20171211Reply Comments - Redacted.pdf

SIffi*.
REOEIVED
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An IDACORP Company
LISA D. NORDSTROM
Lead Counsel
I [e-mail]
December 11,2017
VIA HAND DELIVERY
Diane M. Hanian, Secretary
!daho Public Utilities Commission
472 West Washington
Boise, ldaho 83702
Re: Case No. IPC-E-17-11
2017 lntegrated Resource Plan - ldaho Power Company's Reply Comments
Dear Ms. Hanian
Enclosed for filing in the above matter please find an original and seven (7) copies
of ldaho Power Company's Redacted Reply Comments.
Also enclosed are an original and seven (7) copies of confidential page 40 to the
Reply Comments. PIease handle the confidential information in accordance with the
Protective Agreement executed in this matter.
Very truly yours,
Ua/e@
Lisa D. Nordstrom
LDN:csb
Enclosures
1221 W. ldaho St. (83702)
P.O. Box 70
Boise, lD 83707
LISA D. NORDSTROM (lSB No. 5733)
ldaho Power Company
1221West ldaho Street (83702)
P.O. Box 70
Boise, ldaho 83707
Telephone: [phone]
Facsimile: [phone]
lnord strom@ ida hopower. com
RECEIVED
20110EC I I Pl{ b: Str
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UT ILIT
IDAHO POWER COMPANY'S
REDACTED REPLY COMMENTS
ilto.H*Ffil8r,n*
Attorney for ldaho Power Company
BEFORE THE IDAHO PUBLIC UTIL]TIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S 201 7 INTEGRATED
RESOURCE PLAN
CASE NO. IPC-E-17.11
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TABLE OF CONTENTS
I. INTRODUCTION
II. PORTFOLIO DESIGN
A. The 2017 IRP Allows for Effective Comparison of the Least-Cost Resources. ..
1. Portfolio Modeling Reasonably Focused on Major Resource Decisions. ......
2 The Company's Portfolios Reasonably Compared the Most Economica!
Resources to Guide Key Resource Decisions..........
3 Additional Tipping Point Solar Analysis Supports the Company's PortfolioSelections .......................7
B. The Preferred Portfolio is the Least-Cost Option
C. The Preferred Portfolio, Which lncludes Continued Operation of the Bridger
1
4
4
,4
5
10
Units, is Not lllegal.
III. SUPPLY.SIDE RESOURCES
A. Jim Bridger......................
2
1 The Anticipated Retirement Dates for Jim Bridger are Appropriate. ............14
The Jim Bridger Units Remain Economic Resource Options. .....15
12
13
13
24
32
32
35
35
37
41
42
42
43
..27
29
30
Solar PV..........
Energy Storage
Wind
Distributed Generation
IV. DEMAND-SIDE RESOURCES
A. Energy Efficiency.
B
c
D
E
................18
....,,,,.,......20
................21
,.,.........,...22
,,,,,,,,,,,,24
1. Evaluating DSM Based on the Total Cost of Acquisition is Consistent with
Supply-Side Resource Acquisition... .. .....24
2. ldaho Power's Method for Determin
Potential is Reasonable and results
Energy Efficiency.3. ldaho Power Properly Accounts for
New Codes and Standards
ing Energy Efficiency
in Prudent IRP Targets
Energy Savings Due to
:l
4. ldaho Power Has a Robust Portfolio of Energy Efficiency Programs5. ldaho Power Will Work to Ensure Fundamental Consistency
Between Transmission and Distribution ("T&D") Methodologies......
B. Demand Response
V. FORECASTS
Load Forecasts
Natural Gas Price Forecasts.
Coal Price Forecasts
Hydro Electric Forecast. .......
VI. BOARDMAN TO HEMINGWAY.............
A. Transmission and the IRP Process
A
B
c
D
1. ldaho Power's IRP Establishes its Specific Resource Need, but Broader
Regional Planning is Also Legitimately Considered as Part of Need. .........43
2. ldaho Power Seeks to Satisfy the EFSC "Need" by having the Oregon
Commission Acknowledge B2H in the lRP. .................44
B. Resource Need. ...............45
1. B2H is Properly Characterized as a Supply-Side Resource 45
a. B2H Will Meet the Capacity Deficit Present in2026. ..............46
b. ldaho Power's Existing Transmission Capacity Does Not Allow for
Sufficient Imports from the Northwest ...........47
2. B2H Satisfies an ldentified Regional Transmission Need. ...........48
C. Costs. ......49
1. The Costs of 82H Compare Favorably to Competing Resources. ...............49
2. The Contingency Costs lncluded for 82H Reasonably Account for the Risk
of Cost-Overruns. .......52
3. The Costs of B2H are Properly Modeled over the 2O-Year IRP PlanningHorizon. ......53
4. ldaho Power Appropriately Modeled the Energy Costs Associated with
Market Purchases Facilitated by B2H. ........54
D. Market Purchases .............54
1. The Northwest Market Depth is Sufficient to Support the Modeled Imports
Enabled by B2H. .........54
2. The IRP's Forecasted Market Prices Account for Coal Plant Retirements. 59
3. The IRP's Forecasted Market Prices Appropriately Reflect the Relationship
Between Natural Gas and Electric Prices. ...................60
4. B2H is Necessary for the Company to Enter lnto Bilateral Contracts..........62
5. The IRP's Transmission Topology Accurately Reflects the Benefits of B2H.
.62
E. The 2017 IRP Reasonably Accounts for Third-Party Transmission Revenue. .62
VII. RISK ANALYSIS 63
vlil. GoNcLUStoN ......64
I. INTRODUCTION
ldaho Power Company ("ldaho Power" or "Company") respectfully submits these
Reply Comments to the Idaho Public Utilities Commission ("Commission" or "!PUC").
These comments respond to the comments of Staff of the ldaho Public Utilities
Commission ("Staff'), STOP B2H Coalition ("STOP B2H"), Sierra Club, the Renewable
Energy Coalition ("Coalition"), and comments from the public, including the ldaho
Conservation League ("lCL"), Reed Burkholder, and Mike Heckler. lt should be noted
that STOP B2H, Sierra Club, and the Coalition filed the same comments in Oregon
Docket No. LC 68. The Company prepared and provided substantive information in
response to those comments, which were filed with the Public Utility Commission of
Oregon ("OPUC' or "Oregon Commission") on December 8, 2017. Because these
parties have raised the same arguments in ldaho, the Company has provided much of
the same information in these Reply Comments for the benefit of the ldaho
Commission, including the filing of the 2017 IRP Appendix D: B2H Supplement.
Attached hereto as Attachment 1.
ldaho Power requests that the Commission acknowledge the Company's 2017
lntegrated Resource Plan ("lRP"). The IRP satisfies the Commission's procedural and
substantive requirements.l The Company's shortterm action plan and longterm
resource portfolio are supported by robust and comprehensive analysis demonstrating
the reasonableness of the plan. ln addition, this IRP served to inform two key resource
decisions related to the Boardman to Hemingway ("B2H") 500 kilovolt transmission line
and the selective catalytic reduction ('SCR') investments required for Units 1 and 2 ot
1 ln the Matter of the lnvestigation by the ldaho Public Utilities Commission into ldaho Electric
Utility Conservation Standards and Practices, Case No. U-1500-165, Order No.22299 (January 27,
1989). Re Consideration of the Federal Electric Utility Ratemaking Standard Dealing with lntegrated
Resource Planning in PURPA S 111(dX7), Case No. GNR-E-93-03, Order No. 25260 (November 29,
1993). ln the Matter of ldaho Power Company's 2006 lntegrated Resource Plan, Case No. IPC-E-06-24,
Order No. 30317 (May 23, 2007).
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 1
the Jim Bridger coal-fired plant. Based on the outcome of the extensive IRP public
process and the Company's detailed analytics, the preferred portfolio in the 2017 IRP
(portfolio P7) includes the B2H line as a least-cost, least-risk resource, but does not
include installation of SCR at Units 1 and 2 of the Jim Bridger plant. The Idaho
Commission Staff recommends the Commission acknowledge the Company's 2017
lRP, stating "the Company performed sufficient analysis, gave reasonably equal
consideration of supply and demand-side resources, and provided acceptable
opportunities for public input, resulting in an IRP that satisfies the requirements set forth
in Commission Order Nos. 25260 and 22299;'2
The 2017 IRP represents a key milestone in the Company's ongoing efforts to
develop the B2H line. Originally specified as a 285 megawatt ("MW') transmission
capacity resource in the Company's 2006 IRP's preferred resource portfolio, increasing
ldaho Power's connection to the Pacific Northwest power markets, the B2H project has
been a critical component of ldaho Power's preferred portfolios since the 2009 IRP and
has consistently represented the least-cost, least-risk resource for customers. ln the
2017 lRP, the Company's least-cost, least-risk preferred portfolio again includes the
B2H project as a transmission resource. ln its Oregon filing, the Company requests
specific acknowledgement from the Oregon Commission of the decision to continue
permitting activities and, more importantly, to begin preliminary construction activities for
the B2H transmission line. The Company intends to use the acknowledgment of B2H in
the 2017 lRP to support its application before Oregon's Energy Facility Siting Counci!
('EFSC'). Thus, acknowledgment of this IRP is critica! to allow project development to
move fonruard so that the transmission line can be in-service to meet the needs of ldaho
Power's customers.
2 Staff Comments at 14
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS.2
Some lntervenors are critical of aspects of the Company's case supporting
acknowledgment of BzH as the Ieast-cost, least-risk resource. The Company
recognizes preliminary construction activities are expected to occur before the 2019 IRP
is filed. Therefore, concurrent with these Reply Comments, the Company is also filing
an addendum to the 2017 lRP, Appendix D: B2H Supplement, that focuses exclusively
on the B2H line and responds in depth to the concerns raised by parties by providing
additional explanation and analytic support for the reasonableness of the project.
Together with these Reply Comments, the B2H addendum further demonstrates that
the preferred portfolio identified in the 2017 IRP is least-cost, least-risk, and should be
acknowledged.
ln addition to responding to the selection of B2H as a least-cost, least-risk
resource, the Company's Reply Comments address other comments raised by parties.
Staff and lntervenors expressed criticism of the Company's methodology for selecting
resource portfolios for modeling. The Company's portfolio design and analysis in this
IRP was driven by the two key resource decisions at issue-B2H and future required
investment in the Jim Bridger SCRs. The Company specifically tailored its portfolios to
focus on these decisions by evaluating a diverse set of resources prior to designing the
portfolios and selecting the most cost-effective resources that, when combined,
provided an acceptable level of reliability. Although this "pre-screening" resulted in
fewer portfolios than the 2015 IRP, the studied portfolios adequately reflected and
compared the most cost-effective resources and produced results that demonstrate that
constructing the B2H line and not investing in the SCRs for Jim Bridger Units 1 and 2
represents the least-cost, least-risk plan to meet future customer demands.
Finally, in these Reply Comments, ldaho Power addresses concerns over the
Company's modeling of coal plant retirement scenarios, demand-side management
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 3
('DSM') resources, and forecasting methodologies, among other issues. The
Company's coal retirement scenarios reasonably account for existing and expected
environmenta! regulations and market conditions and represent a prudent transition
away from coal. The Company has continued to aggressively pursue DSM resources
and included all cost-effective DSM resources before any other resource. The
Company's forecasting methodologies are consistent with prior lRPs and industry
standards and reflect a reasonable basis for analyzing ldaho Power's future resource
needs. ln sum, these Reply Comments demonstrate that the Company's portfolio
design, modeling, and assumptions are reasonable and produce a preferred portfolio
that is least-cost and least-risk.
II. PORTFOLIO DESIGN
A The 2017 IRP Allows for Effective Comparison of the Least-Cost
Resources.
ldaho Power evaluated twelve resource portfolios, with an emphasis on making
an informed decision concerning the two most significant near-term resource
decisions-whether the B2H line remained least-cost and least-risk, and whether to
invest in SCR systems at Jim Bridger Units 1 and 2. These resources were previously
evaluated as part of the Company's resource portfolios in the 2015 lRP, though neither
the SCRs nor construction of B2H were included in the action plan.
1. Portfolio lllloielinq Reasonably Focused on Maior Resource
Decisions.
Staff expresses concern that the Company's modeled portfolios make this IRP
far less robust than the 2015lRP process.3 ICL is critical of the Company's method for
developing resource portfolios and suggests portfolio optimization as a method for
3 Staff Comments at 3.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 4
developing portfolios.a Sierra Club similarly argues that the Company's portfolio design
is flawed because ldaho Power did not use capacity expansion models.s
The Company appreciates the concerns from Staff, lCL, and Sierra Club, and is
amenable to evaluating capacity expansion modeling and more diverse portfolio
sefections in the 2019 IRP cycle. Nonetheless, the Company believes that its specific
portfolio selection in this IRP was appropriate because it allowed for levelized, dollar-
per-megawatt-hour ('MWh") comparison of the most cost-competitive resources, while
fulfilling the projected capacity deficiencies.
While the Company's modeling did not make use of resource-intensive capacity
expansion modeling, the ldaho Power IRP process included a long-term optimization
('LTO') run using the AURORA model. The LTO run iterates through multiple
generation resource build-outs (not transmission) with the objective of minimizing the
Western Electricity Coordinating Council power supply cost. The LTO run for the 2017
IRP placed no new resources in the ldaho Power bubble over the 2O-year analysis
period. ldaho Power was not satisfied with the expected reliability resulting from the
AURORA LTO for its system and performed the portfolio analysis presented in the 2017
IRP.
2.The Companv's Portfolios Reasonablv Gompared the Most
Economica! Resources to Guide Kev Resource Decisions.
ldaho Power agrees with Sierra Club's characterization of the B2H transmission
line and retrofit investments in Jim Bridger Units 1 and 2 as major and discrete
investment choices deserving focused analysis.6 However, the Company disagrees
with Sierra Club and ICL's comments suggesting that the IRP's portfolio analysis is
a ICL Comments at 13.
5 Sierra Club Comments at 3-4.
6 Sierra Club Comments at 4.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 5
deficient and lacking rigor because of the failure to use capacity expansion modeling.
While the Company is not opposed to investigating capacity expansion modeling, the
portfolio analysis for the 2017 IRP is purposefully focused-as appropriate to guide the
Company's key business judgments. Thus, the Company's lack of capacity expansion
modeling does not undermine the Company's portfolio analysis.
ln the 2017 IRP, the Company's portfolio analysis was limited to only the most
cost-effective resources that, when combined, provided an acceptable level of reliability.
Consequently, many of the potential resources evaluated during the development of the
IRP were not ultimately selected for inclusion in a portfolio. By limiting the resources to
only the most cost-effective options, the Company was able to limit the variables
influencing the SCR and 82H resource evaluation.
ln order to effectively evaluate the Company's key resource decisions, the
portfolios included the following new resource options: transmission, single-axis
tracking solar photovoltaic ("PV'), additional demand response, natural gas
reciprocating engines, and combined-cycle combustion turbine ('CCCT"). The set of
resource options analyzed for the IRP included varying levels of technological maturity
and market penetration, allowing for a diverse resource set. The resource options
comprising the IRP portfolios were selected from this diverse set in order to develop
portfolios using the most cost-competitive resources. While including additional
resources may have broadened the diversity of portfolios, the higher levelized costsT
would yield a more diverse afiay of more costly alternatives.
7 2017 IRP Appendix C: Technical Report at 76
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 6
3. Addlliqoal Tippins Point Solar Analvsis Supports the Companv's
Portfolio Selections.
To ensure that the Company's resource selection included the most economic
options, and at the recommendation of the lRP Advisory Council ('IRPAC'), the
Company conducted a solar tipping point analysis to evaluate the sensitivity of the
portfolio rankings to a reduction in solar cost.8 Only when solar PV prices dropped
more than 50 percent did the net present value ("NPV') ranking of the preferred portfolio
(P7) change.
ln light of concerns expressed by Staff, !CL, and in the public comments from Mr.
Hecklere and Mr. Burkholderlo regarding the robustness of the 2017 IRP portfolios and
the assumptions for the resources evaluated, the Company has prepared a
supplemental tipping point analysis comparing resource costs, including projected
capital cost declines for solar and lithium-ion battery resource options, in . The graph
includes the levelized cost of capacity ("LCOC") for solar and battery storage resource
options from the 2017 lRP source document for these costs (2016 Lazard cost reports),
and adds updated capital cost estimates from recently released (November 2017)
Lazard resource cost reports. The graph also includes the LCOC for B2H and natural
gas-fired resources.l 1
I2017 IRP at 118.
e Mr. Heckler's comment at 2
10 Mr. Burkholder's comment at 1
11 The graph is expressed in dollars per on-peak kW per month, rather than cost per installed kW
per month. Expressing LCOC in this manner does not affect the dispatchable resources (i.e., batteries
and natural gas-fired generators) or B2H, but the LCOC of solar is affected due to its contribution to on-
peak capacity, 1 kW of installed solar capacity equals 0.51 kW of on-peak capacity. Additionally, the
LCOC metric reflects the costs to own a resource, including fixed operation and maintenance costs, and
carry the resource as a part of the system ready to operate.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 7
The graph plots LCOC as a function of percentage of capital cost decline, where
only the battery and solar resources are assumed to experience capital cost declines.
The graph also uses resource cost data from the November 2017 Lazard cost reporting
on energy and storage resources.12 When compared to the 2016 Lazard cost reports,
the recent report indicates a modest decrease in average solar capital costs
($1,37s/kilowatt ('kW') to $1,238/kW) and a significant decrease in average lithium
battery capital cost ($3,1141kW to $1,748lkW). The most recent Lazard cost of storage
report projects lithium battery capital costs to decline at an annual rate of 10 percent
through 2021, with 2021 capital costs projected to have declined by 36 percent.
Figure 1: Capital Cost Tipping Point
Lithium battery
IAZARD C6t of
Storage 2.O
Lithium battery
Solar 1-axis
LAZARD CGt of
Energy 1O,O
TAZARD Cost of
Storege 3.o {slld llnel cccr
Solar 1-axis TAZARD Cost of
Energy 11.o (dashed line
overlying lithium battery linel
Recips
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OIcilol
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-l
5so
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540
535
s30
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sro
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B2H
i:.,
% rapital cost decline
12 Lazard's Levelized Cost of Energy Analysis - Version 11.0, November 2017', Lazard's
Levelized Cost of Storage Analysis - Version 3.0, November 2017.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 8
S-
The tipping point graph indicates that the costs for solar and battery storage
resources must decrease more than 90 percent from their current levels to be less
costly than B2H in terms of cost-per-kW of on-peak capacity. Solar and battery storage
costs drop below a CCCT at capital cost declines exceeding 35 percent, and below the
reciprocating engines at capital cost declines exceeding 65 to 70 percent.
The findings of the tipping point analysis indicate that B2H is the low-cost source
of on-peak capacity, and is likely to remain so even with steep declines in solar and
storage capital cost. The analysis indicates that solar and battery storage may out
compete natural gas-fired resources with substantial continued declines in capital cost.
Given the projected capital cost decline reported in the latest Lazard cost of storage
report, battery storage is likely to become cost competitive with natural gas-fired
resources over the coming years. Notably, the levelized peak capacity cost of the
Lithium Battery 3.0 and Solar 1-axis 11.0 overlaythe same line, suggesting thatthese
may be comparable resource options.
Mr. Heckler makes a case that, based on the solar tipping-point analysis detailed
on page 118 of the lRP, P11 may be the lowest cost portfolio after a 50 percent
reduction in the capital cost of solar.13 The IRP solar tipping-point analysis shows the
robustness of the P7 portfolio even in a very low-cost solar future. Table 9.8 of the IRP
illustrates that P7 is more cost-effective than P11 with solar costs reduced by 50
percent, although, as pointed out by Mr. Heckler, the gap between the two portfolios is
greatly narrowed. The gas resources identified in P7 are future-year placeholders and
wil! continue to be evaluated in future lRPs. P7 would become further cost-effective if
solar resources, at 50 percent capital cost, were to replace some of the identified P7
13 Mr. Heckler's comment at 2.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 9
gas resources. Further, the energy costs of P7 would decrease with solar resources,
once again widening the gap between P7, and any B2H-alternative portfolio. Mr.
Heckler comments that PV costs are projected to fall by more than 25 percent by
2026.14 The IRP solar tipping-point analysis suggests B2H would still be a part of the
preferred portfolio at solar cost reductions of more than 50 percent; however, the
resources accompanying B2H in this case would likely include solar instead of
exclusively natural gas.
In sum, the Company's portfolio analysis for the 2017 IRP was intentionally
focused on guiding the Company's major resource decisions. However, the Company
recognizes that the parties value greater diversity in the evaluation of portfolios, and will
continue to enhance its portfolio analysis in future lRPs.
B. The Preferred Portfolio is the Least-Cost Option.
ICL states that the Commission should not acknowledge this IRP because ldaho
Power's method of manually creating alternate portfolios, particularly in the manner
done in this 2017 lRP, is incapable of finding the truly least-cost, least risk option.1s
Staff suggests that the risk assessment of very similar resources is not very robust and
that Portfolio 7 benefits more from the IRP's unreasonably low gas price forecast than
the resource costs in Portfolio 5.16 Additionally, Mr. Heckler states that "it is possible
that P7 is neither the lowest risk nor the lowest cost future portfolio."17
Each portfolio was evaluated by the various cost components: variable costs
(determined through the AURORA model), new resource fixed costs, and remaining Jim
1a Mr. Heckler's comment at 2.
ls ICL Comments at 13.
16 Staff Comments at 13.
17 Mr. Heckler's comment at 3.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - .IO
Bridger costs.18 The portfolios were then ranked based on their relative cost in each
category. Lastly, each portfolio was ranked based on total portfolio cost. Only at this
point was a preferred portfolio identified as the best overall combination of costs. Thus,
while P7 had portfolio rankings other than "1" in the individual cost categories, it
remained the least-cost portfolio on a total-cost basis. lndeed, no single portfolio
ranked the same in variable cost and new resource fixed costs.
The Company also performed sensitivity analyses on each of the 12 portfolios to
determine the robustness of the portfolio rankings. These analyses included stochastic
risk analysis of natural gas prices, hydroelectric production, and system load.le Overall,
the preferred portfolio consistently outperformed other portfolios in the Company's cost
analysis:
o P7 has the lowest total portfolio cost under planning case conditions.2o
o P7 has the lowest total portfolio cost for all but the 400 percent of
planning case natural gas price sensitivity.2l
. P7 has the lowest total portfolio cost for 92 of the 100 stochastic
iterations.22
As a result, the Company reasonably concluded that the preferred portfolio is the least-
cost, least-risk option.
18 2017 IRP at 111.
1s 2017 IRP at 116-117, Figure 9.5 and Table 9.6.
20 2017 IRP at 111, Column 13, Table 9.3.
21 2017 IRP at 1 13, Tables 9.4 and 9.5.
22 2017 IRP at 116.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 11
C. The Preferred Portfolio.llVhich lncludes Continued Operation of the Bridger
Units. is Not lllesal.
ICL and Sierra Club argue that more than half of ldaho Power's resource
portfolios, including the Company's preferred portfolio, are illegal because they involve
ongoing operation of the Jim Bridger Units 1 and 2 in violation of the existing Clean Air
Act without the installation of SCRs.23 Staff is concerned that if early retirement in lieu
of SCRs is not achievable, customers could end up paying for SCRs in addition to the
other resources which were built in advance to replace the Unit 1 and 2 generation.2a
But far from relying on "hopeful speculation regarding the future leniency of regulatory
agencies," ldaho Power engages in reasonable planning based on established
precedent. For instance, in 2010, Portland General Electric Company successfully
negotiated an alternative compliance plan for the Boardman coal plant, which otherwise
would have been subject to mandatory installation of emission control technologies.2s
Under the revised rules adopted in December 2010, the Oregon Department of
Environmental Quality ("DEQ") did not require the installation of SCR on Boardman,
instead requiring installation of less expensive controls, in combination with an earlier
closure deadline for the Boardman boiler.
ldaho Power incorporated a comparable compliance scenario into its IRP
analysis. All portfolios were designed to either (1) comply with Regional Haze rules or
(2) be subject to a negotiated settlement with the Wyoming DEQ and the Environmental
Protection Agency that would allow continued operation without SCRs. To the extent
that Staff, lCL, and Sierra Club disagree with the likelihood of achieving such a
23 ICL Comments at 14; Sierra Club Comments at 7-8.
24 Staff Comments at 12.
2s See State of Oregon, Dept. of Env. Quality, Permit No.25-0016-TV-01, PGE Boardman 2011
Permit Modification.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 12
settlement, this is a difference of opinion concerning regulatory behavior-not a legal or
statistical argument. Moreover, the coal unit modeling considered the Clean Power
Plan COz emissions limits and complied with the state mass-based approach. The
Company's !RP clearly and fully conforms to Iegal and regulatory compliance
requirements.
II!. SUPPLY.SIDE RESOURCES
A. Jim Bridqer.
The Jim Bridger plant plays an important role in ldaho Power's system by
providing approximately 700 MW of baseload capacity, as well as serving as a
dispatchable resource responsive to load balancing requirements. ldaho Power uses
Jim Bridger extensively to provide ramping services, increasing overal! system flexibility.
These services are particularly important to allow for increased renewables penetration,
many of which entail substantial output volatility. The Jim Bridger plant is also used in
concert with the Company's hydro resources, supporting hydro's ability to serve as a
responsive resource as well.
Much as the parties describe-and the Company acknowledges-the multiple
benefits of energy storage resources, the Bridger plant provides system-support
services beyond its capacity and energy contributions. The Company relies on
dispatchable resources like Jim Bridger to provide adequate flexibility to follow variable
energy resources.
Nonetheless, the Company is moving toward a smooth transition from coal
resources. One of the primary goals in the Company's portfolio design for the 2017 IRP
was to evaluate SCR investments and retirement dates for the Jim Bridger coal plant.
ln this analysis, a key shift from the Company's 2015 IRP analysis to its 2017 IRP
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 13
analysis involved the impact of substantially lower natural gas price forecasts.26 These
lower price forecasts emphasized the need for careful review of the possible SCR
investments. As ldaho Power decreases its reliance on a coa!-powered fleet over time,
the Company must establish a responsible and practical path forward to protect the
reliability of the grid, to minimize costs to customers, and to fulfill its obligation to serve.
1. The Anticipated Retirement Dates for Jim Bridqer are Appropriate.
The Company's preferred portfolio includes the early retirement of Unit 1 in 2032
and Unit 2 in 2028.27 Staff and Sierra Club both indicate a need for additional
explanation for the Company's selection of these retirement dates.28 Sierra Club, in
particular, argues that even earlier shutdown dates would be possible-including
immediate shutdown in 2018 or 2020,2e while Staff is concerned that the preferred
portfolio assumes that Bridger Units 1 and 2 would be allowed to operate for 10 and
seven years, respectively, after the mandated SCR compliance dates.3o
As an initial matter, retirement dates for the Jim Bridger units should correspond
with PacifiCorp's target dates. Given that PacifiCorp is 67 percent owner of the units,
unilatera! action in this case is not possible.3l ln part for this reason, ldaho Power
selected a range of retirement and SCR options that correspond to those considered by
PacifiCorp's 201 7 lRP.32
26 The parties' comments concerning the Company's natural gas forecasts are discussed in more
detail below, in Section V.B.
27 2017 IRP at 8.
28 Staff Comments at 12; Sierra Club at 30.
2s Sierra Club Comments at 30.
30 Staff Comments at 13.
31 PacifiCorp20lT IRP at 77.
32 PacifiCorp20lT lRP at 171.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 14
ldaho Power does not doubt that there may be some form of carbon-emission
regulation in the next 20 years, and has expressed the objective of transitioning away
from coal-fired capacity more generally. The Company has also indicated that declining
to pursue the SCRs at Jim Bridger Units 1 and 2 is consistent with a future with
increased emissions regulation-wherein coal-fired generation will fare worse and will
face likely retirement.33 Thus, where Sierra CIub argues that "retiring the Bridger units
in the early 2020s is preferable to retrofitting them with SCR," this argument presents a
false dichotomy.3a
Critically, a decision not to pursue investment in SCRs in no way precludes
shutting down the units at a revised date, depending on the outcome of ongoing
discussions ldaho Power and PacifiCorp are having with the Wyoming DEQ. ln any
event, any ongoing operation of the Jim Bridger units will comply with all necessary
environmental regulations.
Thus, in order to effectively coordinate with the co-owner, and in light of ongoing
negotiations with regulators, the Company has reasonably included retirement dates of
2028 and 2032 in its preferred portfolio, without including SCR investments.
2. The Jim Bridger Units Remain Economic Resource Options.
Sierra Club argues that the Jim Bridger units are, even now, uneconomic,
reasoning that the Company's analysis understates various costs and miscalculates the
relative value of new solar capacity.3s ldaho Power acknowledges that "the utility has
an obligation to serve energy with the lowest reasonable costs to its ratepayers."36
33 2017 IRP at 123.
s Sierra Club Comments at 15.
3s Sierra Club Comments at 25 (stating that "Bridger is uneconomic on a going forward basis").
36 Sierra Club Comments at 26.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 15
However, Sierra Club is incorrect that the Jim Bridger units fail to provide this least-cost
resource.
Sierra Club argues that the SCR scenario portfolios fail to account for any
Bridger costs beyond 2034, and they also assume a rapid tapering of incremental
capital investment in the years leading up to 2034.37 ldaho Power does not, as a
general rule, include the fixed cost of its existing and committed generation in the IRP
portfolio costs because excluding common fixed costs between portfolios does not
impact portfolio ranking results.
Evaluating scenarios that contemplate varying operating lives of existing
resources requires a different modeling approach. For the portfolios that include SCR
investments at Jim Bridger Units 1 and 2, ldaho Power calculated the estimated fixed
costs of their current depreciable life of 2034 in the ldaho jurisdiction. For these
scenarios, ldaho Power did include variable operations and maintenance ("O&M") and
fuel expense associated with Jim Bridger generation modeled in 2035 and 2036 and
those costs were included in the overall portfolio cost through the AURORA model
output. For the portfolios without SCR investments at Jim Bridger Units 1 and 2, the
Company calculated the estimated fixed costs of operating the Jim Bridger plant to the
various accelerated end-of-life dates. The fixed costs for the four Jim Bridger Units 1
and 2 retirement scenarios were calculated and included in the total portfolio cost
evaluation.
ln its Comments, Sierra Club imputes the impact of including fixed costs to the
end of the planning period for portfolios that include the SCR investment. ldaho Power
estimates that including the present value of the 2035 and 2036 fixed O&M costs, as the
Sierra Club recommends, increases the NPV costs of these portfolios by approximately
37 Sierra Club Comments at 13-14
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS. 16
$5.5 million. The addition of $5.5 million to the SCR investment portfolios only makes
them less attractive. The selection of Portfolio 7, which does not include SCR
investment on Jim Bridger Units 1 and 2 still represent the least cost, least risk portfolio.
ln regard to the tapering of capital investments, as a coal plant nears the end of
its useful life, capital expenditures will decrease as long-term capital projects cannot be
justified over a short remaining life. Most capital projects are additions, improvements
or refurbishments. Additions and improvements will no longer be needed as the plant
gets closer to retirement. Refurbishments that can be capitalized wi!! continue, and
some maintenance items that were previously replaced as a capita! project, will be
repaired. Reducing capital expenditures does not necessarily reduce reliability. ldaho
Power chose to reflect a reduced base capital investment need as Jim Bridger units 1
and 2 reached the end of their planned operating life. These assumptions were
validated based on common industry factors and Idaho Power's investments at the
Boardman plant, which will cease coal fired operations at the end of 2020.
Sierra Club argues that the Company's IRP analysis relies on misplaced
assumptions regarding coal costs and market prices, excessively favoring the Jim
Bridger units as capacity resources.3s Sierra Club is correct that historical fuel prices
have increased over the past few years, mainly due to decreased generation at the
plant, resulting in decreased production at the mine, and recent damage to a longwall
mining system. These increases are not forecasted to continue at the present pace.
The Company relies on the most current data when preparing its IRP analysis and
believes the coal forecast is an appropriate reflection of likely future outcomes at the
time the !RP was prepared.
38 Sierra Club Comments at 15.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 17
ldaho Power, in conjunction with co-owners/operators PacifiCorp, is engaged in a
long-term fueling plan to select the least-cosUleast-risk fuel for the Jim Bridger plant on
an ongoing basis. The analysis considers different volumes of coal from several
different suppliers.
Additionally, ldaho Power does not produce an electric market price forecast.
The Company uses the AURORA model to quantify the variable costs of each portfolio.
The resulting market prices are a product of the AURORA model and the prices differ
with the unique characteristics of each portfolio. Contrary to Sierra Club's assertion,
ldaho Power has not skewed market prices to favor the economics of the Jim Bridger
plant.
Sierra Club also suggests that solar could be used to replace any capacity need
created by the retirement of the Jim Bridger units.3e For reasons discussed in Section
lll.B, below, the Company disagrees that new solar development would provide a lower-
cost resource option than the existing Jim Bridger units.
B. Solar PV.
Comments made by Sierra Club, !CL, Mr. Burkholder, and Mr. Heckler argue that
ldaho Power improperly modeled increasing solar costs.ao Sierra Club highlights that,
over the past seven years, the unsubsidized levelized cost of utility-scale solar has
declined by 85 percent.al Sierra Club reasons that ldaho Power is unreasonably
pessimistic in forecasting levelized capital cost prices going forward because solar is
not a "mature technology."a2 Under the Company's forecasts, Sierra Club and Mr.
3s Sierra Club Comments at 21-22; ICL Comments at 8; Mr. Burkholder's comment at 1; Mr
Heckler's comment at 2.
ao Sierra Club Comments at 20-21.
al Sierra Club Comments at 21.
a2 Sierra Club Comments at 20.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 18
Heckler note the unsubsidized levelized cost of solar would cease to decrease and
would instead increase by 13 percent between 2017 and2O23.a3
The Company disagrees with Sierra Club's critique. ldaho Power relies on
Lazard reporting for is estimates of capital costs associated with solar resources.
Additionally, ldaho Power tracks solar-based power purchase agreements made
regionally, nationally, and internationally. While the Company recognizes that solar is
becoming increasingly cost-effective, the parties fail to give adequate weight to two
major hindrances associated with increased solar capacity development: (1) its relative
on-peak capacity credit and (2) its unpredictability and variability. ldaho Power has
calculated that in order to provide one MW of on-peak capacity need identified in the
IRP's resource adequacy assessment, the Company would need to install roughly two
MW of nameplate capacity solar.aa
Moreover, solar carries reliability and cost impacts, as the Company's
dispatchable resources must be modified to accommodate solar generation's
unpredictability and variability. Idaho Power's study of these costs, released in 2016,
suggests modest solar integration costs; however, this study was conducted using
synthetic solar production data. Since that time, ldaho Power has interconnected nearly
300 MW of solar capacity to its system and is assessing the variability and uncertainty
of the actual solar production data to verify the 2016 study results.
Critically, even if solar resources become significantly more cost-effective, the
Company's tipping-point analysis suggests that the capital costs of solar would need to
reduce by more than 35 percent before the resource would become cost-competitive
with natural gas-fired resources, and more than 90 percent from their current levels to
a3 Sierra Club Comments at 21 Mr. Heckler's comment at 2.
44 2017 IRP at 37, Table 4.1.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 19
be less costly than B2H in terms of cost-per-kW of on-peak capacity.as As a result, the
Company is confident that its preferred portfolio accurately represents the appropriate
relative value of solar, as necessary to guide the Company's key decisions.
Sierra Club further suggests that the phasing out of the federal investment tax
credits ("lTC") will not preclude solar resource development between now and 2023, as
some measure of ITC benefit will remain.a6 While Sierra Club is correct that solar
resources may continue to be developed through the Public Utility Regulatory Policies
Act of 1978 ('PURPA") or individual development, the Company's 2017 IRP shows
ldaho Power has no need for additional resources through 2023. The Company would
not have a need to build additional resources; therefore, the costs of building additional
resources when they are not needed would not be prudently incurred. Future lRPs will
evaluate solar costs at that point in time and will capture any cost decreases if they
exist.
C. Enerqv Storaqe.
Sierra Club encourages the Company to revise its assessment of energy
storage, arguing that the Company failed to model substantial decreases in the future
price of energy storage.aT ICL states that the Company did not quantify the potential grid
services various storage technologies can provide.as
ldaho Power recognizes that energy storage is "capable of providing multiple
services" and is decreasing in cost. The Company further understands that, with
batteries' decreasing price, this resource may provide balancing and flexibility to the
a5 See in Section ll.A.3, above.
aG Sierra Club Comments at 21.
a7 Sierra Club Comments at 22 (arguing that "most battery storage technologies remain relatively
nascent").
48 ICL Comments at 9.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS.20
future grid. lndeed, batteries and transmission provide similar grid service, by moving
existing energy to where it is needed-be it in time (batteries) or in place (transmission).
However, the Company also recognizes two barriers to aggressive storage
implementation: (1) even with substantial price drops, energy storage continues to
demonstrate substantially higher capital costs than other resources, including highly
flexible natural gas-fired reciprocating engines, which also provide grid-support
services, and (2) the lifetime cycles of these resources remain uncertain, complicating
longterm analysis and planning.
To be clear, ldaho Power understands (and shares) parties' interest in further
comparisons of the costs of solar and storage with B2H and natural gas-fired resources.
This shared interest prompted the Company to prepare additional tipping point analysis
in in Section l!.A.3, above, which illustrates the LCOC for each resource. As noted in
the discussion accompanying that graph, however, capital costs for storage-like for
solar-would need to drop by more than 90 percent to out compete B2H in terms of
cost-per-kW of on-peak capacity, 35 percent to out compete a CCCT, and between 65-
70 percent to out compete reciprocating engines. As a result, even if parties are correct
that more substantial capital cost savings might be expected from these resources,
storage remains a higher-cost option compared to B2H for many years to come.
D. Wind.
Sierra Club objects to the Company's treatment of existing wind contracts, stating
that ldaho Power fails to explain why it assumes that some contracts will be renewed
and not others.ae ln particular, Sierra Club compares two sets of PURPA contracts as
evidence that the Company's approach is arbitrary: approximately 584 MW of wind
contracts are forecasted to expire during the planning period, while 502 MW of
as Sierra Club Comments at 12
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 21
contracted non-wind renewable generators are not similarly forecasted to expire. Sierra
Club instead urges the Company to assume, "barring any specific evidence to the
contrary," that wind Qualifying Facilities will renew contracts because of their negligible
operating costs.so
!n ldaho Power's experience, PURPA contracts involving small hydro, biomass,
cogeneration, and other renewable resource types have been renewed with little or no
additional investment required to maintain generation capacity. By comparison, the cost
of repowering wind QFs is less certain, and the Company cannot as accurately predict
whether these generators will choose to repower, resulting in no contract renewal.
ldaho Power understands that repowering wind turbines is being actively examined and
pursued in the wind industry, but is not yet clear when or how this approach will be
adopted for particular projects. ldaho Power continues to monitor developments in wind
repowering and may choose to adjust future planning processes accordingly.
E. Distributed Generation.
STOP B2H presents a number of arguments suggesting that ldaho Power has
failed to adequately value distributed generation. Broadly, STOP B2H urges the
Company to "use efficiencies and build at the smallest scale possible," while
nonetheless "ensuring [that] utilities remain a reliable engine of economic prosperity and
environmental sustainability.'51 More specifically, STOP B2H argues that the Company
failed to analyze the full benefits of distributed generation resources such as solar and
battery installations, arguing that the Company opposes PURPA development of solar
50 Sierra Club Comments at 13.
51 STOP B2H Comments at 25.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS.22
and battery storage. lnstead, STOP B2H proposes its own resource portfolio, including
substantial distributed generation.52
While ldaho Power appreciates STOP B2H's general sentiment concerning the
need to balance efficiency, economic benefits, and sustainability, STOP B2H fails to
recognize the internal inconsistency in its recommendation to build at the smallest scale
possible, while "us[ing] efficiencies": economies of scale favor utility-scale investment, a
method that also protects customers from unnecessarily inflated rates. lndeed, the
portfolio alternatives to B2H modeled by the Company's IRP included new resources to
account for load growth or coal retirements; in those contexts, the efficiency of
investments like B2H and CCCT resulted in their selection as the most cost-effective
resources over the 2}-year study period.
While STOP B2H is also correct that the IRP portfolios did not include large
quantities of distributed solar and storage in its portfolios, the Company focused its
portfolio design on cost-competitive resources in order to helpfully guide the Company's
decision making, without unnecessarily modeling significant numbers of high-cost
portfolios that would unavoidably fail to provide customers with the least-cost, least risk
resource profiles. At present, neither distributed solar nor storage resources represent
cost-effective resources, particularly on a scale necessary to supplant a resource like
the B2H line.
Separately, STOP B2H discusses the lack of combined heat and power ('CHP")
opportunities for ldaho Power customers, noting that "[t]he cost to deploy CHP is far
less than the cost to build standalone generation."S3 STOP B2H highlights the potential
52 STOP B2H Comments at 29-32
53 STOP B2H Comments at 28.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 23
of above-ground compressed air energy storage installation as a novel installation
model with promising implementation prospects.il
ldaho Power is greatly interested in CHP, which was discussed at multiple
IRPAC meetings. However, STOP B2H fails to account for substantial logistical and
administrative difficulties, which have proven surprisingly challenging. For instance, the
timing of production and costs needed to make a CHP project economically viable has
been more elusive than STOP B2H's analysis would suggest. Nonetheless, the
Company is open to evaluating additional CHP projects as either the need or the
opportunity arises. i
IV. DEMAND.SIDE RESOURCES
A. Enerqv Efficiency.
Cost-effective energy efficiency and demand response is ldaho Power's resource
of choice-both from a cost and from an environmental perspective. The cleanest,
most efficient resource in the Company's portfolio is one that does not have to be built.
The Company shares Staffs view that the benefits of energy efficiency extend beyond
the value of the energy saved and the avoidance of generating capacity; energy
efficiency also has the potential to defer other investment in grid infrastructure.ss ln its
2017 lRP, energy efficiency continues to be a valuable portfolio resource delivering !ow-
cost energy savings to ldaho Power's customers.
1. Evaluatino DSM Based on the Total Cost of Acquisition is Consistent
with Supplv-Side Resource Acquisition.
ldaho Power disagrees with Staff that the Company does not give equal
treatment to supply-side and demand-side resources in its IRP resource planning. ln
54 STOP B2H Comments at 29
ss Staff Comments at 10.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS -24
fact, ldaho Power gives preferred treatment to demand-side resources in its IRP by
putting these resources in every portfolio and continuing to plan on investing in the
expansion of these resources regardless of resource need.
ldaho Power would like to clarify the difference between the following terms:
. Utility Cost ("UC") versus Total Resource Cost ("TRC")
. Utility Cost Test ('UCT") or ratio versus Total Resource Cost test
("TRC test") or ratio.
The UC and TRC are simply the cost of an asset or measure levelized over its
useful life. The UC excludes costs not incurred by the Company. The TRC includes the
UC plus additional costs from participating customers. lt is important to remember, that
in supply-side and demand-side resources, the UC is funded by all customers through
the rates. The UCT and the TRC test factors in benefits from the measure or program
being evaluated and are used in DSM to determine the cost-effectiveness of the
measure or program, expressed as a ratio of benefits to costs.
For the IRP's comparative analysis of supply-side resource options, the
Company uses the TRC. Thus, to compare the cost of demand-side resources
equivalent with supply-side resources, the Company also uses the TRC. Generally,
using the UCT alone to determine the energy efficiency cost-effective achievable
potential could result in the selection of measures that are uneconomic for customers or
measures for participating customers that may never pay back during the measure's
useful life.
Also, in proqram planning, ldaho Power uses both the UCT and TRC test
because "the Company believes it is prudent to consider all the tests prior to making a
determination on offering a new program or making a decision to continue offering an
existing program. The Company believes that this process ensures a DSM portfolio that
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 25
is not only good for the utility, but one that is good for all customers, both participating
and non-participating customers."56 The benefits of the TRC test do include values that
are not used in supply-side planning such as the 10 percent system cost benefit for
conservation identified in the 1980 Northwest Electric Power Planning and Conservation
Act ("the Act"),57 transmission and distribution deferral benefit, and non-energy benefits.
Regionally, utilities still use the TRC for resource planning. ln Oregon, all
program administrators (including ldaho Power) must comply with OPUC Order No.
94-590,58 stating the expectation of the OPUC that measures and programs pass both
the UCT and TRC test. Because the IRP addresses system-wide planning, it would be
problematic from a program operation perspective to determine two levels of cost-
effective energy efficiency between ldaho and Oregon. The ldaho Commission has
likewise recognized the value of the TRC test to screen potential programs and expects
the Company to "make program investments that are prudent under the totality of the
circumstances" in order to recover its expenses.ss
56 ln the Matter of the Application of ldaho Power
Side Management Expenditures as Prudently lncurred
Connie Aschenbrenner at 18-19.
s7 While not directly applicable to investor-owned utilities, the Act specifically provides a 10
percent system cost benefit for conservation when comparing the estimated incremental system cost of
conservation with that of a non-conservation measure or resource. 16 U.S.C. S 839a(4)(D). The
Northwest Power and Conservation Council, established by the Act to carry out its purposes, interprets
that 10 percent cost benefit to reflect nonquantifiable benefits of energy efficiency (direct costs and
quantifiable benefits of a measure or resource are specifically addressed in 16 U.S.C. 839a(a)(B)). The
10 percent "adder," as it if often referenced, is incorporated directly into the Northwest Power and
Conservation Council's cost-effectiveness analysis for conservation measures.
58 ln the Matter of the lnvestigation into the Calculation and Use of Cost-Effectiveness Levels for
Conservation, Docket No. UM 551, Order No. 94-590 (April6, 1994).
5s ln the Matter of the Application of ldaho Power Company for a Determination of 2014 Demand-
Side Management Expenditures as Prudently lncurred, Case No. IPC-E-15-06, Order No. 33365, pp 9-
10 ("The TRC, UCT, and PCT evaluate EE programs from different perspectives. We believe each
perspective can help inform the Commission, the utility, and stakeholders about a particular program's
effectiveness. We thus find it reasonable for the Company to continue screening potential programs
using each test as a guideline, and to advise us on how the Company's programs fare under each test.
When the Company ultimately seeks to recover its prudent investment in such programs, however, we
believe the Company may (but need not exclusively) emphasize the UCT-and that test's focus on
Company-controlled benefits and costs-to argue whether the programs were cost-effective. As always,
the Company ultimately must persuade us that its program investments were prudent under the totality of
the circumstances.")
Company for a Determination of 2016 Demand-
Case No. IPC-E-17-03, Direct Testimony of
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 26
Further, the Northwest Power and Conservation Council ("Council") uses "an
estimate of all direct costs of a measure or resource over its effective life." While the
Council does not use the TRC test as defined by the California Standards Practice
Manual, it does use a form of a "total resource" cost test. The Council's version of a
TRC test does capture all costs and all benefits. As Tom Eckman, former Conservation
Resource Manager of the Council has stated, it "directs funds toward measures that
minimize total Utility and Customer investments in energy services" and "avoids
promoting measures that may impose non-energy costs on others."60 However, the
Council also recognized that one test was not enough and there is a need to use each
test in combination.6l
ldaho Power believes that using the TRC to compare supply-side and demand-
side resources in power supply planning is reasonable and aligns with the methods
used by most utilities.
2. Idaho Power's Method for Determininq Enerqv Efficiencv Potentia! is
Reasonable and results in Prudent IRP Targets for Enerqv Efficiencv.
ldaho Power recognizes that alternatives exist for determining the target amount
of lRP energy efficiency, including the alternative methods referenced by Staff in its
Comments. ldaho Power has discussed methods with regional utility counterparts,
including Avista and PacifiCorp. Through these discussions, as well as review of
documentation included in their respective !RPs, ldaho Power understands an
alternative method in which modeling software is used to select demand- and supply-
side resources to develop IRP resource portfolios. The Company sees this approach as
60 Cost-Effectiveness Analysis: A Tail of Two
Solutions,http://www.neec.neUsites/defaulUfiles/paqe attach/neeccosteffectiveness eckman 072313 2sli
des.pdf, slide 18.
61 Cost-Effectiveness Analysis: A Tail of Two Solutions,
http://www. neec. neUsites/defaulUfiles/paqe attach/neeccosteffectiveness eckman 072313 2slides. pdf,
slide 24.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS -27
an alternative to its existing method, and maintains that its practice of determining
energy efficiency potential prior to the consideration of supply-side resources is also a
viable and fair alternative that results in prudent IRP targets for energy efficiency. This
practice results in the selection of energy efficiency beginning in the first year of the IRP
planning period, even if the first energy and capacity deficits are years into the future; in
contrast, the model-based process favored by Staff selects demand- and supply-side
resources only for the purpose of satisfying resource deficits. Moreover, there are
reports that the model-selected energy efficiency potential differs little from that
determined by a process similar to ldaho Power's. For example, in its 2017 !RP, Avista
describes the modeling process by which "individual energy efficiency resources
compete with supply- and demand response options", noting that "this methodology
does not change the amount of conservation selected in the PRS."62
Prior to lhe 2017 lRP process, ldaho Power contracted with a third-party
consultant, Applied Energy Group ('AEG"), to produce an Energy Efficiency Potential
Study ("Potential Study"). AEG is an experienced and reputable third-party contractor in
conducting DSM potential studies, having conducted studies in over 25 states and
provinces for over 40 energy providers, including multiple studies for 13 companies in
the Northwest. Using AEG's forecasts, ldaho Power included all achievable energy
efficiency in every portfolio prior to any supply-side resource being considered, making
energy efficiency the first resource the Company has included to meet future resource
needs. ldaho Power's 2017 study determined that the Company cumulatively has 273
average megawatts of achievable energy efficiency potential and 483 MW of achievable
peak potential by the end of the IRP planning cycle in 2036. AEG estimated this level of
62 ln the Matter of Avista Corporation's 2017 Electric lntegrated Resource Plan, Case No.
AVU-E-17-08 at 5-6.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 28
achievable potential using acquisition rates similar to the 85 percent acquisition rate
used by the Council.
Idaho Power believes that the amount of energy efficiency determined by AEG is
cost-effective and achievable and sets an appropriate and prudent target for energy
efficiency for long-term planning purposes. As the Company evaluates its resource
adequacy over the planning period through the load-resource balance, energy efficiency
is the first resource applied to serve the projected load. lncluding unrealistic amounts of
energy efficiency potential in the load-resource balance may understate the need for
future resources and undermine the Company's obligation to reliably serve its load. To
be clear, however, the Company does not consider the achievable potential as a ceiling
or limit for the Company's energy efficiency efforts.
ldaho Power also emphasizes that prudent IRP targets for energy efficiency
should not be interpreted as conservative, nor should they be described as static.
Efforts to achieve the IRP targets are ongoing, and involve collaboration between the
Company and stakeholders; ldaho Power considers the consistent achievement and
exceedance of the IRP targets as a reflection of the effectiveness of this collaboration,
rather than the result of setting low targets. The IRP analysis has been described as a
"freeze frame"63 by the ldaho Commission. ldaho Power shares this view and
recognizes that key inputs to the IRP process, including the alternate costs driving the
analysis of energy efficiency cost-effectiveness may dynamically shift from IRP to lRP.
3. Idaho Power Properlv Accounts for Energv Savings Due to New
Godes and Standards.
Sierra Club raises concerns about declining forecasted savings due to ongoing
changes in lighting standards that will culminate in 2020 and argues that the Company
63 ln the Matter of ldaho Power Company's 2015 lntegrated Resource Plan, Order No. 33441 at1
(December 23,2015).
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 29
should model declining savings prior to the final 2020 phase-in of standards.oa lt is
important to clarify that when savings are lost from ldaho Power's program portfolio due
to manufacturing standards or code changes, the savings then become part of the load
forecast econometric process, which incorporates data and trends related to codes and
standards into the forecast. Thus, total impacts from energy efficiency, whether the
savings come from codes and standards or achievable potential from utility programs,
are fully accounted for in the IRP process prior to the consideration of any new supply-
side resources.
4. ldaho Power Has a Robust Portfolio of Enerqy Efficiency Programs.
ln its Comments, STOP B2H claims that ldaho Power has added only two new
energy efficiency programs since 2009.65 As described in more detail in Appendix B to
the 2017 lRP, ldaho Power has continually added new measures to its 23 energy
efficiency programs, and all but two are offered in both the ldaho and Oregon
jurisdictions. These 23 programs comprise over 275 energy efficiency measures.66 ln
fact, since 2009, ldaho Power not only added two new programs that STOP B2H
identified, but has also added the Multifamily Energy Savings program and expanded
the measure offerings in its Energy House Calls program, Simple Steps, Smart Savings
program, Heating & Cooling Efficiency program, and Commercial & lndustrial Energy
Efficiency program. ldaho Power has a standing program planning group,67 participates
in Northwest Energy Efficiency Alliance (NEEA) Regional Emerging Technology
Advisory Committee, is a voting member of the Council's Regional Technical Forum,
6a Sierra Club Comments at 10-1 1.
6s STOP B2H Comments at 18.
66 See 2017 IRP Appendix B: DSM Report at 196
67 2017 IRP Appendix B at 153.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 30
and is a member of E Source, a national organization of electric utilities and energy
providers focusing on energy efficiency and potential new programs and measures.
Additionally, ldaho Power disagrees with STOP B2H's assertion that "ldaho
Power has achieved much less in energy relative efficiency saving when compared to
other utilities."68 The 2017 State Energy Efficiency Scorecardoe lists ldaho as one of the
most-improved states this year. ldaho, 95 percent of the Company's service area,
posted the largest point increases over its previous year's score. The following excerpt
summarizes ldaho's 2017 score:
ldaho added the most to its score this year, rising in the
ranks from 33rd to 26th. Although the state's utility savings
have yet to rebound to peak levels seen in 2010 and 2011,
they have edged upward recently thanks to resurgent levels
of spending on demand-side management programs. ldaho
has also seen a recent increase in electric vehicle
registrations and updates to building energy codes modeled
on the 2015 !nternational Energy Conservation Code (IECC),
due to take effect in January 2018. This was the state's best
finish since 2012.
Although the score relates to the entire state, not just ldaho Power, the
Company's substantial contributions are a key driver in the state's overall energy
efficiency performance.
The Company is committed to pursuing all cost-effective achievable energy
efficiency. While the Company does not view the amount determined in the Potential
Study to be a ceiling by any means, it does represent a prudent target for long-term
resource planning.
68 STOP B2H Comments at 18.
eg The 2017 State Energy Efficiency Scorecard, American Council for an Energy-Efficient
Economy, September 2017 Report U1710, page viii.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 31
5.Power Will rk to Ensure Fundamental Consiste
Transm ission and Distri bution ("T&D") Methodoloq ies.
As noted above in these comments, ldaho Power understands the potential of
energy efficiency to defer investment in grid infrastructure. In August 2016, near the
start of the 2017 IRP process, the Company held separate conference calls with
PacifiCorp and Avista to discuss methods. ldaho Power also participated with other
Northwest utilities in a Council workshop on T&D deferral on August 22, 2017. While
ldaho Power's method of estimating T&D deferral benefit from energy efficiency is
thorough and defensible, the Company will continue to work with regional utility
counterparts to ensure fundamenta! consistency between methodologies. Additionally,
ldaho Power will calculate the T&D deferral costs and benefits over a 20-year period in
future energy efficiency T&D deferral benefit studies.
B. Demand Response.
The goal of demand response ("DR") programs is to minimize or delay the need
to build new on-peak, supply-side resources. On a comparative basis, DR as a
resourceTo is a very economic capacity resource and a very expensive energy
resource.Tl Unlike supply-side resources, DR programs must acquire and retain
participants each year to maintain a level of demand-reduction capacity for the
Company. ldaho Power plans for its DR capacity based on commission ordersT2 in both
ldaho and Oregon and assesses its DR capacity through actua! annual deployment of
70 2017 IRP at 87, Figure 7.5.
71 2017 IRP at 89, Figure 7.6.
72 ln the Matter of the Continuation of ldaho Power Company's A/C Cool Credit, lrrigation Peak
Rewards, and FlexPeak Demand Response Programs tor 2014 and Beyond, Case No. IPC-E-13-14,
Order No. 32923 (November 12,2013). ln the Matter of ldaho Power Company, Staff Evaluation of the
Demand Response Programs, Docket No. UM 1653, Order No. 13-482 (December 19, 2013).
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 32
these resources. ldaho Power experiences its system peak in the summer months, so
its DR programs are offered from June 15 to August 15 of each year.
STOP B2H was critical of ldaho Power's DR programs.T3 ldaho Power has three
DR programs: A/C Cool Credit, Flex Peak Program, and lrrigation Peak Rewards, all
offered in ldaho and Oregon.Ta The A/C Cool Credit program is a direct load control
('DLC") program that allows ldaho Power to remotely cycle participants' residential air
conditioners on and off to reduce summertime demand on its system. The Flex Peak
Program is a behavioral load control program for commercial and industrial customers.
Participants nominate load reduction at their facilities and reduce load through
managing their energy use. The lrrigation Peak Rewards Program is a DLC program by
which ldaho Power can remotely turn off irrigation pumps to reduce system load.
Idaho Power has 390 MW of DR load control, which is over 11 percent of its all-
time system peak. The Council's 7th Power Plan7s "assume[s] the technically
achievable potential for DR in the region is over eight percent of peak load during winter
and summer peak periods by 2035," while ldaho Power currently has 11 percent of its
summer peak load under DR control. Idaho Power provides the most summer DR in
the Pacific Northwest region according to the 7th Power Plan.76
As part of the public workshops in Case No. IPC-E-13-14 and Docket UM 1653,
ldaho Power and other stakeholders agreed on a new methodology for valuing DR. The
settlement agreement, as approved in IPUC Order No. 32923 and OPUC Order No.
73 STOP B2H Comments22-24.
74 2017 lRP, Appendix B at 33, 126, 140.
7s Northwest Power and Conservation Council's 7th Power Plan, Chapter 14 Demand Response,
page 14-2. Available at https://www.nwcouncil.orq/media/7149925/Tthplanfinal chap14 dr.pdf.
76 Northwest Power and Conservation Council's 7th Power Plan, Chapter 9 Existing Resourcesand Retirements, page 9-28. Available at
https://www.nwcouncil.orq/media/7149929/Tthplanfinal chap09 existresources.pdf.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 33
13-482, maintains the current DR programs even in years when ldaho Power does not
anticipate peak-hour capacity deficits, setting in place the program infrastructure for
when capacity deficits return. The settlement and subsequent orders stipulated when
and how each program wil! be utilized, allowing for the deployment of each program
three times per season even when the programs are not needed. Additionally, the
stipulation even prescribes what programs can be actively marketed or expanded.
STOP B2H argues that ldaho Power has "failed to build-out its AMl, costing
customers the savings they would receive from having digitally mediated demand
response in place."77 ldaho Power disagrees with these views. The Company uses a
power line carrier system, Aclara Two Way Automated Communications (TWAC)
system and its Automated Meter lnfrastructure system ("AMl') to deploy most of its DLC
programs (A/C Cool Credit and lrrigation Peak Rewards). Additionally, the Company
uses a cell phone system to deploy some of the lrrigation Peak Rewards for participants
that do not have AMI communications. ldaho Power currently has gg percent of its
customers on the AMI with a 99.9 percent read success rate and 91.3 percent of its
Oregon customers on the AMI system with the same 99.9 percent read success rate.
The Company continually upgrades and expands its AMI capability and believes AMI is
an efficient and effective system for many operations-including DR-considering the
geography, topography, and density of its service area.
The Company would like to clarify STOP B2H's statement that "no one is going
to attach that framework to a customer electric pane!" to participate in the lrrigation
Peak Rewards program.Ts ln 2016, ldaho Power had 2,286 service points (panels) with
77 STOP B2H Comments at 22.
78 sToP B2H Comments at 22
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 34
DR devices attached, with 50 in its Oregon area.Te Additionally, in 2016, 28,315 A/C
Cool Credit participants had DR devices on or near their central A/C units, with 368 in
Oregon.
ldaho Power believes that it is effectively deploying demand response for its
customers, and will continue to improve and upgrade its technology as economically
and logistically feasible.
V. FORECASTS
A. Load Forecasts.
The Company recognizes the significance of the role of peak forecasting in long-
term capacity planning and continues its commitment to engage with its peers regarding
demand forecasting models, methodologies, and other load forecasting topics. Staff
suggested the Company's peak load forecasts could be improved by incorporating
class-specific forecasts in its analysis.8o The Company supports including additional
narrative in future lRPs to further discuss its peak forecasting methodologies,
sensitivities, and results.
Given the importance of peak forecasting, the Company believes that the
architecture of its system peak models provides the best probabilistic forecast for long-
term planning decisions. While hourly class observations at the customer level are
available for peak modeling, system level data carries a necessary breadth of history
steeped in actual outcomes that reflect diverse economic and weather scenarios which
are not available for the limited span of class data. There is not sufficient empirical
evidence to suggest that the assumptions required to leverage limited data for customer
7s See 2017 IRP Appendix B: DSM Report at 196
80 Staff Comments at 3-6.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 35
class leve! peak models behave in a more stable and accurate manner than system
data for long-term capacity planning.
lCL is critical of two points in the Company's load forecast: (1) the irrigation load
forecast did not include the impact of an agreement to reduce groundwater and ignores
observed changes to historical weather patterns and (2) the lack of consideration of
changing weather trends.81 ldaho Power did analyze potential impacts of irrigation
electric consumption as a result of agreements to reduce groundwater use from the
Eastern Snake Plain Groundwater Districts and ldaho Ground Water Association.
Members who have agreed to reduce groundwaterconsumptions by nearly 15 percent
acre-feet annually will do so by implementing an April 1 to October 31 season, idling
acreage, planting less water intensive crops, and increasing pump efficiencies. As
policy is a component to energy forecasting, additional evidence of a sustained long-
term trend of a change in electricity usage directly due to these agreements will
continue to be investigated and incorporated if warranted. The Company has
considered and acted upon changing climate conditions. Given recent climatology
trends in the Boise load pocket, ldaho Power has explored the inclusion of different
weather variables in the residential customer classification outside the 30-year normal
period. The Company supports and implemented in the 2017 IRP residential load
forecast modeling the use of a shortened weather normal period (1S-year average) to
give more weight to the most recent trends of weather data while continuing to establish
normal climatological weather with measurable and accurate data.
Lastly, Sierra Club argues that the IRP fails to model load stochastically, allowing
for year-to-year variation and systemic variation.s2 The Company utilized load forecasts
81 ICL Comments at 4.
82 Sierra Club Comments at 32
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 36
with different starting points to perform the stochastic modeling in the AURORA model.
The Company believes this view of load is valuable in determining the impact of a low or
high load environment on portfolio performance. A more varied load stochastic may be
considered for the 2019 IRP.
B. Natural Gas Price Forecasts.
Several parties criticized ldaho Power's selection of the Planning Case natural
gas price forecast.s3 ldaho Power attempts to use the gas price forecast that most
closely aligns with future expectations. Prior to the 2013 lRP, ldaho Power's natural
gas forecast was internally developed using several blended proprietary forecasts,
resulting in a non-public natural gas forecast. ln the 2013 lRP, ldaho Power began
using an Energy lnformation Administration's ("ElA') forecast as the basis for the IRP
natural gas forecast, to increase transparency. The Company used the EIA Reference
Case as the Planning Case natural gas forecast in the 2013 and 2015 lRPs. ln a
departure from the 2013 and 2015 !RPs, the Company selected the High Oil and Gas
Resource and Technology ("EIAHO') case from the 2016 EIA Annual Energy Outlook
for the 2017 IRP Planning Case.
The Company chose the EIAHO case forecast as its Planning Case because
actual natural gas prices have consistently been lower than the ldaho Power IRP
Planning Case EIA forecast selected in the past several IRP cycles. A detailed review
of the lntercontinental Exchange ("lCE') settled forward contracts demonstrated ICE to
be a more accurate indicator than the EIA Planning Case forecast used in the IRP over
the past few years. Comparing the ICE reviewed data to the 2016 EIA forecasts
83 See Staff Comments at 6; ICL Comments at 24, Sierra Club Comments at 32; Coalition's
Comments at4-5.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 37
available, the 2016 EIAHO case forecast was selected, as it closely followed the ICE
fonryard contract prices as compared to the other available EIA forecasts.
Staff and others question the use of ICE data to substantiate the selection of a
natura! gas price forecast for the IRP.84 ldaho Power believes it is appropriate to
validate the gas forecast and doing so in this manner served to confirm the selection of
the EIAHO case over the EIA Reference Case. Settlement prices that ICE publishes
are based off actual market transactions. ICE uses these transactions along with its
own fundamental review of the market (including the EIA forecasts) to provide monthly
prices throughout the time horizon that it publishes. These published prices are
accepted and used by the market as not only a basis for forecasting, but also to set
margin requirements leading to the exchange of real dollars on a daily basis.
Additionally, the natura! gas industry uses the Henry Hub futures contract as a
basis for determining forward prices and applies a basis differential to adjust for
locational differences. For example, most of the gas that ldaho Power purchases for its
power plants is bought at the U.S./Canadian border at Sumas, Washington. For
forecasting and hedging purposes, ldaho Power would use the Henry Hub futures
contract in combination with a Sumas basis swap to represent the forward price of
natural gas at Sumas. Both the Henry Hub futures contract and the Sumas basis swap
are traded and cleared on the ICE platform, as are hubs from all over the country.
ldaho Power uses the Sumas Hub because this is where most of its firm pipeline
transportation is sourced from and is where the Company buys most of its physical
natural gas supply.
8a See, e.9., Staff Comments at 7; Renewable Energy Coalition's Comments at 8.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 38
ldaho Power believes Staff incorrectly describes ICE futures as an option.8s An
ICE future is in fact a fix for floating swaps.86 The ability for one party or the other to exit
such a transaction would require an offsetting transaction. For example, a party who
buys 100 contracts, could reverse this position by simply selling 100 contracts. Price
movements between the buy and sell transaction would either be a gain or loss
depending on the direction the market moves. Parties buy and sell ICE futures for
different reasons. Many utilities and industrial companies, ldaho Power included, buy
futures as a hedge to protect against prices going up without regard to their belief of
which way prices may go. Conversely, producers often hedge to guarantee their
production will remain profitable in the event prices fall, protecting profitability and cash
flow.
As shown in the graph below, the 2017 IRP Planning Case (EIAHO case) and
the ICE settled contracts line up very well through 2028, which is the extent of ICE data
available at the time.
Figure 2: Henry Hub Natural Gas Prices (Nominal $/MMBtu)
s15.OO
s14.OO
s12.OO
s10.oo
s8.@
S6.oo
s4.OO
S2.@
s-
Henry Hub Natural Gas Prices (Nominal
S/mmbtu)
-Historical
-2077
EIA Reference Cas
-2017
IRP Plannint
:tCE Settles 2016
7997 2m1 2m5 2@9 2013 2077 2021 20.25 2029 2033
2017 EIA Low Oil and Ga5
Resource and
Technology C6se
8s Staff Comments at 8.
86 https://www.theice.com/publicdocs/lCE NatGas Brochure.pdf.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 39
Because future natural gas price assumptions influence the financial results of
the operational modeling used to evaluate and rank resource portfolios, the Company
also evaluated historical price trends to inform the selection of a natural gas price
forecast for the lRP. The natural gas price forecast in the last two lRPs have
consistently overstated the gas price forecast when using the EIA Reference Case, as
shown in the graph below.
The confidential graph below compares natural gas prices from ICE Henry Hub
contract settles and EIA forecasts from 2009 to 2016. The graph shows a strong
correlation between the ICE and EIA futures in 2009, 2010, 2011, and 2012. Starting in
2013, the futures begin to diverge with EIA continuing to show a much larger increase in
the forecast and ICE contracts showing a much flatter future. Looking at the actual
Henry Hub line, which is flat or declining from 2009 fonnrard, ldaho Power believes the
past seven-year trend of low prices (dotted pink line) will persist-as does the market,
as shown by the 2016lCE contracts (solid pink line).
Figure 3: (CONFIDENTIAL) Comparison of Henry Hub to other Forecasts
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 40
ln the 2017 !RP, ldaho Power's planning case natural gas forecast (the EIA High
Oil and Gas Resource and Technology Case) was analyzed over varying price
sensitivities (or scenarios). Pages 112-113 of the 2017 IRP describe the analysis in
which ldaho Power analyzed natural gas price sensitivities ranging up to 400 percent of
planning case natural gas price forecast. For the stochastic risk analysis, described on
pages 114-117 of the 2017 lRP, ldaho Power analyzed 100 different natural gas price
scenarios.sT While the price sensitivities only evaluated upward pressure on natural gas
prices, the stochastic risk analysis sampled prices above and below the Planning case,
in line with Sierra Club's concern that gas prices should allow for the risk that prices will
rise or fall.
An additional argument against the selection of the EIAHO natural gas price
forecast is the concern that it will lead to underinvestment in conservation. lt is true that
the DSM alternative costs that are used for program cost-effectiveness are based on
the 2017 IRP preferred portfolio using the 2017 IRP Planning Case natural gas price
forecast. That said, the Company has been pursuing-and continues to pursue-all
cost-effective achievable energy efficiency. As discussed above, the Potential Study
provides a prudent target for long-term planning purposes, but it is not viewed as a
ceiling or cap by the Company.
C. Coal Price Forecasts.
Sierra Club recommends that coal prices should be included in the stochastic
analysis.ss Idaho Power believes that by varying the natural gas prices relative to the
coal price and limiting the new resource technologies to B2H, solar, and natural gas in
87 2017 IRP at 114, Figure 9.2.
88 Sierra Club Comments at 33
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 41
the portfolio design, the Company's analysis has effectively tested the viability of coa! to
economically compete in the future.
D. Hvdro Electric Forecast.
ICL is critical of the Company's hydroelectric forecast and suggests that the
Commission should not acknowledge this IRP "until ldaho Power at least attempts to
understand the future impacts to the backbone of their generation fleet."8e The
Company has not-and does not-make predictions specific to changes in the scale
and timing of hydrologic effects or any other aspect of the Company due to future
climate variability. Outside of the IRP process, the Company does track the latest
science related to future climate impacts on the scale and timing of the hydrology. The
Company is an active participant in the ongoing River Management Joint Operating
Committeeeo meetings, which have included input from University of ldaho researchers,
and actively keeps up to date with current agency and academic research and
publications related to the Pacific Northwest climate variability. ldaho Power is currently
working with Boise State University Department of Geosciences to initially evaluate
unique atmospheric models in conjunction with physically based hydrologic models to
examine potential variability in temperature, precipitation, and snowpack.
VI. BOARDMAN TO HEMINGWAY
STOP B2H is the only party that submitted comments in opposition to the B2H
transmission project, which is the major resource in the Company's least-cost, least-risk
preferred portfolio. As stated before, STOP B2H's Comments were identical to those
filed in Oregon Docket No. LC 68. Therefore, much of the Company's Reply Comments
8e ICL Comments at 7
e0 A forum of water managers, hydrologists, and power schedulers from the U.S. Bureau of
Reclamation, U.S. Army Corp of Engineers, University of ldaho, and Bonneville Power Administration.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 42
below are the essentially the same as the Company's Reply Comments in Docket No.
LC 68, and are filed here to provide a complete record.
A. Transmission and the IRP Process.
The Company seeks acknowledgment of its preferred portfolio in the 2017 lRP,
which includes the Company's proposal to begin construction activities for the B2H line.
This proposed line is considered as a resource that wil! provide the Company with
critical capacity required to serve its ldaho and Oregon retai! customer Ioads and to
maintain system reliability, without adding a carbon-producing resource. The
Company's planned transmission line is reasonable, cost-effective, and necessary to
ensure that the Company's customers receive adequate services at reasonable rates.
The Company does nof request that the Commission review, approve, or acknowledge
the specific routing of the line nor the ratemaking treatment of the line.
1. ldaho Power's IRP Establishes its Specific Resource Need. but
Broader Regional Planninq is AIso Legitimately Considered as Part
of Need.
Idaho Power's preferred portfolio includes the B2H capacity resulting from the
Company's ownership share of the line. The Company is therefore seeking
acknowledgment of only its proportiona! capacity as the least-cost, least-risk resource
for ldaho Power customers. This approach is consistent with the treatment of other
resources in which the Company has shared ownership. Acknowledgment of Idaho
Power's resource need, therefore, does not require that the Commission also
acknowledge a specific resource need for ldaho Power's co-participants, PacifiCorp and
the Bonneville Power Administration ('BPA'). While ldaho Power seeks
acknowledgment of only its share of B2H, the Company recognizes that the overall
cost-effectiveness of the resource relies on shared ownership and that the Company will
likely not move forward with B2H alone.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 43
Moreover, although the Company is not seeking acknowledgment of the total
capacity of the proposed B2H line, the Commission can consider the regional need for
the B2H line and the broader benefits it provides. For more information, please see the
2017 IRP Appendix D: B2H Supplement, Attachment 1.
2. ldaho Powet Seeks to Satisfv the EFSC "Need" bv havins the Oreqon
Commission Acknowledqe B2H in the lRP.el
EFSC is specifically tasked with establishing siting standards for energy facilities
in Oregon and ensuring certain transmission line projects, including B2H, meet those
standards.s2 EFSC will issue a site certificate authorizing the construction of a
transmission line ("non-generating facility") only after the Company demonstrates a
need for the facility in accordance with EFSC's least-cost plan rule or system reliability
rule.e3 The requirements of the least-cost plan rule can, in turn, be met through an
acknowledgment of the resource in the Company's lRP.s4 ln this case, ldaho Power
seeks to satisfy EFSC's least-cost plan rule by having the Oregon Commission
acknowledge the Company's lRP.
The ldaho Commission should note, however, that even if the OPUC
acknowledges the Company's proposed plan, that does not mean that EFSC will
automatically issue a site certificate and authorize construction along the route
proposed by the Company. A demonstration of need is only one of many requirements
the Company must satisfy before issuance of the site certificate.ss
e1 2017 IRP Appendix D: B2H Supplement at 58-60.
s2 See generally ORS 469.300-469.563, 469.590-469.619, and 469.930-469.992.
s3 oAR 345-023-0005(1 ).
s4 oAR 345-023-0020(2).
s5 See ORS 469.310 (siting decisions must be consistent with the health and welfare of the
people of Oregon); OAR 345-022-0000 to 345-022-0120 (general standards for siting facilities).
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 44
B. Resource Need.
Idaho Power's 2017 IRP relies on the same methodologies used in prior lRPs to
identify its first capacity and energy deficits over the IRP planning period. Based on the
Company's preferred portfolio, the first capacity deficit occurs in 2026, unless the Jim
Bridger units are retired early, in which case the first capacity deficit occurs as early as
2023.e6 The first energy deficit occurs in 2029, or as early as 2024 with Jim Bridger
retirements.
Once these deficits were identified, ldaho Power then studied the resources
available to find the least-cost, least-risk combination of resources to meet the need.
The Company's analysis consistently selected portfolios that included B2H as a least-
cost, least-risk resource because its capacity costs are nearly half of the next best
alternative, it provides grid flexibility, and allows the Company to avoid the acquisition of
a carbon-producing resource. Contrary to the implications made in several comments,
the Company did not identify a need for additional transmission resources, and then
selected B2H as the least-cost, least-risk fransmission resource. Rather, the Company
identified a need for a supply-side resource and B2H consistently and substantially
outperformed the competing alternative resources.
1. B2H is Properlv Characterized as a Supplv-Side Resource.eT
Consistent with its historical treatment of B2H in prior lRPs, the Company's
modeling treats B2H as a supply-side resource because it allows greater access to
Northwest markets, thereby allowing ldaho Power to import additional lower-cost energy
to serve its Oregon and ldaho customers. STOP B2H argues that transmission lines
are not supply-side resources and that the IRP is "devoid of any analysis of the
s6 2017 IRP at 96.
s7 2017 IRP Appendix D: B2H Supplement at 5-6
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS .45
underlying power resource actually represented by B2H in the lRP, which are short-term
forward capacity purchases[.]"e8 This claim is both factually incorrect and
misunderstands modeling of transmission resources in an !RP.
ln describing resource planning requirements, the ldaho Commission found that
the utility should discuss "contingencies for upgrading, optioning and acquiring
resources at optimum times (considering cost, availability, lead time, reliability, risk, etc.)
as future events unfold."ee The OPUC's IRP guidelines describe the requirements for
transmission resources and specifically state that "utilities should consider . . . electric
transmission facilities as resource options, taking into account their value for making
additional purchases and sales, accessing less costly resources in remote locations,
acquiring alternative fuel supplies, and improving reliability."too Consistent with these
requirements, ldaho Power has appropriately accounted for the costs of the underlying
market transactions when determining the forecasted overall costs and benefits
associated with the B2H line.1ol
a. B2H Will Meet the Capacity Deficit Present in 2026.
When early coal unit retirement scenarios are considered, the Company has
capacity deficits ranging from 213 MW beginning in 2023 to 34 MW in 2026 (preferred
portfolio capacity deficit is 2026). These deficits continue to grow throughout the 20-
year planning period reaching 967 MW and 635 MW for the retirement and non-
retirement scenarios, respectively, by 2036. B2H provides 500 MW of capacity starting
s8 STOP B2H Comments at 6
ss Order No.22299 at7.
too Q1(s1No. 07-002 at 13.
t01 16 be clear, the capacity costs of B2H do not include the cost of the underlying market
transactions that will be facilitated by the line, just as the capacity cost for a natural-gas-fired plant does
not include the underlying costs of the gas that will be burned to generate electricity. The market
transaction costs are included as an energy cost in the overall portfolio modeling.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS.46
in 2026 to reduce the deficiencies through 2031, at which time another resource is
needed.
ldaho Power's Existinq Transmission Capacitv Does Not Allow
for Sufficient lmports from the Northwest.
b.
STOP B2H claims that ldaho Power already has more long-term firm import
capacity from the Northwest than it did in the 2015 IRP because of the capacity
reallocation between ldaho Power and PacifiCorp.toz STOP B2H accuses ldaho Power
of failing to disclose the asset exchange to the appropriate commissions and claims that
because of the exchange, ldaho Power now has sufficient firm transmission to the
Northwest and does not need B2H. STOP B2H's claims are incorrect.
First, in the asset exchange, Idaho Power acquired assets associated with the
ldaho-to-Northwest path from PacifiCorp. By acquiring these assets, ldaho Power has
been able to reduce wheeling costs associated with importing energy across the ldaho-
to-Northwest path. ldaho Power also addressed any uncertainty around future usage
by now owning-rather than merely using-the assets. However, contrary to STOP
B2H's claims, the asset exchange did not provide ldaho Power with any new capacity.
ldaho Power was utilizing this capacity prior to the asset exchange, and continues to
utilize this capacity post asset exchange. Thus, the asset exchange increased system
utilization/efficiency through reduced wheeling costs-not increased capacity.
Second, there is no additional transmission capacity available for imports to
Idaho Power from the Northwest. Idaho Power is a summer peaking utility, while the
remainder of the Northwest is winter peaking. Therefore, the Northwest has a surplus
of electrical power capacity and energy during ldaho Power's peak demand period.
ldaho Power currently utilizes the Northwest power markets to meet peak demand
102 STOP B2H Comments at 7-8
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 47
needs in late June and early July and to make economic market resource purchases
throughout the year. However, the transmission system between the Northwest and
ldaho is capacity constrained. ldaho Power is unable to deliver incremental market
purchases to customers in the ldaho Power service territory. The B2H project will
increase transmission capacity between the Northwest and ldaho that will allow ldaho
Power to deliver additional lower-cost energy to Idaho Power customers from resources
in the Northwest.l03
Third, ldaho Power fully disclosed to the ldaho and Oregon commissions the
effects of the asset exchange with PacifiCorp. ln fact, the Company obtained approval
for the asset exchange from both commissionslo4 and the transmission rights resulting
from the asset exchange are properly modeled in the lRP.
2. .10s
With regard to B2H's role in regional transmission planning, the Company notes
that, in addition to meeting an identified ldaho Power resource need, B2H has long
been identified as a critical transmission project to bolster the reliability and resiliency of
the regional transmission grid. For more information, please see the 2017 lRP
Appendix D: B2H Supplement (pages 16-17), Attachment 1.
103 Page 58 of the 2017 IRP provides more information about the existing transmission capacity
constraints, and the issue is also addressed in greater detail in the B2H addendum at 13-16.
1il ln the Matter of the Application of PacifiCorp DBA Rocky Mountain Power and ldaho Power
Company for an Order Authorizing the Exchange of Certain Transmission Assets, Case Nos. IPC-E-14-41
andPAC-E-14-11,OrderNo.33313(June5,2015). lntheMatterofPacifiCorp,dbaPacificPowerand
ldaho Power Company, Request for Approval to Exchange Certain Transmission Assets Associated with
the Jim Bridger Generation Plant, Docket No. UP 315, Order No. 15-184 (June 9, 2015).
1os 2017 IRP Appendix D: B2H Supplement at 16-17.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 48
C. Costs.
1. The Costs of B2H Compare Favorablv to Competinq Resources.106
The B2H line has consistently been the most cost-effective resource modeled in
ldaho Power's lRP. When evaluating and comparing alternative resources, there are
two major cost components: (1) the fixed, or capacity cost of the project, and (2) the
variable, or energy cost, of the project. The capacity costs for a resource reflect the
estimated cost to construct the resource. The energy costs are calculated using a
detailed model (the AURORA model) that considers forecasted natural gas prices, coal
prices, hydro conditions, loads, and numerous other factors intended to provide a
comprehensive forecast of the resource's operation and dispatch over a long-term
planning horizon, taking into consideration how the proposed resource wil! interact with
ldaho Power's existing resource portfolio.
Different resources will have different capacity and energy costs, reflecting the
fact that some resources are expensive to build, but generate low-cost electricity (e.9., a
solar plant), while other resources are low-cost to construct, but have high operating
costs (e.9., a diesel generator). Therefore, an assessment of total resource costs
requires consideration of both capacity and energy costs.
The table below provides the capacity costs for several different types of
resources considered in the 2017 lRP.107 Please note that solar costs have been
updated from those reported in the IRP with capital costs from the November 2017
Lazard energy cost report. The capita! costs for B2H in the table below reflect the
inclusion of local interconnection costs and, consequently, also differ from the per kW
cost reported in the 2017 IRP Appendix C: Technical Report. Also, local
loo 2017 IRP Appendix D: B2H Supplement at6-7.
107 The original table is found on page 73 of the 2017 IRP Appendix C: Technical Report.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 49
interconnection costs for B2H were included in portfolio cost modeling performed for the
IRP.
Table 1: Tota! Gapital $rkw for select resource considered in the 2017 IRP
Resource Type Total Capital $/kW Tota! Capital
$/kW-peak
Depreciable
Life
Boardman to Hemingway $783.$548**55 years
CCCT (1x1) F Class (300 MW)$1,344 $1,344 30 years
SCCT - Frame F Class (170
MW)$995 $995 30 years
Reciprocating Gas Engine $887 $887 30 years
Solar PV - Utility Scale 1-Axis $1,382 $2,692 25 years
* Utilizes the B2H 350 MW average capacity.** Utilizes the B2H 500 MW April-September capacity.
As indicated in Table 1, the total capital costs (peak) for B2H are 62 percent of
the cost of the next lowest-cost resource. Additionally, as a transmission line, B2H will
depreciate over 55 years, as compared to 30 years for a gas plant-meaning that B2H
will continue to provide customer benefits long after the competing resources will have
been retired. lmportantly, the B2H cost estimate above includes a 20 percent
contingency that is not included for any of the other resources. Thus, the construction
costs of B2H could increase significantly and it would still have lower capital costs than
the competing resources by a substantial margin.
The energy costs associated with B2H reflect the increased market transactions
enabled by a larger connection to Northwest markets. The price of market purchases in
the summer months is generally a function of the price of natural gas. With B2H, ldaho
Power would therefore pay a slight premium for market power, as compared to owning
a natural gas plant. This slight premium is reflected by the fact that in each resource
portfolio that includes B2H, the portfolio has a higher energy cost than the non-B2H
portfolio.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS.50
Although B2H has a slightly higher energy cost compared to alternatives, its
dramatically lower capacity costs far outweigh the increased energy costs. Thus,
portfolios containing B2H are consistently lower-cost than portfolios that do not.
Energy efficiency or a CCCT plant could be comparable to if not less expensive
than B2H, and may be considered by some as compelling alternatives to BzH.
However, the 2017 IRP already includes all cost-effective energy efficiency in all the
portfolios and therefore incremental energy efficiency is not available to displace B2H.
And although a CCCT is a reasonable alternative, the Company's portfolio analysis
indicated that it did not perform as well as B2H in the portfolio modeling.
Moreover, B2H has been a cost-effective resource included in the Company's
preferred portfolio since the 2009 lRP. The fact that it has consistently out-performed
competing resources, despite changing market conditions and resource costs over the
last eight years, reflects favorably on its durability and ability to withstand dramatic
changes in market conditions. The B2H project brings additional benefits beyond cost-
effectiveness. The B2H project will increase the efficiency, reliability, and resilience of
the electric system by creating an additional pathway for energy to move between major
load centers in the West. The B2H project also provides the flexibility to integrate any
resource type and move existing resources during times of congestion, benefiting
customers throughout the region. According to the ElA, different resource types have
different values to the system.1o8 ldaho Power believes that B2H provides value to the
system beyond any individua! resource because it enhances the flexibility of the existing
system and facilitates the delivery of cost-effective resources not only to ldaho Power
customers, but customers throughout the Pacific Northwest and Mountain West regions.
108 U.S. Energy lnformation Administration, "Levelized Cost and Levelized Avoided Cost of New
Generation Resources in the Annual Energy Outlook 2014" , April2014.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 51
STOP B2H requests that the Company provide an estimate of the customer bill
impact associated with the B2H line.1oe The estimated system revenue requirement
impact for B2H will be approximately $38 to $45 million.110 More importantly, however,
because the B2H portfolio is the least-cost portfolio in the 2017 lRP, the estimated
customer rate impact associated with not building B2H will necessarily be higher.
2. The Continqencv Cos bly Accountlor
the Risk of Cost-Overruns.l1r
STOP B2H states definitively that cost-overruns "for transmission lines are
between 30-50%' and questions whether the Company has accounted for the possibility
of a cost-overrun.112 As set forth above, the costs of B2H used in the portfolio modeling
include a 20 percent contingency intended to capture the risk associated with possible
cost-overruns. And even with the 20 percent contingency, the costs of B2H are
substantially below the next best alternative. Moreover, STOP B2H's definitive claim
that cost-overruns "are between 30-50%" is based on a limited set of examples of
projects constructed by other utilities in other parts of the country. The detailed cost
estimate for the transmission line construction was prepared by HDR, the Owners'
Engineer for the B2H project. HDR relied on experience and industry knowledge to
prepare estimates. ldaho Power calibrated HDR estimates against recent transmission
line projects in the West, including recent projects for both BPA and PacifiCorp. There
1os STOP B2H Comments at 17
110 The Company's website contains a report called the "Estimated Revenue Requirement lmpact
Disclosure," which is intended to provide ldaho Power customers with a resource for identifying and
understanding potential large capital projects and investments. The current report includes information
for projects identified forthe first 1O-year period in the preferred portfolio of the 2015 lRP, Order No. 16-
160; however, for B2H, the estimated revenue requirement is still consistent with ldaho Powe/s 2017 IRP
estimates. The report is available at the following link:
https://www.idahopower.com/about-us/company-information/rates-and-requlatory/reports/.
111 2017 IRP Appendix D: B2H Supplement at 38-40.
112 STOP B2H Comments at 16.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 52
is no evidence that the cost-overruns that occurred for those few other projects will
occur for the B2H project.
STOP B2H also claims that the contingency costs must account for the costs
associated with burying certain segments of the proposed line and the potential litigation
associated with permitting the construction of the line. The Company's cost estimates
for B2H include permitting costs, which account for litigation costs, and 20 percent
contingency is for any unexpected cost increase.
3. The Costs of B2H are Properly Modeled over the 20-Year lRP
Planninq Horizon
STOP B2H argues that ldaho Power has understated the true costs of B2H by
limiting its analysis to only the 20-year planning horizon used for the lRP. Specifically,
STOP B2H claims that ldaho Power should mode! the inflation rate and financing costs
for the entire life of the resource.113 Modeling B2H as a S5-year resource, as STOP
B2H recommends, would create a mismatch with the 20-year planning horizon used in
the lRP, making it inapt to compare B2H to competing alternative resources with shorter
lives. The Company's modeling is consistent with Order No. 22299, the OPUC's lRP
guidelines and is consistent with generally accepted financial accounting practices for
comparing projects with unequal lives.
Moreover, as noted above, B2H has a lower installed capacity cost than
competing resources and will have a longer useful life. Thus, the extended life does not
disadvantage customers even though the depreciable life will be longer than a
generation resource. lndeed, all portfolio modeling could be extended to 55 years,
requiring a "replacement chain" analysis to be performed. However, the result would
113 STOP B2H Comments at 16.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS.53
simply demonstrate even higher net present value benefits associated with B2H by
virtue of its longer useful life.
Finally, contrary to STOP B2H's implication, the Company's estimated cost of
capital is included in the cost estimate for B2H, just as those costs are included in the
construction costs of the other competing resources on a consistent and comparable
basis.
4. ldaho Power Appropriatelv Modeled the Enersv Costs Associated
with Market Purchases Facilitated bv B2H.1ra
STOP B2H claims that the IRP "ignores the cost of wheeling PNW power to the
ldaho Power system" because B2H "will not access any power plants directly."11s This
is incorrect. The AURORA model used to develop energy costs includes wheeling
expenses and line losses when determining the economics of importing energy within
the hourly dispatch optimization.
D. Market rchases.
1. The Northwest Market Depth is Sufficient to Support the Modeled
lmports Enabled bv B2H.
The Company has conducted extensive analysis of expected market conditions
and is confident that there is sufficient market depth to allow the Company to utilize the
market transactions that B2H will allow. The market purchases included in the cost
analysis are determined during the AURORA modeling. The AURORA model
determines the lowest cost alternative of either self-generating or importing via a market
purchase with losses and transmission wheeling costs to serve load, and considers both
generation and market constraints in its modeling.
114 2017 IRP Appendix D: B2H Supplement at 8-11
115 STOP B2H Comments at 16.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 54
The Council recently studied the Northwest power system to determine resource
adequacy utilizing a five-year forecast. ln July 2017, the Council published its 2022
Assessment. The Council, through its analysis, attempts to quantify resource adequacy
through a loss of load probability ("LOLP") analysis. ln Figure 4 below, a higher LOLP
indicates worse performance (more customer risk), and a lower number indicates better
performance. ldaho Power's peak load occurs in a narrow window in the late-
June/early-July time frame. The figure below illustrates that the Northwest will continue
to have sufficient resources available for ldaho Power to purchase and deliver to ldaho
Power customers across the B2H line.
The NWPCC figure suggests that the Northwest region, as a whole, must add
resources to address deficiencies in the winter and late summer. Resource additions to
address these needs will further increase late-June/early-July resource availability.
Figure 4: Monthly LOLP
3.0
r OY 2022 r OY 2O2L
2.5
}OZL Annual LOLP = 6.9Yo
2022 Annual LOLP =7.2Yo
I
CL
o
-t.}-c+,Co
2.O
1.5
.01
ll.
0.5
0.0 E B E E € -E EE. E 5 = E E S
I ,l
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 55
r
Adding to the NWPCC analysis, the recent lRPs of various regional utilities
indicate new resources will be built in response to coal retirements, load groMh, and
renewable portfolio standards ('RPS"), thereby providing the market volumes necessary
to support the imports assumed in the B2H portfolios. The table below summarizes the
recently filed IRP's resource additions and retirements plans to reliably meet their load.
Table 2: lntegrated Resource Plan Summary for Various Western Utilities
lntegrated Reeurce Pla Summry for Varoius Westsm Udlites
Resource Additions, Retiments and Ma*et Purchases
As ot Ortober 201 7
Bowlrldr
1Xl CC
Battery
cccr
CCCT (Remaining 29% of Silverhawk)
Oispatchable Standby Gen
Efficlent Gpedty (CCf)
Genaic (Frame GasCT)
Geothermal
Hydro
tandflll
Natural Ga
Nuclear (Diabb Canyon)
Peaker
Reciprocating engines
Reduction in Coal / Gas
Reduction in Coal / Gas (Ft Churchill 2,Trary 3l lan 2029
Reduction in Coal / Gas{Eoardman and Mkt
Reduction in Coal / Gas (Reid Gardns Unit 4)
Reduction in Coal / Gas (Tracy 4 & 5)
Reduction in Coal JB 2
Reduction in Coal J81
Reduction in G6
Reporvered Wind
sccI
5ola
Storage
Therma!
Thermal Upgrades
Wind
Wood
Transmi$ion Capacity
GnndTolrl
Total Re$urce Additions
Total Reeurce Retirments
Total Tril$isbn Capahy Additions
Total
300
180
( 158)
480
(617)
726
1 Avita 2017 IRP published Aug. 31, 2017.
2 Pacifkorp 2017 IRP published furi|4,2017
3 Ponland Gaeral IRP published Nov, 2016.
4 Puget Sound IRP published Nov,2015. 2017 IRP ilailable in Nov 2017.
5 BC Hydro IRP published in 2015. Trhnnial filing available in 2018.
726
t89
Total
Sum of ldrho
Pow6
Sm of Aviit.
11,
Sum of
FrcifiCorp (2|
Sum of
Pordand
Gcnenl (3)
tum of Puget
ssnd (4)
Smof
S€td. City
Litht
Sm of BC
Hydro (5)
792
143
15
5
136
rll'1
491
436
1,959
30
87?
1,041
{1,535}
(387)
(3se)
(3ssl
(3s8)
905
730
2,479
5,248
t3,099)
730
3,305
3.803
{4e7}
(4971
515
1,545
60
389
7.294
1,154
(1,31s)
1,086
126
805
1,495
3,351
4.656
( 1,315)
8
392
44
44tt
444
t1@
1,100
1,100
180
(1.862)
12,2s4l
ls27l
ls27t
{358)
1,420
136
4,982
44
1,456
t2,t@
76,232
(5,s28)
1,456
2,O82
186
1,194
2,932
30
1,100
8
877
1,056
5
3.306 3.351 444 1.100 1 2.15058949r2.879
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 56
Further, !daho Power's assessment of market liquidity demonstrates the
reasonableness of its reliance on future market transactions facilitated by the B2H line.
The Mid-Columbia market hub ("Mid-C") is a hub where power is traded actively both
financially (derivative) and physically in different blocks: long-term, monthly, balance-of-
month, day-ahead and hourly. The Mid-C market exhibits all six characteristics of a
successful electric trading market.116 Figure 5, below, shows the relative volume of
energy in the Northwest.
Figure 5: Northwest Regional Forecast
Make Up of Existing Generation
r tnsul,ed Capac,ty Winter Paak
{apadty
:l.{,ESMw 1$a
r iwo r &ocvlHrg{llEr r Soai(. Wfi . ftudax . Saralrtanaal&f&c.{xFtr. l'ttr'{Ga . Co!!mnss.! . CeI
PilUCC
2017 l.Iorfnrcst Regional Forecasl
The Mid-C market is very liquid. ln 2017, on a day-ahead trading basis, daily
average trading volume during heavy load hours during the months of June and July
ranged from nearly 40,000 MWh to over 51,000 MWh. When combining heavy load
hours with light load hours, on a day-ahead trading basis, the monthly volumes for June
and July were each approximately 2,000,000 MWh. These volumes are in addition to
month-ahead trading volumes. Mid-C is by far the highest volume market hub in the
west which includes: COB, Four Corners, Mead, Mona, Palo Verde, and SP15. ln fact,
116 Appendix D: B2H Supplement at 8
5
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 57
frequently Mid-C volumes are greater than the other hubs listed above combined, as
shown for late November 2017 in the table below.
Table 3: West Day Ahead lndices
ln 2017, ldaho Power averaged approximately 55,000 MWh of Mid-C purchases
in June and July. As stated previously, the average monthly volumes at Mid-C, on a
day-ahead basis, were approximately 2,000,000 MWh. Based on these averages,
Idaho Power's purchases represented less than 3 percent of the total market volumes in
June and July. Based on the total transactions, ldaho Power represents a very small
fraction of the Mid-C volume during the months when ldaho Power relies on Mid-C the
most, further demonstrating that Mid-C is a highly liquid market with sufficient depth to
meet future resource needs.
ln addition, ldaho Power's market price risk analysis demonstrates that even if
supply decreases and prices increase, B2H remains least-cost of a broad range of
future market prices. ln fact, B2H portfolios remain the least-cost portfolios for all
natural gas price/market price sensitivities except the sensitivity that assumes a 400
percent natural gas increase over the Planning Case. Based on this sensitivity analysis,
the Company is confident that B2H remains least-cost over the reasonable range of
future market price scenarios.
Change(l)ilo. of
CompsnhsHub
wtd
Avg
lnder
Change{%
I Hi0h Low Vol(Mwh)l{o, of
Trades
Weekly
AYO
Monthly
AYO
Begin
Date
End
Date
IOB Of,-Peak 22 00 -3.25 -'tz.8t%2700 4,000 A 5 23 63 25 90 11t23t17 fizil17
3OB Peak 30 00 -4 50 -13 04%l0 00 1,200 3 2 Jt.t5 30 51 1124t1t 11ft4t't I:our Corne$ Ofl-Peak ZO.J3 -3.55 -14.86%z1 00 2,400 I 20 33 23 40 11n3t17 11r24!17
:our Corners Peak 24.00 -2.50 -9 43%24 00 24 00 400 1 2 24 00 27 50 fin4n7 fir24t17
24 08 -1.42 -5.5/%2,400Vlead Off-Peak 6 24.79 26 15 11tzil17 1124t1t
\rlead Peak 29 00 -2.81 -8.83%29 00 29 00 1,200 3 4 30 41 J2 53 1'lt24t1t 11U4t1t
Mro c oft-Peak 19 15 -5.t I -23.1 596 I /.50 32,000 39 1l 22 04 23 65 11t23t11 11r24t11
-2.24 -8 19%Mitt C Peak 21 14 25 50 ?125 25,600 64 1b 25 tA zo 9'l 11t24t1 t 11r24t1 I
M0na ofi-Peal(ZU UU -3.U0 -13.u4%2,40t 21 50 22 69 1123t11 1124t11
Mona Peak 2700 -4 00 -15 38%22 00 40c I 2 24 00 to14 11t24t1 t 11U4!11
Palo Verde Ofl-Peak 21 90 -2.06 -8.60%20 00 9,60[1?11 2293 ?4 81 fin3t1t 1124!17
Palo Verde Peak 26 38 -2.11 -7 609t 27 00 26 00 4,00c 10 5 27 47 29 68 11n4t1t 11u4!1I
SP15 EZ Gen OA LMP Peafi 38 00 13 88 -26.15%38 00 40c 1 2 44 94 45 27 fir24t11 11D4t1l
ST Day Ahead lndices
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS.53
STOP B2H argues that the Company's assumption that by 2026 almost 18
percent of forecasted peak load will be met by imports "lacks credibility.'117 ldaho
Power's review of regional resource adequacy assessments conducted by the Council
and BPA indicates that B2H will provide access to a wholesale electric market with
capacity for meeting summer load needs. ln addition, BzH provides expanded access
to the Northwest wholesale market and its attendant diverse mix of low-cost energy
resources and abundant zero-carbon energy.
2. The IRP's Forecasted Market Prices Account for Coal PIant
Retirements.
STOP B2H further claims that the IRP has insufficient analysis of the effect of
retired coal capacity on spot market power prices.118 ln fact, the planned retirement of
coal plant capacity is reflected in the spot market prices in the AURORA portfolio
analysis. Prior to conducting its portfolio analysis, the Company performed a long-term
capacity buildout using AURORA, to determine which regional coal plants would likely
be retired during the IRP planning period. This buildout was included in the Company's
portfolio analysis.
Table 4, below, represents the coal units retired in the AURORA long-term
capacity run. The Boardman, Valmy, and Jim Bridger units were not selected by
AURORA to retire in the long-term run. Table 4 shows the over 8,600 MW of capacity
that was retired in the AURORA long-term capacity buildout during the Company's 20-
year planning period.
117 STOP B2H Comments at 10
118 STOP B2H Comments at 11
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 59
Table 4: AURORA Capacity Build-Out Coal Retirements
Name Util ity HeatRateNameplateCapacitvlFuel ResourceBeginDate ResourceEndDate
Apache Station ST3 Arizona Electric PowerCoopera
Neil Simpson ll (Gillette) (Unit2) Black Hills Power&LiShtComp
10293
72400
9952
10157
11011
9674
10774
9730
9895
9762
10481
10113
11484
9845
1@39
9433
9860
10413
9829
9974
1!t89
11670
11670
11670
8905
11140
10m0
100m
120@
120@
7/!2@1
9lurEgs
1/!teu
411179t36
611/IW
Tlrl$83
r2ll1972
51711963
10lLl1968
70lLlL97r
u717 2
ytlLs6s
717/796s
91717976
!u7w
121717979
r2lLl7979
1017/7980
5l!7s74
7y!7s7s
tll!79s9
7111/795e
tl|y7959
llrlr97
6ltllw
6l!2cf.3
rl!2017
3/tl2cf/6
sly2m,8
3l!2m8
t2l37l2Or8
r213712017
!213u202s
r213712026
1213712022
1213u2077
r213112028
r2137/2077
r213712077
r213u2077
L2l3!12077
r2l3!12020
nl3r/2037
Dl3r/2037
7213r12077
7213r/2077
,2l3rl2026
7213u2023
7213r120t9
7213112020
7213r12018
7u31120t8
7u3rl2018
7213712017
72l3rl20u
7u3t12017
12/3112011
r213u2033
r213112022
72131120t7
204 Coalus
80 CoalUS
778 CoalUS
778 CoalUS
172.8 CoalUS
294.8 CoalUS
729.9 CoalUS
163.2 CoalUs
217.6 CoalUs
326.4 CoalUs
U0.5 CoalUS
380.8 CoalUS
190 Coalus
275.4 CoalUS
191.7 CoalUS
555 CoalUS
410.9 CoalUS
410.9 CoalUS
803.1 CoalUS
445.4 CoalUS
11.5 CoalUS
11.5 CoalUS
11.5 CoalUS
79.3 Coalus
424.8 Coalus
88 coalUs
3m coalus
115.7 CoalUs
CoalUs
18.5 CoalUs
Colstrip 3
Colstrip 4
Corette 1
Reid Gardner 4
Centralia 1
Naughton 1
Naughton 2
Naughton 3
Cherokee 3
cherokee 4
Hayden 1
Hayden 2
Valmont 5
San luan 3
Coronado !.
Coronado 2
Navajo 1
CtaiE2
Nucla 1
Nucla 2
Nucla 3
Nucla 4
Springeruille 2
WYGEN #1-Gillette
Removed Two Elk
Hardin Generator Project
Lamar Plant #4A-48
Lamar Plant lt6
PPL lvlontana LLC
PPL Montana LLC
t\4ontana Power Co The - M
Nevada Power Co - NV
TransAlta Centralia Gen LLC
PacifiCorp
PacifiCorp
PacifiCorp
PublicSeruice co of colo
Publicseruice co of colo
PublicService co of colo
PublicSeryice co of colo
PublicSeruie Co ofColo
PublicSeruice Co of New
Salt River Pro,iect - AZ
Salt River Project - AZ
Salt River Project - Az
Tri-State Generation & Transmi
Tri-State Generation & Transmi
Tri-State Generation & Transmi
Tri-state Generation & Transmi
Tri-State Generation & Transmi
Tucson Electric Power Co
Black Hills
Postponed lndefinitely - North American Power Group
Rocky Mountain Power lnc
Lamar CO City of
Lamar CO city of
Total 8,ffi.2
Even accounting for the impact of coal retirements, the Company's preferred
portfolio, which includes B2H, remains the least-cost, least-risk scenario.
3.The IRP's Forecasted Market P rices Aoorooriatelv Reflect the
Relationship Between Natural Gas and Electric Priqeli.
STOP B2H claims that the IRP "fails to account for the relationship between daily
natural gas prices and the daily market price of power in the PNW'because, according
to STOP B2H, the Company used only a single point estimate for monthly power
prices.lle On the contrary, ldaho Power used extensive natural gas price sensitivities,
not single point estimates, to determine how the B2H portfolios withstood dramatically
different forecasted market prices. ln every scenario except the most extreme (i.e., a
11e STOP B2H Comments at 11
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 60
400 percent price increase), the BzH portfolios outperformed the next best
alternatives.l20
STOP B2H further argues that the IRP "penalize[s] non-B2H portfolios in the high
gas price sensitivities based upon the higher cost of dispatching existing and new gas-
fired resources, but does not similarly penalize B2H Portfolios that rely on relatively
higher cost market purchases in this higher gas environment."121 Again, this is untrue-
the market prices used in the IRP correctly correlate natural gas and electric market
prices. Figure 6, below, illustrates three stochastic iterations that show how natural gas
prices and Mid-C market prices share the same shape. This graphic shows that gas
fired resources and Mid-C market prices for import on B2H correctly correlate and thus
are treated fairly.
Figure 6: Mid C and Sumas Natural Gas Prices
Mid-C Markea and Sumas NaturalGas
52S
s2@
!1S
s25
920
51s
s10
-terarion44
GPlannintcase
-treration91
...... somastteratio.44 ......sumasPlan.i.gcne
t
=
slm
s50
s0
5s
50
120 To the extent that STOP B2H is focused on the fact the IRP used monthly, instead of daily,
prices, that concern is unfounded. For purposes of a 2}-year planning study, there is no need for the
granularity provided by daily pricing.
121 STOP B2H Comments at 13.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 61
4. B2H is Necessary for the Gompany to Enter lnto Bilatera! Contraqlo.
Bilateral market transactions are not an alternative to B2H-they are the resulting
energy resource facilitated by B2H. As discussed above, the Company has no
incremental transmission capacity from the Northwest. Therefore, without incremental
transmission, the Company cannot move generation from additional bilateral
transactions with Northwest generators to its service area. To engage in additional
bilateral market transactions, the Company needs B2H. Thus, contrary to claims that
bilateral transactions and B2H are competing resources, they are complementary and
B2H is a prerequisite to the Company entering into additional bilateral contracts.
5. The IRP's Transmission Topqloqy Accurately Reflects the Benefits of
B2H.
AURORA makes the optima! economic decision on where to purchase market
energy based on transmission constraints and resource dispatch costs. lf transmission
is available to one low-priced zone and two higher-priced zones, then AURORA will
choose to purchase power from the lowest cost zone-taking into consideration
wheeling costs and transmission line losses. Economically using regiona! resources to
achieve the lowest cost power supply helps to lower the cost for ldaho Power
customers.
E.The 2017 !RP Reasonablv Accounts for Third-Partv Transmission
Revenue.122
The inclusion of estimated third-party transmission wheeling revenue is new in
the 2017 IRP. To accurately quantify the total cost of the B2H line, additional third-party
transmission wheeling revenue resulting from the B2H line is appropriately included as
a revenue credit or an offset to the costs in the B2H portfolios.
122 2017 IRP Appendix D: B2H Supplement at40-41
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 62
STOP BzH doubts the existence of this third-party transmission wheeling
revenue.l23 STOP B2H also claims that the Company "hardwired" these revenues into
the AURORA model.124 STOP B2H is incorrect. The wheeling revenue is not an input
or output from the AURORA model. The additional transmission revenue is calculated
separately and included in the B2H portfolios.
VII. RISK ANALYSIS
ICL suggests that the risk analysis performed for the IRP inadequately captured
B2H's exposure to wholesale price volatility.l2s ldaho Power recognizes B2H's
exposure to wholesale electric price risk, and understands that the flexing of natural gas
price is not an exact simulation of flexed wholesale electric price. As noted by lCL, this
is particularly true in recent years during which abundant wind generation has
intermittently brought about a marked disconnect between the natural gas and electric
wholesale markets.
ldaho Power's risk analysis focuses on analyzing exposure to high market
conditions rather than volatile market conditions. Further, the finding that a resource
option performs well economically under high market conditions, does not mean that it
will not similarly outperform other resource options under volatile market conditions. ln
fact, B2H, as a dispatchable and flexible resource, is ideally suited for taking advantage
of market conditions in which intermittently available renewable generation periodically
drives wholesale electric prices to low levels.
ln contrast, less flexible and/or baseload generation resources (e.9., coal and
nuclear) have been disadvantaged economically by the wholesale electric price volatility
123 STOP B2H Comments at 14.
124 STOP B2H Comments at 14.
125ICL Comments at'15.
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 63
of recent years. Thus, while ldaho Power agrees with lCL that wholesale electric price
volatility has increased over recent years, it does not agree with the suggestion that the
risk analysis is deficient by failing to capture wholesale electric price volatility.
Additionally, ICL asserts that "ldaho Power's practice of relying exclusively on
historical records to assess future hydroelectric and customer load conditions may no
longer be valid."126 ldaho Power notes that IRP streamflow forecasting takes into
account trends and changes observed in Snake River Basin streamflows, and even
extrapolates trends as statistically significant or highly likely water management
practices.lzz,tza Thus, to describe the IRP's hydroelectric projections as relying
exclusively on historical records is incorrect.
VIII. CONCLUSION
Based on the detailed and comprehensive analysis set forth in the 2017 lRP,
along with these Reply Comments and the 2017 IRP Appendix D. B2H Supplement,
ldaho Power has demonstrated that its preferred portfolio, which includes the B2H
transmission line as a least-cost, least-risk resource, meets the resource need identified
in this lRP. ldaho Power respectfully requests acknowledgment of the Company's 2017
IRP as meeting both the procedural and substantive requirements of Order Nos. 22299,
25260, and 30317.
Respectfully submitted this 11th day of December 2017.
LISA D. NORD OM
Attorney for ldaho Power Company
126ICL Comments at 16.
127 2017lRP at 79_81.
128 2017 IRP Appendix C: Technical Report at 115-117
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS.64
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 11th day of December 2017 ! served a true and
correct copy of IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS upon
the following named parties by the method indicated below, and addressed to the
following:
Gommission Staff
Sean Costello
Deputy Attorney General
ldaho Public Utilities Commission
472 West Washington (83702)
P.O. Box 83720
Boise, ldaho 83720-007 4
lndustrial Customers of ldaho Power
Peter J. Richardson
RICHARDSON ADAMS, PLLC
515 North 27th Street (83702)
P.O. Box 7218
Boise, ldaho 83707
Dr. Don Reading
6070 Hill Road
Boise, ldaho 83703
Sierra Glub
Gloria D. Smith
Sierra Club
2101 Webster Street, Suite 1300
Oakland, California 94612
ldaho lrrigation Pumpers Association, lnc.
Eric L. Olsen
ECHO HAWK & OLSEN, PLLC
505 Pershing Avenue, Suite 100
P.O. Box 6119
Pocatello, ldaho 83205
X Hand Delivered
_U.S. Mail
_Overnight Mail
_FAXX Email [e-mail]
_Hand DeliveredX U.S. Mail
_Overnight Mail
FAX
x Email [e-mail]
_Hand DeliveredX U.S. Mail
_Overnight Mail
_FAXX Email [e-mail]
_Hand DeliveredX U.S. Mail
_Overnight Mail
_FAXX Email [e-mail]
_Hand DeliveredX U.S. Mail
_Overnight Mail
_FAXX Email [e-mail]
Anthony Yankel
12700 Lake Avenue, Unit 2505
Lakewood, Ohio 44107
_Hand DeliveredX U.S. Mail
_Overnight Mail
_FAXX Email [e-mail]
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 65
!dahydro
C. Tom Arkoosh
ARKOOSH LAW OFFICES
802 West Bannock Street, Suite 900
P.O. Box 2900
Boise, ldaho 83701
Micron Technology, lnc.
Thorvald A. Nelson
Emanuel T. Cocian
Kim Stanger
HOLLAND & HART, LLP
6380 South Fiddlers Green Circle, Suite 500
Greenwood Village, Colorado 80111
Pete Bennett
Micron Technology, lnc.
8000 South FederalWay
Boise, ldaho 83707
STOP B2H
Jim Kreider
STOP B2H
60366 Marvin Road
La Grande, Oregon 97850
Renewable Energy Coalition
Gregory M. Adams
RICHARDSON ADAMS, PLLC
515 North 27th Street
Boise, ldaho 83702
_Hand DeliveredX U.S. Mail
_Overnight Mail
_FAXX Email [e-mail]
erin. cecil@arkoosh. com
_Hand DeliveredX U.S. Mail
_Overnight Mail
_FAXX Email [e-mail]
etcocian @ hol la nd hart. com
kcsta nqer@ hol land hart. com
[e-mail]
_Hand DeliveredX U.S. Mail
_Overnight Mail
_FAXX Email [e-mail]
_Hand DeliveredX U.S. Mail
_Overnight Mail
_FAXX Email [e-mail]
_Hand DeliveredX U.S. Mail
_Overnight Mail
_FAXX Email [e-mail]
sta
IDAHO POWER COMPANY'S REDACTED REPLY COMMENTS - 66
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
GASE NO. IPC-E-17-11
IDAHO POWER COMPANY
ATTACHMENT 1
APPENDIX D: B2H SUPPLEMENT