20171124Comments.pdf

SIERRA
CLUB
RECE IVED
?ilI]1{0Y 2b At{ 9: l9
l;l:,irll ;rLi;LlC
i, I ll'i i, i:.'c0ill',ilsslcN
November 22,2017
Via FedEx
Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472W. Washington St.
Boise, ID 83702-5983
diane.holt@puc. idaho. gov
Re: Case No. IPC-E-17-llz Sierra Club Comments
Please find enclosed the COMMENTS OF SIERRA CLUB in the above mentioned case. The
public version of this document was sent via FedEx and served upon all party representatives
for this proceeding via e-mail. The confidential portion of this document was sent via FedEx
and served upon all eligible party representatives via U.S. Mail.
Please do not hesitate to contact me if you have any questions or need other materials. Thank
you.
Sincerely,
/s/ Ana Boyd
Ana Boyd
Legal Assistant
Sierra Club Environmental Law Program
2l0l Webster Street, Suite 1300
Oakland, CA94612
Phone: [phone]
[e-mail]
CERTIFICATE OF SERVICE
I hereby certify that on this 22nd day of November 2017,1delivered true and correct
copies of the foregoing COMMENTS OF SIERRA CLUB to the following persons via the
method of service noted. The public version of this document was served upon pafties via email,
and the confidential portion of this document was served upon all eligible party representatives
via U.S. Mail or FedEx:
FedEx:
Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472W. Washington St.
Boise, ID 83702-5983
diane.holt@puc. idaho. gov
(Original and eight copies provided)
Email:
Lisa D. Nordstrom (C)
Timothy E. Tatum
MichaelJ. Youngblood
Idaho Power Company
l22l West Idaho Street
PO Box 70
Boise, Idaho 83707
lnordstrom @idahopower. com
[e-mail]
[e-mail]
[e-mail]
Dr. Don Reading (C)
6070 Hill Road
Boise, ID 83703
[e-mail]
Eric L. Olsen
Echo Hawk & Olsen PLLC
505 Pershing Ave., Suite 100
PO Box 6l l9
Pocatello, ID 83205
[e-mail]
Peter J. Richardson (C)
Richardson Adams PLLC
PO Box 7218
515 N.27th Street
Boise. lD 83702
[e-mail]
Anthony Yankel
12700 Lake Ave. Unit 2505
Lakewood, OH44107
[e-mail]
Brad M. Purdy
Attorney at Law
2019 N. l Tth Street
Boise, lD 83702
[e-mail]
ThorvaldA. Nelson (C)
EmanuelT. Cocian (C)
Kim Stanger
Holland &Hart
6380 S. Fiddlers Green Circle, Suite 500
Greenwood Village, CO 801I I
tnelson@hol landhart.com
etcocian@hol landhart.com
[e-mail]
[e-mail]
Gregory M. Adams (C)
Richardson Adams, PLLC
515 N. 27th Street
Boise, ID 83702
gr e g@richard so n adam s. c o m
C. Tom Arkoosh (C)
David Arkoosh (C)
Arkoosh Law Offices
Idahydro
802 W. Bannock Street. Suite 900
PO box 2900
Boise, ID 83701
[e-mail]
[e-mail]
Pete Bennett (C)
Micron Technology, Inc
8000 S. Federal Way
Boise, ID 83707
[e-mail]
Sean Costello
Deputy Attorney General
Idaho Public Utilities Commission
472W. Washington
Boise, lD 83702
sean.costel lo@puc. idaho. gov
/s/ Ana Bovd
Ana Boyd
Legal Assistant
Sierra Club Environmental Law Program
2l0l Webster St., Suite 1300
Oakland, CA94612
Phone: [phone]
Gloria D. Smith (CA No. 200824 pro hac vice)
Managing Attorney
Sierra Club Environmental Law Program
2101 Webster Street, Suite 1300
Oakland, CA94612
(4ts) e77 -ss32
[e-mail]
TN THE MATTER OF IDAHO POWER
COMPANY' S 2OI7 INTEGRATED
RESOURCE PLAN
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
)
)
)
)
CASE NO. IPC-E-17-11
)
)
SIERRA CLUB COMMENTS
IREDACTEDI
SIERRA CLUB COMMENTS November 22,2017
J
4
5
TABLE OF CONTENTS
l. INrRooucrroN
2. SuvtutaRy AND RECoMMENDATToNS
Tup IRP,s ANALYSIS STRUCTURE IS FLAwED ..................3
3.1. Lack of portfolio optimization reduces rigor, transparency, and usefulness of IRPanalysis ....... 3
3.2. IPC's inappropriate application of the Clean Air Act's Regional Haze Rule leads it to
select an unlawful portfolio ..............7
INpur ASSUMpIoNS BIASED TowARD GREATER NEED .........
4.1. IPC understates its energy efficiency potential
4.2. IPC assumes certain wind contracts will not be renewed.............
WonrpappR ERRoRS BIAS IRP ANALySES IN FAVoR op Jrwr BnroceR RETRoFITS
5.1 . IPC mistakenly neglected to account for long-term Bridger fixed costs under SCR
scenanos
5.2. IPC calculation error results in understatement of Portfolio I new resource costs
5.3. NPV Impact of corrections to IPC workpaper errors
6. INpur ASSUMeTToNS ARE coNSrsrENTLy (AND TNACCURATELv) FAVoRABLE To BntoceR
..8
.9
t2
l3
l3
t4
l5
UNITS
6.1 .
6.2.
6.3.
6.4.
l5
t6
l6
l8
20
IPC understates the operational costs associated with SCR controls ...............
IPC assumes that Bridger coal prices will decline after years of increasing..............
IPC assumes that market prices will increase rapidly
Solar and battery storage cost assumptions are inflated
HIsToRy AND NEAR-TERM MoDELING INDICATE BRIDGER IS NoT ECoNoMIC.
7 .1 . IPC did not examine the economics of Jim Bridger Units 3 and 4.......
7.2. Jim Bridger will continue to be uneconomic on a going forward basis
IPC ruST ANALYSES ARE PooRLY APPLIED
8.1. Natural gas prices
8.2. Customer load...........
8.3. Coal prices
8.4. Lack of portfolio response to stochastic variation.....
,22
24
25
3l
)Z
32
33
34
7
8
SIERRA CLUB COMMENTS November 22,2017
TABLE OF FIGURES
Figure l. Portfolios in the IPC 2017 IRP (excerpted from Table 9.3 in 2017 IRP) .......................4
Figure 2. Incremental energy efficiency savings as percentage of sales, historical and IPC
forecast.....l0
Figure 3. 2015 incremental savings, AEG projected potentials and actual achieved -.................. 12
Confidential Figure 4. Alternative Bridger coal price forecasts ..............17
Confidential Figure 5. IPC forecasted fuel and energy prices relative to 2017 Levels, Portfolio 7
19
Figure 6. IPC forecasted market energy prices and Bridger production costs, Portfolio I ..........20
Figure 7. Utility-scale solar levelized costs relative to 2017 levels, historical and IPC forecast . 2l
Figure 8. Battery storage levelized costs relativeto20lT levels, Lazard and IPC projections....22
Confidential Figure 9. Bridger Unit I forward-going costs compared to market cost, Portfolio I
26
Confidential Figure 10. Bridger Unit I forward-going costs compared to market cost, Portfolio 7
Confidential Figure I l. Bridger Unit I fixed O&M for Portfolios l, 4, l0 and 7 .............-..-.-.....28
Confidential Figure 12. Value of Bridger Unit I under Portfolio 7, as modeled and with various
corrections.........
ConfidentialFigure 13. Value of Bridger Unit2 under Portfolio 7, as modeled and with various
corrections.........
Confidential Figure 14. Value of Bridger Unit I under various portfolios, with correction to fixed
O&M in Portfolio 7 30
Confidential Figure 15. Value of Bridger Unit 2 under various portfolios, with correction to fixed
O&M in Portfolio 7............31
Figure 16. Coal deliveries to Jim Bridger plant.JJ
.....,..,.............. 27
.,,,,................. 29
...................... 29
SIERRA CLUB COMMENTS
ll
November 22,2017
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
)
)
)
)
)
IN THE MATTER OF IDAHO POWER
COMPANY'S 20 I 7 INTEGRATED
RESOURCE PLAN
CASE NO. IPC-E-17-II
SIERRA CLUB COMMENTS
IREDACTED]
1. INrnooucrroN
Sierra Club appreciates the opportunity to comment on ldaho Power Company's (IPC) 2017
Integrated Resource Plan (lRP). These comments were prepared with the assistance of Avi
Allison and Dr. Jeremy Fisher of Synapse Energy Economics, and they are based on examination
of IPC's input assumptions, portfolio construction, and evaluation of resource options. Sierra
Club participated in the 2017 IPC IRP Advisory Counciland actively intervenes in utility
planning proceedings in jurisdictions across the United States. In these comments, we focus on
the overarching goal of achieving transparent, evidence-based resource planning that strikes a
balance between low costs and risk mitigation.
2. SunIulRy AND RECoMMENDATToNS
An IRP should identify a path toward reliably satisfying future energy service demands in an
economic and sustainable manner. A useful IRP contains a reasonable array of input
assumptions, and fairly evaluates the costs and benefits of competing demand- and supply-side
resources.
We recognize and applaud certain aspects of IPC's IRP. Specifically, this IRP explicitly
acknowledges the uneconomic nature of the North Valmy coal units and includes a plan to retire
North Valmy Unit I by the end of 2019. The IRP also accurately recognizes the importance of
pursuing allcost-effective energy efficiency, and of evaluating whether it is worth investing
substantial incremental capital in Jim Bridger Units I and2.
However, we find that the IRP relies on a deeply flawed analytical structure, multiple analytical
errors, and implausible assumptions regarding the costs and benefits of continuing to operate the
Bridger units. Ultimately, IPC's IRP appears to be persistently biased in favor of maintaining the
Bridger units despite the economic challenges that they currently face.
SIERRA CLUB COMMENTS November 22,2017
I
Bridger units. Ultimately, IPC's IRP appears to be persistently biased in favor of maintaining the
Bridger units despite the economic challenges that they currently face.
Our review indicates that the most serious flaws in the IPC IRP include:
Lack of portfolio optimization. IPC chose not to use any capacity expansion models in
this IRP, instead manually determining each portfolio it analyzed. IPC's claim that its
portfolio design enables it to asses alternative Bridger and Boardman to Hemingway
(B2H) investments in a fair fashion is misleading and inaccurate. Instead, the Company's
portfolio construction scheme renders virtually useless its comparative assessment of the
value of alternative Bridger retirement options. Furthermore, IPC's portfolio design all
but ensures that the IRP does not select a least-cost, least-risk plan.
Selection of illegal portfolio. Half of the portfolios evaluated in this IRP, including the
selected portfolio, do not comply with current regulatory requirements. IPC's proposed
plan banks on convincing regulatory agencies to allow it to continue to operate Bridger
Units I and 2 without selective catalytic reduction (SCR) technology well beyond the
date at which SCR retrofits are currently required. The Company's assessment of an
"alternative compliance" pathway for Bridger is not equivalent to the rigorous Regional
Haze alternatives that were evaluated-and discussed extensively with regulators-for
the Boardman, Centralia, or San Juan generating stations.
Understated costs of retrofitting Jim Bridger Units 1 and 2 with SCR. Under the
portfolios in which IPC installs SCR on the Bridger units, the IRP mistakenly fails to
account for any fixed costs incurred at the Bridger plant beyond 2034.The economic
assessment contained in the IRP also relies on a calculation error that artificially reduces
the cost of the lowest-cost SCR retrofit scenario. In addition, the SCR scenarios
incorrectly fail to account for increased operations and maintenance costs associated with
SCRs.
o
a
Deflated coal cost assumptions, paired with assumed rapid growth in market energy
prices. Integrated into the Company's analysis structure, these assumptions make the
Bridger units appear to become economically viable in the long term, despite the IRP's
implicit acknowledgment that these units are currently losing money on behalf of IPC
ratepayers. An independent valuation of the Bridger units indicates that they are likely to
remain uneconomic indefinitely. Only an unhelpful analysis structure and erroneous
inputs result in the Company's finding that Bridger is economic if maintained into the
2030s.
Lack of evaluation of the economic status of Jim Bridger Units 3 and 4. In
commenting on and evaluating PacifiCorp's recent 2017 IRP, Sierra Club presented
strong evidence that Bridger Units 3 and 4 are substantial liabilities. Yet IPC does not
SIERRA CLUB COMMENTS November 22,2017
a
a
a
2
a
a
even consider the economic status of Bridger Units 3 and 4 in this IRP, and it does not
provide sufficient data to allow for an independent valuation of these units.
Low estimates of achievable energy efficiency potential. While the IRP says the right
things about pursuing all cost-effective energy efficiency, it assumes future savings that
are much lower than the levels currently being achieved by IPC's cost-effective
programs.
Inflated alternative resource cost assumptions. IPC assumes that the levelized costs of
allresources will increase atthe rate of inflation. This assumption is inconsistentwith
recent evidence and industry expectations regarding the declining costs of technologies
such as battery storage and solar.
Based on our findings, Sierra Club recommends that the Commission not acknowledge IRP
Action Number 4 (planning on retirement dates of 2028 for Bridger Unit 2 and 2032 for Bridger
Unit l) and instead require IPC to re-assess Bridger Units I through 4. We recommend thatthe
Commission disavow inadequate resource plans with substantial flaws and not defer the re-
analysis of the Bridger plant to the next IRP. In addition, we recommend that IPC remedy each
of the flaws identified above in future IRP filings. Finally, we recommend that the Commission
consider revisiting its requirements to IPC under Orders 32929 and 32996 in Case No. IPC-E- l3-
16, IPC's application for a Certificate of Public Convenience and Necessity (CPCN) to install
SCR on Jim Bridger Units 3 and 4.
Sierra Club's comments follow a narrowing structure: first, they discuss the overall analysis
structure used by IPC. They then focus on errors and biases in IPC's input assumptions within
that analysis structure. Next, they specifically focus on the economics of the Bridger plant, and
discuss how the IRP mischaracterizes Bridger's economic viability. These comments conclude
by critiquing the risk assessment applied by IPC.
3. TUB IRP,S ANALYSIS STRUCTURE IS FLAwED
The analytical structure underlying IPC's IRP suffers from several major flaws. Most notably,
IPC made little effort to identify a least-cost resource plan, and ultimately selected a portfolio
that would violate current laws and regulations.
3.1 Lack of portfolio optimization reduces rigor, transparency, and usefulness of IRP
analysis
Portfolio design is a criticalcomponent of any IRP analysis. The portfolio construction process
establishes the universe of future resource decisions that are assessed meaningfully by the utility.
Ensuring selection of a least-cost, least-risk plan typically requires that a utility consider as full a
range of viable resource actions as possible. The most common and rigorous way of achieving
SIERRA CLUB COMMENTS November 22,2017
J
this is through the use of an industry-standard capacity €Xpansisll optimization model.It is
therefore conceming that IPC did oot make any use of capacity expansion modeling in its 2017
IRP.
IPC states that it "designed the portfolio Flgure l. Portfollos ln the IPC 2017IRP
analysis for the 2017 IRP with the objective of (ercerpted from Teble 93 h 20f7IRP)
informing the IRP's Action Plan with respect to portro,oDer.tb
two key resource actions: (l) SCR investnents
required for Jim Bridger Units I and,Zby 2022 -Bddsgr
atd2Lll,respectively, and (2) the B2H Portloro portfolo D,escrtpuon B2H n?rffit
transmission line." l Specifi cally, "lhe portfolio
design consisted of fou Jim Bridger SCR
investment scenarios, with three resource
portfolios formulated within each scenario,
resulting in 12 resotuce portfolios."2 fPC refers
to this portfolio design approach as a "factorial
experimental desigur," and characterizes it as
approximating a "contolled experiment" that
addresses the two questions of u&ether to
refrofit Bridger Units I and 2 with SCR or retire
them early, and whether or not to invest in
B2H.3 The combination of these two sets of
decisions are developed into the 12 different
portfolios described in Figrue l.
IPC's decisions to evaluate whether to retofit
or retire Bridger Units I atdZ, and whether to
invest in B2H, are laudable. These are the sorts
of major, discrete investuent choices that
justifu focused analysis. IPC chose one
Pl SCR hvest. B2H. recips r'
P2 SCR hveat, DR, recipe,
solar
P3 SCR hvcst. DR recips,cccr
(t)(2t (3)(1)
P4
P5
Brilger retre ln24 & E,
B2H, r€cir6
Bndg€r retir" n24&8,
DR, rc<rpc, solc
PO Brklger rctire in24&8,
DR, rccipo, CCCT
Pl Brilger retire in 28 & ?, r' J
B2H, recps, CCCT
P8
P9
BriJger retire in 28 & 32,
DR, rccips, sola, CCCT
Briigcr retire in 28 & 32,
DR. rccips, CCCT
P10
P11
BrkJger retire in2'l &2,.
B2H, recir
Brklgcr rc[irc rn.21 &2..
DR, recip, solar
P12 Briclgcr retire in21 & 2,
DR. recips, CCCT
reasonable way to begin such an analysis - constnrcting alternative portfolios rmder which the
Bridger retirement decision and the B2H investment decision are manually set to the different
alternatives trnder consideration- However, IPC erred when it decided to manually select not just
these two major investnent decisions, brutt every resource itruestntent decision in every portfolio
for the nat 20 years.a
4
SIERRA CLUB COMMENTS November 22,2017
I IPc 2otz IRP, p. 97.
2Id.
t Id.
t See PC Response to Sierra Club's Data Rerpest No. l-4 in Onegm Public Utilities Commission @UC) Docket
No. LtC 68 (verifring ttat *capacitv expansiq modeling was not used to determine the oortfotios'1. Throushout
There are two core problems with IPC's choice to model only portfolios that it had determined
entirely manually, without the aid of a capacity expansion model. First, IPC's choice results in a
plan that is not demonstrably least-cost or least-risk. Second, IPC's modeling construct fails to
adequately address the key questions identified by the Company as the focus of this IRP.
The Commission's Order 33441 in the IPC 2015 IRP proceeding clarifies expectations for IRP
submissions in Idaho, stating that "an IRP is a status report on the utility's ongoing, changing
plans to adequately and reliably service its customers at the lowest system cost and least risk
over the next 20 years."s There is no evidence that any of the portfolios that IPC modeled
constitute a least-cost or least-risk resource plan. Given the variety of resource types available to
IPC and the two-decade length of IPC's modeling period, the number of possible resource
portfolios that would meet IPC's reliability and regulatory constraints could easily number in the
millions. A capacity expansion model is designed to rapidly sort through this enormous range of
possibilities and come up with a least-cost plan that satisfies all system constraints. A human
brain is not so designed. When humans-no matter how well trained and well intentioned-
attempt to arrive at an optimal resource plan, the result is almost certain to be costlier and more
tinged with blas than a modeled, optimized plan.
The impact of IPC's manual resource selection on its IRP conclusions may not be obvious at first
glance, but the distinction between manually selected replacement resources and an optimal
buildout can be substantial. For example, in a recent IRP, Tucson Electric Power Company
(TEP) examined a coal retirement scenario in which coal was replaced exclusively with modular
nuclear reactors.6 TEP's conclusion that coal retirements were not viable because the portfolio
costs were too high had nothing to do with the retirements, and everything to do with the
extraordinary cost of modular nuclear reactors. At a lesser, but still relevant scale, IPC's
replacement portfolios may include new resources that are not least-cost expansion or
replacement options. Knowing the difference in cost between IPC's hand-selected options and an
optimal choice is almost impossible.
Parts of IPC's IRP verify that the Company fails to adequately recognize the fundamental
importance of cost in resource planning. At one point, IPC states that the "primary goal of the
IRP is to ensure Idaho Power's system has sufficient resources to reliably serve customer
demand over the 2}-year planning period," leaving out any mention of cost or risk.7 Elsewhere,
IPC affirms that its IRP methodology was "designed to remediate any energy or capacity
these comments, we rely in part on IPC's responses to data requests issued in Oregon PUC Docket LC 68, which
addresses the same IRP at issue here.t Iduho Public Utility Commission (IPUC) Order 3344 I in Case No. IPC-E- I 5- 19, p. I . December 23,2015 .
(Emphasis added).
u tEP 2Ol7lRP, page 276 andTable24, page 283. https://www.tep.com/wo-content/uploads/2016/04/TEP-2017-
I ntegrated-Resource-FNAL-Low-Resolution.pdf.
' tpc zon IRP, p. 3.
SIERRA CLUB COMMENTS November 22,2017
5
deficiency over the planning period."8 This means that IPC did not consider retirements (other
than two of the four Bridger units) or resource acquisition during times of sufficiency, even if
doing so would reduce system costs.
The second problem with IPC's portfolio design construct is that it undercuts IPC's ability to
answer the very questions that this IRP is supposedly designed to address. A core premise of the
IRP is that IPC has isolated the Bridger and B2H investment alternatives in such a way that they
can be fairly compared against each other as if through a "controlled experiment."e
Unfortunately, this premise is plainly false. To understand why, one need only consider the left-
most column of the very first table in the IRP, reproduced below as Table l.l0 From the way that
this table is constructed-and the way the factorial design is discussed throughout the IRP----one
would thinkthat Portfolios 1,4,7, and l0 allhave very similar resource build plans, allof which
are dominated by the B2H project coming online at a fixed date. After all, IPC "emphasizes that
the validity of the factorialdesign relies on by-column and by-row uniformity."ll Yet, the
resource builds across these four portfolios are clearly substantially different from each other. To
take one example, more than 30 percent of new capacity in the preferred Portfolio 7 comes from
a combined-cycle combustion turbine (CCCT), whereas zero CCCT capacity is built in any of
the three other B2H portfolios.'2 To take another example,2l6 MW of reciprocating engine
capacity is built by 2023 in Portfolio 10, whereas Portfolio I includes no new capacity before
2034 other than B2H. '' Eu., the B2H in-service date varies across these portfolios, ranging from
2024 under Portfolio l0 to 2026 under Ponfolios I and 7 .ta
Table 1. IPC "factorial design" portfolio structure
Primary Portfolio Elem€nt{s)
Treatnent of Jim Bridger Units 1 ffid 2 B2H Solar Pv/Natural Gas Natural Gas
lnEt in SCR
Retire Unit 1 in Z)28 and Ljnit 2 in?JJz4
Retire Unit 1 in 2032 and l.rnit 2 in2o,28
Relire Unit 1anzo22.and trlit2 in2IJ,21
Source: IPC 2017 IRP
t rRP, p.4.
n rpc 2or7IRP, p. 97
to Id., p.7.
" 1d.,p.7.
" Id.,pp.99-105.
" Id.
'o Id.
P1
P4
P7
Pl0
72
P5
P8
P11
P3
P6
P9
P12
6
SIERRA CLUB COMMENTS November 22,2017
It is important to emphasize that there is no manual resource selection process that IPC could
have used to adequately "control" for resource build decisions in its assessment of alternative
Bridger retirement dates. The differences in retirement dates necessarily drive differences in the
timing and degree of resource needs. It should be obvious that the best option for replacing
retiring capacity in202l may be very different from the best option for replacing retiring
capacity in2032. The way to deal with these differences is not through a hopeless effort to
manually impose similar-looking resource builds across different contexts. Instead, the
reasonable path involves using an optimization model to determine the least-cost portfolio under
each Bridger retirement scenario. Only once IPC has determined the best it can do under each
Bridger retirement alternative (and each B2H alternative) can it reasonably compare across
alternatives. IPC's failure to even attempt to determine the least-cost plan under each Bridger
retirement scenario greatly reduces the meaningfulness of IPC's comparison of these scenarios.
3.2.IPC's inappropriate application of the Clean Air Act's Regional Haze Rule leads it
to select an unlawful portfolio
The Clean Air Act's Regional Haze program requires states to meet certain visibility milestones
in order to restore air quality in national parks and wilderness areas by 2064. The first aspect of
the program required power plants constructed between 1962 and 1977 to install Best Available
Retrofit Technology (BART) to meet unit-specific emission limits. States, working with utilities,
drafted implementation plans to submit to EPA for approval based on a five-factor analysis.ls
BART retrofits reduce sulfur dioxide (SOz) and oxides of nitrogen (NOx), which are precursors
to visibility- and health-impairing particulates and ozone. In the alternative, the RegionalHaze
program provided states and entities the opportunity to propose emission reduction plans that are
technically shown to be "better than BART," i.e., achieving visibility improvements equal to or
greater than those achievable through strict implementation of BART.
In the 2017 IRP, IPC has presented four compliance pathways for Bridger Units I and 2 under
the RegionalHaze rule: compliance with the rule as promulgated through installation of SCRs in
202112022, or various altemative retirement dates, ranging from 2021 to 2032-just two years
prior to the end of Bridger's depreciable life. IPC provides no basis or explanation for these
alternatives, other than to say that they are intended to "help guide future discussions with the
[Wyoming Department of Environmental Quality] in developing a [State Implementation Plan]
for regional-haze compliance." l6
r5 The five-factor analysis: (l) the costs of compliance; (2) the energy and non-air quality environmental impacts of
compliance; (3) any existing pollution control technology in use at the source; (4) the remaining useful life of the
source; and, (5) the degree of visibility improvement which may reasonably be anticipated from the use of BART.
'u rPC 2or7IRP, p. 83.
7
SIERRA CLUB COMMENTS November 22,2017
IPC's alternatives for the retirement date of Bridger Units I and 2 aim to mimic the regionalhaze
program's "better than BART" approach utilized at the Boardman, Centralia, and San Juan coal-
fired plants-atactic used by PacifiCorp in its 20l7lRP. However, like PacifiCorp's IRP, IPC's
IRP evidences no engagement on the Company's part with the appropriate state air quality
agencies or the U.S. Environmental Protection Agency (EPA) to verify that the range of
retirement dates put forward in the IRP could comply with EPA's technical requirements for
approvable emission limits and control technology.
Better than BART provides utilities with flexibility if they commit to retiring regulated units at a
date certain (Boardman and Centralia) or retire some units at a date certain while installing lesser
controls on other units (the retirement of San Juan2 & 3). In all cases, the EPA-approved
alternative plans achieved the required emission reductions at the affected Class 1 areas.
Like PacifiCorp, IPC has offered an IRP with a range of alternative plans but has not offered any
emissions or visibility analyses to support the viability of these plans. IPC's IRP then selects a
plan in which one Bridger unit retires just two years prior to the end of its depreciable life,
without installing any incremental emissions controls. It is unreasonable to think that such a plan
represents a Better than BART alternative. Instead, it appears to reflect hopeful speculation
regarding the future leniency of regulatory agencies.
A Better than BART alternative requires a careful-and highly technical- assessment of the
visibility implications of foregoing near-term, unit-specific retrofits. The complete line of
evidence provided by IPC that its plans are reasonable is summarized in two statements in
discovery responses that describe an "informal meeting with the Wyoming DEQ [Department of
Environmental Quality]" and no communications with EPA on regional haze compliance
deadlines or options. '' IPC's lack of documentation does not support the concept that anything
aside from compliance with current Regional Haze requirements-as written-is reasonable.
Existing law requires either retrofitting or retiring Bridger Units I and 2 in 2022 and 2021,
respectively.
4. INpUT ASSUMPTIoNS BIASED TOWARD GREATER NEED
IPC understates its near-term energy efficiency potential and baselessly assumes that many of its
wind contracts will not be renewed. For these reasons, IPC's IRP likely exaggerates both the
Company's need for new resources and the value of existing resources such as the Bridgeiunits.
'' IPC Response to Sierra Club Data Request No. l-7(c), Oregon PUC Docket No. LC 68. "ln September 2016,
Idaho Power and PacifiCorp had an informal meeting with the Wyoming DEQ to discuss regional haze compliance
requirements for Bridger Units I and 2. Idaho Power has no written communications or materials resulting from that
meeting or otherwise." IPC Response to Sierra Club Data Request No. l-7(d), Oregon PUC Docket No. LC 68.
"ldaho Power has not had any communication with the U.S. Environmental Protection Agency regarding regional
haze compliance deadlines and options for Bridger units I and 2; therefore, no documents exist."
8
SIERRA CLUB COMMENTS November 22,2017
4.1. IPC understates its energy efficiency potential
IPC's IRP likely substantially understates the potential for energy efficiency to reduce its sales
and peak load. IPC asserts that it "puts 100 percent ofits cost-effective achievable energy
efficiency potential in each portfolio prior to the consideration of any supply-side resources."l8
In other words, IPC uses the same efficiency trajectory in each of its IRP portfolios, and then
asserts that this trajectory constitutes the maximum economically achievable quantity of
efficiency savings. However, IPC's recent experience refutes the idea that the savings assumed
in the IRP constitute the maximum "cost-effbctive achievable" level.
Figure 2 compares IPC's historical efficiency savings levels to the savings levels included in the
IRP. In three of the past five years, including each of the past two, IPC has achieved total
incrementalsavings greaterthan I percentof sales.le IPC's savings levels have increased for
each of the past three years, surpassing 1.2 percent of sales in2016. Nonetheless, IPC forecasts a
drastic drop in its efficiency savings, effective immediately. Each of IPC's scenarios assumes
that total savings will plummet by more than 33 percent from 2016 to 2017, and never again
reach the levels that IPC has consistently hit over the past several years.20 The drop-off is
particularly extreme for residential savings, which are forecasted to decline by about 70 percent
in a single year.
'' IPC Response to Oregon PUC Staff s Data Request No. 12, Oregon PUC Docket No. LC 68
'n U.S. Energy Information Administration (EIA). Form EIA-861. Available at
https://www.eia. gov/electricityidata/eia86 I /index html.
'o IPC 2017 IRP Appendix C - Technical Appendix, pp. 9-10, 67.
9
SIERRA CLUB COMMENTS November 22,2017
Figure 2. Incremental energy efficiency savings as percentage of sales, historical and IPC forecast
--,-,,,,,ib\
0oEa
o
be
6b0c
((lra
(!Uco
Eo)t-(,c
1.6%
1.4%
1.2%
t.0%
0.8%
0.6%
O.4"/"
0.27"
0.0%
att-. rli\at\,
t.r4t
-r
tII
,'u\,
IIII
'.I-ty.-rr'-'a.lit1l1
U
,
c&t
Total
Residentiol2t-t,,
,-''r rn t ur \o r\ I I R N N R X K H N RR 3 ; S g S n 3ooooaoooooooooooooooooooo(\ c.{ (\ r{ c.l c{ c{ f\{ o{ (\ (n r..l c{ (n (n (n a{ .\l .\l (\ c{ .\l (n (\ c..l
Sources: Form EIA-861: IPC 2017 IRP,
Perhaps the forecasted decline in savings would be justified if IPC's current programs were not
cost-effective. But that is clearly not the case. IPC's latest annual review of its demand-side
management programs reports that in 20l6,lPC's energy efficiency portfolio was remarkably
cost-effective, with a benefit-cost ratio greater than 2.5 whether viewed from the utility,
participant, or total resource perspective.'' Only four of IPC's prograrns had a benefit-cost ratio
less than one on any of the three major benefit-cost tests.22 Those four programs contributed less
than 1.5 percent of savings in 201 6.23 lncontrast, the uniformly cost-effective programs
contributed more than 168 GWh of savings in 2016. This is more than 50 GWh greater than the
savings assumed by IPC for 2017, and more than 25 GWh greater than the savings assumed by
IPC in any single future year.'o
Other justifications offered by IPC for the decline in projected savings are unconvincing. IPC
attributes lower forecasts of cost-effective savings to lower alternative resource costs and the
impact of the Energy Independence and Security Act (EISA) on lighting standards.25 But natural
2t IPC 2Ol7 tRP Appendix B - Demand-Side Managem ent 2016 Annual Report, p. 27.
" Id. Those programs include the Fridge and Freezer Recycling Program, Home Improvement Program,
Weatherization Assistance for Qualified Customers, and Weatherization Solutions for Eligible Customers.
" IPC 2Ol7 IRP Appendix B - Demand-Side Management 2016 Annual Report, p. 31.
'o IPC 2Ol7 IRP Appendix C - Technical Appendix, p. 67.
" IPC Response to Oregon PUC Staff s Data Request No. 14, Oregon PUC Docket No. LC 68.
SIERRA CLUB COMMENTS
l0
November 22,2017
gas prices, a primary driver of costs avoided by efficiency programs, have been consistently
higher in 2017 thanthey were in 2016, when IPC's efficiency programs prospered.26 And the
next major change in the stringency of EISA lighting standards will not come until lanuary 2020,
and therefore cannot explain such a sharp decrease in savings between 2016 and 20fi .27
Furthermore, while the EISA standards may reduce the level of savings that IPC's programs can
claim responsibility for, they will only improve the efficiency of electricity usage within IPC's
service territory. It is unclear whether IPC's load forecast captures this effect.
IPC's energy efficiency forecast is ultimately based on a potential study conducted on its behalf
by the Applied Energy Group (AEG). As in its previous IRP, IPC relies on AEG's estimate of
"achievable potential."28 Ho*ever, evidence from the past two years indicates that AEG's
"achievable potential" estimates tend to greatly understate the cost-effective savings that IPC can
actually achieve. The 201 5 version of AEG's potential study estimated that IPC's "achievable
potential" was limited to 99 GWh in 2015, or 0.7 percent of sales.2e In fact, IPC ended up
achieving 163 GWh of savings, or I .1 percent of sales in 2015, before going on to achieve l7l
GWh of savings in 2016.30 Figure 3 shows that these actual achieved savings levels are very
similar to the values the 201 5 AEG report identified as "economic potential," reflecting "the
savings when the most efficient cost-effective measures are taken by allcustomers."3l
'u EIA. Henry Hub Natural Gas Spot Price. Available at https://www.eia.eov/dnav/ne/hist/rnewhhdM.htm.
" U.S. Energy Independence and Security Act. Public Law I l0-140. Available at
https://www.eno.gov/fdsys/pke/BILLS-l l0hr6enr/pdf/BILLS-l l0h16enr.pdf; Energy Conservation Program:
Energy Conservation Standards for General Service Lamps; Proposed definition and data availability. October 18,
2016. Available at https://www reeulations.eov/document?D=EERE-2013-BT-STD-005 l-0079.
" rPC 2or7 IRP, p. 50.
"AEG. February 23,2015.Idaho Power Company Energy Efficiency Potential Study. P. 50. Available at
h.ttps://www.idahopower.com/pdfs/EnerevEfficiencv/Reports/2014 DemandSideManaeementPotentialStudv.pdf.
'o EIA. Form EIA-861.
" AEG. February 23,2015.Idaho Power Company Energy Efficiency Potential Study. P. 50.
SIERRA CLUB COMMENTS
lt
November 22,2017
Figure 3. 2015 incremental savings, AEG projected potentials and actual achieved
t80
t60
t40
t20
t00
80
60
40
20
0
"Achievable Potential"Actual Achieved "Economic Potential"
Sources: Form EIA-861: AEG 2015 Potential Studv.
Based on this evidence, we recommend that IPC's IRP analyses assume future energy efficiency
savings that are consistent with its recent savings levels rather than assuming unjustified declines
in savings. At a minimum, IPC must evaluate some scenarios in which its energy efficiency
savings are consistent with "economic potential" estimates, rather than with "achievable
potential" estimates that have consistently proven to be too low.
4.2. IPC assumes certain wind contracts will not be renewed
IPC has adopted an inconsistent approach in its treatment of existing energy contracts. On the
one hand, the Company assumes that its Raft River Geothermal contract, expiring in 2033, is
replaced. On the other hand, with respect to the Elkhorn Valley Wind contract expiring in 2027 ,
"a replacement contract is not contemplated."32 The Company does not explain why one contract
is assumed to be renewed, but the other is explicitly not to be renewed.
IPC takes a similar approach to The Public Utility Regulatory Policies Act (PURPA) wind and
non-wind contracts: "ldaho Power assumes all PURPA contracts, except for wind projects, will
continue to deliver energy throughout the planning period, and the renewal of contracts will be
consistent with PURPA rules and regulations existing at the time the replacement contracts are
" IRp, p. 95
.C
=(J
qooC
(!a
(t,pco)
Eo)L(,c
SIERRA CLUB COMMENTS
t2
November 22,2017
negotiated. Wind contracts are not expected to be renewed."33 IPC includes no information
suggesting that the wind turbines will be decommissioned at the time of the contract expiration,
that the turbine owners have or will have contracts with other parties, or that the wind will cease
to blow. It is certainly true that the wind-powered generators may not choose to sign with IPC,
but that risk exists with the Raft River Geothermal plant and each of the non-wind PURPA
qualifying facilities (QFs) as well.
In its IRP planning, IPC allows approximately 584 MW of wind contracts to expire,3a but
appears to ensure that the remaining 502 MW of contracted renewable-but-not-wind-fueled
generators are not allowed to expire during the planning period.3s IPC's approach is arbitrary and
clearly inappropriate. The correct way for IPC to model the renewal of PURPA contracts is to
assume, barring any specific evidence to the contrary, that the QF with virtually no operating
costs will re-sign a PURPA contract and continue to provide the power to IPC. With respect to
non-QF power purchase agreements, IPC should include the resource in a comprehensive
capacity expansion modeling exercise, and then allow the optimization modelto determine if re-
signing the contract is part of a least-cost, least-risk portfolio.
5. WoRxpapoR ERRoRS BrAS IRP ANALySES rN FAvoR oF JrM BRrocon RETRoFrrs
Sierra Club's review of IPC's workpapers revealed several errors that bias the IRP in favor of the
installation of SCR at Bridger. These simple analytical errors result in IPC understating the cost
of its SCR installation scenarios by tens of millions of dollars.
5.1.IPC mistakenly neglected to account for long-term Bridger fixed costs under SCR
scenarios
In the clearest case of analytical error, IPC did not account for any fixed costs at Bridger Units I
and 2 beyon d 2034.36 This would be reasonable for the three Bridger scenarios in which both
Bridger units retire by 2032. But under the scenario in which IPC installs SCR, the IRP is very
clear that both Bridger units continue to operate through 2036.37 Furthermore, IPC's workpapers
" IRP, p.95.
ra IPC currently has l0l MW with Elkhorn Valley Wind and 55%o x I I l5 MW : 613 MW of QF capacity under
contract. The wind-powered QF capacity total drops to 130 MW by 2033 (lRP, page 95). l0l + 613 - 130 = 584
MW of expired contracts.tt 45Yo x I I l5 N{w : 502 Mw.
16 Attachment 5 to IPC's Response to Sierra Club Data Request No. l-2, cells U7:V 10, Oregon PUC Docket No. LC
68.
" rPC 2or7 IRP, p. 6.
SIERRA CLUB COMTVIENTS
l3
November 22,2017
make plain that IPC's SCR installation scenarios include generation provided by Bridger Units I
and 2 in both 2035 and2036.38
To quantify the magnitude of this error, we made the simplifying assumption that Bridger Units
I andZ would incur the same incremental capital and fixed operational revenue requirements in
2035 and 2036 that IPC expects them to incur in 2034. Under this assumption, the additional
Bridgerfixedcostsin2035and2O36adduptoanetpreSentvalue(NPV)orf.rnis
value may substantially understate the impact of IPC's error on the valuation of the IRP's SCR
retrofit scenarios. This is because the SCR scenarios not only fail to account for any Bridger
fixed costs beyond 2034,but they also assume a rapid tapering of incremental capital investment
in the years leading up to 2034. Under IPC's modeling, incremental investment in Bridger Units
I and2 i.I each year from2029 through 2034, such that by 2034 investment drops to
! p.r."nt b.lo* itr steady-state 2029level.3e It is unlikely that the Bridger units would continue
to be reliably operable for long with such a dwindling level of investment. It is therefore likely
that a full correction to IPC's mistaken modeling of the SCR scenario Bridger retirement dates
would include increased investment in all years from 2030 onward. This would amount to a
value greater than the conservative figure cited above.
5.2. IPC calculation error results in understatement of Portfolio I new resource costs
In a separate analytical error, IPC mistakenly under-counted the cost of the 82H transmission
expenditure in Portfolio l, but not in any other portfolios. In its initialworkpapers, IPC treated
the Portfolio I costs of B2H as commencing in 2027,eventhough B2H is constructed in2026
under this portfolio.a0 After Sierra Club pointed this out in a discovery request, IPC
acknowledged the error and provided updated workpapers.al However, IPC evidently did not
update its IRP, because the Company concluded that the correction 'ohas no impact on the
relative ranking of this resource or the results of the Company's portfolio analysis."42
Nonetheless, IPC confirmed that the correction added $l l.l million to the cost of Portfolio l-
the best-performing of the SCR retrofit portfolios.
18 Attachment 3 to IPC's Response to Sierra Club Data Request No. I -2, tabs "P 1," "P2," and "P3," Oregon PUC
Docket No. LC 68.
'n PROTECTED INFORMATION - Attachment to IPC's Response to Sierra Club Data Request No. l-2, tab "SC 2-
4b - Incremental Invest," Oregon PUC Docket No. LC 68.
a0 Attachment 6 to IPC's Response to Sierra Club Data Request No. l-2, tab "Fixed Cost Streams- by Resource,"
cellsL2LL22, Oregon PUC Docket No. LC 68.
ar Attachment to IPC's Response to Sierra Club Data Request No. 2-7, Oregon PUC Docket No. LC 68.o' IPC's Response to Sierra Club Data Request No. 2-7(a), Oregon PUC Docket No. LC 68.
SIERRA CLUB COMMENTS
t4
November 22,2017
5.3. ItiPV Impect of corrections to IPC worlprper errors
Taken together, conservative corrections to the errors in IPC's workpapers amount to an NPV
ofI in the cost of Portfolio l. This is significant b,_rcause Portfolio I is easilylncrease
the lowest-cost Bridger SCR retofit portfolio that IPC evaluated and it is one of the two lowest-
cost portfolios that cau comply with Clean Air Act requirements. In fact, under the NPV results
presented in the IRP, Portfolio I is shown as having nearly identical total costs as Portfolio l0-
the lowest-cost portfolio in which Bridger Units I and 2 are retired n2022 and,202l.at The IRP
makes it appear that the choice between retrofitting or retiring Bridger Units I and 2 is
essentially a toss-up. However, with the corrections to IFC's workpapers, it becomes evident that
retiring the Bridger urdts in the early 2O2Os is preferable to rehofitting them with SCR.
Confidential Table 2 demonstrates the impact of the worlryaper corrections on the cost
differential between Portfolios I and 10.
Confldentlel Table 2. Net present velue costs of Portfolios I and 10, es llled and wlth con'ections
(mlllion 2015$)
As Filed $6.40r $6.,!01 $0
Bridger Fixed Cost Corrections I
Bridger & B2H Cost Corrections I
Notc: IN 's rwrlqnpers praart NPl ruuhs as in dolbr yar 2O I 7 . Ilortltzrq, Silrrta Club's reyicv of Irc *ortgpas clarly
shows tllot IK dirr,olarr,t all cost stra na h& o 2016t $utr'cs: IPC 2017 IRP, $naptc analysi:s.
6. Lxpur AssLarprroNs ARE coNsrsrEltirly (AI\D trJAccuRATELy) FAvoRABLE To Bnmcrn
TEiITS
The IPC IRP analysis relies on a variety of assumptions that are generally favorable to the Jim
Bridger plant- Most importantly, IPC assumes slow growth in coal prices, rapidly increasi.g
market prices, minimel operational environmental costs, and increasing alternative resource
costs. Together, these assumptions bias IPC's analysis in favor of the prolonged operation of
Bridger Units I and2.
t3 Pc 2ol7IRP, p. lll
l5
SIERRA CLUB COMMENTS November 22,2017
I I
L__l
t__l
6.1. IPC understetes the operetionrl costs essocieted with SCR controls
SCR systems are widely understood to impose costs on an affected plant that go well beyond
weig[ty upfront construction costs. These additional costs include increases in both variable and
fixed operations and maintenance (O&M) expenses.a Yet our review of IPC's workpapers
indicates that the Company did not account for any SCR-related O&M costs in its modeling of
Bridger SCR refiofit scenarios.a5 We therefore relied on technical documents published by the
EPA to estimate the impact of SCR on the costs of Portfolio l, the most cost-effective Bridger
retofit scenario.tr We found that accotmting for the fixed O&M penalties of an SCR increases
the NPV cost of Portfolio I by $2.4 million, and that the SCR variable O&M penalty increases
the NPV cost of Portfolio I by $17.2 million.
Confidential Table 3 shows that, when combined with the corrections to IPC's workpaper elrors,
theinclusionofSCR-relatedo&McostscausesPortfolioltobecomeE-orecostly
than Portfolio 10.
Contrdentlal Teble 3. I\PV of Portfolios I end 10, es filed and with correctlons lncluding SCR costs
(mlllion 2016$)
burca: IPC 2017 IRP, U.S. EPA; $napse anafuis.
6.2. IPC rssumes thet Bridger coal prices will decline efter yeers of increesing
IPC assumes that the price of coal burned at the Bridger plant will decline steadily in the near
term, and that it will remein below curent levels tbroughout the study period. Under IPC's
* See, e.g., U.S. Ewironmeotal Protection Ageocy. Octobcr 2001. Cost of Selectire Catatytic Redtrction (SCR)
Application forNOx Control on Coal-Fired Boilers.ft Att"chment 3 to IPC's Response to Sierra Chrb Data Request No. l-2: PROTECTED INFORMATION -
Attacbm€ot to IPC's Respoose to Sierra Club Data Request No. l-2, tab *SC 2-48 - Existing," Oregoo PUC Docket
No. LC 68.* U.S. EPA. Noreober 2013. Documenation for EPA Base Case v.5.13 Using the Integrated Plmning Modet. Page
5-T. Available at
07/docuoents/<bcumentation for eln base case v.5.13 usinq the inteFated oleoning model.pdf.
SIERRA CLUB COMMENTS
l6
November 22,2017
II L]
II ll L]
tt l__l
forecast, the real price of fuel at Bridger declines at an average rate of! percent per year
between 2017 and 2022. Otrer the two decades from 2016 through 2036, the price of coal
declines at an average rate of! percent per year.aT This projected decline stands in sharp
contast to the historical growth in the price of fuel delivered to Bridger, which averaged 6.6
percent per year over the past decade, and 1.5 percent per year over the past five years.os IPC's
projected fuel price decline is also inconsistent with the U.S. Energy Information
Adminisfration's (EIA) forecasted stability in the price of cod delivered to power plants in the
Mountain regf,on.n'Confidential Figrre 4 compares IPC's projected price of Bridger coal to
altemative projections based on recent trends in Bridger's fuel price and the ggowth rates
projected in EIA's Annual Energy Outlook (AEO) 2017.
Conlidential 4. Alternatlve forecasts
a7 CoNFDEI.rIAL Attachment 2 to IPC's Response to Sierra Club Data RequestNo. l-2. oregon PUC Docket
No. LC 58.{ Attachments 2 and 5 to IPC's Response to Sierra Club Data Request No. l-6, Oregon PUC Docket No. LC 68.
'EIA. Amual Energry Outlook 2017. Enerpy Prices: Nominal: Electric Power: Naturat Gas @egdon: Mountain).
Al'ailable at https://www.eiagodoutlooks/aeoldata/browser/#/?id=3-AEO20l7&reqiorFl-
8&cases=ef no cpp-hiqhgrice^-lowl,ricE hiqhrt-lourrt&starF20l5&€nd=2050&FA&linecharr-*ref
no qll>dl208l5a.I06-3-AEO20l7.l-8-hiqhpricedl208l6a.l06-3-AEO20l7.l-8-lowprice'd120815a.106-3-
AEO20l7.l-8-hi&rtd1208l5e.l06-3-AEO20l7.l-8-lourtdl208l6a.I0G3-AEO20l7.l-8&mapdighprice'
d1208 I 5a.3-3-AEO20l 7. l-8&sourcekry=O.
t7
SIERRA CLUB COMMENTS November 22,2017
The use of a low coalprice forecast clearly favors scenarios in which Bridger continues to
operate longer. Specifically, this effect makes Portfolios I andT (long-term use of Jim Bridger)
look better relative to Portfolio l0 (near-term retirement).
6.3. IPC assumes that market prices will increase rapidly
While IPC expects delivered coal prices to decline, it forecasts a rapid increase in the average
price of energy that it sells on the market. IPC neglected to provide market price assumptions
requested in discovery, and the Company asserted that it could not report energy market
revenues by unit.s0 Nonetheless, we were able to use market sales, purchases, and revenue data
contained within IPC's workpapers to calculate the average annual price of power sold and
purchased by IPC.5l We found that under IPC's modeling of its selected portfolio, the average
real price received by IPC for its energy sales increases at an average annual rate of3.3 percent
between 2017 and2036.
It is unclear what is driving IPC's asserted increased energy prices. Over the study period, IPC
assumed that the price of natural gas delivered to its power plants will increase at an average
annual rate of only 0.5 percent.s2 At the same time, the continued groMh of low-marginal-cost
renewables is likely to suppress power prices. And yet, IPC evidently expects the real price it
receives for market sales to double over the next two decades. Confidential Figure 5 compares
the growth in fuel prices assumed by IPC to the growth in average market energy prices under
Portfolio 7.
to Sierra Club Data Request No. l-2(a); IPC's Response to Sierra Club Data Request No. 2-2, Oregon PUC Docket
No. LC 68.
5r Attachment 3 to IPC's Response to Sierra Club Data Request No. l-2, Oregon PUC Docket No. LC 68.
52 Attachment I to IPC's Response to Sierra Club Data Request No. l-2, Oregon PUC Docket No. LC 68.
SIERRA CLUB COMMENTS
l8
November 22,2017
Confideuflal Flgure 5. IPC forecasted ftrel end energXr prlces relatlve to 2017 Levels, Portfollo 7
It is the combination of the IRP'S assumed decreasing coal prices and increasing market prices,
shown in Confidential Figrre 5, that makes prolonging the life of Bridger appear economically
viable. Figrre 6 compares the average production cost of Bridger Unit I to the average market
energy sales and purchase prices faced by IPC under Portfolio 1.53 This figrre shows that IPC
projects that the average production cost of the Bridger units will be higher than the average
price at which IPC sells and ptuchases energy for each of the next fotr years. This indicates that
for those years, the Bridger units will likely not eam enougft revenues (or offset enough market
purchases) to cover their production costs, to say nsthing of their fixed costs.fl [o othu, words,
Bridger would be losing money in the short term, and [anlring on low coal prices and higfier
energry prices over the long term to enable it to become profitable. Without the rapid recovery of
market prices, Bridger would be an ongoing economic buden to IPC ratepayers.
t3 Attachmeot 3 to IPC's Respoose to Sierra Club Data Request No. l-2, tab "P1". Oregon PUC Docket No. LC 68.
This chart focuses on Portfolio I because it is the looe B2H portfolio that conains Bridger cost and generation data
througfi the end of &e srudy period The productioo cost data for Bridger Unit 2 is nearty ideotical to 6at of BridBer
Utrit l.r It should be noted ftat it is not clear ftom tPC's wortpapers in which hours Bridger produces, and in which hours
IPC purchases and sells eoerg1/ on the martet. It may be that Bridger only produces in the highest-priced hours.
whereas IFC engages wifr the martet in lower-priced hous. Howel'er. i1 is unliks$ that IPC both purchases from
and sells to the martet at low-priced hours.
SIERRA CLUB COMMENTS
l9
November 22,2017
Figure 6. IPC forecasted market energy prices and Bridger production costs, Portfolio I
$70
Morket Soles Price
Morket Purchase Prke
Bridger I
Produaion Cost
N @ O\ O - f{ .,n t l.r,t \O N @ O\ O - C{ f?l t l..t \Od (\{ C.{ C.l C.{ C.l f{ a.t ft a{ ryr fvt (?r rn fv) (Yt rnoooooooooooooooooooor! (\l r{ c,l (\l f.{ N (\l r{ r..{ c{ r.{ f{ N (\{ r{ o{ c! (\t r\t
6.4. Solar and battery storage cost assumptions are inflated
The Company's IRP relies on inflated assumptions regarding the future costs of alternative
resources. This is especially the case for solar and battery storage resources. IPC's estimates of
the current unsubsidized costs of these resources appear to be grounded in the widely respected
Lazardreports.s5 But, as IPC itself states, the current costs of alternative resources have liule
impact on the IRP, since none of IPC's portfolios include the near-term procurement of new
resources.56 What most matters in the context of the IRP are thefuture costs of alternative
resources. IPC's efforts to accurately model these future costs are not adequate.
IPC's workpapers show that the Company has assumed that the levelized cost of every new
resource technology under consideration will increase at an annual nominal inflation rate of 2.1
percent every year between20lT and2036.s1This is equivalent to assuming that allresource
costs will stay flat in realterms. Such an assumption may be reasonable for certain mature
technologies that are no longer undergoing major improvements. However, it is completely
unreasonable to assume that the costs of emerging technologies will increase in this way.
'5 IpC 2017 IRP, pp. 35, 89; IPC Response to Staff Data Request No. 59, Oregon PUC Docket No. LC 68.
s6 See IPC Response to Sierra Club Data Request No. I - I I , Oregon PUC Docket No. LC 68.
57 Attachment 6 to IPC Response to Sierra Club Data Request No. l-2, Oregon PUC Docket No. LC 68.
$60
$s0
$40
$30
$20
$10
$0
E
=z
G
+J6oU
OJU'tr(L
Ec
troz
Sources: IPC 2017 IRP ll/orkpapers.
SIERRA CLUB COMMENTS
20
November 22,2017
The recent dramatic declines in the cost of solar resources demonstrate the fallacy of IPC's cost
inflation assumptions. The very Lazard report cited by IPC shows that the unsubsidized levelized
cost of utility-scale solar has declined by 85 percent over the past seven years.ts While the rate of
that decline has diminished somewhat over time, utility-scale solar has nonetheless continued to
get cheaper each year. Yet tPC ignores this evidence in assuming that solar costs will transition
from their trajectory of decline toward one of steady increase, starting this very year. Figure 7
compares historicaland IPC forecasted levelized solar costs, shown in terms of percentage
difference from nominal20lT levels. Under IPC's unjustified assumption of increasing costs, the
unsubsidized levelized cost of solar would increase l3 percent between now and 2023, the first
year in which solar is procured under any of the IRP portfolios.se
Figure 7. Utility-scale solar levelized costs relative to 2017 levels, historical and IPC forecast
16ff/"
140%
120%
100%
N%
60%
40%
20%
OYo
Historical
'.'"o2'-::
t'',.olt
.-r'4 t''r'o F- I I R N N R N K th R R 3 ; S B H A Hoooooo oo o oc>o oooooo oao oo oof\l r! C.,l C.{ C.{ (\{ N d C! c\{ f{ (! C.l C.{ r.{ C.l C.{ C{ C.l C\{ c\{ C! C{ Ct c\{
Sources: IPC 2017 IRP Workpapers; Lazard.
IPC further erroneously overstates the future cost of solar resources by assuming that the solar
investment tax credit (lTC) will have fully expired by the time that IPC would build any new
solar resourc"t.uo While it is true that the ITC will be phased down between now and2023,the
tax credit is currently slated to remain at a level of l0 percent for all years from 2022 onwards.6l
s8 Lazard. December 2016.Levelized Cost of Energy Analysis - Version 10.0. P. 10.t' tPC 2ot7 IRP, pp. 99-105.
uo IPC Response to Sierra Club Data Request No. l-l l, Oregon PUC Docket No. LC 68.u' NC Clean Energy Technology Center. February 2017 . Database of State Incentives for Renewables and
Efficiency: Business Energy Investment Tax Credit (lTC). http://programs.dsireusa.ore/svsten/proeram/detail/658.
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bs
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oJ
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Furthermore, the solar ITC is based on the year in which project construction starts, rather than
on the in-service date. If IPC was to begin construction in 2021 on solar projects used to meet
resource needs in2023, it would benefit from a 22 percenttax credit.62
IPC's assumed future costs of battery storage are likely even more inflated than its solar cost
assumptions. This is because most battery storage technologies remain relatively nascent, with
major cost efficiency improvements likely stillto come. Lazard is one of many industry
observers that expects battery costs to decline steadily over the coming years. The Lazard report
cited in support of IPC's battery cost assumptions projects that the cost of zinc batteries will
decline at a rate of 8 percent per year over the next five years, and that the cost of lithium-energy
batteries will drop by I I percent per year.u3 In spite of this, IPC assumes that the costs of each of
these technologies will increaseby 2.1percent per year (see Figure 8). While none of IPC's
manually selected portfolios appear to include battery storage, a proper IRP analysis would
include storage as one selectable option. It would then incorporate reasonable assumptions about
the future costs of battery technologies.
Figure 8. Battery storage levelized costs relative to 2017 levels, Lazard and IPC projections
70%
to%lPC, oll botteries
-lu/"
-zff/"
Lazor d, lithiu m-energy
Lazord,zinc
Lozord,ltthium-power4V"20|7 2018
Sources: IPC 2017 IRP ll/orkpapers; Lazard.
20 t9 2020 2021
7. HIsTony AND NEAR-TERM MODELTNG INDICATE BNIOCNR IS NOT ECONOMIC
u2 Id.u'Lazard. December 2016.Levelized Cost of Storage - Version 2.0.P.20.
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The Jim Bridger coal plant represents the largest single power plant on IPC's system. With a
one-third ownership share, IPC controls770.5 MW (gross) at Jim Bridger, or 2l percent of IPC's
capacity.64
In 201 5 and 2016,ldaho Power Company and partner PacifiCorp finished the installation of SCR
equipment at Bridger Units 3 and 4 to meet obligations under the federal Clean Air Act's
Regional Haze Rule. Units I and 2 must meet2022 and 2021 deadlines for the installation of
SCR under the same rule. While not active in IPC's dockets reviewing the decision to install
SCR at Units 3 and 4, Sierra Club has been a very active stakeholder and intervenor in the
economic assessment of Jim Bridger from PacifiCorp's perspective. We have engaged in IRPs
since 201 1, the 2012 Bridger SCR preapproval cases before the Utah and Wyoming
commissions, and a2016 rate case before the Washington Utilities and Transport Commissions
(wurc).
On December 2,2013, the Idaho Public Utility Commission granted CPCN to Idaho Power
Company to install the SCRs at Bridger Units 3 & 4, but admonished that the Company should
continuously assess the economics of the decision stating:
...all parties, including Idaho Power, acknowledge that the future of coal is
uncertain. Additional future environmental regulations are likely. 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
analyzing the 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 altematives to the
Bridger Units 3 and 4 upgrades become available.6s
The Company did not return to the Commission, even though viable alternatives to the Bridger
Units 3 and 4 upgrades became available. In a recent prudence review in Washington (WUTC
UE-t52253), the Commission agreed with Sierra Club that Bridger's owners (who also own the
captive coal mine) had been privy to a forecast of substantially higher coal prices prior to the
Company's finalization of the SCR contract for Bridger Units 3 and 4 in December 2013, and
that such higher prices had potentially rendered the decision to retrofit imprudent. WUTC
subsequently disallowed PacifiCorp's return on investment from the SCR.66 It is notable that the
WUTC case established that Bridger's owners had substantial new data on the relative costs of
coal at Bridger prior to this Commission's order granting a CPCN and requiring continuous
uo IPC2017IRP Appendix C, pp. I I0-I I L
6s lpUC Order 32929 in Case No. IPC-E-13-16. Page 3. December 2,2013.
66 Washington Utilities and Transport Commission Docket UE-152253. Order l2
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analysis (December 2013), and had clear information counter-indicating against the project prior
to the Commission's final order on March 2014, which reemphasized the need for continuous
review.67
Since the Company's ill-fated decision to proceed despite the depleted economic condition of
Bridger, gas prices have remained depressed, and market prices have declined substantially-a
function of both low gas prices and a blossoming of low-cost renewable energy across the
Northwest. Coal prices at the Bridger mine have increased substantially, and the Bridger plant is
increasingly marginal. This is demonstrated by the collapsing capacity factor of the Bridger
plant, and IPC's estimated reduction in capacity factor in the next few years (estimated at about
I percent in IPC's Aurora modeling for 2018-2020).68
Cetting the future right for Jim Bridger should be a critical part of IPC's planning, and yet the
Company has provided an erroneous, misleading, and incomplete analysis of the Bridger plant in
this IRP. This analysis leaves the casual reader of the IRP with the distinct impression that Jim
Bridger would be economic, if only IPC weren't required to install SCRs in 202112022. [n fact,
Bridger is uneconomic irrespective of the disposition of the SCRs, an outcome shown decisively
by IPC's own modeling.
We find evidence that this Commission's explicit requirements for continuous review of the
economic status of Bridger Units 3 and 4 were not followed. The deep evidentiary record in
Washington UTC's review of the SCR decision at Bridger Units 3 and 4 indicates that there was
substantial new information available to both PacifiCorp and IPC regarding the economic
viability of Bridger prior to and during the contracting for the SCRs. Much of the information
was available well before the Commission's approval order in December, and all of the new
information was available to the utilities before this Commission's final order in March 2014.ln
violation of both orders'requirements, IPC failed to present any new analyses to this
Commission.
We recommend that the Commission consider revisiting its requirements to IPC under Orders
32929 and32996 to determine if IPC followed the Commission's guidance on continuous
evaluation, and if IPC maintained an appropriately complete evidentiary record before this
Commission.
7.1. IPC did not examine the economics of Jim Bridger Units 3 and 4
67 IpUC Order 32996 in Case No. IPC-E-13-16. Page 2. March l4,2014. "ldaho Power was put on notice that it
needs to remain vigilant about whether proceeding with the upgrades to Units 3 and 4 is the best alternative for
customers and the Company."
68 Attachment 3 to IPC's Response to Sierra Club Data Request No. l-2, Oregon PUC Docket No. LC 68.
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Irrespective of IPC's failure to return to this Commission with new information prior to and
during the construction of the SCRs, IPC's 2017 IRP continues to failto examine the value of
Bridger Units 3 and 4. Presumably, the Company determined that an examination of these units
was not warranted because these units do not have impending major capital requirements. This is
a first-order error. Coal plants in the United States today are often simply marginal----or fully
uneconomic-due to persistently low power prices and the cost of maintaining large thermal
generation. Navajo, San Juan, Four Corners, Big Brown, and Monticello are allexamples of very
recently announced large coal-fired power plant retirements for units that are not facing
immediate compliance obligations or capital requirements. Instead, the owners and operators of
those units simply determined that the continued expenditures required to keep them operational
were not worth it.
Sierra Club's recent examination of PacifiCorp's 201 7 IRP revealed that Bridger Units 3 and 4
were amongst the least economic in that utility's fleet. Like IPC, PacifiCorp decided not to even
assess Bridger Units 3 and 4. However, unlike IPC, PacifiCorp provided suffrcient information
on fixed costs to allow for an independent evaluation. IPC, on the other hand, simply assumes
the ongoing operation of these units, with the incumbent assumption that the fixed costs of
Bridger Units 3 and 4 are unavoidable and therefore not worthy of reporting or modeling.
It is neither reasonable nor prudent for IPC to not assess Bridger Units 3 and 4 as part of this
IRP. Together these two units incur millions of dollars in capital expenses each year, are
instrumental in the future of the jointly owned (and capital intensive) Bridger Coal Mine, and
comprise l0 percent of [PC's generation fleet.
Without an examination of Units 3 and 4, the IPC 2017 IRP did not balance cost and risk, or
approach any form of least-cost planning.
7.2. Jim Bridger will continue to be uneconomic on a going forward basis
According to the IRP, it is more economic to retain Bridger Units I and 2 through2032 and2028
(without an SCR) than to retire the units earlier (without an SCR). The implication of this is that
if Bridger can avoid an SCR through negotiations with EPA, the units will remain economic.
This is definitively notthe case; it is based on an inaccurate economic analysis of Bridger's
viability, i.e., the flawed analytical structure and erroneous model inputs discussed previously.
Our review of the economics of Jim Bridger shows that the plant is highly likely to incur a net
loss-under all circumstances-for IPC ratepayers.
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Confidential Fignre 9, below, shows a cash flow of costs at Bridger Unit I derived from
workpapers provided in discovery.o This figure shows expendihues on fuel, O&M, and
amortized capital in Portfolio l, where Bridger Unit I contimres to operate tbrougfi 2036 (thougfi
IPC erroneously does not accotrnt for any fixed costs in 2035 or 2O36, as discussed previously).
The lipure shows the all-in cost of Bridger against the highest possible cost of market enerery,
the replacement resource for incremental energy reductions. The cash flow assessment shows
that if Jim Bridger were a merchant generator, it would effectively make back just enough on the
market to cover the cost of fuel-and lose substantial fixed costs. From 2017 to 2021, Bridger
Unit I inctus
losses rise to
a net loss ofabout per year. After the installation of the SC& annual
per year. Overall, relative to the market, Bridger Unit I
loses (NPV,2016$) or
Confldentlet Flgure 9. Brldger Unlt I forwmd-golng costs compered to mrrket cost, Portfolio I
The fact that Jim Bridger is a rate-regulated resotuce rather than a market-based generator is
relatively immaterial: the utility has an obligation to serve energy with the lowest reasonable
costs to its ratepayers. If IPC predicted that Bridger would eventually break out of its loss steak
through an expected change in circumstances, the Compauy might be able to show that
ratepayers are best served by holding onto the option of the resource. This is not the case.
Bridger does not recover under any of the cilsnmsfssses IPC itself modeled.
c Attachments to tPC Respooscs to Siena Chrb Ihta Reqrrcst No. l-2, 2-4O), 2a(c), Oregm PUC Docket No. LC
68.
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Confidential Figrue 10, below, shows the same visualization of a cash-flow analysis, but for
Portfolio 7. In this portfolio, Bridger Utrit I is maintained through 2032 atdno SCR is installed.
There are two notable feattues of this graphic relative to Confidential Figrre 9, above, aside from
the shorter lifespan. First, Bridger Unit I does not inctu the costs of an SCR, resulting in a
substantially smaller capital cost steam (the light blue wedge). Secondly, the fixed O&M steam
is substantially smaller than what is shown in Portfolio l. As a result of these two featues, the
all-in cost of Bridger Unit I is closer to---although still above-market rates until2028. From
2028 to 2032,Bridger appears less expensive than the market, and thus makes a small amount of
margin in that time.
Confldentlal Flgure 10. Brldger Unlt I forwerd-golng costs compered to market cost, Portfollo 7
The smaller fixed O&M for Bridger Units t & 2 n Portfolio 7 is atnost certainly an error, as
shown in Confidential Figue I l, below. The substantially smaller fixed costs in Portfolio 7 are
inconsistent with all other scenarios modeled, and lower than PacifiCorp projections. It is clear
that IPC expects the fixed O&M costs of each Bridger unit to remain the same across all Bridger
retirement scenarios for all years in which that unit continues to operate. It is rmclear how the
Portfolio 7 fixed O&M eror came about, but it appears to be a transcription error. While we
have determined that this error likely did not impact Portfolio selection, it absolutely impacts the
valuation of the Bridger trnits. Overall, the erroneous fixed O&M costs of Portfolio 7 appear to
reduce the forward-looking costs of Bridger Units I and 2 by orerf NPv. In the
sections below, we describe our corrections for this error.
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Confidential Figure 11. Bridger Unit 1 fixed O&M for Portfolios 1, 4, 10 and 7
Confidential Figure 12, below, shows the cumulative present worth (CPW) of Bridger Unit I as
modeled by IPC in "preferred" Portfolio 7 relative to the highest possible cost of energy modeled
by IPC. The black line ("lPC Base") represents the accumulating value (or loss, negative) of
Bridger Unit I through 2032.The steady drop in the black line through 2028 is indicative of
ongoing losses relative to the market. The slight uptick near the end represents a small
improvement relative to market in the last years of Bridger's life. Overall, IPC would estimate a
market value for Bridger Unit I of about (NPV, 201 6$) orltW. Correcting
Bridger's fixed O&M values to be consistent with all other portfolios results in the lighter blue
line marked "Corrected FOM," and a net liability ofI.
We demonstrated in Section 6.2 that IPC predicts coal prices will drop in real terms from 2017
through 2034, a prediction completely antithetical to observed trends at Jim Bridger over the past
decade. In addition, IPC estimated that variable O&M costs at Bridger will drop UVI
ftom2ol7 to 2022 1rromfroI), an assumption that is inconsistent *ith th.
operations of coal plants throughout the United States. Simply holding the cost of coal and
variable O&M costs steady at2017 levels (plus inflation) has a dramatic impact on the viability
of Bridger Unit I in this same scenario. Accounting for both the corrected fixed O&M and
flattened fuel and variable o&M costs, Bridger Unit I emerges ur ul liability
through 2032,losing value each and every year. The story at Bridger Unit2 is no different, as
shown in Confidential Figure 13, below.
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Conf,dential Flgure 12. Value of Brldger Unlt I under Portfollo 7, as modeled end with varlous
corrections
Conf,dentlel Flgure 13. Value of Brldger Unlt 2 under Portfollo 7, rs modeled aud wlth varlous
corrections
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November 22,2017SIERRA CLUB COMMENTS
While we believe these fuel and variable O&M corrections to be valid, we do not rely on those
adjustments for our basic point. The fixed O&M schedule under Portfolio 7 is clearly an error.
Once this schedule is made consistent with fixed O&M costs in Portfolio l, the IRP results are
much clearer-and far more intuitive. Jim Bridger loses money each and every year that it is
online-irrespective of whether it has an SCR obligation or not.
Confidential Figure 14, below, shows the value streams of Bridger Unit I under Portfolios 1,4,
7, and l0-the various retirement options in which B2H is constructed. The Portfolio I results
indicate that if, in fact, Bridger Unit I were required to obtain an SCR, the unit would ultimately
cost ratepayers more than above market energy procurement costs (conservatively)
However, the three yellow lines are yet more useful. The close trajectories of Portfolios l0
(2022), 4 (2028) and 7 (2032) show that Bridger will continue to cost ratepayers-and the longer
the units remain online, the deeper the obligations become. This means that solutions not
modeled by IPC-including a 201 8 or 2020 retirement or disentanglement from Bridger-would
have resulted in substantial savings relative to the potential costs still yet to be incurred.
These results show that Ponfolio 7 is not the least-cost or least-risk resource plan available to
IPC, and of the portfolios modeled by IPC, Portfolio l0 should result in the least cost to
consumers.
Confidential Figure l5 shows nearly identical results for Bridger Unit 2
Confidential Figure 14. Value of Bridger Unit I under various portfolios, with correction to fixed
O&M in Portfolio 7
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Confidentlal Flgure 15. Velue of Brldger Uilt 2 under varlous portfollos, wlth correctlon to flxed
O&M ln Portfolio 7
8. IPC nrsr nx.l,rysEs ARE p(x)Rr,y Appr rFn
Finally, the comments below ad&ess IPC's risk analysis stnrchre. As an initial matter, a risk
analysis is a method of testing and shessing a model result. In this case, it tests the different
resource portfolios created by IPC. However, if those portfolios are not optimal, or are based on
biased or incorrect input assumptions or analysis sb:ncttues, the risk analysis ;s pganingless.
Nonetheless, these comments can still inform futtre risk analyses performed by IPC.
The Commission's IRP requirements explicitly call for utilities "to demonstrate the risks
associated with various proposed responses"To by evaluating the relevant uncertainties at
reasonable bounds. At other utilities, risk analyses are often nm through a stochastic, or
*sdsmized modeling framework. They can help a utility rmderstand the risks associated with
different resource portfolios. An effective stochastic analysis (l) identifies key inputs, (2)
identifies the statistical properties those inputs will exhibit in fuhre years, and (3) analyzes the
levelized cost of various portfolio strategies under a variety of outcomes for the key inputs.
IPC identifies three variables for stochastic analysis "based on the degree to which there is
uncertainty regarding their forecasts and the degree to which they can affect the analysis results
'0 Ordo 222gg ltCase U-150G165. Page 11. January 27. lgSg
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(i.e., portfolio costs):" natural gas price, customer load, and hydroelectric variability. Tl IPC did
not identify coalprices as a variable worthy of stochastic analysis.
8.1. Natural gas prices
IPC models natural gas prices as a "log-normal distribution adjusted upward from the planning
case gas price forecast."72 A log-normal distribution may be an appropriate distribution for
natural gas prices, and the year-to-year variability value of 0.6 may also be reasonable (although
historical values in the pre-hydrofrackin g 1997-2007 era may fail to correctly capture year-to-
year variation). However, an appropriate stochastic analysis of natural gas price would allow for
prices to climb or fall. Rather than capture results associated with unexpectedly low gas prices as
well as unexpectedly high prices, the IPC stochastic analysis has "natural gas prices adjusted
upward from the planning case to capture upward risk in natural gas prices."73 This technique
captures the downside risk of building more natural gas generation, but it makes no attempt to
quantify the risk that a decision to continue operating the Bridger plant will be a poor one due to
unexpectedly low gas prices. By introducing statistical bias to the distribution function, IPC fails
to correctly measure risk. The correct way to model natural gas prices in a stochastic analysis is
to select a distribution wherein the median aligns with the forecasted gas price trajectory.
8.2. Customer load
IPC modeled customer load with a normal distribution, and with the distribution median aligned
with the planning case load forecast. IPC implemented the stochastic analysis with randomly
sampled customer consumption in 201 7 , but it then applied an identical growth rate for each of
the 100 samples for years 2018-2036. It is an absurd notion that on the one hand IPC cannot
predict next year's load to within 30 percent, but on the other hand it is absolutely certain of the
year-on-year growth for each year between 2018 and2036. There is considerable risk associated
with customer load in future years, and that risk is highly dependent on the load growth rate.
This is a value which IPC makes no attempt to model stochastically. The correct way to model
customer load growth is similar to how IPC modeled both natural gas prices and hydroelectric
variability-with random walks in which both (a) there is year-to-year variation, the result of
random fluctuations of weather and other factors, and (b) there is systemic variation of the
trajectory of the random walk, to represent the uncertainty surrounding the rate at which long-
term load is growing. By not taking a stochastic approach to year-on-year load growth, IPC has
failed to correctly model the risk associated with its load growth forecasting.
'' IRP, p. l 14.
'2 rRP, p. I14.
" IRP, p. I14.
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8.3. Coal prices
Inexplicably, IPC did not include the uncertainty of coalprices in its stochastic analysis. Jim
Bridger is supplied by Black Butte and Bridger Mine. Historically, Black Butte has served
approximately one-third of Bridger's requirements, while Bridger Mine has served the remainder
from an older surface mine and a newer underground mine. Bridger Mine is owned by Bridger
Coal Company, a wholly owned subsidiary of a PacifiCorp and IPC partnership. Despite being a
mine-mouth facility with regulated utility ownership, the cost of coal from Bridger Mine has
been anything but predictable over the last decade, as shown in Figure 16, below.Ta Coal quality
problems at the underground mine have led to a continuous re-allocation and long-term planning
process. In March 2017,PacifiCorp reported that costs at Bridger Mine had increased by $32.7
million due to lower fuel quality, reduced production, and the abandonment of an expensive
longwall miner, causing another delay in mining activities.Ts Overall, the cost of coal procured
for the Bridger plant has varied substantially over time.
Figure 16. Coal deliveries to Jim Bridger plant
4.50
4.m
3.v)
3.m
2.50
7.0
1.50
1.00
0.50
a
.oo
o O--
Io
==<tl
o()
EoU
a
a\..G.o a
a aa .'\''l.*or'-.crari.'t o
o
f,t'-td.aEU.aa
a Bridger Coal Company
* Black Butte And Leucite Hills
2m1 2009 20t7 2013 2015 2017 20t9
Source: EIA Form 923, compiled 2008-2017.
" Figure maps each coal delivery reported to EIA Form 923.The size of each dot is proportional to the quantity
(tons) of fuel delivered. Note that since 20 l0 Bridger Coal Company reports the all-in cost of coal, equivalent to the
wholesale cost ofthe coal, rather thanjust the "cash cost" (i.e. not including capital).
75 See Idaho Docket PAC-E- I 7-02, Direct Testimony of Michael Wilding, page I 8 at 23 to page I 9 at 4 and page 20
at2-6.March 20l7. "During mining operations at the end of December 2015,a section of panels in the Joy
Longwall became stuck in soft claystone material due to difficult geological conditions. Significant efforts were
made by BCC to retum the Joy Longwall to operations in 2016; however, due to unsafe working conditions the Joy
Longwall was ultimately abandoned."
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aa
Q.. ttd
IPC should have included coal prices in its stochastic analysis. The correct way to model the coal
price stochasticity is very similar to the correct way to model gas price stochasticity-with a log-
normal or similar distribution wherein the median of the distribution aligns with the forecasted
coal price trajectory. The variability of the price should reflect allof the risks associated with the
mine detailed above.
8.4. Lack of portfolio response to stochastic variation
In calculating the costs of each of the l2 studied capacity buildouts in each of 100 different
iterations, IPC locks in the capacity procurement-even in the latter years. While this preserves
IPC's ability to consistently compare outcomes across the same set of portfolios, the outcomes it
compares are not useful. For example, in cases where the stochastic iteration of customer load
grows more slowly than in the forecast, IPC continues to procure generating assets on the same d
priori schedule, despite those resources no longer meeting a required need. The resulting
comparison informs the reader that one imprudent procurement costs less than another imprudent
procurement. This provides no information about the risks associated with ensuring the ability to
reliably serve customers in a prudent manner. The correct way to implement the stochastic
analysis is to allow a capacity expansion model to select the most cost-effective resources that
ensure reliability in each of the 100 different iterations. The procured portfolios would be
different, which is a sensible result for an experiment where the inputs are altered.
Dated: November 22, 2017 Respectfully submitted,
/s/ Gloria D. Smith
Gloria D. Smith
Managing Attorney
Sierra Club Environmental Law Program
2l0l Webster Street, Suite 1300
Oakland, CA94612
(41s) 977-ss32
gloria. smith@s ierrac lub.org
Attorneyfor Sierua Club
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