substitution or reductions at one facility to compensate for lower
reductions at another plant, or the option of shutting down a unit or plant in place of reductions at another
plant, or delaying installation of environmental controls for a guaranteed early shutdown. As IPC is not the
operating partner of Jim Bridger or North Valmy, it is highly unlikely Idaho Power would have the ability to
negotiate alternative scenarios as described above.
The following table summarizes the CTA alternatives that were analyzed. lncluded are the potential
compliance deadlines for installing environmental controls and effective dates for the retirement and
replacement with CCCT and natural gas conversion ahernatives:
Enhanced Alternatives
The enhanced upgrade alternative was included for North Valmy which takes into account the possibility of
future environmental regulations that would require the installation of SCR and Wet Flue Gas Desulfurization
(WFGD)for compliance. At this time, there are no regulations requiring the installation of the emission
controls that are included in the enhanced upgrade alternative. Any future regulations are expected to have
at least a five- year compliance period. A five- year compliance window would require any investment or
replacement to be installed and in-service by 2018. The following table summarizes the enhanced
alternatives:
Compliance Timing Alternatives (CIAI
Environmental
Compliance
Deadline
RetirdReplace w/CCCT
& Natural Gas Conversion
Effective Date
North Valmy Units #1 & fi2
Retire both units
Retire/Replace with CCgf (SCR & WFGD not installed)
Natural Gas Conversion (SCR & WFGD not installed)
Jim Bridger Units #3 & #4
Retire both units
Retire/Replace with CCCI (SCR not installed)
Natural Gas Conversion (SCR not installed)
L213L|2022
L2l3Ll2O20 & L2l3u2o2t
tltl2o23
tlLl2023
tlLl2OzL & LlLl2O22
LlLl202L & Lltl2022
Coal Unit Environmental Analysis Page 13
ICL/SC Attachment 4
Page 14 of30
Results
SAIC lndividual Unit Analvsis
The SAIC analysis included the following objectives:
r Review ldaho Powe/s assumptions for capital costs of the proposed environmental compliance
upgrades, including SCR, DSl, WFGD, and other systems, as well as the costs of replacement capacity.
r Review ldaho Power's assumptions for variable costs of the proposed environmental compliance
upgrades, coal replacement with CCCT's and natural gas conversion. ldaho Power provided SAIC
forecasted generation output for each unit from AURORA. ldaho Power also provided plant
operational data obtained from the coal unit's co-owner and operator; PacifiCorp for the Jim Bridger
units and NV Energy for the North Valmy units.
r Develop cost estimates for replacing the coal units annual generation, under three natural gas and
three carbon futures, with three investment alternatives: (1) installing environmental compliance
upgrades, (2) retiring the unit and replacing with CCCT or (3) converting the unit to natural gas. These
total costs include capital costs, O&M, decommissioning costs and unrecovered investments of the
existing coal units.
r Develop a capital investment analysis allowing assets with different lengths of operation as well as
different implementation dates to be compared equitably.
r Provide planning recommendations regarding the three investment alternatives.
The following table summarizes the results from the SAIC analysis. The left column groups each unit with the
investment alternatives. The columns to the right show the net present value (NPV) of operating and capital
costs over the twenty-year period 20t3-2O32 in 2013 dollars. The green highlighted cell indicates the least
cost option for the unit under each scenario. SAIC's investment recommendations, which can be found in
their report Coal EnvironmentalComoliance Upgrade lnvestment Evaluation Section 5 Conclusions.
The SAIC results are summarized in Figure 3 below
Enhanced Alternatives
Environmental
Compliance
Deadline
RetlrdReplace w/CCCT
& Natural Gas Convercion
Effective Date
North Valmy Unit #1
Enhanced Upgrade (installation of SCR & WFGD)
Retire/Replace with CCCI (SCR & WFGD not installed)
Naturalgas conversion (SCR & WFDG not installed)
t2l3Ll20t7
Lltlz0ts
rlLl20L8
North Valmy Unit f2
Enhanced Upgrade (installation of SCR & WFGD)
Retire/Replace with CCCf (SCR & WFGD not installed)
Naturalgas conversion (SCR & WFGD not installed)
12l3Ll2OL7
tlLlzOLs
LlLl20t8
Coal Unit Environmental Analysis Page 14
ICUSC Attachmeot 4
Page 15 of30
Flgure 3. SAIC Analysls Summary Results by Scenarlo for the 2013-2032 Forecast Perlod (52013 Mllllonsl
ldaho Power utilized the AURORA modelto determine the total portfolio cost of each investment alternative
analyzed by SAIC. The total portfolio cost is estimated over a twentyayear planning horizon (2013 through
20321. ldaho Power used the simulated operational performance of each investment alternative relative to
the existing rosource under varying future natural gas price forecasts and carbon adder assumptions. ldaho
Power conducted the simulation using the AURORA mode!. The AURORA model applies economic
assumptions and dispatch cost simulations to model the relationships between generation, transmission, and
demand to forecast future electric market prices. AURORA is ldaho Powe/s primary tool used to simulate
the economic performance of different resource portfolios evaluated in the lntegrated Resource Planning
(lRP) process.
The fixed costs used by SAIC are incorporated into the ldaho Power Study. SAIC reviewed the fixed costs of
each investment ahernative and scheduled the costs annually for the various investment alternatives for the
twenty-year study period. These annual costs included environmentalcapital investments, ongoing capital
expenditures, unit replacement capital and the fixed O&M costs for the specific unit configuration. The ldaho
Power Study combines the Net Present Value (NPV) of the fixed costs from the SAIC model; with the NPV of
lfihOrr
8rr
lowGr
IIo
Gr.tcn
LaGr
Sara
Ca6o.t
lowGu
lUl
C.rbon
b.
C..ton
SL62
North Velmy l upgmde
l{orth Velmy 1 2015 NG
1
tlortft Valmy l Edranced Upgra&
North Vclmy 1201t l{G
1 2018Itlorth
?lorth Vrlmy 2 Enhenced Upgrede
North Vdmy 2 tlG
North 2
Jlm Brldger 2 Upgrade
Jlm Mdge;2 NG
$1,3s,$L$e Sr,nss
Present Value Power Costs by Scenario (520f 3 M)
EITTil IEEt-"r--*?-HHil-',-Efl
###HB#mruGil-EilHEr @
EllEiilrEil rrlrHHilril
IilEil-BffiIffiffiMffi
II?EIHHEFHIffiffiffiMffi
IilHHE=-mffiffiffiffiffi
HH@ffilffiHI
ffiHET
HH
fil
Coal Unit Environmental Analysis Page 15
ICL/SC Attachment 4
Page 16 of30
the twenty-year Aurora generated total portfolio cost to form the basis for the quantitative evaluation of the
investment ahernatives.
Figure 4 below, summarizes the combined NPV resuhs of ldaho Powe/s Aurora analysis and SAICs fixed
costs analysis for each investment option under varying carbon and natural gas futures. The planning case
(planning case carbon/planning case natural gas) is denoted in bold.
The left column groups each unit with the investment ahernatives. The columns to the right show the NPV of
the total portfolio costs over the h^renty-year period (2013-2032) in 2013 dollars. The green highlighted cell
indicates the least cost option for the unit under that scenario. The preponderance of least cost outcomes
and the relative cost difference between ahernatives helps determine the investment recommendation.
Flgure 4. Total Portfollo Costs
ldeho Power Company
Coal Envlronmcntal lnrrestmcm Modellng Resuhs
Total Portfollo Costs (Auro6 Portfollo Cost + SAIC Flxed Costs )
Forthe 20 ycar forecast pcrlod 20L?2032
Nrry h 2013 $Milllons
Coal Unit Environmental Analysis Page 16
NN'Portfolio
tnvtstmcIlt Ah.n[thrcs
NG Hlgh
$o
NGLil
9o
NG Low
$u
NG low
$rs
NG
$o
NG
$u
NG
Sss
3,965
4,079
3,859 1,7222015 naunl convarslon
2015 r.tlrc/repl.ce wlth CCCT
1 lvll DSt
6,786
4,032 4r{o
4.792
6,t7't)
c681
6,797
7A394,580
f,283
5,372
4,98:t
1471
1,3:r9
spre
t6a4{03
v2 Enh.occd Upgndc (SCR & WFGDI 2018
IA rcurcy'rcplecc utlth CCCr2o$
\r2 n.turd t.3 oonvrrdon 2018 6,969
5,063 7316 4,5t2 s31s
1,256
V1V2 Enhmad Uilrad. (scR & wRiD) 2023
vl v2 rctlrc/r.pbc. wlth CCCr 2023
V1 V2 n tur.l 2023
a,054
Brldgcr 1 (JB1l lnst n scR
rctlrcy'rcphc. wlth CCCT 2023
natural tr convtrslon 2023
1,8r!)6,962
7,@S
t1,156
+16s
1,v2
a,!165
natural convcrslon 2022
Brldtcr 2 UB2llnnall SCR
rctln/replace with CCCI mil:l 1,117 tl,935 7,UR
7
4l!18 4981
4,231.5,015
conrrcrsion 2015nstural
Brld&r 3 (J83, lmtallSCR
rctlrcy'rcplme with CCCT 2016 7,UtZ 4,mL 1gtt
1827 5153
4,253
4,210
5,0!ofrrt 6931
6,969
7,124-J83.184 lnstall SCR
- J83 ,84 rctlrc/rcpLce w CCCT 2020-21
-JB3J84 n.tural convaFlon 202$,21
4,895 5,576 7,351.
7
4s39 5,zfrt 4,712 5126
EEEE
Iri,ilrEilEEreT*'.'MEBETrt'IMBB
MEBMffiHEEIB
@
@
M@EEm:BH
ICL/SC Attachment 4
Page 17 of30
Conclusions and Recommendations
North Valmv Unit fl1
North Valmy is a critical facility for the reliability of the electric system in northern Nevada.
With the exception of the installation of DSI for MATS compliance, under current and proposed regulations
further environmental investment is not required for the continued operation of NV1. lnstallation of DSI was
the lowest cost resuh for most of the sensitivities analyzed by SAIC. The SAIC resuhs show installing DSI as
the least cost option in six of the nine sensitivities analyzed including the planning scenario (planning natural
gas/planning carbon).
The AURORA analysis, performed by ldaho Power, shows installing DSI as the least cost option in four of the
nine sensitivities analyzed including the planning scenario (planning naturalgas/planning carbon). The
majority of scenarios not supporting the installation of DSI are the extreme low natural gas and high carbon
cases which have a lower probability of occurring.
ldaho Powe/s conclusion is that the option to make the DSI investment represents a low cost approach to
retain a diversified portfolio of generation assets including the 125 MW's of NV1 capacity for our customers
benefit. The continued operation of NV1 as a coal-fired unit will provide fuel diversity that can mitigate risk
associated with high natural gas prices. While noting that tdaho Power does not recommend the
retire/replace with CCCT option or the conversion of the unit to natural gas, it is also important to recognize
that such replacements and conversions do not happen instantaneously. Conversion to naturalgas could
require from three to six years for permitting, installation of the natural gas pipeline, and boiler
modifications. Permitting and construction of a CCCT would require approximately four years.
Based on these results, ldaho Power recommends installing DSI and continuing to include NV1 in its
generation portfolio for the 2013 !RP and future resource planning.
Figure 5 illustrates the results of the Study for installation of DSI at NV1 and Figure 6 contains a comparison
of the costs of the DSI investment to the retire/replace with CCCT and natural gas conversion alternatives:
Coal Unit Environmental Analysis Page L7
ICL/SCAttrchmt4
Page 18 of30
FEure 5. illrt D6l lnstallstlon Rcsutts
Fl3urc 6. NVI DSI lnstalla$on Cost Deltao
North Valmy Unit #1
a
g
=IllraC'NG;
6II
€oo
E
=
s8,fl)o
s7,fl)o
56,q)o
s5,(n0
s4,(m
S3,ooo
s2,q)0
Sl,(no
So
tlnst I DSI
f ncdnfTcdeedGccf
ll{rurnl GesConwrsbn
Sensitffiics
t{rhaS lrar.G lorr€tl.malrlG ,t tmm
l6lrll
rl|F-{rilllffi5H;I EH
ffilIIEI
E
MIffiTEEIIITmr
HffiIE
Coal Unit Environmental Analysis Page 18
ICL/SC Attachment 4
Page 19 of30
North Valmv Unit f2
At this time, under current and proposed regulations, further environmental investment is not required for
the continued operation of NV2. Additional analysis will be performed if future regulations require significant
environmental investments in NV2.
ldaho Power recommends including NV2 in its generation portfolio for the 2013 IRP and future resource
planning.
North Valmv Units #1and il2 lCombined Analvsisl
The assumption in the North Valmy Enhanced Upgrade alternative is both units are upgraded, replaced or
converted to burn natural gas at the same time. The Enhanced Upgrade alternative includes installation of
SCR and WFGD. Consequently, a combined investment analysis is made for both units.
Under both the SAIC and AURORA analyses, proceeding with the Enhanced Upgrade environmenta!
investments at NVl and NV2 are not supported. However, as there are no current or proposed regulations
requiring this investment, ldaho Power recommends including NVl and NV2 in its planning and as part of
!daho Powe/s generation portfolio.
Figure 7 illustrates the results of the Study for the Enhanced Upgrade at NV1 and NV2 and Figure 8 contains a
comparison of the Enhanced Upgrade costs to the retire/replace with CCCT and natural gas conversion:
Coal Unit Environmental Analysis Page 19
Flgure 7. NVl and NV2 Enhanced Upgrade Results
North Valmy Units #1 and #2
_ - ___ Fnhanced Upgrade
ICUSC Attacbmeot 4
Page 20 of30
Ilnst llSCR&WFGD
I Retlre/Replace dCCCT
I Natural Ges C.onver5bn
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.9oEocI2
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Sensitivities
Flgure 8. NVl and NV2 Enhanced Upgrade lnstallatlon Cost Deltas
Additional analysis was performed using the compllance timing alternative. The resutg of delaying the
implementation date do not support proceeding with the Enhanced Upgrade environmental investments on
NVl and NV2.
In the event additionalenvironmental controls are required for NVl and NV2, the compliance requirements
and available control technologies will be analyzed to determine whether installing the environmental
controls are the least cosVleast risk option.
irrh lG
leCOr
t{drItE
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lflrfi OOr
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-
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EE
Coal Unit Environmental Analysis Page 20
ICUSC Attachment 4
Page 2l of30
Figure 9 illustrates the results of the Study for the Enhanced Upgrade compliance timing alternative at NVl
and NV2 and Figure 10 contains a comparison of the compliance timing alternative Enhanced Upgrade costs
to the retire/replace with CCCT and naturalgas:
Figure 9. ltl. and NV2 Enhanced Upgrade Compllance Tlmlng Altematlve Results
s8,ooo
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54,ooo
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North Valmy Units #1 and #2
Com pl ia nce TimingAttemative_
\d \!rt'
Sensitivities
Figure 10. NVl and NV2 Enhanced Upgrade Compllance Tlming Altematlve Cost Deltas
(,tCo
==nldC'Nrr!
I0o(,toEI
a.2
tlnstsll SCR & WFGO
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ll{etunl Gas Comersbn
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ilG conYsrion
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Coal Unit Environmentd Analysis Page2l
ICUSC Attac&meot 4
Page 22 of 30
Jm.Eddreilloftfl
Under both the SAIC and AURORA analyses, proceeding with environmental investments at JBl is the lowest
cost option for the majority of the carbon and natural gas scenarios. ln the most probable scenario, the
ldaho Power planning scenario which identifies a planning carbon and planning natural gas future, the
environmental upgrade option is ovenrhelmingly the least cost option.
The installation of SCR, which is the most significant of the environmental investments analyzed, is far
enough in the future to make the forecast assumptions highly speculative. As ldaho Power nears the actual
SCR investment decision poing a more detailed analysis will be performed with updated assumptions.
Based on these results, ldaho Power recommends continuing to include JBI in its generation portfolio for the
2013 IRP and future resource planning.
Figure 11 illustrates the results of the Study for installation of required environmental controls at JBI and
Figure 12 contains a comparison of the installation of required emission controls to the retire/replace with
CCCT and natural gas conversion options:
Flgure 11. JBl Results
Jim Bridger Unit #1
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0
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r lnstsll Controls
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Coal Unit Environmental Analysis Page22
ICL/SC Attachment 4
Page 23 of30
Figure 12. JBl installation of Emission Controls Cost Deltas
Jim Bridser Unit S2
Under both the SAIC and AURORA analyses, proceeding with environmenta! investments at J82 is the lowest
cost option for the majority of the carbon and natural gas scenarios. ln the most probable scenario, the
ldaho Power planning scenario which identifies a planning carbon and planning natural gas future, the
environmental upgrade option is ovenrhelmingly the least cost option.
The installation of SCR, which is the most significant of the environmenta! investments analyzed, is far
enough in the future to make the forecast assumptions highly speculative. As ldaho Power nears the actual
SCR investment decision point, a more detailed analysis will be performed with updated assumptions.
Based on these results, ldaho Power recommends continuing to include JB2 in its generation portfolio for the
2013 IRP and future resource planning.
Figure 13 illustrates the results of the Study for installation of required environmental controls at J82 and
Figure 14 contains a comparison of the installation of required emission controls to the retire/replace with
CCCT and natural gas conversion options:
High i,lc High l.lc HiSh NG tow NG lowNG Low llc Plannlry NG PIAITI{IIG I{G PlanninS l,lc
lnstall Controls
Rrtire/Replace
Natural Gas
Conversion
lnstall conbols-
ccct
conv6ston
s- l,lc
Coal Unit Environmental Analysis Page23
ICL/SC Attachmeot 4
Page 24 of30
Flgure 13. JB2 Results
Flgure ltl. JB2lnstallation of Emlsslon Controls Cost Deltas
Jim Bridger Unit #2
6C.9
-
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rft dre/n€d.cew/CCCt
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d,L cPl d d
\rt'\r$
Sensitivities
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lfl
illdr llc ]illrc ldLG lnltc Pllnnltf,tac a^urlr€ xo
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Coal Unit Environmental Analysis Page24
ICI-/SC Anachmeot 4
Page 25 of30
Jim Brldser Unit S3
Under both the SAIC and AURORA analyses proceeding with environmental investments at JB3 is the lowest
cost option for the majority of the carbon and natural gas scenarios. ln the most probable scenario, the
ldaho Power planning scenario which identifies a planning carbon and planning natural gas future, the
environmental upgrade option is overwhelmingly the least cost option. Based on these results ldaho Power
concludes that making the environmental investments in JB3 is the most prudent actaon and provides the
lowest cost and least risk option.
Based on these results, ldaho Power recommends proceeding with the installation of all identified
environmental controls (including SCR) and continuing to include J83 in its generation portfolio for the 2013
IRP and future resource planning.
Figure 15 illustrates the results of the Study for installation of required environmental controls at JB3 and
Figure 15 contains a comparison of the installation of required emission controls to the retire/replace with
CCCT and natural gas conversion options:
Figure 15. r83 Results
Jim Bridger Unit #3
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Coal Unit Environmental Analysis Page 25
ICLISC Attachment 4
Page 26 of30
Figure 16. JB3 installation of Emission Controls Cost Deltas
Jim Bridser Unitf4
Under both the SAIC and AURORA analyses proceeding with environmental investments at J84 is the lowest
cost option for the majority of the carbon and natural gas scenarios. ln the most probable scenario, the
ldaho Power planning scenario which identifies a planning carbon and planning naturalgas future, the
environmental upgrade option is ovenrhelmingly the least cost option. Based on these results ldaho Power
concludes that making the environmental investments in J84 is the most prudent action and provides the
lowest cost and least risk option.
Based on these results, ldaho Power recommends proceeding with the installation of all identified
environmental controls (including SCR) and continuing to include J84 in its generation portfolio for the 2013
IRP and future resource planning.
Figure 17 illustrates the results of the Study for installation of required environmental controls at JB4 and
Figure 18 contains a comparison of the installation of required emission controls to the retire/replace with
CCCT and natural gas options:
Hlah l{G Hlth l{G Hith Nc lfltlc Low t{G LilMi Phnnlrf Mi PIAI{T{NGilG Plrnnlra t{G
lntt ll Controls
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CoNs3lon
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convGBlon
Coal Unit Environmental Analysis Page26
EtE
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Jim Bridger Unit #4
"d'c "dtd
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Sensitivities
Flgure lS. rB4lnstallatlon of emlsslon controls Cost Deltas
ICUSC Attacbment 4
Page 27 of30
rlnstal Controls
I Redre/Replace dCCCT
I l{ahrral Gas Conc€rslon
Lflr{6 LoutG Pl.nnlrf tGHlai lC lrorG
CdrGdm
Gr3
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convtrtloo
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Coal Unit Environmental Analysis Page27
ICUSC Attachment 4
Page 28 of 30
Jim Brideer Unlts S3 and ll4 lComblned Analvslsl
The assumption in the compliance timing alternative is both JB3 and J84 are not upgraded and are replaced
or converted to burn natural gas with a five year delay. Consequentially, a combined anvestment analysis is
made for both unis.
As shown in the figure above, the results of the compliance timing alternative still support the installation of
emission controls on J83 and JM.
Figure 19 illustrates the results of the Study for the installation of controls compliance timing alternative at
JB3 and JB4 and Figure 20 contains a comparison of the compliance timing alternative costs to the
retire/replace with CCCI and natural gas conversion options:
Flgure 19. r83 and JB4 Compliance Timlng Alternatlve Resuhs
Jim Bridger Units #3 and #4
Com plia nce Tim ing Alternatives
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.Acot3
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0
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(jriof
Coal Unit Environmental Analysis Page28
ICLlsC Attachment 4
Page29 of30
Figure 20. r83 and JB4 Compliance Timing Alternative Cost Deltas
Hlth NG
Low GO,
Hith l{G
Plrnnlnr @'
Hlth N(i
Hlrh CO,
Lowilc
l,ilCO'
lflNG
Pl.nhlhr CO,
lfll{G
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Pl.nnllr NG
|.il CIr'
NAXX]IGTIG
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Coal Unit Environmental Analysis Page29
ICL/SC Attachment 4
Page 30 of30
Review Process and Action Plan
The objective of this Study is to ensure a reasonable balance between protecting the interests of customers,
meetint the obligation to serve the current and reasonably projected future demands of customers, and
complying with environmental requirements, while recognizing that the regulatory environment is uncertain.
ln a commitment to honor these goals ldaho Power antends to perform systematic reviews, similar to this
analysis, whenever certain triggering events occur. These triggering events include:
o A significant change in the current state of environmental regulation
o A significant change in the estimated cost of anticipated environmental controls
o Within a year of committing to a major environmental upgrade
o Whenever ldaho Power files an lntegrated Resource Plan
In conclusion, this Study shows the economics of incremental environmental investments is highly dependent
upon the assumptions for both natural gas and carbon adders. This Study highlights the challenge in making
investment decisions today in the frce of significant uncertainties. Despite these uncertainties, certain
environmental control equipment investment decisions must be made in the near-term. ldaho Power will
continue to work with regulatory agencies and stakeholders to analyze these major investment decisions
prior to commitment and implementation.
Coal Unit Environmental Analysis Page 30
Attachment 5
ConfidentialAttachment I to IPC Response to Sierra Club RequestNo. 22
ICLISC Attachment 5 contains confidential information subject to the protective agreement in
Case No. IPC-E-2I-17 and has been served upon the Commission and eligible parties.
Attachment 6
ConfidentialAttachment 3 to IPC Response to Sierra Club RequestNo. 28
ICL/SC Attachment 6 contains confidential information subject to the protective agreement in
Case No. IPC-E-21-17 and has been served upon the Commission and eligible parties.
Attachment 7
Confidential Attachment I to IPC Response to Sierra Club Request No.
24 - Bridger Coal Price Forecast
ICL/SC Attachment 7 contains confidential information subject to the protective agreement in
Case No. IPC-E-21-17 and has been served upon the Commission and eligible parties.
Attachment 8
Confidential Attachment 2 to IPC response to Sierra Club Request
No. 28 - JB Coal Aurora Vectors
ICL/SC Attachment 8 contains confidential information subject to the protective agreement in
Case No. IPC-E-21-17 and has been served upon the Commission and eligible parties.
Attachment 9
RMI Jim Bridger Analysis
Attachment 9 is an Excel spreadsheet and is being provided as a
separate attachment.
CERTIFICATE OF SERVICE
I hereby certi$ that on this 27ft day of April2O22,l delivered true and correct copies of
the foregoing JOINT COMMENTS OF SIERRA CLUB AI\[D IDAHO CONSERVATION
LEAGUE to the following persons via the method of service indicated below.
Electronic mail only (see Order 35375)
Idaho Public Utilities Commission
Jan Noriyuki, Secretary
secretary@Fuc. idaho. gov
Commission Staff
Chris Burdin
chris.burdin@puc. idaho.sov
Idaho Power Company
Lisa D. Nordstrom
Matt Larkin
lnordstrom@ idahopower.com
[e-mail]
dockets@ i dahopower.com
Industrial Customers of ldaho Power
Peter J. Richardson
Richardson Adams, PLLC
[e-mail]
Dr. Don Reading
dread ine@mi ndsprin g.com
Idaho Conservation League
Benjamin J. Otto
botto@ idahoconservation.org
City of Boise
Ed Jewell
Bo i seC ityAttorney@cityofboi se.ore
ejewel [e-mail]
Clean Energ,t Opportunities for ldaho
Michael Heckler
Courtney White
m ike@c leanenerg),opportun ities.com
courtney@cleanenersyopportun ities.com
I
Kelsey Jae
[e-mail]
MicrunTechrulogt, htc:
Jirn Swier
[e-mail]
Austin Rueschhoff
Thorvald A. Nelson
Austin W. Jensen
[e-mail]
tnelsontOhol landhartcom
awi ensen(Ehollandhart.com
ac loetOhol landhart.com
gl [e-mail]
/s/ Aru Bovd
AnaBoyd
Research Analyst
Sierra Chrb Environmeirtal Law Program
2l0l Webster St., Suitc 1300
Oaklan4 CA946l2
Phone: [phone]
[e-mail]
2