20171211Appendix D.pdf

effi*.INTEGRATED RESOURCE PLAN
An IDACORP Company
APPENDIX D: B2H SUPPLEMENT
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SAFE HARBOR STATEMENT
This document may contain Iorward-looking statements,
and it is important to note that the future results could
differ materially from those discussed. A full discussion
of the Iactors that could cause future results to differ
materially can be found in ldaho Power's filings with the
Securities and Exchange Commission.
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38ffi*.INTEGRATED RESOURCE PLAN
An IDACORP Company
APPENDIX D: B2H SUPPLEMENTIRP
ACKNO\/1rLEDGEMEI{T
Resource planning is an ongoing process at ldaho Power. ldaho Power
prepares, files, and publishes an lntegrated Resource Plan (lRP) every two
years. ldaho Power expects that the experience gained over the next few
years will likely modi{y the 2O-year resource plan presented in this
document.
ldaho Power invited outside participation to help develop the 2017 lRP.
ldaho Power values the knowledgeable input, comments, and discussion
provided by the lntegrated Resource Plan Advisory Council and other
concerned citizens and customers.
It takes approximately one year for a dedicated team of individuals at
ldaho Power to prepare the lRP. The ldaho Power team is comprised of
individuals that represent many departments within the company. The
IRP team members are responsible for preparing forecasts, working with
the advisory council and the public, and performing all the analyses
necessary to prepare the resource plan.
ldaho Power looks fonruard to continuing the resource planning process
with customers, public-interest groups, regulatory agencies, and other
interested parties. You can learn more about the ldaho Power resource
planning process at idahopower.com.
DECEMBER o 2017
7
\
ldaho Power Company Appendix D-B2H Supplement
TaeLe oF GoNTENTS
List of Figures.......
List of Appendices
Executive Summary..
Resource Need Evaluation
Capacity Needs .........
IRP Guideline Language-Transmission Evaluated on Comparable Basis
Boardman to Hemingway as a Resource
I
IV
......v
... I
...5
...5
...5
Capacity Costs
Energy Cost..........
Market Overview
Power Markets
Mid-C Market
Mid-C and Idaho Power.......
Modeling of the Mid-C Market in the IRP.........
B2H Comparison to Other Resources.
Idaho Power's Transmission System......
...8
8
.......10
... .... I I
.......1I
.......t2
Transmission Capacity Between Idaho Power and the Pacific Northwest ............13
Montana-Idaho Path Utilization ................15
Idaho to Northwest Path Utilization ..........16
Regional Planning-Studies and Conclusions...t6
t7The B2H Project...
Project History ....t7
....17Public Participation...............
Project Activities.....
2006...
...20
...20
2017 tRP Page i
Appendix D-B2H Supplement ldaho Power Company
20
20
202009.......
2010.......
2011.......
2012.......
2013.......
2015.....
Ice
.20
.20
.21
.21
.21
.21
.21
.21
.22
.27
.28
.29
.29
.31
.32
.JJ
.34
.34
.35
..35
..35
..35
2016..........
2017..........
Route History.............
B2H Capacity Interest
Capacity Rating-WECC Rating Process
B2H Design
Transmission Line Design
Transmission Line Structural Loading Considerations......
Transmission Line Foundation Design
Lightning Performance ...
Earthquake Performance .
Wildfire
Wind Gusts/Tomados
Landslide..
Flood
Direct Physical Attack .....
B2H Design Conclusions....................
Project Co-Participants ...............
Page ii 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
PacifiCorp and BPA Needs..35
36
37
a-3t
38
38
38
39
39
39
PacifiCorp
BPA.....
Co-Participant Expenses Paid to Date
Co-Participant Agreements ..
Cost..........
Cost Estimate .............
Transmission Line Estimate....
Substation Estimates
Calibration of Cost Estimates
Costs Incurred to Date .......
Cost-Estimate Conclusions
Transmission Revenue .............
.40
.40
.40
.41
.42
.42
.43
.44
.44
.45
.46
.47
.47
.48
.48
.49
.49
.49
Potential BPA and Idaho Power Asset Swap.........
Benefits.....
Capacity
Avoid Constructing New Resources (and Potentially Carbon-Emitting Resources...
Improved Economic Effi ciency
Renewable Integration
Grid Reliability/Resiliency ..
Resource Reliability.
Reduced Electrical Losses ...
Flexibility..
EIM
B2H Complements All Resource Types....
B2H Benefits to Oregon................
Economic and Tax Benefits.....
Local Area Electrical Benefits..
2017 tRP Page iii
Appendix D-B2H Supplement ldaho Power Company
Risk .....50
.....5 I
.....52
.....52
Capital-Cost Risk......
Market Price Risk
Liquidity and Market Sufficiency Risk.....
Data Point 1. Peak Load Analysis from Table 6
Data Point 2.Pacifrc Northwest Power Supply Adequacy Assessment for 2022-
Northwest Power Conservation Council Report.......
Data Point 3:2016 Pacific Northwest Loads and Resources Study-BPA.............
Data Point 4: Northwest and California Renewable Portfolio Standards
Market Sufficiency and Liquidity Conclusions
Co-Participant Risks
Siting Risk......
Schedule Risk.
Catastrophic Event Risk
Project Activities..
Schedule Update
Permitting
Post-Permitting ....
53
53
54
57
57
57
58
58
59
59
.59
.59
.60
Table l.
Table 2.
Table 3.
Table 4.
Table 5.
Table 6.
LIsT oF TABLES
Total capital $/kW for select resources considered in the 2017 IRP
High-level differences between resource options
Pacific Northwest to Idaho Power import transmission capacity from the
201 6 transmission forecast
The Idaho to Northwest Path (WECC Path 14) summer allocation
B2H joint permit funding capacity interests by funder
2026 peak load estimates-illustration of load diversity between western
regions
Page iv 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
Table 7.
Table 8.
Table 9.
Table 10
NERC-AC transmission circuit sustained outage metrics
NERC forced-outage rate information for a fossil or gas power plant
Projected annual B2H tax expenditures by county
2027 datapoints from Figure 12
LIsT oF FIGURES
Northwest regional forecast (Source: 2017 PNUCC)
Idaho Power transmission system map
Routes developed by the CAP advisory teams (2009 timeframe)
B2H proposed route resulting from the CAP process (2010 timeframe)
BLM final EIS routes
BLM Agency Preferred route from the 2017 BLM ROD
B2H route submitted in20l7 EFSC Application for Site Certificate
Transmi ssion tower components
Comparison of total portfolio costs from 2017 IRP (Table 9.3 in2017
rRP)
Correlation between Mid-C market prices and natural gas prices
2021-22 LOLP by month (Source: NWPCC northwest analysis)
January, June, and July forecast Pacific Northwest resource surplus/deficit
(Source: 2016 BPA White Book)
Figure 1.
Figure 2.
Figure 3.
Figure 4.
Figure 5.
Figure 6.
Figure 7.
Figure 8.
Figure 9.
Figure 10.
Figure I l.
Figure 12.
LIsT oF APPENDIcES
Appendix D-l.Transmission line alternatives to the proposed B2H 500-kV
transmission line
Appendix D-2.Detailed list of notable project milestones
Appendix D-3.B2H funding agreement
Appendix D-4.B2H MOU
Appendix D-5.NTTG studies
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Appendix D-B2H Supplement ldaho Power Company
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ldaho Power Company Appendix D-B2H Supplement
EXCCUTvE SUMMARY
The Boardman to Hemingway Transmission Line Project (B2H) is a planned 500-kilovolt (kV)
transmission project that would span between the Hemingway 500-kV substation near Marsing,
Idaho, and the proposed Longhorn Substation near Boardman, Oregon. Once operational,BzH
will provide Idaho Power increased access to reliable, low-cost market energy purchases from
the Pacific Northwest. Idaho Power's planned capacity interest in B2H will increase the
availability of capacity and energy of the Pacific Northwest market by 500 megawatts (MW)
during the summer months, when energy demand from Idaho Power's customers is at its highest.
B2H (including early versions of the project) has been a cost-effective resource identified in each
of Idaho Power's integrated resource plans (IRP) since 2006 and continues to be a cornerstone of
Idaho Power's 2017 IRP preferred resource portfolio. In the 2017 IRP, as has been the case in
prior IRPs, the B2H project is not simply evaluated as a transmission line, but rather as a
resource that will be used to serve Idaho Power load. That is, the B2H prqect, and the market
purchases it will facilitate, is evaluated in the same manner as a new combined-cycle gas plant,
or a new utility-scale solar complex.
As a resource, the B2H project is demonstrated to be the most cost-effective method of serving
projected customer demand. In the 2017 IRP, B2H was identified as the least-cost and least-risk
resource to serve peak-hour load deficits forecast to occur beginning in2026. As can be seen in
Table 9.3,page 111 of the 2017 IRP, the four lowest-cost resource portfolios (P1, P4, P7, and
Pl0) each included B2H. The information presented in Table 9.3 also indicates that the next
lowest-cost portfolio that does not include B2H had a present-value portfolio cost of
approximately $147 million dollars greater than Idaho Power's preferred resource portfolio, P7.
When compared to other individual resource options, B2H is also the least-cost option in terms
of both capacity cost and energy cost. B2H is expected to have a capacity cost that is 71 percent
lower than either a combined-cycle gas plant or utility-scale solar alternatives.l B2H is also
expected to have a levelized cost of energy that is 22 percent lower than a combined-cycle gas
plant and 38 percent lower than utility-scale solar.2 As a resource alone, B2H is the lowest-cost
alternative to serve Idaho Power's customers in Oregon and Idaho. As a transmission line, B2H
also offers incremental ancillary benefits and additional operational and resource integration
flexibility.
In addition to being the least-cost, lowest-risk resource to meet Idaho Power' resource needs,
the B2H project has received national recognition for the benefits it will provide. The B2H
| 2017lRP, page 87, Figure 7.5.
2 2017lRP, page 89, Figure 7.6.
Footnotes continued on the next page.
2017 tRP Page 1
Appendix D-B2H Supplement ldaho Power Company
project was selected by the Obama administration as one of seven nationally significant
transmission projects that, when built, will help increase electric reliability, integtate new
renewable energy into the grid, create jobs, and save consumers money. Most recently, B2H was
acknowledged as complementing the Trump Administration's America First Energy Plan, which
addresses all forms of domestic energy production. In a November 17, 2017, United States (US)
Department of the Interior press release,3 B2H was held up as "a Trump Administration priority
focusing on infrastructure needs that support America's energy independence..." The release
went on to say, "This project will help stabilize the power grid in the Northwest, while creating
jobs and carrying low-cost energy to the families and businesses who need it..." The benefits
B2H is expected to bring to the region and nation have been recognized across both major
political parties.
Under a 2012 B2H Permit Funding agreement, Idaho Power is allocated a 21.2-percent project
interest, with PacifiCorp and Bonneville Power Administration (BPA) subscribed for the
remainder of the line's capacity. The agreement will allow Idaho Power customers to benefit
from the project's economies of scale and from load diversity between the project co-
participants. While Idaho Power's 21.2-percent share would provide for an annual average of
350 MW of west-to-east import capacity, the agreement is structured to provide Idaho Power
with 500 MW of import capacity during the summer months, when Idaho Power experiences
peak demand, and 200 MW of import capacity in the winter months, when the load-serving need
is less.
The total cost estimate for the B2H project is $1 to $1.2 billion dollars, which includes Idaho
Power's allowance for funds used during construction (AFUDC). Co-participant AFUDC is not
included in this estimate range. The total cost estimate includes a 20 percent contingency for
unforeseen expenses. In the 2017 IRP, Idaho Power assumes a21.2-percent share of the direct
expenses, plus its entire AFUDC cost, which equates to approximately $258 million in B2H
project expenses. Idaho Power also included costs for local interconnection upgrades totaling
$16 million. The 2017 IRP was the first year for which the B2H route was relatively certain,
resulting in a more accurate cost estimate compared to prior IRPs.
Idaho Power is the project manager for the permitting phase of the B2H project. The B2H project
achieved a major milestone nearly l0 years in the making with the release of the Bureau of Land
Management (BLM) Record of Decision (ROD) on November 17 ,2017 . The BLM ROD
formalized the conclusion of the siting process at the federal level, as required by the National
Environmental Policy Act of 1969 (NEPA). The BLM ROD provides the ability to site the B2H
project on BlM-administered land.
3 blm.gov/press-release/doi-announces-approval-transmission-line-project-oregon-and-idaho
Page2 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
For the State of Oregon permitting process, Idaho Power submitted the amended application for
Site Certificate to the Oregon Department of Energy in summer 2017 . Oregon's Energy Facility
Siting Council (EFSC) is tasked with establishing siting standards for energy facilities in Oregon
and ensuring certain transmission line projects, including B2H, meet those standards.a
Before Idaho Power can begin construction on B2H, it must obtain a Site Certificate from EFSC.
The Oregon EFSC process is a standards-based process based on a fixed site boundary. For a
linear facility, like a transmission line, the process requires the transmission line boundary be
established (a route selected) and fully evaluated to determine if the project meets established
standards. Idaho Power must demonstrate a need for the project before EFSC will issue a Site
Certificate authorizing the construction of a transmission line (non-generating facility). Idaho
Power's demonstration of need is based on the least-cost plan rule, for which the requirements
can be met through a commission acknowledgement of the resource in the company's IRP.s In
this case, Idaho Power seeks to satisfy EFSC's least-cost plan rule requirement through an
acknowledgement of its 2017 IRP.
As of the date of this report, Idaho Power expects the Oregon Department of Energy (ODOE)
to issue a Draft Proposed Order in 2018 and a Final Order and Site Certificate in2020.To
achieve an in-service date in the mid-2020s, preliminary construction activities must commence
in parallel to EFSC permitting activities. Preliminary construction activities include, but are not
limited to, geotechnical explorations, detailed ground surveys, sectional surveys, right-of-way
(ROW) acquisition activities, and detailed design and construction bid package development.
After the Oregon permitting process and preliminary construction activities conclude,
construction activities can commence.
This B2H 2017 IRP Appendix D provides context and details that support evaluating this
transmission line project as a supply-side resource, explores (qualitatively and quantitatively)
many of the ancillary benefits offered by the transmission line, and considers the risks and
benefits of owning a transmission line connected to a market hub in contrast to direct ownership
of a traditional generation resource.
a See generally Oregon Revised Statute (ORS) 469300469.563,469.590-469.619, and 469.930-469.992.
5 oAR 34s-023-0020(2).
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Appendix D-B2H Supplement ldaho Power Company
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ldaho Power Company Appendix D-B2H Supplement
ResouRcE Neeo EvnluRrroru
Gapacity Needs
The entire Integrated Resource Plan (IRP) process is predicated on defining a need for resources
in the future to serve projected customer demand.
The IRP analysis begins by developing a monthly load forecast, which incorporates the future
electricity needs of our customers. The load forecast consists of both average monthly (energy)
and monthly peak-hour (capacity) conditions. The existing Idaho Power resources (generating,
demand side management [DSM], and transmission) are evaluated against the load forecast. The
load less the available resources determines the load and resource balance. Times where the load
exceeds the resources defines the need for resources to reliably serve our customers.
All resources on Idaho Power's system are considered in the load and resource balance,
including hydro, gas, coal, existing cogeneration and small-power producer (CSPP) contracts,
existing power purchase agreements (PPA) (including the Public Utility Regulatory Policies Act
of 1978 [PURPA]), and available import transmission capacity. All supply-side resources, all
DSM and EE programs, and transmission import capacity are summed and subtracted from the
appropriate load forecast-either peak hour or average monthly. If the result of load is greater
than resources is, Idaho Power's system is resource insufficient and the need for a resource
is established.
As detailed in Idaho Power's 2017 IRP, Idaho Power has a peak-demand capacity deficit in the
year 2026. The Jim Bridger unit retirement evaluations in the 2017 IRP can accelerate the
capacity deficit date depending on the retirement date assumptions.
Refer to Chapter 7 of Idaho Power's 201 7 IRP for more information on the planning period
forecasts and establishment of need.
IRP Guideline Language-Transmission Evaluated on
Comparable Basis
In Order No. 07-002, the Public Utility Commission of Oregon (OPUC) adopted guidelines
regarding integrated resource planning. 6
Guideline 5: Transmission. Portfolio analysis should include costs to the utility
for the fuel transportation and electric transmission required for each resource
being considered. In addition, utilities should consider fuel transportaion and
electric transmissionfacilities as resource options, taking into account their value
6 apps.puc. state.or.us/or dersl 2007 ords/07-002.pdf
2017 tRP Page 5
for making additional purchases and sales, accessing less costly resources in
remote locations, acquiring altemative fuel supplies, and improving reliability.
Boardman to Hemingway as a Resource
The Boardman to Hemingway Transmission Line Project (B2H) is one of the most cost-effective
IRP resources Idaho Power has considered and proven through successive IRPs. When
evaluating and comparing alternative resources, two major cost considerations exist: 1) the
capacity cost of the project (fixed costs) and2) the energy cost of the project (variable costs).
The 2017 IRP details the results of each component of the various portfolios in Table 9.3 of the
IRP. Capital costs are derived through cost estimates to install the various projects. Energy costs
are calculated through a detailed modeling analysis, using the AURORA software. Energy prices
are derived based on inputs into the model, such as gas price, coal price, nuclear price, hydro
conditions, etc.
Illustrating the difference between capacity and energy, a diesel generator may have a very low
cost to install; however, the cost of diesel fuel and the maintenance required would be
significant. Alternatively, a utility-scale solar plant will have almost no energy cost; the fuel to
run the plant-the sun-is free. However, in the case of a solar plant, the capacity cost to install
the plant is quite expensive. The installed capacity needed to ensure the solar is available during
the ldaho Power peak is even larger.
Capacity Costs
Exploring the capacity costs of different resources, page 73 of the 2017 IRP Appendix C-
Technical Appendix details the total capital cost per kilowatt (kW) for many various resources.
This capital-cost data feeds into Table 9.3 of the main IRP report. Data from the technical
appendix is copied into Table I below for illustrative purposes. Note that solar costs have been
updated from those reported in the IRP with capital costs from the November 2017 Lazard
energy cost report.T The capital costs for B2H in the table below reflect the inclusion of local
interconnection costs for B2H, and consequently also differ from the per-kW cost reported in the
IRP technical appendix. The local interconnection costs for B2H were included in portfolio cost
modeling performed for the IRP.
Table 1 Total capital $/kW for select resources considered in the 2017 tRP
Appendix D-B2H Supplement ldaho Power Company
Resource Type TotalCapital$/kW TotalCapital$/kw-peak DepreciableLife
B2H
Combined-cycle combustion
turbine (CCCT) (1xl) F Class
(300 megawatts [MW])
$783-
$1,344
$548*.
$1,344
55 years
30 years
Page 6 2017 tRP
7 Lazard's Levelized Cost of Energy Analysis-Version 11.0, November 2017.
ldaho Power Company Appendix D-B2H Supplement
Simple-cycle combustion turbine
-Frame F Class (170 MW)
Reciprocating Gas Engine
Solar Photovoltaic (PV)-
Utility-Scale 1-Axis
$99s
$887
$1,382
$995
$887
$2,692
30 years
30 years
25 years
* Utilizes the B2H 350-MW average capacity
*" Utilizes the B2H 500-MW average capacity
The B2H total capital cost per kilowatt at peak is 62 percent of the cost of the next lowest-cost
resource. Additionally,B2H, as a transmission line, will depreciate over 55 years compared to 30
years for a gas plant or 25 years for a solar plant. The low up-front cost and slower depreciation
further reduces the cost impact to Idaho Power's customers. Finally, the B2H cost estimate
includes a20 percent contingency, whereas none of the other resources evaluated in the 2017
IRP include a cost contingency. The summation of these factors suggest B2H is the lowest
capital-cost resource by a substantial margin.
Energy Cosf
B2H provides Idaho Power with more capacity to the Pacific Northwest to purchase power from
the Mid-Columbia (Mid-C) trading hub. Market power in the summer months is generally a
function of the price of natural gas. Idaho Power, in a B2H future, would therefore pay a slight
premium for market power compared to a future in which Idaho Power owned its own
combined-cycle gas plant. This slight premium is reflected in the 2017 IRP by comparing the
energy costs of B2H and the non-B2H gas portfolios: Pl and P3,P4 and P6, P7 and P9, and Pl0
andPl2.In each of these cases, the B2H portfolio has a higher energy cost than the non-B2H
portfolio. Higher energy costs for B2H portfolios are due to the following:
Idaho Power will pay a slight premium to Pacific Northwest entities for purchased power
(selling entities must recover some of their fixed costs).
P3, P6, P9, and P12 include Idaho Power constructing power plants rather than B2H.
In these portfolios, Idaho Power would have the opportunity to sell excess energy to the
market and generate revenue to offset costs.
Idaho Power must purchase transmission service (transmission wheeling) from a Pacific
Northwest entity (likely Bonneville Power Administration [BPA]) to transmit the
purchased power to the edge of Idaho Power's system at Longhorn Substation (once B2H
is built). If Idaho Power and BPA can complete an asset swap, these transmission
wheeling costs may be avoided, which would reduce the energy cost component of B2H
portfolios. Refer to Appendix D-4 for the Memorandum of Understanding (MOU)
relating to the potential Idaho Power-BPA asset swap.
a
a
a
2017 tRP PageT
Appendix D-B2H Supplement ldaho Power Company
The B2H portfolios' capacity costs are so low that capacity installation savings far outweigh
the additional energy costs, leading B2H portfolios to be the lowest-cost option for
Idaho Power's customers.
Market Overview
Power Markets
A power market hub is an aggregation of transaction points (often referred to as bus points or
buses). Hubs create a common point to buy and sell energy, creating one transaction point for
bilateral transactions. Hubs also create price signals for geographical regions.
Six characteristics of successful electric trading markets include the following:
1. The geographic location is a natural supply/demand balancing point for a particular
region with adequate available transmission.
2. Reliable contractual standards exist for the delivery and receipt of the energy.
3. There is transparent pricing at the market with no single player nor group of players with
the ability to manipulate the market price.
4. Homogeneous pricing exists across the market.
5. Convenient tools are in place to execute trades and aggregate transactions
6. Most importantly, there is a critical mass of buyers and sellers that respond to the five
characteristics listed above and actively trade the market on a consistent basis. This is the
definition of liquidity, which is clearly the most critical requirement of a successful
trading hub.
Mid-C Market
The Mid-C electric energy market hub is a hub where power is transacted both physically and
financially (derivative). Power is traded both physically and financially in different blocks:
long term, monthly, balance-of-month, day ahead, and hourly. Much of the activity for
balance-of-month and beyond is traded and cleared through a clearing exchange,
the Intercontinental Exchange (ICE). For short-term transactions, such as day-ahead and real
time (hourly), trades are made primarily between buyers and sellers negotiating price, quantity,
and point of delivery over the phone (bilateral transactions). In the Pacific Northwest, most of
the price negotiations begin with prices displayed for Mid-C on the ICE trading platform.
The Mid-C market exhibits all six characteristics of a successful electric trading market
discussed above. Figure 1 shows the relative volume of energy in the Northwest.
Page 8 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
Make Up of Existing Generation
installed capacitY Winter P€ak
Capaclty
14,800 MW 6D52,600 MW
. tlydro. Witd. tlaturalc6
. Rffibles&s. Nudeat. ColEn€ratirn
. solat. Slrlall nl€rmal & Miscdlan€ous
. fid
Figure 1. Northwest regionalforecast (Source: 2017 PNUCC)B
In the western US, the other major market hubs are Califomia-Oregon Border (COB),
Four Corners (Arizona-New Mexico border), Mead (Nevada), Mona (Utah), Palo Verde
(Arizona), and SP15 (California). The Mid-C market is very liquid. In 2017, on a day-ahead
trading basis, daily average trading volume during heavy-load hours during June and July ranged
from nearly 40,000 megawatt-hours (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 MWhs. These volumes are in addition to month-ahead
trading volumes. Mid-C is by far the highest volume market hub in the west; frequently, Mid-C
volumes are greater than the other hubs combined.
The following market participants transact regularly at Mid-C. Additionally, numerous other
independent power producers trade at Mid-C.
a Avista Utility
o BPA
a Chelan County Public Utility District (PUD)
a Douglas County PUD
o Eugene Electric Board
o Idaho Power
o PacifiCorp
a Portland General Electric
8 pnucc. org/system-planning/northwest-regional-forecast
2017 tRP Page 9
a Powerex
Puget Sound Energy
Seattle City Light
Tacoma City Light
Energy traded at Mid-C is not necessarily physically generated in the Mid-Columbia River
geographic area. For instance, Powerex is a merchant of BC Hydro in British Columbia and
frequently buys and sells energy at Mid-C. A trade at Mid-C requires that transmission is
available to deliver the energy to Mid-C. Transmission wheeling charges must be accounted for
when transacting at Mid-C. Sellers at Mid-C must pay necessary transmission charges to deliver
power to Mid-C, and buyers must pay necessary transmission charges to deliver power to load.
Mid-C and ldaho Power
Historically, Idaho Power wholesale energy transactions have correlated well with the Mid-C
hub due to Idaho Power's proximity to the market hub and because it is the most liquid hub in
the region. Energy at Mid-C can be delivered to, or received from, Idaho Power through a single
transmission wheel through the BPA or Avista. Additionally, long-term monthly price quotes are
readily available for Mid-C, making it an ideal basis for long-term planning.
Idaho Power uses the market to balance surplus and deficit positions between generation
resources and customer demand, and to take advantage of price differences across the region.
For example, when market purchases are more cost-effective than generating energy within
Idaho Power's generation fleet, Idaho Power customers benefit from lower net power supply cost
through purchases instead of Idaho Power fuel expense. Idaho Power customers also benefit
from the sale of surplus energy. Surplus energy sales are made when Idaho Power's resources are
greater than Idaho Power customer demand and when the incremental cost of these resources are
below market prices. Idaho Power customers benefit from these surplus energy sales as offsets to
net power supply costs through the power cost adjustment (PCA).
In 2017, Idaho 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. At 3 percent of total
market volume on average in June and July, Idaho Power represents a very small fraction of the
Mid-C volume during the months when Idaho Power relies on Mid-C the most.
The Mid-C market could be used more to economically serve Idaho Power customers, but Idaho
Power's ability to transact at Mid-C is limited due to transmission capacity constraints between
the Pacific Northwest and Idaho. In other words, sufficient transmission capacity is currently
Page 10 2017 tRP
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Appendix D-B2H Supplement ldaho Power Company
ldaho Power Company Appendix D-B2H Supplement
unavailable during certain times of the year for Idaho Power to procure cost-effective resources
from Mid-C for its customers, even though generation supply is available at the market.
Modeling of the Mid-C Market in the IRP
As part of the IRP analysis, Idaho Power uses the AURORA to derive energy prices at the Mid-C
market. Energy prices are derived based on inputs into the model, such as gas price, coal price,
nuclear price, hydro conditions, etc. Refer to Chapter 9 of the 2017 IRP for more information on
AURORA and modeling.
Energy purchases from the market require transmission to wheel the energy from the source to
the utility purchasing the energy. Purchases from the Mid-C market would need to be wheeled
across the BPA system to get the energy to the proposed Longhorn Substation near Boardman,
Oregon.
Transmission wheeling rates and wheeling losses are included in the AURORA database and are
part of the dispatch logic within the AURORA modeling. AURORA economically dispatches
generating units, which can be located across any system in the West. All market energy
purchases modeled in Aurora include these additional transmission costs and are included in all
portfolios and sensitivities.
B2H Comparison to Other Resources
The 2017 IRP provides an in-depth analysis of the B2H project compared to alternative resource
options. Table 2 summarizes some of the high-level differences between B2H and other notable
resource options.
2017 tRP Page 11
Appendix D-B2H Supplement ldaho Power Company
Table 2. High-level differences between resource options
lntermittent
renewable
Dispatchable
capacity providing
Non-dispatchable
(coincidental)
capacity providing
Balancing,
flexibility providing
Energy providing
Variable costs
(primary variable
cost driver)
Capital costs
Fuel price risk
Wholesale power
market price risk
Other
1-axis solar PV
No variable costs
$2,500/on-peak
KW
Renewable, clean,
scalable (modeled
plants 30-MW
nameplate)
Notes:
1. ldaho Power's 2016 solar integration study suggests modest impacts from solar intermittency. Study based on synthetic
solar data. Actual production from currently onJine solar projects will be reviewed in 2018 to verify study findings.
2. Solar is not dispatchable but tends to produce at fairly high levels during periods of high customer demand (on-peak
capacity factor or contribution to peak equal to 51.3 percent of installed capacity).
3. Lithium battery is a net energy consumer (roundtrip efficiency = 86 percent). Lithium battery provides energy during heavy
load hours or other high energy demand/high energy value periods; battery recharge costs tied primarily to Mid-C market
costs or variable costs of ldaho Poweis system resources during light load hours.
4. B2H capital-cost estimate includes a 2O-percent contingency. Lithium battery capital costs are on a declining trend;
2017 Lazard reporting projects 1 0 percent per year annual rate of capital cost decline. Solar capital cost decline slowing.
B2H and solar capital costs are expressed in terms of $/on-peak kW, where on-peak kW for B2H are based on 500-MW
summer capacity and for solar is based on on-peak capacity equal to 51 percent of installed capacity.
ldaho Power's Transmission System
Idaho Power's transmission system is a key element to providing reliable, responsible,
fair-priced energy services. A map of Idaho Power's transmission system is shown in Figure 6.1
on page 58 of the 2017 IRP and in Figure 2. Transmission lines facilitate the delivery of
economic resources and allow resources to be sited where most cost effective. In most instances,
82H
Reciprocating
Engines cccT Lithium batteries
Mid-C market Natural gas Natural gas Mid-C market
$450/on-peak kW $77slkw $1,250/kW $1,7solkw
Expanded access to
market (Mid-C)
providing abundant
clean, renewable
energy, highly
reliable (low forced
outage), as long-
lived resources
promote stability in
customer rates,
benefit to regional
grid
Scalable
(modeled
generators
18.8-MW
nameplate),
relatively
short-lead
resource
Relatively
short-lead
resource
with recent
construction
experience
Nascent, uncertainty
related to
performance (e.g., #
of lifetime cycles),
potential grid benefit
depending on
resource siting,
scalable and
potential for
geographic
dispersion
Page 12 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
the most economic/best location for resources is not immediately next to major load centers
(i.e., hydro along the Columbia River, wind in Wyoming, solar in the desert southwest).
For much of its history, Idaho Power has taken advantage of resources outside of its major load
pockets to economically serve its customers. The existing transmission lines between Idaho
Power and the Pacific Northwest have been particularly valuable. Idaho Power has maximized its
use of the transmission path between Idaho and the Pacific Northwest. Additional transmission
capacity is required to access incremental resources to meet projected peak demand. The B2H
project is the mechanism to increase capacity between the Pacific Northwest and Idaho Power's
service area.
Transmission lines are constructed and operated at different operating voltages depending on
purpose, location, and distance. Idaho Power operates transmission lines at 138 kV, 161 kV,
230 kV, 345 kV, and 500 kV. Idaho Power also operates sub-transmission lines at 46 kV and
69 kV, but these voltages will not be discussed further in this appendix; the focus of this
appendix is on higher voltage transmission lines used for moving bulk electricity. The higher the
voltage, the greater the capacity of the line, but also the greater the construction cost and physical
size requirements.
The utility industry often compares transmission lines to roads and highways. Typically,
lower-voltage transmission lines (138 kV) are used to facilitate delivery of energy to substations
to serve load, like a two-lane highway. Much like roads and highways can become congested,
so can transmission lines. High-voltage lines are used to facilitate the bulk delivery of power,
sometimes referred to as backbone transmission. Depending on the capacity needs, economics,
distance (higher voltages result in less losses for longer distances), and intermediate substation
requirements, either 230-kV, 345-kV, or 500-kV transmission lines are used. A 230- or 345-kV
line can be compared to a multi-lane interstate, whereas a 500-kV line can be compared to a
major (6+ lane) freeway used to move as many vehicles as possible.
Transmission Capacity Between ldaho Power and the
Pacific Northwest
Idaho Power owns 1,280 MW of transmission capacity between the Pacific Northwest
transmission system and Idaho Power's transmission system. Of this capacity, 1,200 MW are on
the Idaho to Northwest path (Western Electricity Coordinating Council IWECC] Path 14),
and 80 MW are on the Montana-Idaho path (WECC Path l8). A transmission path is one or
more transmission lines that collectively transmit power to/from similar geographic areas.
The Idaho to Northwest transmission path is comprised of three 230-kV lines, one 500-kV
transmission line, and one 1 l5-kV transmission line. The capacity limit on the path is established
through a WECC rating process based on equipment overload ratings resulting from the loss of
the most critical element on the transmission system. Collectively, these lines between Idaho and
the Northwest have a transfer capacity rating that is greater than the individual rating of each line
2017 tRP Page 13
Appendix D-B2H Supplement ldaho Power Company
but less than the sum of the individual capacity ratings of each line based on reliability limits
Figure 2 shows an overview of Idaho Power's transmission system.
Figure 2. ldaho Power transmission system map
Table 3 details the capacity allocation between the Pacific Northwest and Idaho Power in2017.
The shaded rows represent capacity amounts that can be used to serve Idaho Power's native load.
Although Idaho Power owns 1280 MW of transmission capacity between the Pacific Northwest
and Idaho Power's system, after all other uses are accounted for, Idaho Power was only able to
use 307 MW to serve Idaho Power's native load in 2017.Idaho Power used 361 MW to serve
BPA or PacifiCorp network load on Idaho Power's system, 282 MW were allocated to
transmission reserve margin (TRM), and 330 MW were allocated to capacity benefit
margin (CBM).
Table 3.Pacific Northwest to ldaho Power import transmission capacity from the 2016
transmission forecast
Firm Transmission Usage (Pacific Northwest to ldaho Power) Capacity (July MW)
BPA Load Service (Network Customer)
Boardman Generation
Fighting Creek (PURPA)
360
60
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Page 14 2017 tRP
Pallette Load (PacifiCorp-Network Customer)
TRM
CBM
I
282
330
ldaho Power Company Appendix D-B2H Supplement
Subtotal
Pacific Northwest Purchase (ldaho Power Load Service)
1,037
243
Total 1,280
TRM is transmission capacity that Idaho Power sets aside as unavailable for frrm use, for the
purposes of grid reliability. Idaho Power's TRM methodology, approved by the Federal Energy
Regulatory Commission (FERC) in2002, requires Idaho Power to set aside transmission
capacity based on the average loopflow on the Idaho to Northwest path. In the west, electrical
power is scheduled through a contract-path methodology, which means if 100 MW is purchased
and scheduled over apath, that 100 MW is decremented from the path's total availability.
Physics dictate the actual power flow over the path (based on the path of least resistance), so
actual flows don't always follow contract-path schedules. This unscheduled flow is sometimes
referred to as loopflow. The average adverse loopflow across the Idaho to Northwest path during
the month of July is282 MW, which is equal to Idaho Power's TRM in July. Idaho Power
reserves TRM to ensure a safe and reliable transmission system.
CBM is transmission capacity Idaho Power sets aside as unavailable for firm use, for the
purposes ofrecovering from severe unexpected generation outages. Reserve generation capacity
is critical to being able to recover from unexpected outages. CBM allows a utility to reduce the
amount of reserve generation capacity on its system by providing transmission availability to
another market, such as the Pacific Northwest, which is rich with surplus capacity necessary for
emergency conditions. Idaho Power's 330 MW of CBM is based on Idaho Power's share of the
unplanned loss of two Jim Bridger units. The loss of two Jim Bridger units results in the removal
of over 1,000 MW of generation in Wyoming, leaving Idaho Power and PacifiCorp searching to
replace approximately 330 MW and 670 MW, respectively. Recovering from such an event,
especially during peak summer load, can be extremely difficult without access to
Pacific Northwest generation capacity, hence the reserve margin.
Montana-ldaho Path Utilization
To utilize Idaho Power's share of the Montana-Idaho 80 MW of capacity, Idaho Power must
purchase transmission service from either Avista or BPA. This transmission system connects the
purchased resource in the Pacific Northwest to Idaho Power's transmission system. Avista or
BPA transmits, or wheels, the power across their transmission system and delivers the power to
Idaho Power's transmission system. The Montana-Idaho path is identified in Figure 2 above.
2017 tRP Page 15
Appendix D-B2H Supplement ldaho Power Company
ldaho to Northwest Path Utilization
To utilize Idaho Power's share of the Idaho to Northwest capacity, Idaho Power must purchase
transmission service from Avista, BPA, or PacifiCorp. Table 4 details a typical sulnmer
allocation of the Idaho to Northwest capacity:
Table 4. The ldaho to Northwest Path (WECC Path 14) summer allocation
Transmission Provider Idaho to Northwest Allocation (SummerWest to East) (MW)
Avista (to ldaho Power)
BPA (to ldaho Power)
PacifiCorp (to ldaho Power)
Total Gapability to ldaho Power
340
350
s10
1,200*
* During times of very low generation at Brownlee, Oxbow, and Hells Canyon hydro plants, the ldaho to Northwest path total
capability can increase to as much as 1,340 MW; low generation at these power plants does not correspond with ldaho Power's
system peak.
Avista, BPA and PacifiCorp share an allocation of capacity on the western side of the Idaho to
Northwest path, and Idaho Power owns 100 percent of the capacity on the eastem side of the
Idaho to Northwest path. For Idaho Power to transact across the path and serve customer load,
Idaho Power's Load Servicing Operations must purchase transmission service from Avista, BPA,
or PacifiCorp to connect the selling entity, via a contract transmission path, to Idaho Power.
Construction of B2H will add 1,050 MW of capacity to the Idaho to Northwest path in the
west-to-east direction, of which Idaho Power will own 500 MW in the summer months (April-
September), and 200 MW in the winter months (January-March and October-December).
A total breakdown of capacity rights of the B2H permitting co-participants can be found in the
Project Co-Participants section of this report. The Idaho to Northwest path is identified in
Figure 2 above.
Regiona! Planning-Studies and Conclusions
The Northern Tier Transmission Group (NTTG) and Columbia Grid are regional planning
organizatrons that are organized and operate in compliance with FERC orders 890 and 1000.
The purpose of these organizations is to consolidate each member's local transmission plans and
determine a regional plan that can meet the needs of the combined member footprint in a
more efficient or cost-effective manner. The NTTG and Columbia Grid develop transmission
plans biennially.
B2H is a committed project in the most recent Columbia Grid lO-year plan, and it is part of the
projects compromising the NTTG 2014-2015 Biennial Plan and the soon-to-be-published NTTG
2016-2017 Biennial Plan. The identified need for the B2H project in these regional planning
organizations is based on transmission needs submitted by BPA, Idaho Power, and PacifiCorp.
Page 16 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
At NTTG, all member utilities submit their load forecasts, generation forecasts, and transmission
needs. NTTG studies the members' transmission footprints to determine the more efficient or
cost-effective plan to meet those needs.
B2H has been, and remains, an integral part of NTTG's 10-year plan. NTTG's analysis indicated
B2H is the most cost-effective and efficient project to meet the needs of the NTTG footprint.
Appendix D-5 contains the latest NTTG materials. For the most recent updates related to
Idaho Power's regional planning organization, please refer to the NTTG website atnttg.bizl
Tne B2H Pnolecr
Project History
The B2H project originated from Idaho Power's 2006 IRP. The 2006 IRP specified 285 MW of
additional transmission capacity, increasing Idaho Power's connection to the Pacific Northwest
power markets, as a resource in the preferred resource portfolio. A project had not been fully
vetted at that time but was described as a 230-kV transmission line between McNary Substation
and Boise. After the initial identification in the 2006 IRP, Idaho Power evaluated numerous
capacity upgrade alternatives. Considering distance, cost, capacity,losses, and substation
termination operating voltages, Idaho Power determined a new 500-kV transmission line
between the Boardman, Oregon, area and the proposed Hemingway 500-kV substation would be
the most cost-effective method of increasing capacity. Refer to Appendix D-1 for more
information on the upgrade options considered.
Transmission capacity, especially at 500 kV, can be described as "lumpy''because capacity
increments are relatively large between the different transmission operating voltages. In the 2009
IRP, Idaho Power assumed 425 MW of capacity, which was 50 percent of the assumed total
rating. Idaho Power's long-standing preference was to find a partner or partners to constructBzH
with to take advantage of economies of scale. In the 201I IRP, Idaho Power assumed 450 MW
of capacity . ln 2ll2,Idaho Power achieved two major milestones: 1) PacifiCorp and BPA
officially joined the B2H project as permitting co-participants and 2) Idaho Power received a
formal capacity rating for the B2H project via the WECC Path Rating Process (more on this
process in preceding section). In the 2013 IRP, Idaho Power began to use the negotiated capacity
from the permitting agreement: 500 MW in the summer and 200 MW in the winter, ayearly
average of 350 MW, for a cost allocation of 21 percent of the total project. Idaho Power used the
same 21.2 percent interest in the 2015 and 2017 IRPs.
Public Participation
The B2H project has involved considerable stakeholder involvement over the last 10 years.
Idaho Power has hosted and participated in over 250 public and stakeholder meetings with an
2017 rRP Page 17
Appendix D-B2H Supplement ldaho Power Company
estimated 3,000+ participants. After approximately a year of public scoping in 2008, Idaho
Power paused the federal and state review process and initiated a year-long comprehensive
public process to gather more input. This community advisory process (CAP) took place in2009
and 2010. The four objectives and steps of the CAP were as follows:
l. Identify community issues and concerns.
2. Develop a range of possible routes that address community issues and concerns.
3. Recommend proposed and alternate routes.
4. Follow through with communities during the federal and state review processes.
Through the CAP, Idaho Power hosted 27 Project Advisory Team meetings, 15 public meetings,
and 7 special topic meetings. In all, nearly 1,000 people were involved in the CAP,
either through Project Advisory Team activities or public meetings. Additionally, numerous
meetings with individuals and advocacy groups were held during and after the process.
Ultimately, the route recommendation from the CAP was the route Idaho Power brought into the
National Environmental Policy Act of 1969 (NEPA) process as the proponent-recommended
route. The NEPA process included additional opportunities for public comment at major
milestones, and Idaho Power worked with landowners and communities along the way.
Ultimately, the route selected through the NEPA process was based on the Bureau of Land
Management's (BLM) analysis and public input. For more information on the CAP, including
the final reporte, and Idaho Power's initial scoping activities, visit the documents sectionlo on the
B2H website.
Throughout the BLM's NEPA process, including development of the Draft Environmental
Impact Statement (EIS), issued Dec. 19, 2014, and prior to the Final EIS, issued Nov. 22, 2016,
Idaho Power worked with landowners, stakeholders and jurisdictional leaders on route
refinements and to balance environmental impacts with impacts to farmers and ranchers.
For example, Idaho Power met with the original "Stop Idaho Power" group in Malheur County to
help the group effectively comments and seek change from the BLM when the Draft EIS
indicated a preference for a route across Stop Idaho Power stakeholder lands. BLM's decision
was modified, and the route moved away from an area of highly valued agricultural lands in the
Final EIS almost two years later.
e boardmantohemingway.com/documents/CAP%20Report-Final-Febo/o2O20l l.pdf
I 0 boardmantohemingway.com/documents.aspx
Page 18 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
Idaho Power worked with landowners in the Baker Valley, near the National Historic Oregon
Trail Interpretive Center (NHOTIC), to move an alternative route along fence lines to minimize
impacts to irrigated farmland, where practicable. This change was submitted by the landowners
and included in the BLM's Final EIS and ROD (issued Nov. l7 ,2017). Another change in Baker
County was in the Burnt River Canyon and Durkee area, where Idaho Power worked with the
BLM and affected landowners to find a more suitable route than what was initially preferred in
the Draft EIS. Idaho Power is still working with landowners and local jurisdictional leaders to
microsite in these areas to minimize impacts.
Unfortunately, the route preferences of Idaho Power and the local communities aren't always
reflected in the BLM's Agency Preferred route. For example, Idaho Power had worked in the
Baker County area to propose a route on the backside of the NHOTIC (to the east) to minimize
visual impacts, and in the Brogan area, to avoid landowner impacts. However, both route
variations went through priority sage grouse habitat and were not adopted in BLM's Agency
Preferred route.
However, Idaho Power worked with Umatilla County, local jurisdictional leaders and
landowners to identify a new route through the entire county, essentially moving the line further
south and away from residences, ranches, and certain agriculture. This southem route variation
through Umatilla County was included the BLM's Agency Preferred route.
At the urging of local landowners along Bombing Range Road in Morrow County, Idaho Power
has been working with local jurisdictional leaders, delegate representatives, farmers, ranchers,
and other interested parties to gain the Navy's consideration of an easement along the eastern
edge of the Boardman Bombing Range. This cooperative effort with the local area has benefited
the Project, providing an approach that meets the interests and common good for all in the area.
Idaho Power is still working with the Navy to obtain that easement, but all indications point to
receiving an authorization from the Navy in 2018.
Finally, in Union County Idaho Power worked with local jurisdictional leaders, stakeholder
groups, such as the Glass Hill Coalition and some members of StopB2H (prior to that group's
formation) to identify new route opportunities. The Union County B2H Advisory Commission
agreed to submit a route proposal to the BLM that followed existing high-voltage transmission
lines, which was later identified as the Millcreek Alternative. At the same time, Idaho Power met
with a large landowner to adjust the Morgan Lake Alternative route to minimize impacts to the
landowners. Idaho Power understood that both the Mill Creek and Morgan Lake route variations
were favored over BLM's Agency Preferred Alternative (Glass Hill Alternative) by landowners,
the Glass Hill Coalition, several stakeholders, and the Confederated Tribe of the Umatilla Indian
Reservation due to concerns of impacts on areas that had no prior development. Idaho Power
continued support of the community-favored routes in its amended preliminary Application for
2017 tRP Page 19
Appendix D-B2H Supplement ldaho Power Company
Site Certificate. Idaho Power will work with Union County and local stakeholders to determine
the route preference between the Morgan Lake and Millcreek alternatives.
Project Activities
Below is a summary of notable activities by year since project inception. For more information
about any of the activities, please visit the B2H website.
2006
Idaho Power files its IRP with a transmission line to the Pacific Northwest identified in the
preferred resource portfolio.
2007
Idaho Power analyzes the capacity and cost of different transmission line operating voltages and
determines a new 500-kV transmission line to be the most cost-effective option to increase
capacity and meet customer needs. Idaho Power files a Preliminary Draft Application for
Transportation and Utility Systems and Facilities on Federal Lands. Idaho Power scopes routes.
2008
Idaho Power submits application materials to the BLM. Idaho Power submits a Notice of Intent
to the EFSC. The BLM issues a Notice of Intent to prepare an EIS; officially initiating the
BLM-led federal NEPA process. Idaho Power embarks on a more extensive public outreach
program to determine the transmission line route.
2009
Idaho Power pauses NEPA and EFSC activities to work with community members throughout
the route as part of the CAP to identify a proposed route that would be acceptable to both Idaho
Power and the public. Forty-nine routes and/or route segments were considered through CAP.
201 0
The CAP concludes. Idaho Power resubmits a proposed route to the BLM based on input from
the CAP. The BLM re-initiates the NEPA scoping process and solicits public comments. Idaho
Power publishes its B2H Siting Study. Idaho Power files a Notice of Intent with EFSC.
201 1
Additional public outreach resulted in additional route alternatives submitted to the BLM.
The Obama Administration recognizes B2H as one of seven national priority projectsl l.
I I boardmantohemingway.com/documents/RRTT Press Release _1 0-5-20 1 1 .pdf
Page 20 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
2012
The ODOE conducts informational meetings and solicits comments. The ODOE issues a Project
Order outlining the issues and regulations Idaho Power must address in its Application for Site
Certificate. Additional public outreach and analysis resulted in route modifications and
refinements submitted to the BLM. Idaho Power issues a Siting Study Supplement. Idaho Power
conducts field surveys for the EFSC application. WECC adopts a new Adjacent Transmission
Circuits definition with a separation distance of 250 feet, which would later modify routes in the
EIS process. Idaho Power receives a formal capacity rating from WECC.
2013
Public meetings are held. Idaho Power submits its Preliminary Application for Site Certificate to
the ODOE. The BLM releases preliminary preferred route alternatives and works on a Draft EIS.
2014
The BLM issues a Draft EIS identifying an Agency Preferred Alternative. The 90-day comment
period opens. Idaho Power conducts field surveys for EFSC application.
201 5
The BLM hosts open houses for the public to learn about the Draft EIS, route alternatives,
environmental analysis. The BLM reviews public comments. Idaho Power notifies the BLM of a
preferred termination location, Longhorn Substation. Idaho Power submits an application to the
Navy for an easement on the Naval Weapons System Training Facility in Boardman.
Idaho Power conducts field surveys for the EFSC application.
2016
Idaho Power submits a Draft Amended Application for Site Certificate to the ODOE for review
The BLM issues a Final EIS identifying an environmentally preferred route alternative and an
Agency Preferred route alternative. Idaho Power incorporates the Agency Preferred route
alternative into the EFSC application material. Idaho Power collaborates with local area
stakeholders in Morrow County to find a routing solution on Navy-owned land. Idaho Power
submits a revised application to the Navy. Idaho Power conducts field surveys for the EFSC
application.
2017
Idaho Power submits an Amended Application for Site Certificate to the ODOE. The BLM
issues a ROD.
For a detailed list of project activities by year, please refer to Appendix D-2
2017 tRP Page 21
Appendix D-B2H Supplement ldaho Power Company
Route History
As stated previously, the B2H project was first identified in the 2006 IRP. At that time, the
transmission line was contemplated as a line between Boise and McNary. The project evolved
into a 500-kV line between the Boardman area and the Hemingway Substation. Several northern
terminus substations were considered over the years, including the Boardman coal plant 500-kV
yard, the proposed Grassland Substation to be constructed by Portland General Electric to
integrate the then-proposed Carty Plant, and the proposed Longhom Substation, which at the
time was proposed by BPA to integrate wind onto the BPA 500-kV transmission system. During
scoping, a considerable number of routes were considered to connect Hemingway and the
Boardman area. Figure 3 is a snapshot of a number of routes considered early on during the CAP
process (2009 timeframe). Numerous alternatives were considered, including routes through
Idaho and through central Oregon. This large number of routes was further refined during the
CAP process.
Page22 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
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2017 tRP Page 23
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The CAP process resulted in Idaho Power submitting the route shown in Figure 4 as the
company's proposed route in the BLM-led NEPA process.
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Page 24 2017 tRP
ldaho Power Company
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The BLM considered Idaho Power's proposed route, along with a number of other reasonable
alternative routes, in the NEPA process. Figure 5 shows the route alternatives and variations
considered in the BLM's November 2016 Final EIS.
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2017 tRP Page 25
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Appendix D-B2H Supplement ldaho Power Company
The conclusion of the BLM-led NEPA process, the BLM's ROD, resulted in a singular route-
the BLM's Agency Preferred route. The 293.4-mile approved route will run across 100.3 miles
of federal land (managed by the BLM, the U.S. Forest Service [USFS], the Bureau of
Reclamation, and the U.S. Department of Defense),190.2 miles of private land, and 2.9 miles of
state lands. Figure 6 shows the BLM's Agency Preferred route.
Figure 6. BLM Agency Preferred route from the 2017 BLM ROD
As discussed previously, the BLM-led NEPA process and the EFSC process are distinct
processes. Idaho Power submitted its Amended Application for Site Certificate to the ODOE in
summer 2017. The route Idaho Power submitted to the ODOE as part of the Application for Site
Certificate is very similar to the BLM's Agency Preferred route, except for a small section of
private property west of La Grande. The BLM's Agency Preferred route in this area was a
surprise to Idaho Power and seemingly all stakeholders in the area. The section the BLM chose
was not the county's stated preference, nor was it the variation Idaho Power had worked with a
large local landowner to modify to minimize impacts to his property.
At the time of EFSC application finalization (which was prior to the Final EIS release), Idaho
Power did not feel as if there was a stakeholder consensus preference between the County's
preferred route and the modified route west of the City of La Grande. Therefore, Idaho Power
brought both alternatives into the EFSC application. Idaho Power intends to continue to work
with the community to finalize which of the two variations in this area willbe constructed.
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ldaho Power Company Appendix D-B2H Supplement
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BzH Capacity lnterest
Per the terms of the Joint Permit Funding Agreement (see Appendix D-3), each co-participant
(funder) is assigned a permitting interest based on the annual weighted capacity expressed in the
project. The permitting interest is determined by the sum of a funder's eastbound capacity
interest and westbound capacity interest, divided by the total of all eastbound and westbound
capacity interest. Table 5 details the capacity interest of each funder.
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Table 5.B2H joint permit funding capacity interests by funder
Capacity lnterest (West-to-East) Gapacity Interest (East-to-West) Ownership %
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550 MW (Winter)
OMW 24.2o/o
Unallocated OMW 4OO MW
Idaho Power's capacity interest is seasonally shaped, with 500 MW of eastbound capacity from
April through September and 200 MW of eastbound capacity from January through March and
October through December. BPA's capacity interest is seasonally shaped with 250 MW of
eastbound capacity from April through September and 550 MW of eastbound capacity from
January through March and October through December. PacifiCorp's capacity is constant
throughout the year. The sum of the capacity interest in the east-to-west direction is less than the
rating (1,000 MW), so the unallocated capacity is divided among the funders based on their
respective percentage permitting interest.
The seasonal capacity shaping is a great benefit for Idaho Power's customers, and one of the
reasons why the B2H project is such a competitive and cost-effective option in the IRP process.
Idaho Power is effectively purchasing 500 MW of capacity (peak summer need) at a cost based
on 350 MW of capacity.
Capacity Rating-WECC Rating Process
Idaho Power coordinated with other utilities in the Western Interconnection via a peer-reviewed
process known as the WECC Path Rating Process. Through the WECC Path Rating Process,
Idaho Power worked with other western utilities to determine the maximum rating (power flow
limit) across the transmission line under various stresses, such as high winter or high summer
peak load, light load, high wind generation, and high hydro generation on the bulk power system.
Based on industry standards to test reliability and resilience, Idaho Power simulated various
outages, including the outage of B2H, while modeling these various stresses to ensure the power
grid was capable of reliably operating with increased power flow. Through this process,
Idaho Power also ensured the B2H project did not negatively impact the ratings of other
transmission projects in the Western Interconnection. Idaho Power completed the WECC Path
Rating Process in November 2012 and achieved a WECC Accepted Rating of 1,050 MW in the
west-to-east direction and 1,000 MW in the east-to-west direction. The B2H project, when
constructed, will add significant reliability, resilience, and flexibility to the Northwest
power grid.
Page 28 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
B2H Design
B2H is routed and designed to withstand catastrophic events, including, but not limited to,
the following:
o Lightning
o Earthquake
o Fire
o Wind/tornado
o Ice
o Landslide
o Flood
o Direct physical attack
The following sections provide more information about the design of the B2H transmission line
and address each ofthe catastrophic events listed above.
Transmission Line Design
The details below are not inclusive of every design aspect of the transmission line but provide a
brief overview of the design criteria. The B2H project will be designed and constructed to meet
or exceed all required safety and reliability criteria.
The basic purpose of a transmission line is to move power from one substation to another for
eventual distribution of electricity to end users. The basic components of a transmission line are
the structures/towers, conductors, insulators, foundations to support the structures, and shield
wires to prevent lighting from striking conductors. See Figure 8 for a cross-section of a
transmission line.
For a single-circuit transmission line, such as B2H, power is transmitted via three-phase
conductors (a phase can also have multiple conductors, called a bundle configuration).
These conductors are typically comprised of a steel core to give the conductor tensile strength
and reduce sag and of aluminum outer strands. Aluminum is used because of its conductive
properties, and it provides the ability to move more power using a smaller amount of material.
Shield wires, typically either steel or aluminum, and occasionally including fiber optic cables
inside for communication between substation equipment, are the highest wires on the structure
Their main purpose is to protect the phase conductors from a lightning strike.
Structures are designed to support the phase conductors and shield wires and keep them safely in
the air. For the B2H project, structures were chosen to be steel lattice tower structures,
2017 tRP Page 29
Appendix D-B2H Supplement ldaho Power Company
which provide an economical means to support large conductors for long spans over long
distances. The typical structure height for B2H is 135 feet tall (structure height will vary
depending on location) with a structure located roughly every 1,200 feet on average. The tower
height and span length were optimizedto minimize ground impacts and material requirements;
taller structures could allow for longer spans (less structures on average per mile) but would be
costlier due to material requirements. Again, the B2H tower and conductors were engineered to
maximize benefits and minimize costs and impacts.
Foundations are the support mechanism that bind the structures to the earth and safely keep the
phase conductors and shield wires in the air. For the B2H project, the foundations at each lattice
tower structure are planned to be concrete-drilled pier shafts. A cylindrical hole will be drilled at
each tower footing of adequate diameter and depth to support the loads applied to the structure
from the shield wires and phase conductors. The loads applied to structures via shield wires and
conductors are discussed in further detail below.
Page 30 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
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Transmission Line Structural Loading Considerations
Reliability and resiliency are designed into transmission lines. Overhead transmission lines have
been in existence for over 100 years, and many codes and regulations govern the design and
operation of transmission lines. Safety, reliability, and electrical performance are all incorporated
into the design of transmission lines. Idaho Power's EFSC application includes an exhaustive list
of standards. Several notable standards are as follows:
a American Concrete Institute 3|8-Building Code Requirements for Structural Concrete
a American National Standards Institute (ANSD standards (for material specs)
a American Society of Civil Engineers (ASCE) Manual No.7{-Guidelines for Electrical
Transmis sion Line Structural Loading
2017 tRP Page 31
/
a National Electrical Safety Code (NESC)
National Fire Protection Association (NFPA) 780-Guidefor Improving the Lightning
Performance of Transmission Lines
NESC provides for minimum guidelines and industry standards for safeguarding persons from
hazards arising from the construction, maintenance, and operation of electric supply and
communication lines and equipment. The B2H project will be designed, constructed,
and operated at standards that meet, and in most cases, exceed, the provisions of NESC.
Physical loads induced onto transmission structures and foundations supporting the phase
conductors and shield wires for the B2H project are derived from three phenomena: wind, ice,
and tension. Under certain conditions, ice can build up on phase conductors and shield wires of
transmission lines. When transverse wind loading is also applied to these iced conductors, it can
produce structural loading on towers and foundations far greater than normal operating
conditions produce. Design weather cases for the B2H project exceed the provisions in the
NESC. As an example, for a high wind case, NESC recommends 90 miles per hour (mph) winds.
The criteria proposed for this project is 100 mph wind on the conductors and 120 mph wind on
the structures. There are multiple loading conditions that will be incorporated into the design of
the B2H project, including unbalanced longitudinal loads, differential ice loads, broken phase
conductors, broken sub-phase conductors, heavy ice loads, extreme wind loads, extreme ice and
wind loads, construction loads, and full dead-end structure loads.
Transmission Line Foundation Design
The 500-kV single-circuit lattice steel structures require a foundation for each leg of the
structure. The foundation diameter and depth shall be determined during final design and are
dependent on the type of soil or rock present. The foundations will be concrete pier foundations
designed to comply with the allowable bearing and shear strengths of the soil where placed. Soil
borings shall be taken at key locations along the project route, and subsequent soil reports and
investigations shall govern specific foundation designs as appropriate.
Common industry practices design transmission line structures to withstand wind and ice loads
of NESC or greater, and are accepted as more stringent than the potential loads resulting from
ground motion due to earthquakes. The 2017 NESC Rule 250A4 observes the structure capacity
obtained by designing for NESC wind and ice loads at the specified strength requirements is
sufficient to resist earthquake ground motions. Additionally, ASCE Manual No. 74 states
transmission structures need not be designed for ground-induced vibrations caused by earthquake
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o
Appendix D-B2H Supplement ldaho Power Company
o Occupational Safety and Health Administration (OSHA) 1910.269 April I1,2014
(for worker safety requirements)
ldaho Power Company Appendix D-B2H Supplement
motion; historically, transmission structures have performed well under earthquake events,l2'l3
and transmission structure loadings caused by wind/ice combinations and broken wire forces
exceed earthquake loads.
Lightning Performance
The B2H project is in an area that historically experiences 20 lightning storm days per year.la
This is relatively low compared to other parts of the US. The transmission line will be designed
to not exceed a lightning outage rate of one per 100 miles per year. This will be accomplished by
proper shield wire placement and structure/shield wire grounding to adequately dissipate a
lightning strike on the shield wires or structures if it were to occur. The electrical grounding
requirements for the project will be determined by performing ground resistance testing
throughout the project alignment, and by designing adequately sized counterpoise or using
driven ground rods with grounding attachments to the steel rebar cages within the caisson
foundations as appropriate.
Earthq uake Performance
Experience has demonstrated that high-voltage transmission lines are very resistant to ground-
motion forces caused by earthquake, so much so that national standards do not require these
forces be directly considered in the design. However, secondary hazards can affect a
transmission line, such as landslides, liquefaction, and lateral spreading. The design process
considers these geologic hazards using multiple information streams throughout the siting and
design process. The currentB2H route evaluated geologic hazards using available electronic
(geographic information system [GIS]) data, such as fault lines, areas of unstable and/or steep
soils, mapped and potential landslide areas, etc. Towers located in potential geologic hazards are
investigated further to determine risk. Additional analysis may include field reconnaissance to
gauge the stability of the area and subsurface investigation to determine the soil strata and depth
of hazard. At the time of this report, no high-risk geologic hazard areas have been identified. If,
during the process of final design, an area is found to be high risk, the first option would be to
micro-site-route around or span over the hazard.If avoidance is not feasible, the design team
would seek to stabilize thehazard. Engineering options for stabilization include designing an
array of sacrificial foundations above the tower foundation to anchor the soil or improving the
subsurface soils by injecting gtout or outside aggregates into the ground. Ifthe geotechnical
r2 Risk Assessment of Transmission System under Earthquake Loading. J.M. Eidinger, and L. Kemper, Jr
Electrical Transmission and Substation Structures2012, Pg. 183-192 O ASCE 2013.
r3 Earthquake Resistant Construction of Electric Transmission and Telecommunication Facilities Serving
the Federal Government Report. Felix Y. Yokel. Federal Emergency Management Agency (FEMA).
September 1990.
'4 usDA RUS Bullerin l75l-801.
2017 rRP Page 33
Appendix D-B2H Supplement ldaho Power Company
investigation determines the problematic soils are relatively shallow, the tower foundations can
be designed to pass through the weaker soils and embed into competent soils.
Wildfire
The transmission line steel structures are constructed of non-flammable materials, so wildfires do
not pose a physical threat to the transmission line itself. However, heavy smoke from wildfires in
the immediate area of the transmission line can cause flashover/arcing between the phase
conductors and electrically grounded components. Standard operation is to de-energize
transmission lines when fire is present in the immediate area of the line. Transmission lines
generally remain in-service when smoke is present from wildfires not in the immediate vicinity
of the transmission line. Alternatively, solar PV is susceptible to smoke, which can move into
areas even if fires are not in the immediate vicinity of the solar generation. For example, the
forest fires in the Pacific Northwest in 2017 caused much smoke along the proposed B2H
corridor and in the Pacific Northwest in general. The B2H line would likely still operate for the
fires not in the immediate area, whereas solar PV would likely operate at a much-reduced
capacity while heavy smoke is covering the area.
Wind Gusts/Tornados
Tomados are unlikely along the B2H route. As noted in the Transmission Line Structural
Loading Considerations section above, the B2H transmission line is designed to withstand
extreme wind loading combined with ice loading.
lce
Ice formation around the phase conductors and around the shield wires can add a substantial
amount of incremental weight to the transmission line, putting extra force on the steel structures
and foundations. As described in the Transmission Line Structural Loading Considerations
section above, the B2H transmission line is designed to withstand heavy ice loading combined
with heavy wind loading.
Landslide
The siting and design process considers geologic hazards, such as landslides, liquefaction, and
lateral spreading. See the Earthquake Performance section above. Through the siting and design
process, steep, unstable slopes are avoided, especially where evidence of past landslides is
evident. During the preliminary construction phase, geotechnical surveys and ground surveys
(light detection and ranging ILiDAR] surveys) help verify potentially hazardous conditions. If a
potentially hazardous area cannot be avoided, the design process will seek to stabilize the area.
Page 34 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
Flood
The identification and avoidance of flood zones was incorporated into the siting process and will
be further incorporated into the design process. Foundations and structures can be designed to
withstand flood conditions.
Direct Physical Attack
A direct physical attack on the B2H transmission line will remove the line's ability to deliver
power to customers. In the case of a direct attack, B2H is fundamentally no different than any
other supply-side resource should a direct physical attack occur on a specific resource.
However, because the B2H project is connected to the transmission gnd, a direct physical attack
on any specific generation site in the Pacific Northwest or Mountain West region will not limit
B2H's ability to deliver power from other generation in the region. In this context, B2H provides
additional ability for generation resources to serve load if a physical attack were to occur on a
specific resource or location within the region and therefore increases the resiliency of the
electric grid as a whole.
If a direct physical attack were to occur on the B2H transmission line and force the line out of
service, the rest of the grid would adjust to account for the loss of the line. Per the WECC facility
rating process, the B2H capacity rating is such that an outage of the B2H line would not overload
any other system element beyond equipment emergency ratings. Idaho Power also keeps a
supply of emergency transmission towers that can be very quickly deployed to replace a
damaged tower allowing the transmission line to be quickly retumed to service.
B2H Design Conclusions
As evidenced in this section, the B2H project is designed to withstand a wide range of physical
conditions and extreme events. Because transmission lines are so vital to our electrical grid,
design standards are stringent. B2H will adhere to, and in most cases, exceed, the required codes
or standards observed for high voltage transmission line design. This approach to the design,
construction, and operation of the B2H project will establish utmost reliability for the life of the
transmission line. Additionally, as discussed in the Direct Physical Attack section, transmission
lines add to the resiliency of the grid by providing additional paths for electricity should one or
more generation resources or transmission lines experience a catastrophic event.
P nOI eCT CO.PARTIc I PANTS
PacifiCorp and BPA Needs
PacifiCorp and BPA are co-participants on the B2H project (also referred to as funders).
Collectively, Idaho Power, PacifiCorp, and BPA represent a very large electric service footprint
in the western US. The fact that three large utilities have each identified the value of the B2H
2017 tRP Page 35
Appendix D-B2H Supplement ldaho Power Company
project indicates the regional significance of the project and the value the project brings to
customers throughout the West. Idaho Power, PacifiCorp, and BPA have worked closely to
assign the capacity rights of the project to correlate with each party's needs. More information
about PacifiCorp's and BPA's needs and interest in the B2H project can be found in the
following sections.
PacifiCorp
PacifiCorp is a locally managed, wholly owned subsidiary of Berkshire Hathaway Energy
Company. PacifiCorp is a leading western US energy services provider and the largest grid
owner/operator in the West, serving 1.8 million retail customers in six western states. PacifiCorp
is comprised of two business units: Pacific Power (serving Oregon, Washington, and California)
and Rocky Mountain Power (serving Utah, Idaho, and Wyoming). Visit pacificom.com for more
information.
PacifiCorp has invested in the permitting of the B2H project because of the strategic value of the
B2H corridor, which connects the Pacific Northwest to the lntermountain West. The existing
transmission path between the two regions is fully used during key operating periods. As a
potential owner in the project, PacifiCorp would be able to use its bidirectional capacity to
increase reliability and efficiency for its customers. The following is a list of additionalB2H
benefits identified for PacifiCorp.
a Customers: PacifiCorp continues to invest to meet customers' needs, making only
critical investments now to ensure future reliability, security, and safety. The B2H project
is identified as an investment that will ensure future reliability, security, and safety for
PacifiCorp customers.
a Renewables: PacifiCorp continues to grow their renewable resources and transition to
a lower-carbon future. The B2H project has been identified as a strategic project to
facilitate PacifiCorp's use of renewable resources across their two balancing
authority areas.
a EIM: PacifiCorp was a leader in implementing the western energy imbalance market
(EIM). The real-time market helps optimizethe electric grid, lowering costs, enhancing
reliability, and more effectively integrating resources. PacifiCorp believes the B2H
project will help advance the objectives of the EIM, benefitting PacifiCorp customers and
the broader region.
a Regional Benefit: PacifiCorp, as a member of the regional planning entity Northern Tier
Transmission Group (NTTG), supports the conclusion that the B2H project is as a cost-
effective project providing regional solutions to identified regional needs.
Page 36 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
Balancing Area Consolidation: PacifiCorp operates/controls two balancing areas in the
West. After the addition of B2H and portions of Gateway West, more transmission
capacity will exist between PacifiCorp's two balancing areas, providing the ability to
increase operating efficiencies.B2H will provide PacifiCorp 300 MW of additional west-
to-east capability and 600 MW of east-to-west capability to move resources between
PacifiCorp's two balancing authority areas.
a
BPA
BPA is a nonprofit federal power marketing administration based in the Pacific Northwest. BPA
provides approximately 28 percent of the electric power used in the Pacific Northwest, which
has-an estimated population of over l3 million people. BPA also operates and maintains about
three-fourths of the high-voltage transmission in its service area. BPA's area includes Idaho,
Oregon, Washington, western Montana, and small parts of eastern Montana, Califomia, Nevada,
Utah, and Wyoming. For more information, visit bpa.gov.
Similar to the Idaho Power IRP process for identifying cost-effective service alternatives,
BPA identified the B2H project plus associated asset exchange as its top priority for pursuit for
serving customers in southeast Idaho. BPA's load and resource mix in southeast Idaho results in
a net winter peak demand that exceeds the summer peak demand. BPA's winter peak load
couples well with Idaho Power's summer peak load to allow for seasonal shaping of the B2H
capacity. Seasonal shaping of capacity would allow BPA to own 550 MW of B2H capacity in the
winter and 250 MW of capacity in the summer, dramatically increasing the cost-effectiveness of
the project for BPA customers. A recent analysis performed by BPA continues to support the
B2H project plus the asset exchange as its top priority for pursuit. For more information about
the southeast Idaho load service analysis, visit bpa.gov.r5
As a federal agency, BPA has responsibilities to comply with NEPA and consider the
environmental impacts of its actions, such as participating in transmission line construction.
To that end, BPA was a cooperating agency in the development of the B2H EIS and continues to
coordinate with the BLM and other federal agencies. BPA will ensure an appropriate
environmental review has been conducted on any BPA-proposed action associated with the
prqect and plans to prepare a ROD to the B2H EIS as appropriate and in accordance with the
B2H project's permitting schedule.
Co-Participant Expenses Paid to Date
Approximately $92 million, including allowance for funds used during construction (AFUDC),
have been expended on the B2H project through September 30,2017 . Pursuant to the terms of
15 Southeast Idaho Load Service analysis:
bpa.gov/transmission/Customerlnvolvement/SEldaholoadService/Pages/default.aspx
2017 tRP Page 37
Appendix D-B2H Supplement ldaho Power Company
the joint funding affangements, Idaho Power has received approximately $48 million of that
amount as reimbursement from the project participants as of September 30, 2017. Idaho Power
has accrued in receivables approximately $18 million more that will be billed by Idaho Power in
the future to the project co-participants for expenses Idaho Power has incurred, for a total amount
reimbursable by co-participants of $66 million. Co-participants are obligated to reimburse Idaho
Power for their share of any future prqect permitting expenditures incurred by Idaho Power.
Co-Partici pant Ag reements
Idaho Power, BPA, and PacifiCorp (collectively, the funders) entered a Joint Permit Funding
Agreement on January 72,2012, with the intent to be joint owners of the B2H line. The Joint
Permit Funding Agreement provides for the permitting (state and federal), siting, and acquisition
of right-of-way (ROW) over public lands. A copy of the Joint Permit Funding can be found in
Appendix D-3.
Cosr
Gost Estimate
The total cost estimate for the B2H project is $l to $1.2 billion dollars, which includes Idaho
Power's allowance for funds used during construction (AFUDC). Co-participant AFUDC is not
included in this estimate range. The total cost estimate includes a 20-percent contingency for
unforeseen expenses.
In IRP modeling, Idaho Power assumes a21.2-percent share of the direct expenses, plus its entire
AFUDC cost, which equates to approximately $258 million. Idaho Power also included costs for
local interconnection upgrades totaling $ 16 million . The 2017 IRP was the first year for which
the B2H route was relatively certain. In prior years, the estimate was based on uncertain route
and terminus location information.
Page 38 2017 tRP
Related to the project, but not specific to the B2H permitting activities, the B2H co-participants
entered into an MOU on January 12,2012, to l) explore alternatives to establish BPA eastern
Idaho load service from Idaho Power and PacifiCorp's Hemingway Substation and2) consider
whether to replace certain transmission affangements involving existing assets with joint
ownership transmission arrangements and other alternative transmission arrangements pursuant
to definitive agreements mutually satisfactory to the co-participants. In other words, in
conjunction with the project, the parties agreed to explore cost-effective methods to serve
customers by jointly owning facilities other than the B2H project. A copy of the MOU can be
found here or in Appendix D-4.
ldaho Power Company Appendix D-B2H Supplement
Transmission Li ne Esti mate
Idaho Power has contracted with HDR to serye as the B2H project's third-party owners' engineer
and prepare the B2H transmission line cost estimate. HDR has extensive industry experience,
including experience serving as an owner's engineer for BPA for the last seven years. HDR has
prepared a preliminary transmission line design that locates every tower and access road needed
for the project. HDR used utility industry experience and current market values for materials,
equipment, and labor to arrive at the B2H estimate. Material quantities and construction methods
are well understood because the B2H project is utilizing BPA's standard tower and conductor
design for 500-kV lines. BPA has used the proposed towers and conductor on hundreds of miles
of lines currently in-service. HDR was the owner's engineer on recent BPA projects, so HDR is
also familiar with the BPA towers and conductor the B2H project is using.
Substafion Estimafes
Idaho Power prepared the substation cost estimate for the Hemingway Substation, and BPA
prepared the Longhorn Substation estimate. Idaho Power used experience designing and
constructing the Hemingway Substation in 2013. The Hemingway Substation is designed to
accommodate the B2H line terminal in the future. New equipment must be ordered and installed,
but no station expansion will be required. The Longhorn Substation is a station proposed by BPA
near Boardman, Oregon. BPA owns the land for the Longhorn Substation, but the station has yet
to be constructed. BPA proposed the Longhorn Substation to integrate certain wind projects in
the immediate area. BPA has extensive experience designing and constructing substations.
Calibration of Cosf Estimates
The B2H estimate was reviewed and approved by BPA and PacifiCorp. BPA and PacifiCorp
both have recent transmission line construction projects to calibrate against. The recent projects
included the following:
BPA: Lower Monumental-Central Ferry 500-kV line (38 miles, in-service 2015)
BPA: Big Eddy-Ituight 500-kV line (39 miles, in-service 2016)
PacifiCorp: Sigurd to Red Butte 345-kV line (160 miles, in-service 2015)
PacifiCorp: Mona to Oquirrh 500-kV line (100 miles, in-service 2013)
Additionally, in early 2017 ldaho Power visited with NV Energy and Southern Califomia Edison
to learn from each company's recent experience constructing 500-kV transmission lines in the
West. As part of the discussions with each company, Idaho Power calibrated cost estimates and
resource requirements.
The two projects were as follows
a
a
a
o
2017 tRP Page 39
Appendix D-B2H Supplement ldaho Power Company
NV Energy: ON Line project (235 miles, 500 kV, in-service 2014)
Southem California Edison: Devers to Palo Verde (150 miles, 500 kV, in-service 2013)
Costs lncurred to Date
Approximately $92 million, including AFUDC, has been expended on the Boardman-to-
Hemingway project through September 30,2017 . Refer to the Co-Participant Expenses Paid to
Date section for co-participant reimbursements. The $92 million incurred through September 30,
2017 , is included in the $1 to $1.2 billion total estimate. Idaho Power's share of the costs
incurred to-date is included B2H IRP portfolio modeling.
Cosf-Es ti m ate Co ncl u sions
The cost estimate for B2H has been thoroughly vetted. Idaho Power used third-party contractors
with industry experience, relied on PacifiCorp and BPA recent transmission line construction
experience, and benchmarked against multiple recent high-voltage transmission line investments
in the West to arrive at the B2H construction cost estimate. Material quantities and construction
methods are well understood because the B2H project is using BPA's standard tower and
conductor design for 500-kV lines. As a conservative measure, Idaho Power has added a
20 percent contingency to cover any unanticipated expenses. As a reminder, Idaho Power's IRP
analysis escalates all resource costs at a2.l-percent inflation rate into the future so future labor
and material cost escalations are accounted for in B2H IRP portfolio modeling.
Transmission Revenue
The B2H transmission line project is modeled in AURORA as additional transmission capacity
available for Idaho Power energy purchases from the Pacific Northwest. In general, for new
supply-side resources modeled in the IRP process, surplus sales of generation are included as a
cost offset in the AURORA portfolio modeling. However, historically, additional transmission
wheeling revenue has not been quantified for transmission capacity additions. For the 2017 IRP,
Idaho Power modeled the additional transmission wheeling revenue for the B2H project.
After the B2H line is in-service, the cost of Idaho Power's share of the transmission line will go
into Idaho Power's transmission rate base as a transmission asset. Idaho Power's transmission
assets are funded by native-load customers, network customers, and transmission wheeling
customers based on a ratio of each party's usage of the transmission system. In the IRP
modeling, the estimated incremental transmission wheeling revenue from non-native-load
customers was modeled as an annual revenue credit for B2H portfolios.
In the B2}1 analysis, Idaho Power chose to conservatively assume that third-party use
(network customers and transmission wheeling customers) across Idaho Power's transmission
system would remain static following the construction of B2H. Idaho Power's FERC
transmission rate is calculated as follows:
Page 40 2017 tRP
o
o
ldaho Power Company Appendix D-B2H Supplement
Transmtssion Costs ($)Transmisston Rate =
Per the formula above, since transmission costs will go up following the installation of B2H,
and transmission usage is assumed to remain the same, Idaho Power's transmission rate will
increase. Idaho Power's existing transmission customers will pay this higher transmission rate,
resulting in incremental transmission revenue to Idaho Power.
As a specific example, based on current third-party long-term usage, Idaho Power forecasts
611 MW of third-party long-term transmission wheeling customers. Idaho Power also forecasts
250 averuge MW of network customers for a combined total of 861 MW usage. For each $1,000
per MW per year increase to the transmission rate (transmission costs in the equation above),
Idaho Power will gain about $861,000 in transmission revenue. B2H will increase Idaho Power's
rate by over $6,000 per MW per year.
An alternative way to understand the FERC transmission rate, and B2H's impact, is to look at the
transmission system from a total load prospective. Native load, network load, and transmission
customers must pay their respective share based on their usage of the system. Native load and
network load usage is measured in peak MW (averaged by month), and transmission customer
usage is measured by reservation amount. The total transmission usage in2026 is forecast to be
approx. 3,900 MW (including Idaho Power's native load usage); therefore, the 861 MW of
network load and transmission customer usage results in approximately 22 percent of the total
transmission system usage. As such, non-Idaho Power customers are estimated to pay about
22percent of the costs associated with B2H.
This transmission revenue will offset the cost of B2H for retail customers. In a similar manner,
other portfolios include revenues from market sales of newly installed supply resources,
which act to offset costs in those portfolios. This section provides a high-level explanation of the
workings of Idaho Power's FERC transmission rate. When determining the annual transmission
revenue credit for B2H portfolios, Idaho Power ran a full corporate financial model,
including rate of return, depreciation expense, operation and maintenance (O&M), etc.
Idaho Power believes short-term usage of the Idaho Power transmission system by third parties
could substantially increase because additional capacity is created, fuither reducing Idaho Power
customer rates. However, to be conservative, Idaho Power assumed there would be no increased
short-term or long-term third-party transmission usage and only applied the higher transmission
rate to the existing usage.
Potential BPA and ldaho Power Asset Swap
Corresponding with the construction of B2H, Idaho Power and BPA are working to complete an
asset swap that would allow Idaho Power to directly access the Mid-C market and avoid a BPA
transmission wheeling charge. Such a swap would result in lower purchased-power prices for
2017 tRP Page 41
Appendix D-B2H Supplement ldaho Power Company
Idaho Power's customers. In retum, BPA would be able to directly serve their load in
southeastern Idaho and avoid an Idaho Power wheeling charge. As part of the 2017 IRP analysis,
Idaho Power conservatively assumed there would be a wheeling charge to access Mid-C
resources across B2H. If an asset swap were to take place, the cost of energy in B2H portfolios
would be further reduced and make B2H an even more attractive project. Refer to Appendix D-4
for the MOU relating to the potential Idaho Power-BPA asset swap.
Beruerrrs
High-voltage transmission lines, such as B2H, are used to serve customer demand and to move
energy between major markets hubs in the Western Interconnection. If the existing western US
were to be overlaid with thousands of new miles of high-voltage transmission lines, the entire
WECC could be optimized such that all customers would be served with the most economic
resources at all times of the year. The long-term need for new supply-side resources would
greatly diminish due to the vast diversity of the loads and resources across the Western
Interconnection. Such a gnd, of course, is economically infeasible, but projects such as B2H are
being developed to allow economic resources to be shared between regions. The existing
transmission gnd is not perfect and many areas of the transmission gr:ld are congested.
Transmission congestion causes both economic and reliability issues.
Gapacity
High-voltage transmission lines provide many significant benefits to the Western
Interconnection. The most significant benefit of the B2H project is the capacity benefit of the
transmission line. Idaho Power is developing the B2H project to create capacity to serve peak
customer demand. The capacity benefit is described in more detail in the Resource Need section
The Pacific Northwest is a winter peaking region. Pacific Northwest utilities continue to install
and build generation capacity to meet winter peak regional needs. Idaho Power operates a system
with a summer peak demand. Idaho Power's peak occurs in the late June/early July timeframe,
which aligns well with spring hydro runoff conditions when the Pacific Northwest is flush with
surplus power capacity. The existing transmission system between the Pacific Northwest and
Idaho Power is constrained. Constructing B2H will alleviate this constraint and add 1,050 MW
of transfer capability between the Pacific Northwest and Idaho Power. Both the Pacific
Northwest and Idaho Power will significantly benefit from the addition of transmission capacity
between the regions. The Pacific Northwest has already built the power plants and would benefit
from selling energy to Idaho Power. Idaho Power needs resources to serve peak load, and a
transmission line to existing, underutilized power plants is much more cost effective than
building a new power plant.
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ldaho Power Company Appendix D-B2H Supplement
Avoid Constructing New Resources (and Potentially
Carbon-Emitting Resources
In the early days of the electric grid, utilities built individual power plants to serve their local
load. Utilities quickly realized that if they interconnected their systems with low-cost
transmission, the resulting diversity of load reduced their need to build power plants. Utilities
also realized transmission allowed them to build and share larger, more cost-effective and more
efficient power plants. The same opportunities exist today. In fact, B2H is being developed to
take advantage of existing diversity.
Table 6 illustrates peak-load estimates, by utility and season , for 2026. The shading represents
winter-peaking utilities. As seen in the table, there is significant diversity of load between the
regions. The Maximum (MW) column illustrates the minimum amount of generating capacity
that would be required if each region were to individually plan and construct generation to meet
their own peak load need: 69,000 MW. When all regions plan together, the total generating
capacity can be reduced to 63,800 MW, a nearly l0 percent reduction. Transmission connections
between the regions, such as B2H, are the key to sharing installed generation capacity.
Table 6. 2026 peak load estimates-illustration of load diversity between western regions
Region Summer Peak (MW) Winter Peak (MW) Maximum (MW)
Avista
BPA
British Columbia
Chelan
Grant
ldaho Power
Nevada
Northwestern Energy
PacifiCorp-East
PacifiCorp-West
Portland General
Puget Sound
Seattle City
Tacoma
Total
2,200
9,200
10,300
600
900
3,800
9,000
2,000
9,500
3,600
4,000
4,000
1,500
800
61,400
2,400
11,000
1 3,1 00
800
900
2,800
6,500
1,900
7,900
4,000
4,100
s,400
1,900
1,100
63,800
2,400
11,000
13,100
800
900
3,800
9,000
2,000
9,500
4,000
4,100
5,400
1,900
1,100
69,000
Note: 2026 regional peak load data extracted from the WECC TEPPC 2026 Common Case.
Load diversity occurs seasonally, as illustrated in Table 6, but it also occurs sub-seasonally and
daily. An additional major variable in the Northwest is hydroelectric generation diversity. Over
the winter, water accumulates in the mountains through snowpack. As this snow melts, water
2017 tRP Page 43
Appendix D-B2H Supplement ldaho Power Company
flows through the region's hydroelectric dams, and northwest utilities generate a significant
amount of power. During the spring runoff, generation capacity available in the Pacific
Northwest can be significantly higher than generation capacity available during the winter, or
even during late summer. Idaho Power is fortunate to have a peak load that is coincident with the
late spring / early summer hydro runoff. Idaho Power's peak load occurs in late June/early July,
when hot weather causes major air-conditioning load coincident with agricultural
irrigation/pumping load. Idaho Power's time window for a significant peak is quite short, with
agricultural irrigation/pumping load starting to ramp down by mid-July.
Utilities have an obligation to serve customer load. This means that utilities are planning to meet
peak load needs. As discussed previously, transmission congestion can cause utilities to build
additional generation to serve load. Due to transmission congestion, utilities may be unable to
leverage their transmission system to access dormant generation already constructed by their
neighbors. The B2H project is an alternative to building new supply-side resources. As
demonstrated in the 2017 IRP, the portfolios that are the most cost-effective other than B2H are
portfolios with natural gas generation. In this case, B2H is an alternative to building a carbon-
emitting supply-side resource.
lmproved Economic Efficiency
Transmission congestion causes power prices on opposite sides of the congestion to diverge.
Transmission congestion is managed by dispatching less economically efficient resources to
ensure the transmission system is operating securely and reliably. Congestion can have a
significant cost. During peak summer conditions, the Idaho to Northwest path in the west-to-east
direction becomes constrained and power prices in Idaho and to the east will generally be high,
while power prices in the Pacific Northwest will be depressed due to a surplus of power
availability without adequate transmission capacity to move the power out of the region.
The construction of B2H will alleviate much of this constraint and create a win-win scenario
where generators in the Pacific Northwest will be able to gain further value from their existing
resource, and load-serving entities in the Mountain West region will be able to meet load service
needs at a lower cost. The reverse situation could be true as well-the Pacific Northwest could
benefit from economical resources from the Mountain West region during certain times of the
years.
Renewable lntegration
Transmission capacity is critical to the integration of renewable generation that, at times, is
curtailed due to a lack of transmission capacity to move the energy to load. Transmission is a
facil itator for future generation development.
Page 44 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
Grid Rel iabil ity/Resil iency
Transmission grid disturbances do occur. B2H will increase the robustness and reliability of the
regional transmission system by adding additional high-capacity bulk electric facilities designed
with the most up-to-date engineering standards. Major 500-kV transmission lines, such as B2H,
substantially increase the grid's ability to recover from major unexpected disturbances.
Unexpected disturbances are difficult to predict, but below are a few examples of disturbances
whose impacts would be reduced with the addition of B2H:
1. Loss of the Hemingway-Summer Lake 500-kV line with heavy west-to-east power
transfer into Idaho. The loss of the Hemingway-Summer Lake 500-kV transmission line,
the only 500-kV connection between the Pacific Northwest and Idaho Power, during peak
summer load is one of the worst possible contingencies the Idaho Power transmission
system can experience. Once Hemingway-Summer Lake 500-kV disconnects,
the transfer capability of the Idaho to Northwest path is reduced by over 700 MW in the
west-to-east direction. After the addition of B2H, there will be two major 500-kV
connections between the Pacific Northwest and Idaho Power. The Hemingway-Summer
Lake 500-kV outage would become much less severe to Idaho Power's transmission
system.
2. Loss of the Hemingway-Summer Lake 500-kV line with heavy east-to-west power
transfer out of Idaho to the Pacific Northwest. In this disturbance, an existing remedial
action scheme (power system logic used to protect power system equipment) will
disconnect over 1,000 MW of generation at the Jim Bridger Power Plant to reduce path
transfers and protect bulk transmission lines and apparatus. Due to the magnitude of the
generation loss, recovery from this disturbance can be extremely difficult. After the
addition of B2H, this enormous amount of generation shedding will no longer be
required. With two 500-kV lines between Idaho and the Pacific Northwest, the loss of
one can be absorbed by the other.
3. Loss of a single 230-kV transmission tower in the Hells Canyon area. Idaho Power owns
two 230-kV transmission lines, co-located on the same transmission towers, that connect
Idaho to the Pacific Northwest. Because these lines are on a common tower, Idaho Power
must consider the simultaneous loss of these lines as a realistic planning event.
Historically, such an outage did occur on these lines in 2004 during a day with high
summer loads. By losing these lines, Idaho Power's import capability was dramatically
reduced, and Idaho Power was forced to rotate customer outages for several hours due to
a lack of resource availability. After the addition of B2H, the impact of this outage would
be substantially reduced.
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Appendix D-B2H Supplement ldaho Power Company
Resource Reliability
Transmission unavailability and unexpected forced outages have historically been a fraction of a
traditional generation resource. Availability, and contribution to resource adequacy on the power
grid, vary significantly by resource type. The North American Electric Reliability Corporation
(NERC) has historically tracked transmission availability through a Transmission Availability
Data System (TADS) and generation availability through a Generation Availability Data System
(GADS) in North America. A telling sign of the reliability of a resource is the equivalent forced
outage rate (EFOR). The EFOR is calculated based on the amount of time a transmission line, or
generator, is either de-rated, or forced out of service while needed. De-rating a generator would
be considered a partial outage, based on the de-rate amount as a percentage of the total capacity.
Table 7 provides the NERC TADS data for different transmission operating voltages. From the
NERC TADS data, a 300-mile, 500-kV transmission line (B2H) would be expected to have an
outage rate of 0.4 percent. Stated differently, the B2H transmission line is expected to have
99.6 percent availability.
NERC-AC transmission circuit sustained outage metrics
Voltage
Class
Circuit
Miles
No. of
Circuits
No. of
Outages
Tota!
Outage
Time (hr)
Frequency
(SCOF) (per 100
CM per yr)
Frequency
(SoF)(per
circuit per yr)
200-299 kV
300-399 kV
400-599 kV
600-799 kV
AllVoltages
103,5s8
56,791
32,184
9,451
201,985
4,477.5
1,623.6
594.7
1 10.0
6,805.8
14,789.6
19,766.8
3,957.9
342.4
38,856.7
0.8459
0.6938
0.4381
0.2963
0.7124
0.1 956
o.2427
0.2371
o.2545
0.2114
876
394
141
28
1,439
By comparison, Table 8, lists the average EFOR for traditional fossil fuel power plants (coal, oil,
gas, etc.) and the average EFOR for gas power plants.
Table 8. NERC forced-outage rate information for a fossil or gas power plant
Generation Type Unit Size EFOR
Fossil(general)
Fossil(general)
Fossil(general)
Gas
Gas
Gas
AllSizes
100-199 MW
200-299 MW
AllSizes
1-99 MW
100-'199 MW
7.960/r
7.49o/o
5.85%
9.610/o
9.72o/o
6.85%
A transmission line with an EFOR of less than 1 percent, on the high end, is significantly more
reliable than a power plant, which has an EFOR of 7 to 10 percent. A transmission line, of
Page 46 2017 rRP
Table 7.
MTTR or
Mean Outage
Duration (hr)
16.9
50.2
28.1
12.2
27.0
ldaho Power Company Appendix D-B2H Supplement
course, requires a resource to source the line and serve load. However, the resources purchased at
the end of the transmission line can be purchased as frrm, whereby the seller must be able to
supply the generation no-matter what (which may require purchasing someone else's generation
if the primary unit experiences an outage). Therefore, if the resource is purchased as firm, the
purchased resource would have an EFOR consistent with the transmission line, which is much
more reliable than traditional supply-side generation. In the management of cost and risk, B2H
will provide Idaho Power's operators additional flexibility when managing the Idaho Power
resource portfolio.
Reduced Electrical Losses
During peak summer conditions, with heavy power transfers on the Pacific Northwest and Idaho
Power transmission systems, the addition of the B2H project is expected to reduce electrical
losses by more than 100 MW in the Western Interconnection. This is a considerable savings for
the region; 100 MW of generation, that customers ultimately pay for, does not need produced to
supply losses alone.
Losses on the power system are caused by electrical current flowing through energized
conductors, which in turn create heat. Losses are equal to the electrical current squared times the
resistance of the transmission line:
Electrtcal Losses = Currentz x Reststance
From the electrical losses equation above, if the current doubles, the electrical losses will
increase by a factor of four. By constructing the B2H line, less efficient (i.e., lower voltage)
transmission lines with very large transfers are relieved, reducing the electrical current through
these lines and dramatically reducing the losses due to heat.
Flexibility
Advances in technoloqy are pushing certain existing generation resources toward economic
obsolescence. Any supply-side resource alternative could face the same economic obsolescence
in the future. B2H is an alternative to constructing a new supply-side resource and therefore,
reduces the risk of technological obsolescence. B2H will facilitate the transfer of any generation
technology, ensuring Idaho Power customers always have access to the most economic
resources, regardless ofthe resource type.
B2H capacity, when not used by B2H owners, will be available (for purchase) to other parties to
make economic interstate west-to-east and east-to-west power transfers for more efficient
regional economic dispatch. This provides a regional economic benefit to utilities around Idaho
Power that is not factored into the analysis. Specifically, the B2H project will make additional
capacity available for Pacific Northwest utilities to sell energy to southern and eastern markets in
the West, and for Pacific Northwest utilities to purchase energy from southern and eastem
2017 tRP Page 47
Appendix D-B2H Supplement ldaho Power Company
markets to meet their winter peak load service needs (southern and eastern WECC entities are
mostly summer peaking). Idaho Power customers benefit from any third-party transmission
purchases as the incremental transmission revenue acts to offset retail customer costs.
The existing electric system is heavily used. Because the system is so heavily used,
new transmission line infrastructure, like B2H, creates additional operational flexibility.
B2H will increase the ability to take other system elements out of service to conduct
maintenance and will provide additional flexibility to move needed resources to load when
outages occur on equipment.
EIM
Idaho Power views the regional high-voltage transmission system as critical to the realization of
EIM benefits, and the expansion of this transmission system (i.e., B2H) facilitates the realization
of these benefits. As fluctuations in supply and demand occur for EIM participants, the market
system will automatically find the best resource(s) from across the large-footprint EIM region to
meet immediate power needs. This activity optimizes the interconnected high-voltage system as
market systems automatically manage congestion, helping maintain reliability while also
supporting the integration of intermittent renewable resources and avoiding curtailing excess
supply by sending it to where demand can use it.
Idaho Power notes that EIM participation does not alter its obligations as a balancing authority
(BA) required to comply with all regional and national reliability standards. Participation in the
western EIM does not change NERC or WECC responsibilities for resource adequacy, reserves,
or other BA reliability-based functions for a utility.
BzH Complemenfs All Resource Types
Utility-scale resource installations allow economies of scale to benefit customers in the form of
lower cost per watt. For instance, residential rooftop solar is growing in popularity, but the
economics of rooftop solar are outweighed by the economics of utility-scale solar installation.r6
Large transmission lines allow the most economical resources to be sited in the most economical
locations. As an example, single-axis tracking utility-scale solar in Salem, Oregon, is expected to
have a capacity factor of approximately l5 percent (where the capacity factor is the amount of
time the system generates over the course of a year). Comparatively, the same single-axis
tracking utility-scale solar system in Boise, Idaho, has a capacity factor of approximately
l9 percentlT. If solar system prices are assumed to be equivalent in Salem and Boise, a Boise
16 The National Renewable Energy Laboratory NREL) estimates the cost of residential rooftop solar
(PV) is approximately 2.5 times the cost of utility-scale solar on a $/Watt basis (NREL, U.S. Solar
Photovoltaic System Cost Benchmark: Ql 2017).
17 NREL, System Advisory Model
Page 48 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
installation would generate over 30 percent more energy over the course of the year.
Transmission lines provide the ability to move the most economical resources around the region.
Idaho Power views transmission lines like B2H as a complement to any resource type that allows
access to the least-cost and most efficient resource, as well as regional diversity, to benefit all
customers in the West.
B2H Benefits to Oregon
Economic and Tax Benefits
The B2H project will result in positive economic impacts for eastern Oregon communities in the
form of new jobs, economic support associated with infrastructure development (i.e., lodging and
food), and increased annual tax benefits to each county for project-specific property tax dollars.
The annual tax benefit for the non-BPA owned portion of the line is shown in Table 9 below.
BPA, as a federal entity, does not pay taxes, so BPA's 25 percent project interest is excluded
from the estimates. Idaho Power anticipates the project will add about 500 construction jobs,
which will provide a temporary increase in spending at local businesses.
Table 9. Projected annual B2H tax expenditures by county
Oregon Gounty Property Tax (excluding BPA's 257o ownership interest)
Morrow
Umatilla
Union
Baker
Malheur
Total Oregon Tax Benefit
$270,295
$569,656
$629,410
$1,778,282
$893,567
$4,141,210
Local Area Electrical Benefits
The B2H project will add 1,050 MW of additional transmission connectivity between the BPA
and Idaho Power systems. Currently, the transmission connections between BPA and Idaho
Power are fully used for existing customer commitments. Idaho Power currently serves
customers in Owyhee County, Idaho, and Malheur County and portions of Baker County in
Oregon. PacifiCorp, through Pacific Power, serves portions of Umatilla County. BPA provides
transmission service to local cooperatives in the remainder of the project area in Morrow,
Umatilla, Union, and Baker counties. Below is a summary of how these areas will benefit
directly from B2H.
La Grande and Baker City are served by the Oregon Trails Electric Cooperative (OTEC).
Portions of Morrow County and Umatilla County are served by Umatilla Electric Cooperative
(UEC) and Columbia Basin Electric Cooperative (CBEC). OTEC, UEC, and CBEC pay BPA's
2017 tRP Page 49
Appendix D-B2H Supplement ldaho Power Company
network transmission rate to receive power and transmission service from the BPA system.
If BPA finds less expensive solutions to meet service obligations to customers in southeast Idaho
and Wyoming, costs are kept low for other BPA customers, including OTEC, UEC, and CBEC.
In other words, BPA customers in Oregon benefit by f,rnding a low-cost solution for customers in
Idaho and Wyoming. BPA's financial analysis to date has projected that a share of the B2H
project with asset exchange appears the most cost-effective, long-term solution to serve
customers in southeast Idaho and eastern Wyoming. Correspondingly, OTEC, UEC, and CBEC
customers would also benefit from this cost-effective solution.
The B2H project provides economic development opportunities. The cost of power is a major
factor in economic development and, as discussed previously,B2H, as a low-cost resource
alternative, will keep power costs low compared to more expensive alternatives.
Capacity must be available on the existing system for additional economic development to take
place. In Union and Umatilla counties, BPA's McNary-Roundup-La Grande 230-kV line has
limited ability to serve additional demand in the Pendleton and La Grande areas but is currently
capable of meeting the 1O-year load forecast. The B2H project will increase the transfer
capability through eastern Oregon by 1,050 MW. This capacity will provide a significant
regional benefit to the entire Northwest and specifically benefit load service to eastern Oregon
and southern Idaho. It is possible this added capacity resulting from the B2H project could be
used to serve additional demand in Union and Umatilla counties.
Portions of Baker County are served by Idaho Power, from Durkee to the east. BPA currently
provides energy to OTEC, which serves Baker City via transmission connections between the
Northwest and Idaho Power's transmission system. At this point, the existing transmission
connections between the Northwest and Idaho Power are fully used for existing load
commitments, with very little ability to meet load growth requirements. The B2H project will
increase the transmission connectivity between the Northwest and Idaho Power by 1,050 MW,
which will allow BPA to serve additional demand in Baker City.
Finally, additional transmission capacity can create opportunities for new energy resources,
which can add to the county tax base and create new jobs.
Rrsx
Risk is inherent in any infrastructure development project. The sections below address various
risks associated with the B2H project. Combining the analysis below with the risk analysis
conducted in the 2017 IRP, Idaho Power believes B2H is the lowest-risk resource to meet
Idaho Power' resource needs.
Page 50 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
Capital-Cost Risk
The capital-cost estimate for the B2H project has been well vetted. See the Cost section for an
explanation of how the B2H project cost estimate was determined. Idaho Power's share of the
B2H projectis$274 million, including Idaho Power's AFUDC and local interconnection costs.
For illustrative purposes, Figure 9 compares total portfolio costs for the 2017 IRP 2}-year
planning horizon. To determine the fixed costs associated with each portfolio, costs for each
resource are levelized over the asset life, and costs beyond2036 are not included in the analysis
The information from Figure 9 was extracted directly from the IRP Table 9.3.
The B2H project has considerable capital-cost bandwidth. The least-cost B2H portfolio
(Portfolio 7) outperforms the least-cost B2H-alternative portfolio (Portfolio 9) by a2017 net
present value (NPV) of $147 million. Note that the B2H estimate already includes 2O-percent
capital-cost contingency. No other resources evaluated in IRP portfolios include a contingency.
Based on NPV analysis over the ZD-year planning horizon, Idaho Power's cost share of the B2H
project could more than double, and the least-cost B2H portfolio would still be more cost-
effective than the least-cost B2H-alternative portfolio.
ooa
€
0N
F
oN
G@
oz
vo
o
otoa
6
o
$6,70o,mo
$5,65O,mo
$6,60o,mo
$o,sso,mo
$6,soo,so
$6,4so,ooo
96,40o,oo
$6 3so,mo
$o,roo,mo
$6,2so,mo
$6,zoo,oo
5147 million
B2H-based portfolios
P4 P10 P1 P9 p2 P8 p6 P'P5 P11 P12
Figure 9. Comparison of total portfolio costs from 2017 IRP (Table 9.3 in 2017 IRP)
2017 tRP Page 51
Appendix D-B2H Supplement ldaho Power Company
Market Price Risk
The cost of dispatching gas-fired generation typically sets the market price of power at Mid-C.
A stochastic risk analysis was conducted on all2017 Idaho Power IRP portfolios, with natural
gas prices ranging up to 400 percent of the planning case. Refer to IRP Table 9.4 and Table 9.5
for more information. The natural gas stochastic risk analysis in the 2017 IRP is a market price
stochastic analysis because natural gas prices set the energy market prices. Figure 10 below
shows three stochastic iterations comparing natural gas prices and Mid-C market prices.
The solid lines represent Mid-C energy hub prices, and the dotted lines represent Sumas hub
natural gas prices; the natural gas prices and market prices are very closely correlated.
Mid-C Market and Sumas Natural Gas
J30
525
920
S15
slo
s29
92e
st$
3:
-[eration4 -Planni.gGte -te.ation91
...... sumarreErbn4 ,..... surasPleninsc6e ...... sum3tte.atbn9l
s1&
s50
ss
50 50
Figure 10. Correlation between Mid-C market prices and natural gas prices
Based on the correlation of natural gas prices and market prices, market price risk analysis was
considered for the B2H project in Idaho Power's 2017 IRP. Results of the stochastic analysis
show B2H portfolios remain the low-cost portfolios for all natural gas price sensitivities,
except a 400 percent price sensitivity. However, Idaho Power believes a 400 percent energy
market price increase is unlikely because a 400 percent increase in natural gas prices, along with
the associated increase in energy prices, would likely result in the development of alternative
resources in place of natural gas (that is, developers of more cost-effective resources would take
advantage of financial opportunities if market prices increased 400 percent due to natural
gas costs).
Liquidity and Market Sufficiency Risk
The Pacific Northwest is a winter peaking region. Pacific Northwest utilities continue to install
and build generation capacity to meet winter peak regional needs. Idaho Power operates a system
Page 52 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
with a summer peak. Idaho Power's peak occurs in the late June/early July timeframe. The Idaho
Power summer peak aligns with the Mid-C hydro runoff conditions when the Pacific Northwest
is flush with surplus power capacity. The existing transmission system between the Pacific
Northwest and Idaho Power is constrained. Constructing B2H will alleviate this constraint and
add 1,050 MW of total transfer capability between the Pacific Northwest and the Intermountain
West region. The Pacific Northwest and Idaho Power will significantly benefit from the addition
of transmission capacity between the regions. The Pacific Northwest has constructed power
plants to meet winter needs and would benefit from selling energy to Idaho Power in the
summer. Idaho Power needs generation capacity to serve summer peak load, and a transmission
line to existing underutilized power plants is much more cost-effective than building a new
power plant.
See the Market Overview section of this appendix for more information about the Mid-C market
hub liquidity. Based on the risk assessment, Idaho Power believes sufficient market liquidity
exists.
The following data points will address the market sufficiency risk.
Data Point 1. Peak Load Analysis from Table 6
Referencing Table 6 from the Benefits section above, British Columbia and other utilities in the
Pacific Northwest have forecast 2026 winter peaks that exceed their forecast 2026 sufilmer peaks
by a combined 7,600 MW. Given the difference in seasonal peaks, coupled with Columbia
runoff hydro conditions aligning with Idaho Power's summer peak, resource availability in the
Pacific Northwest during Idaho Power's surlmer peak is likely.
Data Point 2. Pacific Northwest Power Supply Adequacy Assessmenf
for 2022-Northwest Power Conservation Council Report
The Northwest Power and Conservation Council (NWPCC) recently studied the Northwest
power system to determine resource adequacy using a five-year forecast. In July 2017,
the NWPCC published their 2022 Assessment.18 The report suggests the Northwest must install
400 MW of new effective capacity by 2021to meet the NWPCC standard.
The NWPCC, through their analysis, attempted to quantify resource adequacy through a loss-of-
load probability (LOLP) analysis. In Figure 1l below, a higher LOLP indicates worse
performance (more customer risk), and a lower LOLP indicates better performance. Idaho
Power's peak load occurs in a narrow window in the late June/early July timeframe. Figure 11
illustrates the Northwest has a 0 percent LOLP for the June and July months. This indicates that
I 8 nwcouncil.org/media/7 49 l2l3 I 201 7-5.pdf
2017 tRP Page 53
Appendix D-B2H Supplement ldaho Power Company
the Northwest will continue to have sufficient resources available for Idaho Power to purchase
and deliver to Idaho Power customers across the B2H line.
3.0
2.5
r oY 2022 n OY 202t
tr
o-
o
.8,
co
2.O
1.5
Z.OZL Annua! LOLP = 5.9Yo
2022Annual LOLP =7.ZYo1.0
0.5
lr0.0 Ir .I
8g
I=
Figure 11. 2021-22 LOLP by month (Source: NWPCC northwest analysis)
Evaluating Figure 11 further, the NWPCC information suggests 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 resource availability in late June/early July
This argument is further stressed in Data Point 3.
Data Point 3: 2016 Pacific Northwesf Loads and Resources Study-
BPA
The Pacific Northwest Loads and Resources Studyle, commonly called "The White Book," is
BPA's annual publication of the federal system and the Pacific Northwest regions loads and
resources for the upcoming 10-year period.
Data detailing whether Pacific Northwest resources will be available to purchase post-2025 can
be found in the 2016 Pacifrc Northwest Loads and Resources Technical Appendix, Volume 2,
I e bpa. gov/power/pgp/whitebook/20 1 6/index. shtml
Footnotes continued on the next page.
Page 54 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
Capacity Analysis20. This appendix evaluates the Pacific Northwest resource and generation
balance to determine a monthly surplus/deficit for the next l0 years. Given the importance of
hydro generation in the Pacific Northwest, BPA makes a conservative assumption that there will
be a water year equivalent to 1937, one of the worst water years on record.
The BPA capacity metrics are defined as follows:
120-Hour Capacity-Calculated by averaging the generation forecasts from the six
highest heavy load hours per day, five days per week, for four weeks per month (6 x 5 x 4
: 720 hours).
l-Hour Capacity-Calculated using the highest single one-hour generation per month.
a
a
10000
8000
6000
4000
2000
0
-2000
-4000
-6000
Pacific Northwest Resource Surplus (+) / Deficit (-)
t--
--o..
-4.'!-___-a_ir
2019 G--2023
---o---
---2&s*- 2026 2027*'t-----a
--e ----1_-
"-!r---_{
-{--January (120-Hour) -{--June (120-Hour) **&*. July (120-Hour)
January (1-Hour) *June (1-Hour) *July (1-Hour)
Figure 12. January, June, and July forecast Pacific Northwest resource surplus/deficit
(Source: 2016 BPA White Book)21
Exploring Figure 12 further, Table l0 below lists the critical 2027 datapoints.
20 bpa.gov/power/pgp/whitebook/201612016-WBK-Technical-Appendix-Volume%20-2-Capacity-
Analysi s-20 I 6 1222.pdf
2r bpa.gov/power/pgp/whitebook/201612016-WBK-Technical-Appendix-Volumeo%20-2-Capacity-
Analysis-20 I 6 1222.pdf
2017 tRP Page 55
Table 10. 2027 data points from Figure 12
Month 120-Hour Capacity (MW) 'l-Hour Capacity (MW)
January
June
July
a
a
-5,255
177
-2,349
-3,716
1,748
770
Assuming a critical water year equivalent to 1937, BPA forecasts a2027 January deficit of 5,255
MW in the 120-hour capacity evaluation and a deficit of 3,716 MW in the one-hour capacity
evaluation. July is much better than January; BPA forecasts a 2027 deficit of 2,349 MW in the
120-hour capacity evaluation and a surplus in the l-hour capacity evaluation. BPA forecasts a
surplus for June in both the 120-hour and 1-hour capacity evaluations.
Several BPA considerations are built into the analysis:
a Analysis includes a 1,000+ MW export to Canada (summer and winter). In practice, at
peak, Canada is typically exporting to the Northwest.
Renewables are assumed to have a capacity factor near zero.
California solar exports to the Pacific Northwest are zero.
Analysis includes committed generation retirements. There are no assumptions for
replacement generation.
Given BPA's analysis, Idaho Power believes there will be sufficient resources in the future based
on the following:
Northwest utilities will need to address their severe January deficit. Adding resources to
address this deficit will improve the July deficit. A similar argument was made in Data
Point 2.
Canada generally exports 1,000+ MW over summer peak, rather than importing over
1,000 MW per BPA assumptions in the analysis. This reduces the July deficit to
almost zero.
Solar resources should have a summer capacity factor (should not be zero).Idaho Power
assumed a 5 1-percent summer capacity factor in the 201 7 IRP for potential Idaho Power
utility-scale solar resources.
a
a
a
a
Page 56
All signs point to California exporting solar output to the Pacific Northwest, especially if
renewable portfolio standards (RPS) increase.
2017 tRP
Appendix D-B2H Supplement ldaho Power Company
ldaho Power Company Appendix D-B2H Supplement
The 2016 Pacific Northwest Loads and Resources Study can be found on BPA's website.
Data Point 4: Northulesf and California Renewable Portfolio Standards
The adoption of more aggressive RPS goals by states such as Oregon, California,
and Washington will drive policy-driven resource additions. The RPS goals will also likely result
in the addition of dispatchable flexible ramping resources, such as the recently constructed Port
Westward 2 power plant installed by Portland General Electric.
Market Sufficiency and Liquidity Conclusions
Based on the analysis summarized above and in the Markets section of this report, Idaho Power
believes there will be sufficient resources in the future to source the B2H transmission line. Also,
because the market balances supply and demand based on a market clearing price, liquidity risk
can be modeled in economic terms. Should demand be greater than supply at the Mid-C energy
hub in the future, market hub prices would reflect the scarcity accordingly (higher prices). As
discussed in the Market Price Risk section, a sensitivity analysis conducted in the 2017 IRP
indicates B2H remains the low-cost resource portfolio over a wide range of market price
sensitivities.
Go-Participant Risks
Idaho Power, BPA, and PacifiCorp, collectively referred to as co-participants or funders,
are fully engaged in permitting activities but have not yet entered into construction and operating
agreements. Per the 2012 Joint Funding Agreement, Idaho Power has 60 days following the
publication of the BLM ROD to issue a Notice of Completion (Notice), which triggers the
commencement of construction negotiations. The funders are allotted two 180-day periods
(360 days total), following receipt of the Notice, to negotiate one or more definitive development
and construction agreements. The BLM ROD was published on November 17,2017.
Idaho Power, PacifiCorp, and BPA have been in negotiations regarding a possible amendment to
the Joint Funding Agreement that would clarify ongoing payment terms, update the milestone
schedule, and modify construction agreement triggers and negotiation durations.
The funders may withdraw from the Joint Permitting Agreement at any time and for no reason,
and the withdrawing funder(s) shall pay all costs up to the last day of the month of withdrawal.
If one or more of these funders does not move forward with construction, withdrawals from the
project, all rights, title, and interest will be transferred to the remaining funder(s) such that the
remaining funder(s) shall have 100 percent of the permitting interest in the permitting project.
The remaining funders may then seek other funder(s) and/or proceed with construction.
Although funder commitments are not a guarantee at this point, Idaho Power believes other
parties may have interest in potential ownership in the project should one or more of the funders
decide not to move forward with construction. At least one additional party was involved in the
2017 rRP Page 57
Appendix D-B2H Supplement ldaho Power Company
original negotiations that ultimately lead to the current three-party 2012 Joint Funding
Agreement. Additionally, Idaho Power has been approached by at least one entity that may have
interest in the B2H project. Any consideration of additional project co-participants would be
discussed and agreed on by current funders.
Changes in ownership structure could change cost allocation percentages. Refer to the
Capital-Cost Risk section of this appendix for more information about capital-cost risk. For any
potential changes in ownership structure, Idaho Power will evaluate the potential ownership cost
and capacity allocation, and assuming cost-effective for Idaho Power customers, would request
approval from the Oregon and Idaho public utility commissions for any modification in
ownership.
Siting Risk
Siting any new infrastructure projects comes with siting risk. The BLM ROD, which was
released on November 17,2017, was a significant milestone in the B2H project development and
greatly minimized siting risk. It provided the project authorization to cross BLM land and
provided the BLM Agency Preferred alternative for the remainder of the route. The USFS and
Navy will tier off of the BLM's analysis to conclude their NEPA processes. The State of Oregon
EFSC process is the next major step to ensure siting risk is minimized for privately owned land
in Oregon.
Schedule Risk
As of the date of this appendix, Idaho Power has schedule scenarios for B2H in-service dates in
2024 or later. At a high level, activities prior to energization are peffnitting, co-participant
agteements, preliminary construction, and material procurement and construction.
The B2H project is currently in the permitting phase of the project. For federal permitting,
the B2H project recently achieved the biggest schedule milestone to date with the release of
BLM's ROD on November 17 ,2017 . The ROD formalized the BLM-led NEPA process and
established a BLM Agency Preferred route on public and private property. The USFS ROD and a
Navy ROD and easement are the next major federal permitting milestones. At this point,
neither the USFS ROD nor Navy ROD are expected to be critical path schedule activities.
For the State of Oregon permitting process, the B2H project also achieved a considerable
milestone in summer 2017 withthe submittal of the amended Application for Site Certificate to
the ODOE. The ODOE is expected to issue a Draft Proposed Order in 2018 and a Final Order
and Site Certificate in2020. The EFSC permitting process is a critical path schedule activity.
Schedule risk exists for the EFSC permitting process if the ODOE does not issue a Site
Certificate by late 2020.
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ldaho Power Company Appendix D-B2H Supplement
With the receipt of the BLM ROD and submittal of the amended Application for Site Certificate,
which is expected to be deemed complete in the near future, sufficient route certainty exists to
begin preliminary construction activities. Assuming co-participant agreements are in place,
the current B2H schedule plans to commence preliminary construction activities prior to the
receipt of a Site Certificate to achieve an in-service date in the mid-2020s. The B2H
co-participants have not formally decided on the contracting method for the project, so the
preliminary construction and construction schedule activities remain preliminary until contracts
are in place.
Idaho Power believes schedule flexibility exists if the EFSC process is delayed. For instance,
certain schedule activities could be condensed by employing more resources or certain activities.
Additionally, certain schedule activities could overlap if planned appropriately, such as ROW
acquisition and construction.
Currently, Idaho Power believes there is sufficient schedule flexibility to achieve a2026
in-service date. ldaho Power, BPA, and PacifiCorp plan to negotiate construction agteements in
2018, which should provide additional clarity to the schedule.
Gatastrophic Event Risk
As detailed in B2H Design section, the B2H transmission line is designed to withstand a variety
of extreme weather conditions and catastrophic events. Like most infrastructure, the B2H project
is susceptible to direct physical attack. However, unlike some other supply-side resources, B2H
adds to the resiliency of the electrical gnd by providing additional capacity to transfer energy
throughout the region should a physical attack or other catastrophic event occur elsewhere on the
system. Additionally, Idaho Power also keeps a supply of emergency transmission towers that
can be quickly deployed to replace a damaged tower, allowing the transmission line to be quickly
returned to service.
PnoIecT AcTIVITIES
Schedule Update
Permitting
The B2H projected achieved a major milestone with the release of the BLM ROD on November
17,2017. The BLM ROD formalized the conclusion of the siting process and federally required
NEPA. The BLM ROD provides the B2H project the ability to site the project on BLM-
administered land. The BLM-led NEPA process took nearly 10 years to complete and involved
extensive stakeholder input. Refer to the Project History and Route History sections of this report
for more information on project history and public involvement. The next steps in the federal
permitting process include a USFS ROD and Navy ROD; both are expected in 2018. Both the
USFS and Navy will use the BLM's environmental analysis.
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Appendix D-B2H Supplement ldaho Power Company
For the State of Oregon permitting process, Idaho Power submitted the amended application for
Site Certificate to the ODOE in summer 2017. As of the date of this report, Idaho Power expects
the ODOE to issue a Draft Proposed Order in 2018 and a Final Order and Site Certificate
in2020.
The NEPA and EFSC processes are very distinct permitting processes and not necessarily
designed to work simultaneously. At a high level, the NEPA EIS process evaluates reasonable
alternatives to determine the best alternative (the Agency Preferred Alternative) at the end of the
process. Comparative analysis is conducted at a "desktop" level. Information is brought into the
process on a phased-approach. Detailed analysis must be conducted on the final route prior to
construction, generally once final design is complete.
The Oregon EFSC process is a standards-based process based on a fixed site boundary. For a
linear facility, like a transmission line, the process requires the transmission line boundary to be
established (a route selected) and fully evaluated to determine if the project meets established
standards. The practical effect of the EFSC standards-based process required the NEPA process
be far enough along to conduct field studies and other technical analysis to comply with
standards. Idaho Power conducted field surveys and prepared the EFSC application in parallel
with the NEPA process. The EFSC application is lengthy. Idaho Power estimates the application
submitted in2017 was roughly 17,000 pages long.
Post-Permitting
To achieve an in-service date in the mid-2020s, preliminary construction activities must
commence parallel to EFSC permitting activities. Preliminary construction activities include,
but are not limited to, the following:
Geotechnical explorations
Detailed ground surveys
Sectional surveys
ROW acquisition activities
Detailed design
Construction bid package development and construction contractor selection
After the Oregon permitting process and preliminary construction activities conclude,
construction activities can commence. Construction activities include, but are not limited to,
long-lead material acquisition, transmission line construction, and substation construction.
The preliminary construction activities must commence several years prior to construction.
a
a
a
a
a
Page 60 2017 rRP
ldaho Power Company Appendix D-B2H Supplement
The material acquisition and construction activities are expected to take 3 to 4 years. The specif,rc
timing of each of the preliminary construction and construction activities will be coordinated
with the project co-participants.
Cottcr-usroNS
This B2H 2017 IRP appendix provides context and details that support evaluating the B2H
transmission line project as a supply-side resource, explores (qualitatively and quantitatively)
many of the ancillary benefits offered by the transmission line, and considers the risks and
benefits of owning a transmission line connected to a market hub in contrast to direct ownership
of a traditional generation resource.
As discussed in this report, once operational, B2H will provide Idaho Power increased access to
reliable, low-cost market energy purchases from the Pacific Northwest. B2H (including early
versions of the project) has been a cost-effective resource identified in each of Idaho Power's
Integrated Resource Plans (IRP) since 2006 and continues to be a cornerstone of Idaho Power's
2017 IRP preferred resource portfolio. In the 2017 IRP, B2H was identified as the least-cost and
least-risk resource to serve peak-hour load to resource deficits that are forecast to occur
beginning in2026. When compared to other individual resource options, B2H is also the
least-cost option in terms of both capacity cost and energy cost. B2H is expected to have a
capacity cost that is 7l percent lower than either a combined-cycle gas plant or utility-scale solar
alternatives .22 B2H is also expected to have a levelized cost of energy that is 22 percent lower
than a combined-cycle gas plant and 38 percent lower than utility-scale solar.23
B2H project brings additional benefits beyond cost-effectiveness. The B2H project will increase
the efficiency, reliability, and resiliency 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. Idaho Power believes B2H provides value to the
system beyond any individual resource because it enhances the flexibility of the existing system
and facilitates the delivery of cost-effective resources not only to Idaho Power customers, but
also to customers throughout the Pacific Northwest and Mountain West regions.
The company must demonstrate a need for the project before EFSC will issue a Site Certificate
authorizing the construction of a transmission line. The need demonstration can be met through a
commission acknowledgement of the resource in the company's IRP.24 In this case, Idaho Power
22 2017IRP, Page 87, Figure 7.5.
23 2017IRP, Page 89, Figure 7.6.
24 oAR 345 -023 -oo2o(2).
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Appendix D-B2H Supplement ldaho Power Company
seeks to satisfy EFSC's least-cost plan rule's requirement through an acknowledgement of its
2017IRP.
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ldaho Power Company Appendix D-B2H Supplement
Appendix D-1. Transmission line alternatives to the proposed 82H 500-kV transmission line
Table D-1
Comparison of Transmission Line Capacity Scenarios-New Lines from Longhorn to Hemingway
Scenario
Line
Capacityr
Potential Path 14
West-East lncrease2
Losses on
New Circuit(s)3
a. Longhorn to Hemingway 230 kV single circuit
b. Longhom to Hemingway 230 kV double circuit
c. Longhorn to Hemingway 345 kV single circuit
d. Longhorn to Hemingway 500 kV single circuit
e. Longhorn to Hemingway 500 kV-two separate lines
f. Longhorn to Hemingway 500 kV double circuit
g. Longhorn to Hemingway 765 kV single circuit
956 MW
1,912 MW
1,434 MW
3,214 MW
6,428 MW
6,428 MW
4,770 MW
525 MW
915 MW
730 MW
1,050 MW
2,215MW
1,235 MW
1,200 MW
10.80/o
9.50h
6.6%
4.20/o
3.7o/o
2.90
2.404
Line Capacity is the thermal rating of the assumed conductors and does not account for system limitations of voltage, stability, or
reliability requirements.
Potential Rating is based upon study results to date to meet reliability design requirements for the WECC ratings processes, not
including simultaneous interaction studies.
Estimated Losses are percent losses for the new line at the Potential Rating loading level. Annual energy losses are dependent
on total system loss reductions. All of the scenarios would likely yield a total system loss reduction for the flow levels above.
Table D-2
Comparison of Transmission Line Capacity Scenarios - Rebuild Existing Lines to the Northwest
Scenario
PotentialPath
Line Capacity' 14 lncrease2
Losses on New
Gircuit(s)3
Length of Line/
New ROWa
h. Replace Oxbow-Lolo 230 kV with
Hatwai - Hemingway 500 kV
i. Replace Oxbow-Lolo 230 kV with
Hatwai - Hemingway 500 kV - No
double circuiting with existing lines
j. Replace Walla Walla to Brownlee
230 kV with Sacajawea Tap-
Hemingway 500 kV
k. Replace Walla Walla to Pallette
230 kV with Sacajawea Tap-
Hemingway 500 kV - No double
circuiting with existing lines
l. Build double circuit 500 kV/230 kV
line from McNary to Quartz. Build
500kV from Quartz to Hemingway.
3,214 MW
3,214 MW
3,214 MW
3,214 MW
430 MW W-E
675 MW E-W
710 MW W-E
745 MW E-W
4OO MW W-E
675 MW E-W
720 MW W-E
730 MW E-W
765 MW W-E
870 MW E-W
3.8o/o 255 Miles/136 Miles
4.10/o 255 Miles/167 Miles
3.5o/o 288 Miles/150 Miles
3.80/o 288 Miles/181 Miles
3.90h 298 Miles/168 Miles3,214 MW
1 Line Capacity is the thermal rating of the assumed conductors and does not account for system limitations of voltage, stability, or
reliability requirements.2 Potential Rating is based upon study results to date to meet reliability design requirements for the WECC ratings processes, not
including simultaneous interaction studies.3 Estimated Losses are percent losses for the new line at the Potential Rating west-east loading level. Annual energy losses are
dependent on total system loss reductions. All of the scenarios would likely yield a total system loss reduction for the flow levels
above.4 ln addition to utilizing existing 230 kV right-of-way ("ROW"), each of the scenarios above will require new ROW to be obtained.
2017 tRP Page 63
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ldaho Power Company Appendix D-B2H Supplement
Appendix D-2. Detailed list of notable project milestones
o June, 2006 - Idaho Power files the 2006 IRP - Transmission line between Boise and Pacific
Northwest identified in preferred resource portfolio (this transmission line eventually became
the Boardman to Hemingway project)
December 19,2007 - Idaho Power Completes the B2H Preliminary Plan of Development
2008 - Idaho Power files the 2008 IRP Update
August 28,2008 - Idaho Power submits Notice of Intent to EFSC to submit an Application
for Site Certificate.
September 12, 2008 - Notice of Intent published in the Federal Register for BLM to prepare
an Environmental Impact Statement for B2H
April 10, 2009 - Public Scoping Report for B2H EIS completed by Tetra Tech
December 30,2009 - Idaho Power files the 2009 IRP -B2H Project identified in preferred
resource portfolio
a
a
a
a
a
o
June 2010 - Idaho Power completes the B2H Preliminary Plan of Development
July 2010 - Idaho Power submits a NOI to apply for a Site Certificate for B2H to ODOE
August 2010 - Idaho Power completes the B2H Siting Study
August 2010- February 20ll - Idaho Power completes the Community Advisory Process
February 20ll - Idaho Power completes a Revised Plan of Development for B2H
June 30, 2011 - Idaho Power files the 2011 IRP -B2H Project identified in preferred
resource portfolio
October 5,2011 - Obama administration recognizesB2H as one of seven national priority
projects that when built, will help increase electric reliability, integrate new renewable
energy into the grid, create jobs and save consumers money. See news release.
November 20ll - Idaho Power completes a Revised Plan of Development for B2H
January 12,2012 - Idaho Power, BPA and PacifiCorp enter into Joint Permit Funding
Agreement
March 2,2072 - ODOE issues a Project Order for B2H
a
a
a
a
a
a
a
a
a
a
2017 tRP Page 65
a
a
o
a
a
a
a
a
o
a
a
a
o
Jtne 2012 - Idaho Power completes a Supplemental Siting Study for B2H
October 2,2012 - BPA identifies B2H as the best option for meeting load growth in
southeastern Idaho
November 27,2012 - Idaho Power receives formal capacity rating from Western Electricity
Coordinating Council (WECC)
February 28,2013 - Idaho Power submits Preliminary Application for Site Certificate to
Oregon Department of Energy
June 28, 2013 - Idaho Power files the 2013 IRP
December 19,2014 - Draft EIS and Land-use Plan Amendments Published in Federal
Register
December 22,2014 - ODOE issues amended Project Order for B2H
Iune 22,2015 - Idaho Power submits easement application to Navy to site on Naval
Weapons System Training Facility Boardman (aka "Bombing Range")
June 30, 2015 - Idaho Power files the 2015 IRP - B2H Project identified in the preferred
resource portfolio
a
o
November 25,2016 - BLM issues the Final EIS for B2H
November 18,2016 - Idaho Power submits revised application to Navy, updating the route
on Navy property based on collaborative routing solution
January 20,2017 - Donald Trump inaugurated as 45th President of the United State
June 29, 2017 - Idaho Power submits electronic version of Amended Preliminary
Application for Site Certification to ODOE
June 30, 2017 - Idaho Power files the 2017 Integrated Resource Plan (IRP) -B2H Project
identified in the preferred resource portfolio
July 19, 2017 - Idaho Power submits hard copies of Amended Preliminary Application for
Site Certification to ODOE.
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Appendix D-B2H Supplement ldaho Power Company
o November 17,2017 - BLM issues a Record of Decision (ROD) for the B2H. The Record of
Decision was signed by the Assistant Secretary of Lands and Minerals, U.S. Department of
Interior.
ldaho Power Company Appendix D-B2H Supplement
Appendix D-3. B2H funding agreement
See the attached document.
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Page 68 2017 rRP
Execution Copy
BPA Contract Number 12TX-15583
BOARDMAN TO HEMINGWAY TRANSMISSION PROJECT JOINT PERMIT
FUNDING AGREEMENT
This Boardman to Hemingway Transmission Project Joint Permit Funding Agreement
(the "Aggemed") is entered into this 12th day of January,2}l? (the "Effective Date"), by and
between Idaho Power Company, an Idaho corporation ("Idaho Power"), PacifiCorp, an Oregon
corporation ("EAe"), and the Bonneville Power Administration ("BPA"), a United States
government power marketing administration. Idaho Power, PAC, and BPA are hereinafter
sometimes individually referred to as a "Funder" and collectively as the "Funders."
RECITALS
WHEREAS, Idaho Power, PAC, and BPA have independent obligations to plan for and
expand their respective transmission systems to provide safe, reliable and cost-effective service
to their native load customers, network customers, andlor eligible customers;
WHEREAS, Idaho Power, PAC and BPA recognizethe potential to fuIfilItheir
respective service obligations through the development of ceftain new transmission facilities;
WHEREAS, the proposed Boardman to Hemingway Transmission Project is a 500 kV
single circuit transmission line located from the vicinity of Boardman, Oregon to the existing
Hemingway substation near Melba, Idaho (as further described in Exhibit A, the "Boardman to
Heminewav Transmission Project"), that if constructed could assist ldaho Power, PAC, and BPA
in fulfilling their respective service obligations;
WHEREAS, Idaho Power, PAC, and BPA recognize that obtaining appropriate and
necessary Governmental Authorizations and completing other necessary work is an essential
component to developing the Boardman to Herningway Transmission Project;
WHEREAS, Idaho Power, PAC, and BPA desire to support and contribute funds, with
the intent to be joint owners subject to the terms of this Agreernent, to the processes associated
with obtaining the necessary Govemmental Authorizations and completing other necessary work
to develop, permit, site, and acquire Rights-of-Way over public lands for the Boardman to
Herningway Transmission Project;
WHEREAS, Idaho Power, PAC, and BPA are entering into this Agreement for the
purposes of providing the definitive terms and conditions by which Idaho Power, PAC, and BPA
will jointly support and contribute funds, with the intent to be joint owners subject to the terms of
this Agreement, to permit, site and acquire Rights of Way over public lands for the development
of Boardman to Hemingway Transmission Project;
WHEREAS, Idaho Power has submitted applications to the United States Department of
Interior, Bureau of Land Management ("BLM"), serving as the lead permitting agency under the
National Environmental Policy Act ("NEPA"), to obtain authorizations for the Boardman to
Hemingway Transmission Project to cross federal lands. The United States Forest Service,
United States Department of the Navy and the United States Bureau of Reclamation are
cooperating agencies with the BLM in preparing an Environmental Impact Statement ("EIS") for
the Boardman to Hemingway Transmission Project;
WHEREAS, Idaho Power has submitted its notice of intent to apply for an energy facility
site certificate with the Oregon Department of Energy, Energy Facility Siting Council, to
construct the portions of the Boardman to Hemingway Transmission Project located in the State
ofOregon;
WHEREAS, Idaho Power, PAC, and BPA intend for the express purpose of this
Agreement to facilitate the successful completion of the Project Permitting Objectives (as further
defined herein);
WHEREAS, Idaho Power and PAC recognize that, although BPA is entering into this
Agreement, BPA has certain obligations and responsibilities under NEPA and other federal laws
that it must fulfill before it can make a decision concerning whether to participate in the
development and construction of the Boardman to Hemingway Transmission Project, and BPA
intends to be a cooperating agency under NEPA on the Environmental Impact Statement being
prepared by the BLM and other federal agencies to facilitate completion of BPA's obligations
and responsibilities under NEPA;
WHEREAS, Idaho Power and PAC acknowledge that BPA is considering various
transmission and other alternatives to meet its service obligations in eastern ldaho and that
BPA's decision whether to participate in the development and construction of the Boardman to
Hemingway Transmission Project may be based on BPA's evaluation of such alternatives;
WHEREAS, upon the completion of the Project Permitting Objectives, any of the
Funders that decide to proceed with the development and construction of the Boardman to
Hemingway Transmission Project intend to negotiate in good faith further agreement(s) for the
purposes of providing the definitive terms and conditions by which such Funders may jointly
design, engineer, procure, construct, commission, own and operate the Boardman to Hemingway
Transmission Project (the "Definitive Develop "); and
WHEREAS, nothing in this Agreement shall affect any other existing or proposed
projects, expansions, or developments that are not a part of this Agreement.
NOW, THEREFORE, in consideration of the promises and the mutual covenants and
agreements herein contained, the adequacy of which is hereby acknowledged, Idaho Power,
PAC, and BPA agree as follows:
2
1.1
ARTICLE I
DEFINITIONS; RULES OF INTERPRETATION
Definitions. As used in this Agreement, the following capitalized terms have the
meanings specified in this Section 1.1 :
"Advance Contribution" has the meaning set for in Section 4.2(a).
"Atflegled fe1!y" has the meaning set forth in Section 9.1.
"Affiliate" means, with respect to a Person, each other Person that, directly or indirectly,
controls, is controlled by or is under common control with, such designated Person;
provided, however, that in the case of PAC "Affiliate" includes MidAmerican Energy
Holdings Company and its direct and indirect subsidiaries. For the purposes of this
definition, "control" (including with correlative meanings, the terms "controlled by'' and
"under common control with"), as used with respect to any Person, shall mean (a) the
direct or indirect right to cast at least fifty percent (50%) of the votes exercisable at an
annual general meeting (or its equivalent) of such Person or, if there are no such rights,
ownership of at least fifty percent {50%) of the equity or other ownership interest in such
Person, or (b) the right to direct the policies or operations of such Person.
"Aggement" has the meaning set forth in the Preamble.
"Bankrup!" means, with respect to any Person, that such Person: (a) files a petition or
otherwise commences, authorizes or acquiesces in the commencement of a proceeding or
cause of action under any bankruptcy, insolvency, reorganizatron or similar law, or has
any such petition filed or commenced against it, (b) makes an assignment or any general
,urangement for the benefit of creditors, (c) otherwise becomes insolvent (however
evidenced), (d) has a liquidator, administrator, receiver, trustee, conservator or similar
official appointed with respect to it or any substantial portion of its property or assets, or
(e) is generally unable to pay its debts as they fall due.
"B-LM" has the meaning set forth in the Recitals.
"Boardman to Hemingway " has the meaning set forth in the
Recitals.
"BPA" has the meaning set forth in the Preamble.
"Business Day" means any day other than Saturday, Sunday and arry day which is not a
federal holiday or a day on which banking institutions in New York, New York are
authorized or obligated by Governmental Requirements to close.
J
"Qlsims" has the meaning set forth in Section 11.1.
"Commercially Reasonable Efforts" means the level of effort that areasonable electric
utility would take in light of the then known facts and circumstances to accomplish the
required action at a then commercially reasonable cost (taking into account the benefits to
be gained thereby).
"Completion Fundinq " has the meaning set forth in Section 3.1(aXii) and
Exhibit B.
"Completion Notice" has the meaning set forth Section 3.3(a)
"Defaultine Funder" has the meaning set forth in Section 8.1.
"Digpule" has the meaning set forth in Section 13.1
"Dispute Notice" has the meaning set forth in Section 13.2.
"Disputing Party" has the meaning set forth in Section 13.2
"Definitive Dwelop " has the meaning set forth in the
Recitals.
"Effectlvg !Ate" has the meaning set forth in the Preamble.
"Environmental Impact Stat 'has the meaning set forth in the Recitals.
"Event_ef_Defagt" has the meaning set forth in Section 8.1.
"ExecUiyeq" has the meaning set forth in Section 13.3(_a).
(cEEre" means the Federal Energy Regulatory Commission.
"Final Environmental Imp 'means the Final Environmental [mpact
Statement for the Boardman to Hemingway Transmission Project.
"Force Majeure" has the meaning set forth in Section 9.1
'(ps11ds1s" has the meaning set forth in the Preamble.
"Fundins Committee Representative" has the meaning set forth in Section 3.2(b).
"Eg4dtng_Iqvq1ge" has the rneaning set forth in Section 3.1ftXi).
"Final Expense True&" has the meaning set forth in Section 3,1ftXiii) and Exhibit B.
4
"Good Utility Practice" means any of the practices, methods and acts engaged in or
approved by a significant portion of the electric utility industry during the relevant time
period, or any of the practices, methods and acts which, in the exercise of reasonable
judgment in light of the facts known at the time the decision was made, would have been
expected to accomplish the desired result at a reasonable cost consistent with good
business practices, reliability, safety and expedition. Good Utility Practice is not intended
to be limited to the optimum practice, method, or act to the exclusion of all others, but
rather to be acceptable practices, methods, or acts generally accepted in the region,
including those practices required by Federal Power Act section 215(d).
"Covemmental Authority," means any federal, state, local or municipal governmental
body; any govemmental, quasi-govemmental, regulatory or administrative agency,
commission, body or other authority exercising or entitled to exercise any administrative,
executive, judicial, legislative, policy, regulatory or taxing authority or power, including
FERC, NERC or any regional reliability council; or any court or governmental tribunal,
in each case, having jurisdiction over any Funder (whether as Funder or as Permitting
Project Manager) or any of its Affiliates or the development, permitting, siting,
acquisition of Rights-of Way, or preliminary design of the Boardman to Hemingway
Transmission Project.
"Governmental Authorizali " means any license, permit, order, approval, filing,
waiver, exemption, variance, clearance, entitlement, allowance, franchise, or other
aulhoization from or by a Governmental Authority.
"Governmental Requirements" means all laws, statutes, ordinances, rules, regulations,
codes, and similar acts or promulgations or other legally enforceable requirements of any
Governmental Authority.
"Idaho Power" has the meaning set forth in the Preamble.
"Joint Defense Agreement" has the meaning set forth in Section I 1.1.
"Joint Defense Agreement Notice" has the meaning set forth in Section 1 1.2,
"Manaqer" has the meaning set forth in Section 13,3(a).
"MandatoryPayments" has the meaning set forth in Section 3.1(a) and Exhibit B.
"Neeotiations End Date" has the meaning set forth in Section 3.3(b).
"NEPA" means the National Environmental Policy Act, as the same may be amended
from time to time.
5
"NERC" means the North American Electric Reliability Corporation.
"Non-Defaultins Funders" means a Funder(s) that is not a Defaulting Funder(s).
"Non-Psrmitting Proiect Manager Funders" means PAC and BPA.
"Notice of Palrment" has the meaning set forth in Section 3.1(bX-ii).
(6EAC" has the meaning set forth in the Preamble.
"Per5sn" means an individual, partnership, corporation, limited liability company, joint
venture, association, trust, unincorporated organization, Governmental Authority, or
other form of entity
"Permit Funding Committee" has the meaning set forth in Section 3.2.
"Perrnit Funding Payment S " has the meaning set forth in Section 3.l(aXiii) and
Exhibit B.
"Permitting lnterest" means, with respect to each of the Funders, their Permitting lnterest
as set forth in Exhibit D.
"P_ermtlling_Blqj_99t" has the meaning sct forth in Section 2.1
"Permitting Project Manager" means Idaho Power.
"Private Propertlz Interest" has the meaning set forth in Section 2.1.
"Prej-ect Costs" has the meaning set forth in Section 3.1(d)
"Project Cost Records" has the meaning set forth in Section 3.1(d).
"Project Permitting Objectives" has the meaning set forth in Section 2.2
"Projcct Permitting Tirletable" has the meaning set forth in Section 2.2
"Purchase and Sale Date" has the meaning set forth in Section 3.3(c).
"Purchasing Funder" has the meaning set forth in Section 3.3(c).
"Reptgqeq!4tivgg" means, in respect of a Funder or Permitting Project Manager, the
directors, officers, shareholders, partners, members, employees, agents, consultants,
contractors or other representatives of such Funder or Permitting Project Manager.
6
"Purchase and Sale End Date" has the meaning set forth in Section 3.3(c).
1.2
"Response Notice" has the meaning set forth in Section 3.3(c).
"Rights-of-Way''means all rights-of-way, easements, grants and other interests on which
the Boardman to Hemingway Transmission Project is or will be constructed that are
owned or to be owned by Funders or their Affiliates. Private Property Interests are
expressly excluded from this Agreement.
"Selling Funder" has the meaning set forth in Section 3.3(c).
"Subchg@" has the meaning set forth in Section 14.4(b).
r'Tenn" has the meaning set forth in Sectiotr 6.1.
"WECC Rating Process" has the meaning set forth in Section 3.3(aXiiiXA)
"Wilklrawal.DA!e" has the meaning set forth in Section 7.2(a).
"Withdrawal Payment" has the meaning set forth in Section 7.2(a).
"Withdrawing Funder" has the meaning set forth in Se.gtion 7.1.
Intemretation. The following rules of interpretation and construction shall apply in this
Agreement:
(a) The masculine shall include the feminine and neuter.
(b) References to "Articles," "Sections" and "Exhibits" shall be to articles and
sections of and exhibits to this Agreement.
(c)The Exhibits and Schedule 2.2 attached hereto are incorporated in and are
intended to be a part of this Agreement.
(d) This Agreement was negotiated and prepared by Idaho Power, PAC, and BPA
with the advice and participation of counsel. Idaho Power, PAC, and BPA have
agreed to the wording of this Agreernent and none of the provisions hereof shall
be construed against one Funder on the ground that such Funder is the author of
this Agreement or any part hereof.
(e) Each reference in this Agreement to any agreement or document or a portion or
provision thereof shall be construed as a reference to the relevant agreement or
document as amended, supplemented or otherwise modified from time to time
with the written approval, of Idaho Power, PAC, and BPA.
7
2.1
(0 Each reference in this Agreement to Governmental Requirements and to terms
defined in, and other provisions of, Governmental Requirements shall be
references to the same (or a successor to the same) as amended, supplemented or
otherwise modified from time to time.
(g) The term "dat''shall mean a calendar day, the term "month" shall mean a
calendar month, and the term "year" shall mean a calendar year. Whenever an
event is to be performed, a period cofirmences or ends, or a payment is to be made
on or by a particular date and the date in question falls on a day which is not a
Business Day, the event shall be performed, or the payment shall be made, on the
next succeeding Business Day; plqvidgd, however, that all calculations shall be
made regardless of whether any given day is a Business Day and whether any
grven period ends on a Business Day.
(h) Each refbrence in this Agreement to a Person includes its successors and
permitted assigns; and each reference to a Govemmental Authority includes any
Governmental Authority succeeding to its functions and capacities.
(i)In this Agreement, the words "include," "includes" and'lncluding" are to be
construed as being at all times followed by the words "without limitation."
References to "or" shall be deemed to be disjunctive but not necessarily
exclusive.
0)The words "hereof," "herein" and "hereunder" and words of similar import when
used in this Agreement shall, unless otherwise specif,ted, refer to this Agreement
as a whole and not to any particular provision of this Agreement.
ARTICLE II
THE PERMITTING PROJECT
Joint Permitting. The Funders desire to jointly fund and support, with the intent to be
joint owners pursuant to this Agreement, the process of obtaining Governmental
Authorizations and completing other necessary work directly related to the siting,
permitting, preliminary designing and acquiring Rights-of-Way for the Boardman to
Hemingway Transmission Project (collectively, the "Permitting_Blq.iect"), in accordance
with the terms of this Agreement. The planning, design, procurement, and acquisition of
private rights of way, private easements, private licenses, and similar private property
interests are expressly excluded from this Agreement ("Private Property Int ').
Neither the Funders nor the Permiffing Project Manager shall acquire Private Property
Interests for the Boardman to Hemingway Transmission Project without the written
agreement, not to be unreasonably withheld, of the then current Funders. Idaho Power,
BPA, and PAC will define the terms of any acquisition of Private Property Interests by
8
amending this Agreement in accordance with Section 14.7, entering into a separate
agreement expressly for the purpose of acquiring Private Property Interests, or through
the incorporation of Private Property Interests into one or lnore Definitive Development
and Construction Agreements. The Funders intend the terms of the acquisition of Private
Property Interests to be consistent with the Permitting Interests established in Exhibit D
to this Agreement.
2.2 Lroiect Permittias Obiectives and Timetable. The objectives (the "Proiect Permitting
Obiectives") and timetable (the "Project Permittins Timetable") that Idaho Power, PAC,
and BPA desire to achieve with respect to the Permitting Project pursuant to this
Agreement are set forth in Schedule 2.2. Idaho Power, PAC and BPA agree to use
Commercially Reasonable Efforts to achieve the Project Permitting Objectives and
Project Permitting Timetable in accordance with Schedule 2.2.
ARTICLE III
FUNDERS & PERMIT FUNDING COMMITTEE
3.1 Funders'Riehts & Oblieations.
(a)Pavment Obligations. Subject to the provisions of Article VU and after the
Effective Date:
(1)Each Funder is required to pay the mandatory funding payments as set
forth in Exhibit B (the "Mandatory Payments"). Any payment made by a
Funder will accrue interest, per annum, on behalf of the Funder calculated
in accordance with Idaho Power's AFUDC rate to be credited to the
Funder. Any credit shall be included in the funding invoice provided
pursuant to Section 3.1(bXi) and, as applicable, Section 3.1ftXiii).
(ii) A Funder may elect, but is not required, to pay the final funding payment
as set forth in Exhibit B (the "Completion Fundins Pa).rnent"). A Funder
that does not elect to pay the Completion Funding Payrnent set forth in
Exhibit B consistent with Sections 3.l(bXii) and a Funder that pays such
Completion Funding Payment but does not pay the Final Expense True-Up
payrnent consistent with Sestion 3.I(bxiii), shall be deemed a
Withdrawing Funder under Article VII of this Agteement.
(iii) A Funder may, in its sole and absolute discretion, elect to make any of the
Mandatory Payments or the Completion Funding Payment, in whole or in
part, in advance of the date due identified in the Permit Funding Payment
Schedule set forth in Exhibit B, in accordance with Section 3.1(b). In the
event a Funder elects to make an early payment which includes an
9
AFUDC accumulation component, accumulation of AFUDC will cease
upon receipt of the payn'rent by the Permitting Project Manager.
(b) Method of Payment. All payments required under the terms of this Agreement
shall be made to an account or accounts designated by the Permitting Project
Manager to which payment is owed by electronic transfer in immediately
available funds in the lawful crrrency of the United States. The Permitting Project
Manager shall invoice the payments set forth in Exhibit B of this Agreement as
follows:
(D Mandatorlz Payments. The Permitting Project Manager shall deliver to the
Funders an invoice ("Funding Invoice") ten (10) days in advance ofeach
of the Mandatory Payment dates as set forth in Exhibit B. The invoice
shall provide a sufficient level of detail describing the activities to be
performed by the Permitting Project Manager, as requested by the
receiving Funder. With the exception of Mandatory Payrnent I which is
due twenty (20) days after the Effective Date, Funders shall tender
payments to the Permitting Project Manager within forty (40) days of
receipt of the Funding lnvoice. Any payment past due will accrue interest,
per annum, calculated in accordance with Section 3.1(aXi). The failure of
the Permitting Project Manager to timely deliver an invoice shall not
relieve any Funder of its paynent obligations in respect to the Mandatory
Payments or Completion Funding Payment shown on such invoice.
(ii) Completion Fundine Payment. The Permitting Project Manager shall
provide the Funders with written notice of the expected date of completion
of the Project Permitting Objectives and an invoice for the Completion
Funding Payment within sixty (60) days after the publication of a Final
Record of Decision by the BLM in the Federal Register for the Boardman
to Honingway Transmission Project (the "Final Payment Invoice"). The
Final Payment Invoice shall provide a sufficient level of detail describing
the activities performed or to be performed by the Permitting Project
Managel as requested by the receiving Funder. The Funders shall provide
written notice to the Permitting Prdect Manager of its intent to pay the
Completion Funding Payment within twenty (20) days from receipt of the
Final Payment Invoice for the Completion Funding Payment (the "Notice
of Payrnent"). Any Funder who fails to issue a Notice of Payment within
such twenty {20) day period or issues a Notice of Payment within such
twenty (20) day period but fails to tender payment to the Permitting
Project Manager within forty (a0) days of the Notice of Payment shall be
deemed a Withdrawing Funder pursuant to Article VII, Eyidod,
10
however, that Idaho Power may not withdraw from this Agreement
pursuant to Article VII. The Funders eleoting to make the Completion
Funding Payment shall tender payment to the Permitting Project Manager
within forty (a0) days of the Notice of Payment.
(ii| Final Expense True-Up Payment. Except where a Funder has withdrawn
from this Agreement pursuant to Article VII, the Permitting Project
Manager shall deliver to the Funders an invoice one hundred and eighty
(180) days following the Notice of Payment relating to a Completion
Funding Payment to include a final true up payment as provided in Exhibit
B (the "Final Expense True-Up"). The Final Expense True-Up payment
shall include all cost adjustments to Mandatory Payments 1, 2 and 4
approved by the Permit Funding Committee and not previously paid by
the Funders to the Permitting Project Manager and any credit for any
accrued interest not previously received by the Funders pursuant to
Section 3.1(aXi). The invoice shall provide the Funders sufficient level of
detail describing the activities performed by the Permitting Project
Manager, as requested by the receiving Funder. The Funders shall tender
payment to the Permitting Project Manager within thirty (30) days of
receipt of the invoice. The failure by the Permitting Project Manager to
timely deliver an invoice shall not relieve any Funder of its payment
obligations in respect to the Final Expense True-Up payment shown on
such invoice. Any true up associated with a Funder's withdrawal from the
Agreement is subject to Article VII. In the case of any overpayment by the
Non-Permitting Project Manager Funders, the Permitting Project Manager
shall promptly return the amount of the overpayment to the Non-
Permitting Project Manager Funder, together with interest for the period
from the date of overpayment until such amount has been paid, calculated
in the manner prescribed for calculating interest in Section 3.1(a).
(c) Disputed Amounts. If a Funder disputes any portion of any amount described in
Exhibit B, the Funder shall pay its total amount of the invoice when due, and, if
actually known at the time by the Funder, identify the disputed amount and state
that the disputed amount is being paid under protest. Any disputed amount shall
be resolved pursuant to the provisions of Article XIII. If it is determined pursuant
to Article XIII that an overpayment or underpayment has been made by the
Funder or any amount allocated to a Funder on an invoice is incorrect, then (i) in
the case of any overpayment by a Funder, the Permitting Project Manager shall
promptly retum the amount of the overpayment (or credit the amount of the
overpayment on the next invoice) to the Funder; and (ii) in the case of an
underpa5rment by the Funder, the Funder shall promptly pay the amount of the
1l
underpayment to the Permitting Project Manager (in each case, together with
interest for the period from the date of overpayment, undelpayment, or incorrect
allocation, until such amount has been paid or credited against a future invoice
calculated in the manner prescribed for calculating interest in Section 3.1(a)).
(d) Audit Rights. Each Funder may, at its cost, at any time during normal business
hours and with reasonable prior notice to the Permitting Project Manager and the
other Funders, of not less than ten (10) Business Days, but not more often than
twice in any twelve (12) month period, inspect and audit the books and records of
the Permitting Project Manager and any of its Affiliates (and the Permitting
Project Manager shall secure such rights for the Permitting Project Manager from
its Affiliates) relating: (1) to the determination of the payments set forth in
Exhibit B for which the Funders are responsible under this Agreement, including
the costs set forth in Exhibit C (the "PfqieqI_eo$S"), within twelve (i2) months
prior to the date of the audit notice; and (2) directly related to and involved in
formulating the Mandatory Payments, Completion Funding Payment, and any
applicable true up payment pursuant to this Agreement ("'Project Costs Resods").
Audit findings shall be provided to each Funder to this Agreement. If any audit
discloses that, during such twelve (12)-month period, an ovelpayment or
underpayment of Project Costs has been made by the Funders or the amount of
any Project Costs allocated to the Funders on an invoice is incorrect, then such
overpayment, underpayment or incorrect amount shall be resolved pursuant to
Article XIII. The Funders requesting the audit shall reimburse one hundred
percent (100%) of all reasonable costs and expenses (including intemal costs and
expenses) incurred by or on behalf of the Permitting Project Manager and any of
its Affiliates in complying with the provisions of this Section 3.1(d), plevided,
however. that such Funders shall not be required to reimburse any such costs if
the audit determines that Funders, in combination, have made more than Twenty-
Five Thousand Dollars ($25,000) in overpayments of Project Costs or more than
Twenty-Five Thousand Dollars ($25,000) in Project Costs have been incorrectly
allocated to Funders.
(e) Access. The Permitting Project Manager shall, to the extent possible under any
Rights-of-Ways, provide each Funder and its designees reasonable access to the
Boardman to Hemingway Transmission Project sites to permit the Funders and
their designees to inspect the development, preliminary design, siting, Rights-of-
Way acquisition and permitting of the Boardman to Hemingway Transmission
Project, provided that (i) the Funders and their designees do not interfere with the
development, preliminary designing, siting, Rights-of-Way acquisition and
permitting of the Boardman to Hemingway Transmission Project or any portion
thereof or pose a safety hazard; (ii) the Funders and their designees comply with
I2
any requirements of any Rigfrts-of-Ways applicable to the Boardman to
Hemingway Transmission Project; and (iii) the Funders and their designees
performing the inspection comply with the Permitting Project Manager's or any
other contractor's safety and security rules, notice of which the Permitting Project
Manager shall provide to the Funders.
3.2 Permit Funding Committee.
(a) Scope and Authority. The Permit Funding Committee shall consider, evaluate and
take action with respect to mutually resolving the following matters: (1) any and
all changes in the scope or schedule of the Permitting Project that directly affect
the cost of the Mandatory Payments, Completion Funding Payment or the costs
otherwise associated with the Permitting Project; (2) arry and all proposed cost
adjustments to the Mandatory Payments, Completion Funding Payment or costs
otherwise described in Exhibit B; (3) any and all technical specifications and
other matters related to the Permitting Project; (4) requests from and provide
guidance to the Permitting Project Manager from time to time as necessary or
when requested relating to the advancement of the Project Permitting Objectives
and Project Timetable, or the Permitting Project; (5) general development of
policy and strategy with respect to the Permitting Project; and (6) any and all
direct or indirect effects of the development of other regional transmission
projects (including project schedule and location of potential interconnection
points), including, but not limited to, the Cascade Crossing Project and Gateway
West Project, on the development and permitting of the Boardman to Hemingway
Transmission Project.
(b) Membership. The Permit Funding Committee shall be comprised of a
representative of each Funder (each a "Funding Committee Representative").
Each Funder's Funding Committee Representative shall be a senior level
representative or designee with authority to consider and act to resolve issues that
arise between or among the Funders.
(c) Permitting Project Manaser. The Permitting Project Manager shall inform the
Permit Funding Committee and the Funding Committee Representatives through
formal and informal communication, of the ongoing progress and matters that
impact the Governmental Authorizations or other necessary work relating to the
Permitting Project. The Permitting Project Manager shall confer and communicate
with the Permit Funding Committee and Funding Committee Representatives as
to the matters described in Section 3.2(a) or as otherwise provided in this
Agreement.
13
J.J
(d) Funding Committee Meetines. The Permit Funding Committee will meet at least
monthly, in person or telephonically, or as deemed necessary by the Funding
Committee Representatives. Any Funding Committee Representative may request
a meeting of the Permit Funding Committee atany time and for any reason. The
Permitting Project Manager shall provide the Permit Funding Committee with
regular statements, at least monthly, regarding the Permitting Project that include
future expense proj ections.
(e) Fundins Committee Procedures. The Funding Committee Representatives shall
work in good faith to consider, evaluate and make best efforts to mutually resolve
any issues that are raised before the Permit Funding Committee. If the Funding
Committee Representatives are unable to mutually resolve any issue, they shall
refer the matter to the Executives that have the authority to settle the issue. If the
Executives are unable to mutually resolve the issue, the Funders may move to
dispute resolution as set forth in Article XIIL AII communications and writings
exchanged between andlor among the Permitting Project Manager, Funding
Committee Representatives, and Executives in connection with the Permit
Funding Committee shall be treated as Confidential Information in accordance
with Article XII.
(0 Joint Working Groups. Joint working groups may be established by the Permit
Funders Committee on an ad hoc basis when the need arises to advance certain
specific tasks related to the Permitting Project and the Boardman to Hemingway
Transmission Project, including, but not limited to, consultation on technical
specifications and other matters related to the Permitting Project.
(g) Committee Conversion. Within sixty (60) days after one or more Funders tenders
Mandatory Payment 3 and the Completion Funding Payment set forth in Exhibit
B, the Funders shall amend this Agreanent, or enter into a new agreement, that
establishes a committee structure that is consistent with the Permitting Interests of
the Funders.
Future Ageements
(a) Neqotiation Process
Completion Notice. Unless this Agreement is terminated pursuant to
Article VI, the Permitting Project Manager shall provide the Funders with
written notice within sixty (60) days following the publication of a Final
Record of Decision by the BLM in the Federal Register for the Boardman
to Hemingway Transmission Project (the "Completion Notice") of the
expected date of completion of the Project Permitting Objectives.
(i)
t4
Notwithstanding the foregoing, any Funder may commence negotiations
pursuant to this Section 3.3 for reaching Definitive Development and
Construction Agreements at any time by providing written notice of its
desire to do so to the other Funders pursuant Section 14.10.
(ii) Neeotiation Period. Upon receipt of the Completion Notice, the Funders
shall meet, subject to Section 3.3(d(iii), to negotiate one or more
Definitive Development and Construction Agreements for up to one
hundred eighty (180) days (the "Negotiation Period"). Upon the
termination of the Negotiation Period, the Funders may agtee to extend the
Negotiation Period for an additional period not to exceed one hundred
eighty (l 80) days.
(iii) Negotiations. During the Negotiation Period, the Funders will attempt, to
the greatest extent possible, but subject to the other provisions of this
Section 3.3(aXiii), to keep the Definitive Development and Construction
Agreements consistent with the terms and conditions of this Agreement,
including the Permitting Interests set forth in Exhibit D, as may be
amended from time to time by mutual agreement of the Funders pursuant
to Section 14.7. In negotiating the Definitive Development and
Construction Agreement the Funders shall also consider the following:
(A)Path.Rattu. The Funders acknowledge and agree that the
Permitting Interest set forth in Exhibit D may be impacted by the
WECC Three Phase Project Rating Process (the "WECC Rating
Process") and that each Funder's Permitting Interest is subject to
the results of the WECC Rating Process. Subject to the outcome of
the WECC Rating Process, the Funders may, using the Permitting
Interests set forth in Exhibit D as a baseline for allocation,
mutually agtee to further negotiate, revise, or adjust the Permitting
Interest set forth in Exhibit D for purposes of negotiating
Defi nitive Development and Construction Agreements, including
adjustments to Mandatory Payments, the Completion Funding
Payment or the Final Expense True-Up paid pursuant to this
Agreement. The Funders shall cooperate and support each other in
the WECC Rating Process in a manner consistent with Section 4.5.
(B) Altemative Analysis. BPA is considering various transmission and
other alternatives to meet their service obligations in eastern ldaho.
BPA's decision whether to participate in and timing associated
with participation in the development and construction of the
15
Boardman to Hemingway Transmission Project may be based on
BPA's evaluation of such alternatives.
(c)BPA NEPA Requuements. BPA has certain obligations and
responsibilities under NEPA and other applicable Governmental
Requirements that must be fulfilled before it can make a definitive
decision concerning whether to participate in development and
construction of the Boardman to Hemingway Transmission
Project. Nothing in this Agreement shall be construed as obligating
or committing BPA to enter into the Definitive Development and
Conskuction Agreement before the NEPA review process for the
Boardman to Hemingway Transmission Project has been
completed and BPA has made a decision regarding how to
proceed. Additionally, PAC's participation in the Boardman to
Hemingway Transmission Project may be impacted by the
schedule and design specifications of the Cascade Crossing Project
and,lor the Gateway West Project. As a result, or for other reasons,
BPA or PAC may decide not to proceed further and to withdraw
from this Agreernent in accordance with Article VII at any time.
(D) Additional Materials. The Funders may request the Permitting
Project Manager or other Funders to make available, and the
Permitting Project Manager or other Funders will make available,
on mutually agreed to terms (such agreement not to be
unreasonably withheld) additional information related to the
design, engineering, construction, or procurement of materials
related to the Boardman to Hemingway Transmission Project that
are not part of this Agreement.
(b) Negotiation Termination.Any negotiations pursuant to this Section 3.3 shall
automatically terminate, unless the Negotiation Period is extended as provided in
Section 3.3(aXii) (the "Negotiations End D&").
(c) Transfer of Interest. Following the Negotiations End Date and notwithstanding
Article V herein, to the extent a Definitive Development and Construction
Agreement is not executed, any Funder who has made all payments pursuant to
Exhibit B may issue a written notice to proceed with the development and
construction of the Boardman to Hemingway Transmission Project to the other
Funders (the "Ngligg_te_Bl9gq9d"). Notwithstanding anything to the contrary in
Article VII, within thirty (30) days of the receipt of the Notice to Proceed, each
Funder shall notify the other Funders whether it does or does not desire to proceed
with the development and construction of the Boardman to Hemingway
t6
Transmission Project (each a "Response Notice"). Within two (2) years of receipt
of the last Response Notice (the "Purchase and Sale End Date") the Funders who
desire to proceed with the development and construction of the Boardman to
Hemingway Transmission Project (each a "Purchasing Funder") shall purchase
and the Funders who do not desire to proceed with the development and
construction of the Boardman to Hemingway Transmission Project (each a
"Selling Funder") shall sell all of the Selling Funder's rights, title, and interests in
and to the Permitting Project, including all reports, studies, and Governmental
Authorizations, Rights of Way, and any other property whatsoever of whatever
nature and kind, whether real or personal, tangible or intangible, acquired or
perfected by the Permitting Project Manager for the benefit of the Funder(s)
pursuant to the terms of this Agreement. Purchasing Funders shall select the date
for the purchase and sale (the "Purchase and Sale Date") which shall occur before
the Purchase and Sale End Date, written notice of which they shall provide to the
Selling Funders. On the Purchase and Sale Date, the Purchasing Funders shall pay
immediately available funds pro-rata (based on their Permitting Interest after
glving effect to the sale) and the Selling Funders shall receive the aggregate
amount of all payments made pursuant to Exhibit B. The Funders shall execute
such agreements and documents as may be reasonably required to facilitate the
purchase and sale contemplated pursuant to this Section 3.3 (c).
(d) If two or more Purchasing Funders remain pursuant to Section 3.3(c), the
Purchasing Funders shall meet to negotiate one or more Definitive Development
and Construction Agreements pursuant to Sectiond 3.3(aXii), (aXiii), (!), (g) and
(d)
(e) [n the event no Funder has issued a Notice to Proceed, the Funders retain their
respective right, title and interest in the Permitting Project pursuant to this
Agreement.
Other Projects. Nothing in this Agreement shall preclude a Funder from taking any action
(or having its Affiliates take any action) with respect to any other transmission project,
including a transmission project that may compete with the Permitting Project.
ARTICLE IV
PERMITTING PROJECT MANAGER
4.1 Appointment of Permittine Project Manager.
(a) Appointment. The Funders hereby appoint Idaho Power, and Idaho Power hereby
accepts appointment, to serve as Permitting Project Manager of the Permitting
3.4
l7
Project and will perform the obligations of the Permitting Project Manager
expressly set forth in this Agreement, in accordance with the terms and conditions
of this Agreement.
(b) Duty. The Funders agree that the Permitting Project Manager shall not have any
obligations, responsibilities or duties to the Funders other than as are expressly
provided for in this Agreement.
4.2 Authoritlz of Permitting Pro.iect Manager.
(a) Role of Permittine Project Manager. The Permitting Project Manager shall
administer and oversee the Permitting Project and shall be responsible for the day
to day activities involved in advancing the Permitting Project to achieve the
Project Permitting Objectives and Project Permitting Timetable, including the
responsibility for obtaining all required Govemmental Authorizations, siting, and
Rights-of-Way acquisition relating to the Boardman to Hemingway Transmission
Project. The Permitting Project Manager will advance funds in anticipation of
receiving the Mandatory Payments from Funders, as necessary, to fulfill the
Permitting Project Objectives ("Advance Contributiom"). Idaho Power' s
Advance Contributions will accrue interest, per annum, calculated in accordance
with [daho Power's AFUDC rate. The Advance Contributions and accrued
AFUDC will be reimbursed as part of the Funder's Mandatory Payments 2 or 4 as
set forth in Exhibit B, as applicable. The Permitting Project Manager shall not
collect payments other than those described in Exhibit B or as approved by the
Permit Funding Committee. The Permitting Project Manager will exercise or
enforce all benefits, rights and rernedies under this Agreement for the benefit of
the Funders pro rata (in accordance with their respective Permitting Interests) and
without adverse distinction or undue discrimination between or against the
Funder's respective Permitting lnterests. [n furtherance and not in limitation of
the immediately preceding sentence, the Permitting Project Manager agrees to
transfer, assign, distribute, pay over or otherwise make available to the Non-
Permitting Project Manager Funders, the Non-Permitting Project Manager
Funder's pro rata share (based on its respective Permitting Interests) in any
payments or proceeds obtained pursuant to this Agreement.
(b) Communication. The Permitting Project Manager shall have the duty to
communicate the status of the Permitting Project, including the Project Permitting
Objectives, on a regular basis with the Permitting Funding Committee in a
manner consistent with Section 3.2(.c).
(c) Reporting. The Permitting Project Manager shall be responsible for preparing and
distributing monthly reports to the Permitting Project Committee (or less
18
frequently if mutually required by the Permit Funding Committee) regarding (i)
Project Costs paid and projected to be incurred, and, to the extent necessary,
recommend to the Permit Funding Committee adjustments to the Permit Funding
Schedule to satisfu expected Project Costs to be incurred in relation to the Project
Permitting Objectives and (ii) activity and progress with respect to achieving the
Pmject Permitting Objectives and the Project Permitting Timetable. The
Permitting Project Manager shall be responsible for preparing and distributing
reports to the Permit Funding Committee at such other times as any material
change occurs or is contemplated that affects the achievement of the Project
P ermitting Obj ectives.
(d) Project Coordination. Notwithstanding anything to the contrary contained in this
Agreement, the Permitting Project Manager shall work diligently, consult with
and obtain the express written approval of the Funders with respect to the
location, technical design and engineering specifications relating directly to the
interconnection point of the Boardman to Hemingway Transmission Project and
the proposed Cascade Crossing Project and Gateway West Project.
4.3 Funder's Ownership Interests.
(a) Perfection of Existine Ownership Interests. Commencing on the Effective Date of
this Agreement, the Permitting Project Manager will take all necessary and
reasonable action, unless prohibited by applicable Governmental Requirements, to
perfect and vest, on behalf and in the name of the Funders, in accordance with the
Funders' Permitting Interest set forth in Exhibit D, an undivided ownership
interest as tenants-in-common in all right, title, and interest in all reports, studies,
Governmental Authorizations (including permits) and other property of whatever
nature and kind, whether real or personal, tangible or intangible, purchased or
acquired prior to the Effective Date by or on behalf of the Permitting Project
Manager or Idaho Power for the Boardman to Hemingway Transmission Project,
including all Governmental Authorizations and Rights-of-Way required for the
Boardman to Hemingway Transmission Project and acquired by Idaho Power
hereunder.
(b) Perfection of Future Ownership Interests. Following the Effective Date of this
Agreement, the Permitting Project Manager shall acquire, unless prohibited by
applicable Govemmental Requirements, on behalf and in the name of the
Funders, in accordance with the Funders' respective Permitting Interests set forth
in Exhibit D, an undivided ownership interest as tenants-in-corrmon in all right,
title, and interest in all reports, studies, Governmental Authorizations (including
permits) and other property of whatever nature and kind, whether real or personal,
19
4.4
tangible or intangible, for the Boardman to Hemingway Transmission Project,
including all Governmental Authorizations and Rights-of-Way required for the
Boardman to Hemingway Transmission Project and acquired by the Permitting
Project Manager hereunder. The Funders and the Permitting Project Manager
agree that any reports, studies and Governmental Authorizations shall be issued in
the names of all Funders. Notwithstanding any provision to the contrary contained
in this Agreement, the Permitting Project Manager shall make all applications for
Government Authorizations, and shall obtain all such Govemment
Authorizations, reports, and studies, in the name of the Funders, to the extent
permitted by applicable Govemmental Requirements. In the event a
Governmental Authorization, report or study is not issued in the name of all
Funders, the Funders and Permitting Project Manager agree to take all necessary
and reasonable actions to perfect and vest, on behalf and in the name of the
Funders, in accordance with the Funders' respective Permitting lnterests, an
undivided ownership interest as tenants-in-common in all right, title and interest
in all such Govemmental Authorizations, reports, and studies.
(c) Forfeiture of Ownership lnterests. In the event any Funder elects not to make all
of the payments set forth in Exhibit B, or otherwise withdraws from this
Agreement pursuant to Article VII. the Withdrawing Funder shall convey to the
remaining Funders all right, title, and interest in this Agreement, as well as all
right title and interest in all reports, studies, Governmental Authorizations
(including permits), Rights of Way, and any other property whatsoever of
whatever nature and kind, whether real or personal, tangible or intangible,
acquired or perfected by the Permitting Project Manager for the benefit of the
Funders pursuant to the terms of this Agreement pursuant to Section 7.2. If and to
the extent the right, title, or interest in any permit or Governmental Authorization
is by its terms or pursuant to applicable law not assignable, the Withdrawing
Funder shall execute such reasonable agreements, licenses, or other instruments as
shall be deemed reasonably necessary by the remaining Funders to otherwise
convey all use and enjoyment of the Withdrawing Party's right, title, and interest
in such permit or Governmental Authoization.
Standard of Work. The Permitting Project Manager shall perform all of its obligations
under this Agreement as an independent contractor and in accordance with Good Utility
Practice and applicable Governmental Requirements and Governmental Authorizations
and without adverse distinction among the Funders.
Assistance. Each Funder shall cooperate with the Permitting Project Manager promptly,
as and when reasonably requested by the Permitting Project Manager, to assist the
Permitting Project Manager in the performance of its duties, responsibilities and
4.5
20
obligations under this Agreement, including executing and delivering from time to time
such additional documents, certificates or instruments, and taking such additional actions,
as may be reasonably requested by the Permitting Project Manager. Each Funder shall
bear its own costs for providing such cooperation and assistance as requested by the
Permitting Project Manager unless all of the Funders agree otherwise in writing. Each
Funder shall provide internal personnel, services, know how, intellectual property or
other internal resources as may be reasonably necessary or appropriate to carry out the
intent of and to perform the Funders' and Permitting Project Manager's obligations under
this Agreement or as all of the Funders may otherwise agree to in writingi provi-ded
however to the extent the Permitting Project Manager desires to use for the purposes of
this Agreement services of a Funder that are the subject of a separate agreement, such
Funder shall consent, in its sole and absolute discretion, to such use and be reimbursed by
the other Funders and the Permitting Project Manager as mutually agreed to by all the
Funders. No Funder (other than Idaho Power in its role as Permitting Project Manager)
shall have the right to invoice the other Funders for the costs or expenses associated with
the utilization of internal personnel, services, know how intellectual property or other
intemal resources necessary or appropriate to carry out the intent of and to perform its
obligations under this Agreement, unless otherwise agreed upon in writing by the
Funders. Nothing in this Agreement shall preclude a Funder from exercising any rights
expressly granted it under this Agreement or taking any action (or having its Affiliates
take any action) with respect to any other transmission project, including any such project
that may compete with the Permitting Project. The Permitting Project Manger shall
request assistance under this Section 4.5 without adverse distinction of the Funders.
4.6 Remedies
(a) Notwithstanding any provision to the contrary contained in this Agreement, the
Permitting Project Manager shall not have any liability to the Non-Permitting
Project Manager Funders in connection with the performance of its covenants and
obligations under this Agreement, plevi&d, however, the Permitting Project
Manager shall be liable for any direct actual damages resulting from its own
negligence or breach of this Agreernent. The Funders agree that each Funder has a
duty to mitigate any damages and shall use Commercially Reasonable Efforts to
minimize any damages it may incur as a result of the Permitting Project
Manager's failure to perform or breach of any of its covenants or obligations
under this Agreernent.
(b) The Funders and the Permitting Project Manager acknowledge that the obligations
and covenants performed by the Permitting Project Manager hereunder are unique
and that the Non-Permitting Project Manager Funders will be irreparably injured
should such obligations and covenants not be performed in accordance with the
2l
5.1
5.2
terms and conditions of this Agreement. Consequently, the Non-Permitting
Project Manager Funders will not have an adequate remedy at law if the
Permitting Project Manager shall fail to perform its obligations and covenants
hereunder. The Non- Permitting Project Manager Funders shall have the right, in
addition to any other remedy available under this Agreement, to specific
performance of the Permitting Project Manager's obligations and covenants
hereunder, and the Funders and the Permitting Project Manager agree not to take a
position in any proceeding arising out of this Agreement to the effect that the
Non-Permitting Project Manager Funder has an adequate remedy at law.
4.7 tnjury to Third Parties. Idaho Power and PAC shall be responsible for obtaining
and maintaining during the Term insurance covering their respective legal
liabilities to third persons or the property of third persons related to their
respective obligations under this Agreement in amounts consistent with Good
Utility Practice and any applicable Governmental Requirements. Insurance
coverage required by this Section 4.7 for Idaho Power and PAC may be through a
carrier or self-insured, or any combination of carrier insured and self-insured.
BPA shall be responsible for irju.y or damage to third persons or the property of
third parties related to its obligations under this Agreement and caused by BPA in
accordance with the provisions of the Federal Tort Claims Act.
ARTICLE V
TRANSFER OF RIGHTS AND INTERESTS; ASSIGNMENT
Prohibited Transfers._4nd A.ssignments. Except as provided in Section 3.3(c) and Section
5.2, no Funder may, without the express written consent of the other Funders (such
consent not to be unreasonably withheld, conditioned or delayed) sell, assign, transfer,
convey or otherwise dispose of directly, in whole or in part, any of its rights, titles or
interest in and to (a) this Agreement including its rights, duties and obligations hereunder,
or (b) the Permitting Project. Any sale, assignment, transfer, conveyance or other
disposition in violation of this Article V shall be null and void.
Permitted Assignments and Transfers. Notwithstanding anything to the contrary
contained in this Agreernent, Section 5.1 shall not restrict:
(a) the right of any Funder to transfer voluntarily (and without the consent of the
other Funders) all of its Permitting tnterest in the Permitting Project and all of its
rights, titles and interests in and to this Agreement (including all of its rights and
obligations in this Agreement as Permitting Project Manager, if any) in
connection with any sale, merger or other transfer of substantially all of such
Funder's electric transmission facilities as an operating entity; proyidgd, however,
that the effectiveness of such assignment shall be conditioned upon the assignee
22
5.3
agreeing in writing to assume all of the rights and obligations of the assigning
Funder under this Agreement (including all of its rights and obligations in this
Agreement as Permitting Project Manager, if any) as of the effective date of
assignmart;
(b) the right of any Funder to transfer voluntarily (and without the consent of the
other Funders) all of its Permitting Interest in the Permitting Project and all of its
rights, titles and interests in and to this Agreement (including all of its rights and
obligations in this Agreement as Permitting Project Manager, if any) to an
Afflrliate of the Funder; provided, however, that the effectiveness of such
assignment shall be conditioned upon the assignee agreeingin writing to assume
all of the rights and obligations of the assigning Funder under this Agreement
(including all of its rights and obligations in this Agreement as Permitting Project
Manager, if any) as of the effective date of assignment;
(c) the right of any Funder to transfer voluntarily all of its Permitting lnterest in the
Permitting Project and all of its rights, titles and interest in and to this Agreement
(including all of its rights and obligations in this Agreement as Permitting Project
Manager, if any) to a third party that is financially and technically capable of
performing the transferring Funder's (and, Permitting Project Manager's, if any)
obligations under this Agreement; provided that: (i) the other Funders approve, in
their sole discretion, such transfer, and (ii) the other Funders are offered the right
of first refusal to purchase such Permitting Interest and all of the transferring
Party' rights, titles and interests in and to this Agreement (including all of its
.ights and obligations in this Agreement as Permitting Project Manager, if any) at
the amounts set forth in the Permitting Funding Schedule; provided, however, that
the effectiveness of such assignment shall be conditioned upon the third-party
purchaser agreeing in writing to assume all of the rights and obligations of the
assigning Funder under this Agreement (including all of its rights and obligations
in this Agreement as Permitting Project Manager, if any) as of the effective date
of assignment.
Release. Upon any assignment or transfer pursuant to this Section 5.2, no Funder
transferring or assigning its right, title and interest in this Agreement and the Permitting
Project shall have any further obligations or responsibilities under this Agreement,
ARTICLE VI
TERM
Term. The term of this Agreement ("Term") shall commence on the Effective Date and
shall continue in full force and effect until the successful completion of the duties and
obligations under this Agreement in accordance with the terms of this Agreement, unless
6.i
23
6.2
terminated earlier as set forth in this Article VI. Notwithstanding the foregoing, this
Agreement shall terminate not later than January 1,2022.
Early Termination.
(a) The Term of this Agreement shall terminate effective upon the occurrence of any
of the following:
(i) Withdrawal of two (2) Funders, if there are three (3) Funders at the time,
or one (l) Funder, if there are only two (2) Funders at the time, in each
case, pursuant to Article VII;
(iD the mutual written consent of the Funders; or
(iii) The effective date of a separate written agreement among all of the then
current Funders which by its terms supersedes this Agreement.
(b) If this Agreement is terminated pursuant to this Section 6.2, then, except as for
those provisions that are expressly intended to survive termination pursuant to this
Agreement, this Agreement shall terminate and become void and of no further
force and effect, without further action by any Funder, provided that no Funder
shall be relieved from any of its obligations or liabilities hereunder accruing prior
thereto.
(c) If this Agreement is terminated pursuant to Section 6.2(aXi), then the Non-
Withdrawing Funder may, in its sole and absolute discretion, proceed with the
Permitting Project.
ARTICLE !'II
WITIIDRAWAL
Withdrawal. PAC or BPA may withdraw from this Agreement at any time and for any
reason, or for no reason, subject to the limitations of this Article VII (a "Withdrawing
Funder"). Idaho Power shall have no right to withdraw from this Agreement under any
circumstance or at any time, including if it is a Defaulting Funder pursuant to Article
VIII. A Withdrawing Funder shall provide reasonable prior written notice to the other
Funders of its intent to withdraw from this Agreement ("Notice of Withdrawal"), and the
Notice of Withdrawal shall specify the effective date of withdrawal, which in no event
shall be less than five (5) Business Days after the date of delivery of the Notice of
Withdrawal.
Effbct of Withdrawal. The Withdrawing Funder's withdrawal from this Agreement shall
be subject to the following:
7.1
7.2
24
(a) Withdrawal will become effective as of the last day of the month the Withdrawing
Funder provides its Notice of Withdrawal ("Withdrawal Date"). As of the
Withdrawal Date, the Withdrawing Funder shall be obligated to pay the
Permitting Project Manager any outstanding Mandatory Payments identified in
Exhibit B, including a true up that shall include all cost adjustments to Mandatory
Paynents 1,2 and 4 approved by the Funding Committee and not previously paid
by the Withdrawing Funder as of the Withdrawal Date and any credit for any
accrued interest pursuant to Section 3.1(a)(i) (the "Withdrawal Payment"). The
Permitting Project Manager shall invoice, in a manner consistent with Section
3.1O), the Withdrawing Funder for the Withdrawal Payment within one hundred
twenty (120) days following the Withdrawal Date.
(b) Except as otherwise provided in Article III of this Agreement, effective as of the
Withdrawal Date, a Withdrawing Funder shall forfeit and transfer to the
remaining Funders all of its right, title and interest in: (i) the Permitting Project,
including all Governmental Authorizations, and amounts paid to the Permitting
Project Manager through the Withdrawal Date; (ii) all Rights-of-Way issued by
the BLM and other federal agencies (including any other permits, licenses,
options, permissions); and (iii) any and all reports and studies. The Withdrawing
Funder's Permitting Interest (including all project investrnents associated
therewith) shall be allocated to the remaining Funders at no cost to the remaining
Funders, such that the remaining Funders shall have 100% of the Permitting
Interest in the Permitting Project.
(c) The Withdrawing Funder shall execute such documents and instruments as may
be reasonably requested by the remaining Funders in connection with the
withdrawal, including as may be necessary to evidence the Withdrawing Funder's
relinquishment of its rights, titles and interest in the Permitting Project; plovidgd,
however, that the rernaining Funders shall not be obligated to pay or reimburse
the Withdrawing Funders for any Project Costs or the Withdrawal Payment paid
to the Permitting Project Manager through the Withdrawal Date or to otherwise
compensate the Withdrawing Funder for its rights, titles and interest in the
Project.
ARTICLE VIII
EVENT OF DEFAULT
Event of Default. Each of the following events shall constitute an event of default
("Event of Default") by the defaulting Funder, including the Permitting Manager Funder,
(a "D_qfautiug_Eu4d_9l") :
8.1
25
8,2
(a) Subject to Section 3.1(bXii), the failure to make, when due, any payment required
pursuant to this Agreement, if such failure is not remedied within ninety (90) days
after written notice thereof from a Non-Defaulting Funder;
(b) any material representation or warranty made by a Defaulting Funder herein that
is false or misleading in any material respect when made, unless (i) the fact,
circumstance or condition that is the subject of such representation or warranty is
made true within thirty (30) days after notice thereof from a Non-Defaulting
Funder, provided that if the fact, circumstance or condition that is the subject of
such representation or warranty reasonably cannot be corrected within such thirty
(30) day period, then the Defaulting Funder shall have an additional period of
time (not to exceed sixty (60) days) in which to correct the fact, circumstance or
condition that is the subject of such representation or warranty so long as the
Defaulting Funder commences good faith activities to correct the fact,
circumstance or condition that is the subject of such representation or warranty
during the initial 30-day cure period and continues thereafter to utilize
Commercially Reasonable Efforts to effect a cure, and (ii) (A) such cure removes
any adverse effect on the Non-Defaulting Funders of such fact, circumstance or
condition being otherwise than as first represented, or (B) such fact, circumstance
or condition being otherwise than as first represented does not materially
adversely affect the Non-Defaulting Funders;
(c) a transfer, assignment or other disposition of its interest in this Agreement or its
Permitting Interest in the Permitting Project, in each case, in violation of Article
Y;
(d) the failure to perform or breach of any material covenant or obligation set forth in
this Agreement (other than provided for in this Section 8.1), if such failure is not
remedied within thirty (30) days after written notice thereof from a Non-
Defaulting Funder, provided that if such failure or breach cannot reasonably be
cured within thirty (30) days, then the Defaulting Funder shall have an additional
period of time (not to exceed ninety (90) days) in which to cure such failure or
breach so long as the Defaulting Funder commences good faith activities to cure
the failure or breach during the initial 30-day cure period and thereafter continues
to utilize Commercially Reasonable Efforts to effect a cure; or
(e) the Defaulting Funder or the Permitting Project Manager becomes Bankrupt.
Cure by Non-Defaulting Funders. If a Defaulting Funder fails to cure an Event of
Default, then the Non-Defaulting Funders may, individually or together, in their
respective sole discretion, attempt to cure the Event of Default, provided that the
26
Defaulting Funder shall reimburse the Non-Defaulting Funders for all costs and expenses
incurred by or on behalf of the Non-Defaulting Funders pursuant to this Section 8.2.
8.3 Remedies.
(a) [f an Event of Default occurs and is continuing, then each of the Non-Defaulting
Funders shall be entitled to exercise any of its remedies provided for in this
Agreement and any of its remedies at law or in equity, including recovery from
the Defaulting Funder of any damages suffered as a result of the Event of Default,
subject to Section 11.6. The Non-Defaulting Funders shall use Commercially
Reasonable Efforts to mitigate any damages suffered as a result of the Event of
Default.
(b) If an Event of Default by BPA or PAC occurs and is not cured as provided in this
Article VIII then BPA or PAC, as the Defaulting Funder, shall be deemed to be a
Withdrawing Funder under and subject to the terms of Article VII.
(c) The Funders acknowledge that the obligations and covenants performed by Idaho
Power (as a Funder and Permitting Project Manager) hereunder are unique. If an
Event of Default by Idaho Power occurs and is not cured as provided in this
Article VIII, BPA and PAC shall have the right, in addition to any other remedy
available under this Agreement, at law, or in equity, to seek specific performance
of Idaho Power's obligations and covenants hereunder, and the Non-Defaulting
Funders agree not to take a position in any proceeding arising out of this
Agreement to the effect that the Non-Defaulting Funders have an adequate
remedy at law.
ARTICLE IX
FORCE MAJEURE
Force Majeure Defined. For purposes of this Agreement, "Eorse_\4gj-eure" means an
event or circumstance beyond the reasonable control of, and without the fault or
negligence of, a Funder or Permitting Project Manager claiming Force Majeure
("Affected Party"), which, despite the exercise of reasonable diligence, cannot be or be
caused to be prevented, avoided or removed by such Affected Party including, to the
extent satisfuing the above requirements, acts of God; earthquake; abnormal weather
condition; hurricane; flood; lightning; high winds; drought;peril of the sea; explosion;
fire; war (declared or undeclared); military action; sabotage; riot; insurrection; civil
unrest or disturbance; acts of terrorism; economic sanction or embargo; civil strike, work
stoppage, slow-down, or lock-out that are of an industry or sector-wide nature and that
are not directed solely or specifically at the Affected Party; the binding order of any
Governmental Authority, provided that the Affected Party has in good faith reasonably
9.1
27
contested such order; the failure to act on the part of any Governmental Authority,
provided that such action has been timely requested and diligently pursued; unavailability
of equipment, suppiies or products, but only to the extent caused by Force Majeure;
failure of equipment, provided that the equipment has been operated and maintained in
accordance with Good Utility Practice; and transportation delays or accidents, but only to
the extent otherwise caused by Force Majeure; provided, however, that neither
insufficiency of funds, financial inability to perform nor changes in market conditions
shall constitute Force Majeure.
9.2 Effect of Force Maieure.
(a)If an Affected Party is rendered wholly or partly unable to perform its obligations
under this Agreonent or its performance is delayed because of Force Majeure,
such Affected Party shall be excused from, and shall not be liable for, whatever
performance it is unable to perform or delayed in performing due to the Force
Majeure to the extent so affected, provided that:
(i)The Affected Party, as soon as reasonably practical after the
commencement of the Force Majeure, gives the other Funders (s) and/or
the Project Manager prompt written notice thereof including a description
of the particulars of the Force Majeure;
(ii) The suspension of performance is of no greater scope and of no longer
duration than is required by the Force Majeure; and
(iii) The Affected Party uses Commercially Reasonable Efforts to overcome
and remedy its inability to perform as soon as reasonably practical after
the commencement of the Force Majeure.
(b) Notwithstanding anything in this Article fX to the contrary, no payment
obligation arising under this Agreernent prior to the date of an event of Force
Majeure shall be excused by such event of Force Majeure.
(c) Whenever an Affected Party is required to commence or complete any action
within a specified period and is prevented or delayed by Force Majeure from
commencing or completing such action within the specified period, such period
shall be extended by an amount equal to the duration of such event of Force
Majeure occurring or continuing during such period.
28
ARTICLE X
REPRESENTATIONS AND WARRANTIES
10.1 Representations and.Warranties of Idaho Power. Idaho Power represents and warrants to
PAC and BPA as of the Effective Date as follows:
(a) It is duly formed, validly existing and in good standing under the laws of the
jurisdiction of its formation.
(b) It has all requisite corporate powor necessary to own its assets and carry on its
business as now being conducted or as proposed to be conducted under this
Agreement.
(c) It has all necessary corporate power and authority to execute and deliver this
Agreement and to perform its obligations under this Agreement, and the execution
and delivery of this Agreement and the performance by it of this Agreement have
been duly authorized by all necessary corporate action on its part.
(d) The execution and delivery ofthis Agreement and the performance by it of this
Agreement do not: (i) violate its organizational documents; (ii) violate any
Governmental Requirements applicable to it; or (iii) result in a breach of or
constitute a default of any material agreement to which it is a party.
(e) This Agreement has been duly and validly executed and delivered by it and
constitutes its legal, valid and binding obligation enforceable against it in
accordance with its terms, except as the same may be limited by bankruptcy,
insolvency or other similar laws affecting creditors' rights generally and by
principles of equity regardless of whether such principles are considered in a
proceeding atlaw or in equity.
(0 All material Govemmental Authorizations required by Governmental
Requirements to have been obtained by it prior to the date hereof in connection
with the due execution and delivery of, and performance by it of its obligations
under, this Agreement, have been duly obtained or made and are in full force and
effect.
10.2 Rspresentations and Warranties of PAC. PAC represents and warrants to BPA and Idaho
Power as of the Effective Date as follows:
(a) It is duly formed, validly existing and in good standing under the laws of the
jurisdiction of its formation.
29
(b) It has all requisite corporate power necessary to own its assets and carry on its
business as now being conducted or as proposed to be conducted under this
Agreement.
(c) It has all necessary corporate power and authority to execute and deliver this
Agreement and to perform its obligations under this Agreernent, and the execution
and delivery of this Agreement and the performance by it of this Agreement have
been duly authorized by all necessary corporate action on its part.
(d) The execution and delivery of this Agreement and the performance by it of this
Agreement do not: (i) violate its organizational documents; (ii) violate any
Governmental Requirements applicable to it; or (iii) result in a breach of or
constifute a default of any material agreement to which it is a party.
(e) This Agreement has been duly and validly executed and delivered by it and
constitutes its legal, valid and binding obligation enforceable against it in
accordance with its terms, except as the same may be limited by bankruptcy,
insolvency or other similar laws affecting creditors' rights generally and by
principles of equity regardless of whether such principles are considered in a
proceeding at law or in equity.
(D All material Governmental Authorizations required by Governmental
Requirements to have been obtained by it prior to the date hereof in connection
with the due execution and delivery of, and performance by it of its obligations
under, this Agreement, have been duly obtained or made and are in full force and
effect.
10.3 Representations and Warranties of BPA. BPA represents and warrants to PAC and ldaho
Power as of the Effective Date as follows:
(a) It is duly formed, validly existing and in good standing under the laws of the
jurisdiction of its formation.
(b) It has all requisite stafutory and administrative power necessary to own its assets
and carry on its business as now being conducted or as proposed to be conducted
under this Agreernent.
(c) It has all necessary statutory and administrative power and authority to execute
and deliver this Agreement and to perform its obligations under this Agreement,
and the execution and delivery of this Agreement and the performance by it of
this Agreement have been duly authorized by all necessary statutory or
administrative action on its part.
30
(d) The execution and delivery of this Agreement and the performance by it of this
Agreement do not: (i) violate its organizational documents; (ii) violate any
Governmental Requirements applicable to it; or (iii) result in a breach of or
constitute a default of any material agreement to which it is a party.
(e) This Agreement has been duly and validly executed and delivered by it and
constitutes its legal, valid and binding obligation enforceable against it in
accordance with its terms, except as the same may be limited by bankruptcy,
insolvency or other similar laws affecting creditors' rights generally and by
principles of equity regardless of whether such principles are considered in a
proceeding at law or in equity.
(f)All material Governmental Authorizations required by Governmental
Requirements to have been obtained by it prior to the date hereof in connection
with the due execution and delivery of and performance by it of its obligations
under, this Agreement, have been duly obtained or made and are in full force and
effect.
ARTICLE XI
COMMON DEFENSE & LIMITATION OF LIABILITY
I1.1 Common Defense. The Funders shall, at such time as specified in this Section 11, enter
into a Joint Defense Agreement that is consistent with applicable Governmental
Requiranents and that provides for the common defense, as well as pa)rment for the
common defense, including actual damages, for any and all suits, actions, liabilities,
legal proceedings, claims, demands, losses, costs and expenses of whatsoever kind or
character ( including reasonable attomeys' fees and expenses of third parties) of thjrd
parties, for injury or death of persons or physical loss of or damage to property of persons
(other than of the Funders or the Permitting Project Manager) arising from the
performance by the Permitting Project Manager of its obligations under this Agreement
Claims provided, however, that the Funders shall not be obligated to enter into a
Joint Defense Agreement or otherwise be responsible for any Claims arising from the
Permitting Project Manager's own negligence or willful misconduct in connection with
the performance of its obligations under this Agreement. The Joint Defense Agreement
shall set forth the terms under which the Funders shall provide a common defense for the
Claims described in this Section 1 1 .1, including, but not limited to, the retention of
appropriate legal counsel, advisors, and experts and the resolution of any such Claims.
Each Funder shall contribute under the Joint Defense Agreement, in proportion to its
Permitting Interest set forth in Exhibit D, or as otherwise mutually agreed to by the
Funders in writing, to such common defense.
31
lI.2 Notice and Participation. The Permitting Project Manager shall give the other Funders
prompt written notice of any Claim upon the receipt of actual knowledge or information
by the Permitting Project Manager of a Claim (the "Joint Defense Aereement Notice").
Upon the issuance of the Joint Defense Agreement Notice, the Funders and Permitting
Project Manager shall use all Commercially Reasonable Efforts to agree to the terms of
and enter into a Joint Defense Agreement consistent with the provisions of this Section
1 1 as soon as practicable. Except as otherwise provided in Section 1 1.1, during such
period as the Funders shall not be a party to a Joint Defense Agreernent but a Joint
Defense Agreement Notice or Joint Defense Agreement Notices shall have been
delivered, each of the Funders shall contribute funds and otherwise support the common
defense of the Claims that are the subject of such Joint Defense Agreement Notice, in
proportion to its Permitting Interest set forth in Exhibit D or as otherwise mutually agreed
to by the Funders in writing, and during such period all costs incurred by or on behalf of
the Permitting Project Manager for the defense or resolution of any such Claims
(including, but not limited to, actual damages to be paid to resolve such Claims and
reasonable attorneys' fees and costs) shall be considered Project Costs and payable to the
Permitting Project Manager in proportion to the Funders' Permitting lnterest set forth in
Exhibit D and pursuant to the terms of this Agreement.
I 1.3 Control of Defense Prior to Joint Defense Agreement. After delivery of a Joint Defense
Agreement Notice but before the Funders have entered into a Joint Defense Agreement,
the Permitting Project Manager shall have the right to assume the defense of the Claim,
with counsel designated by the Permitting Project Manager and reasonably satisfactory to
the Funders, and contest or, with or without the prior consent of the Funders, settle such
Claim, provided that the Permitting Project Manager shall not settle any Claim with
respect to which it has sought or is entitled to seek recovery pursuant to Section I l 1
unless it has obtained the prior written consent of the Funders.
ll.4 Failure to Provide Timely Joint Defense Agreement Notice. The Funders shall have no
obligation to enter into a Joint Defense Agreement for any Ciaim for which a Joint
Defense Agreement Notice is not timely provided, but only to the extent that such failure
to give such notice materially and prejudicially impairs the ability of the Funders to
jointly defend the applicable Claim. To the extent that failure to provide a timely Joint
Defense Agreement Notice materially and prejudicially impairs a Funder's ability to
jointly defend the applicable Claim, the Permitting Project Manager shall not be entitled
to recover any costs incurred by or on behalf of the Permitting Project Manager in respect
of such Claim as such Claim shall not be considered a Project Cost.
11.5 Survival of Obligation. The duty to provide for the common defense and enter into a
Joint Defense Agreement shal1 continue in full force and effect for a period of one year
after the expiration or termination of this Agreement, unless a Funder withdraws pursuant
to Article VII in which case the duties and obligations under Sections I 1.1 and 1 1.2 shall
32
not apply to the Withdrawing Funder for any Claim where it receives the Joint Defense
Agreement Notice after the Notice of Withdrawal.
11.6 Limitationorr Liabllity.
(a) [n the case of breach or default by a Funder or Permitting Project Manager
hereunder for which an express remedy or measure of damages is provided, such
express remedy or measure of damages shall be the sole and exclusive remedy,
and the Funder's or Permitting Project Manager's liability shall be limited as set
forth in such provision and all other remedies or damages at law or in equity are
hereby irrevocably waived, unless the provision in question provides that the
express remedies are in addition to other remedies that may be available. Unless
otherwise provided in this Agreement, if no remedy or measure of damages is
expressly provided herein (and a remedy or damages is otherwise permitted), then
the Funder's or Permitting Project Manager's liability shall be limited to direct
actual damages only, and such direct actual damages shall be the sole and
exclusive remedy and all other remedies or damages at 1aw or in equity are hereby
irrevocably waived.
(b) Notwithstanding any provision in this Agreement to the contrary, no Funder,
whether in its capacity as Funder or Permitting Project Manager, shall be liable
under this Agreement in any action at law or in equity, whether based on contract,
tort or strict liability or otherwise, for any special, incidental, indirect, exemplary,
punitive or consequential damages or losses, including any loss of revenue,
income, profits or investment opportunities, loss of the use of equipment, or the
cost of temporary equipment or services, prcvtdgd that any Claims shall not be
excluded under this Section 1 1.6(b) as special, incidental, indirect, exemplary,
punitive or consequential damages or losses.
ARTICLE XII
PROPRIETARY INFORMATION
1,2.1 Dlsclosure o1' Proprjqtary-lqfor[[atiorr Proh i bitcd. The Funders agree that all information
exchanged in connection with this Agreement (but not this Agreement) shall be treated as
"Confidential Information" subject to the terms and conditions of the Nondisclosure
Agreement, dated March 15,2010, between the Funders (the "Confidentiality
Ageement"), the provisions of which are incorporated herein by reference.
12.2 Publicity. Each Funder shall provide reasonable advance notice to, and shall consult with,
the other Funders of any planned press release, public statement or meeting with the
public or Governmental Authorities by such Funder in which discussion of the Permitting
Project is expected to be a material part, provided that nothing herein shall prevent, limit,
or delay any Funder from making my disclosure required by Governmental
JJ
Requirements or Govemmental Authorizations. Each Funder shall provide notice to the
other Funders as promptly as possible of the nature and content of any significant
unplanned communications about the Permitting Project with the public or with
Governmental Authorities. Notwithstanding the foregoing, when the information
provided at a meeting is part of a previously agreed to public affairs plan or otherwise
previously approved for disclosure by the Funders, notice of each such meeting or
communication is not required.
ARTICLE XIII
DISPUTE RESOLUTION
13.1 Exclusive Procedure. Any dispute, controversy or claim arising out of or relating to this
Agreement or the breach, interpretation, termination, performance or validity of this
Agreement (each, a "Dispute") shall be resolved pursuant to the procedures of this Article
XIII.
13.2 Dispute Notices. If a Dispute arises between the Funders or between the Permitting
Project Manager and the Non-Permitting Project Manager Funders, then any Funder or
Permitting Project Manager to such Dispute (each, a "Digpuliug_B3rty") may provide
written notice thereof to the other Disputing Parties, including a detailed description of
the subject matter of the Dispute (the "Dispute Notice"). Any Disputing Party may seek a
preliminary injunction or other provisional judicial ronedy to the extent allowed by law
if such action is necessary to prevent irreparable harm or preserve the stafus quo, in
which case the Disputing Party nonetheless will continue to pursue resolution of the
Dispute pursuant to this Article XIIL
13.3 Informal Dispute Resolution.
(a) The Disputing Parties shall make a good faith effort to resolve the Dispute by
prompt negotiations between and/or among each Disputing Party's representative
so designated in writing to the other Disputing Party or Disputing Parties (each a
6'MA4Ager"). If the Managers are not able to resolve the Dispute within thirty (30)
days after the date of the Dispute Notice, they shall refer the matter to the
designated senior officers of the Disputing Parties (the "EXgg{ives"), who shall
have authority to settle the Dispute. If the Executives are not able to resolve the
Dispute within sixty (60) days after the date of the Dispute Notice, then the
Dispute shall be resolved pursuant to Section 13.4.
(b) All communications and writings exchanged between andlor among the Disputing
Parties in connection with these negotiations shall be confidential and shall not be
used or referred to in any subsequent binding adjudicatory process between the
34
Disputing Parties, either with respect to the current Dispute or any future Dispute
between the Funders and/or the Permitting Project Manager.
13.4 Remedies. If any Dispute arising under this Agreement cannot be resolved as provided in
Section 13.3. then any Disputing Party may, in its sole discretion, pursue any available
remedy at law or equity.
13.5 Continued Performance. During the pendency of any Dispute, each Funder and the
Permitting Project Manager shall continue to perform all of its respective obligations
under this Agreement.
ARTICLE XIV
MISCELLANEOUS
l4.l Counterparts. This Agreement may be executed in counterparts, each of which shall be
considered an original, but all of which together shall constitute the same instrument.
Electronic transmission of any signed original document, and retransmission of any
signed electronic transmission, shall be the same as delivery of an original. At the request
of any Funder or the Permitting Project Manager, the other Funders or Permitting Project
Manager, as applicable, will confirm electronically transmitted signatures by signing an
original document.
T4.2 Headings. The Article and Section headings used in this Agreement (including headings
used in any Exhibits attached hereto) are for convenience ofreference only and shall not
affect the construction of the Agreement or limit the scope of the particular provisions to
which they refer.
14.3 Waiver. No waiver by any Funder of any breach or default by any other Funder or the
Permitting Project Manager of its obligations herein shall be construed as a waiver of any
other breach or default whether of a like kind or different nature. Any delay by a Funder,
less than any applicable statutory period of limitations, in asserting or enforcing any
rights or remedies under this Agreement shall not be deemed a waiver of such rights or
remedies. Failure of any Funder or Permitting Project Manager to enforce any provision
hereof shall not be construed to waive such provision, or to affect the validity of this
Agreernent or any part hereof, or the right of any Funder thereafter to enforce each and
every provision hereof.
14.4 Relationship of Funders.
(a) Several and not Joint. The covenants, obligations, and liabilities of the Funders
are intended to be several and not joint or collective, and nothing herein contained
shall be construed to create an association, joint venture, trust or partnership, or to
impose a trust or partnership covenant, obligation or liability on or with regard to
35
any of the Funders. Each Funder shall be individually responsible for its own
covenants, obligations and liabilities as herein provided. No Funders shall be
under the control of, or shall be deemed to control, the other Funders. No Funder
shall have aight or power to bind any other Funder without such other Funder's
express written consent.
(b) No Partnership. None of the provisions of this Agreement shall be deemed to
constitute a partnership among or between the Funders and none of the Funders
shall have any authority to bind the other Funders in any way, and the Funders
agree that the arrangement contemplated by this Agreement shall be excluded
from subchapter K of the U.S. Internal Revenue Code of 1986, as amended
("Subchapter K"). Idaho Power and PAC agree to report their respective
Permitting Interest of any items of income, deductions and credits of the
arrangement contemplated by this Agreement in a manner consistent with the
exclusion of such alrangement from Subchapter K beginning with the taxable
year which includes the Effective Date.
(c) Additional Funders. This Agreement may be amended to include one or more
additional parties as Funders upon mutual written agreement of the then current
Funders.
14.5 Severabilitv. In the event that any provision of this Agreement or the application thereof
becomes or is declared by a court of competent jurisdiction to be illegal, void or
unenforceable, the remainder of this Agreement will continue in full force and effect and
the application of such provision to other persons or circumstances will be interpreted so
as reasonably to effect the intent of Idaho Power, PAC, and BPA. The Funders and
Permitting Project Manager further agree to replace such illegal, void or unenforceable
provision of this Agreement with a valid and enforceable provision that will achieve, to
the maximum extent possible, the economic, business and other purposes of such illegal,
void or unenforceable provision.
t4.6 Bindine Effect. Upon execution by all Funders, this Agreement shall be binding upon
each of the Funders and the Permitting Project Manager and their respective successors
and permitted assigns. This Agreement is null and void unless it is executed by all
Funders.
14.7 Amendments. This Agreement shall not be modified, amended, supplemented or
otherwise changed in any respect except by a written document signed by the Funders
and the Permitting Project Manager.
14.8 No Third Party Beneficiary. This Agreement is for the exclusive benefit of the Funders
and the Permitting Project Manager, and is not intended to nor shall be construed to
36
confer upon or give to any Person (other than the Funders and the Permitting Project
Manager) any rights or remedies under or by reason of this Agreonent or any transaction
contemplated herein.
14.9 Entire Agreernent. This Agreement, including the Exhibits and Schedde2.2 attached
hereto, constitutes the entire agteement of the Funders and the Permitting Project
Manager with respect to the transactions contemplated by this Agreement and supersedes
all prior agreements (other than the Confidentiality Agreement), oral or written, with
respect thereto.
14.10 Notices.
(a) Except as otherwise provided herein, any notice, demand, request or other
communication required or permitted to be glven pursuant to this Agreement shall
be in writing and signed by the Funder or Permitting Project Manager giving such
notice, demand, request or other communication and shall be hand delivered or
sent by certified mail, return receipt requested, or overnight courier to the other
Funders and/or Permitting Project Manager at the address set forth below:
If to Idaho Power
(as Funder or Permitting Project Manager)Idaho Power Company
1221 West Idaho Street
Boise, ID 83702
Attn: Manager, Delivery Projects
Telephone : [phone]
With a copy to:Idaho Power Company
l22l West Idaho Street
Boise, lD 83702
Attn: Legal Department
Telephone: [phone]
If to PAC
(as Funder)PacifiCorp
825 NE Multnomah Street, Ste. 1600
Portland, OR97232
Attn: Vice President, Transmission
Telephone : [phone]
37
With a copy to:PacifiCorp
825 NE Multnomah Street, Ste. 1800
Portland, OP.97232
Attn: Legal Department
Telephone: 503-8 I 3-5854
If to BPA
(as Funder)Bonneville Power Admini stration
5411 NE Highway 99
Vancouver, WA 98663
Attn: Senior Vice President,
Transmission Services
Telephone: [phone]
Bonneville Power Administration
905 NE 11th Avenue
Portland, OF.97232
Attn: Office of General Counsel
Telephone: [phone]
With a copy to:
(b) Each Funder and the Permitting Project Manager shall have the right to change
the place to which any notice, demand, request or other communication shall be
sent or delivered by similar notice sent in like manner to the other Funder(s) and
Permitting Project Manager. The effective date of any notice, demand, request or
other communication issued pursuant to this Agreement shall be when: (i)
delivered to the address of the Funders or Permitting Project Manager personally,
by messenger, by a nationally or internationally recognized overnight delivery
service or otherwise; or (ii) received or rejected by the Funders or Permitting
Project Manager, if sent by certified mail, return receipt requested, in each case,
addressed to the Funders or Permitting Project Manager at its address and marked
to the attention of the person designated above (or to such other address or person
as a Funders or Permitting Project Manager may designateby notice to the
Funders and/or Permitting Project Manager effective as of the date of receipt by
such Funders).
14.11 Choice of Law. This Agreement shall be governed by and construed in accordance with
the laws of the State of ldaho, without giving effect to conflicts of laws principles.
Notwithstanding the foregoing, for so long as BPA is a Funder, this Agreement shall be
governed and construed in accordance with the laws of the United States.
38
14.12 Further Assurances. Each Funder and the Permitting Project Manager agrees to execute
and deliver from time to time such additional documents, aad to take such additional
actions, as maybe reasonablyrequired by the other Funders or the Permitting Project
Manager to give effect to the pulposes and intent hereof.
14.13 Conflict of Interest. Nothing in this Agreement shall prohibit aay Funder or the
Permitting Project Manager from engaging in or possessing any interest in other plojects
or business ventures of any nature and description, independently or with others.
ISTGNATURE PAGE TO FOLLOWI
39
IN WITNESS WHEREOF, the Funders hereto have caused this Boardman to
Hemingway Transmission Project Joint Permit Funding Agreement to be sxecuted by their
respective authorized representatives on the day and year first above written.
IDAHO POWER COMPANY,
as Funder and Pcrmitting Project Manager
By
Date
PACIFICORP,
as Funder
By
Date
BONNEVILLE POWER ADMIN ISTRATION,
as Funder
By
Date
40
I
IN \\rl'l'NISS WIIIttl.1()['. thc llundcrs lrcrcto havc causcct this l]oardrnar) t()
llcrttinsu'ilr 'l'rausnrission l)ro.lect Joinl I)crnrit I:untlinq Agrccnrcnt t() b(: cxucutccl hy thcil'
respcclir,c;lr.rtlx)ri7-s(l replc\cnlu,tivcs on llte dl! antl ycur ijrst ahnvc writtcn.
ll)Al l( ) P( )\\'l:l{ COI'l l'AN \'.
irr I;untlcr ;urd ['crrrritting ['rrriccl Nlanlrgr:r'
It l'
I )alc
PACIFIC:ORI'.
ir.t I;ultdtrr
Itt
I );tlc
lj()N N I,. V I t-l.t: POWfft ADNl I N ls'l'ltATIO\.
lus [;r.tnricr
llr
Datc
"l(r
lN WI'INESS WI IIIREOF, the Funders hereto havc caused this Boardrnan to
Hemingway Transrnission Project Joint Pemrit Funding Agreenrent to be executed by their
respective authorized representativcs oll the day and year first above written.
IDAIIO POWI]R COMPANY.
as f;under and Permitting Project Manager
13v
Date
PACITICOITP,
as Fundcr
By
Date --7---7-
BONNEVIT,LE POWER ADMINISIITATION.
as Funder
By
Date
40
Exhibit A
D escription of Boardman to Hemingway Transmission Proj ect
The development, siting, and acquisition ofpermits and Rights-of-Way overpublic land,
construction, operation, and maintenance of a single circuit 500kV overhead electric
transmission line and facilities beginning near Boardman, Oregon, and terminating near Melba,
Idatro
4t
Exhibit B
Permit Fundins Schedule
The cost allocation of the Payment Schedule is determined by each Funder's Permitting Interest
as of the Effective Date, which shall be calculated using the methodology described in Exhibit D.
Table B.l. Permit Funding Payment Schedule
Payment Type
ldaho
Power
Amount BPA Amount PAC Amount Date
I
Mandatory
Payment $1,608,839 $ 1,838,673 $4,137,015
Due Twenty (20)
days following the
Effective Date
2
Mandatory
Payment $1,608,839 $ 1,838,673 $4,1 37,015 101112012
3
Mandatory
Payment*$2,255,155 $2,577,320 $5,798,969 31112013
4
Mandatory
Payment $804,420 $ 919,337 $2,068,508 101112013
5
Completion
Funding
Payment*$3,945,498 $ 4,509,141 $10,145,567
Due One hundred
twenty (120) days
following
publication of
FinalBLM Record
of Decision in the
FederalRegr'sfer
6
Final Expense
True-up TBD TBD TBD
Two hundred ten
(21 0) days
following Notice
of Payment
* The payment amounts shown for Mandatory Payments 3 and Completion Funding Payment 5
include estimated AFUDC accruals. The actual invoice may differ from the amount shown
based on the actual monthly AFUDC accrued during the period.
Exhibit C
Project Costs
Project Costs are included as part of the payments set forth in Exhibit B. Project Costs
associated with Govemmental Authorizations and other necessary work include as relating to the
Permitting Project, but are not limited to:
i.
ii.
iii.
iv.
Governmental Authori zation costs ;
NEPA compliance activity;
public involvement activity;
reasonable attorney's fees;
third party contractor work for EIS development and support of the Boardman to
Hemingway Transmission Project, including, but not limited to, the NEPA
process;
vl.Preliminary design and engineering work in support of the Boardman to
Herningway Transmission Project, including, but not limited to, the NEPA
process;
vii Any other costs approved by the Permit Funding Committee associated with
services to be coordinated by the Permitting Project Manager (and not provided
for above), as set forth in this Agreernent; and
viii. Overheads incurred by the Perrnitting Project Manager for the Permitting Project
will be calculated at a 10Yo rate.
Exhibit D
Permittine Interest Work Paper
Each Funder is assigned a Permitting Interest based on the annual weighted capacity
expressed in the Permitting Project. The Permitting Interest is determined by the sum of a
Funder's eastbound capacity interest and westbound capacity interest, divided by the total of all
Funders' eastbound and westbound capacity interests.
Table 1: Boardman to Hemingwav Weiehted Interest
Total
Requested
Capacity
(Mw)
ldaho Power
Capacity
lnterest
(Mw)
BPA
Capacity
lnterest
(Mw)
PacifiCorp
Gapacity
lnterest
(Mlr1,)
West to East 1050 350 400 300
East to West 600 0 0 600
Permitting
lnterest
21.21o/o 24.24o/o 54.55o/o
* Seasonally shaped capacity
The capacity interests are based on:
o ldaho Power's capacity interest is seasonally shaped with 500 MW of eastbound capacity
during the months of April through September and 200 MW of eastbound capacity during
the months of January through March and October through December.
o BPA's capacity interest is seasonally shaped with 250 MW of eastbound capacity during
the months of April through September and 550 MW of eastbound capacity during the
months of January through March and October through December.
o PacifiCorp's capacity interest is constant throughout the entire calendar year.
o The sum of all Permitting lnterest will equal one hundred percent.
o The sum of capacity interest may or may not equal the total rated capacity of project.
Additional Considerations :
If the capacity interests are less than the total rated capacity of the Boardman to
Hemingway Transmission Project, the unallocated capacity will be divided among the
Funders based on the Funders Permitting Interest.
The total rated capacity of the Boardman to Hemingway Transmission Project is subject
to the results of the WECC Rating Process.
a
a
Asstrmed B2H Ratings and Unassigned Capacity
Allocatlon of Unassigned Capacity
Assumed
Rating (MW)
Unallocated
Capacity {MW}
West to Eaet 1050 0
East to West 1 000 400
Percentage
w-E
of
Capacity
Allocation of
E-W Unasslgned Capaclty
{Mw}
tPco 21.21o/o o B5
BPA 24.24Yo 0 91
PAC 54.55r/o 0 218
a
a
Schcdule 2.2
Project Permitting Objectives and Timetable
National Environmental Policy Act (NEPA) - BLM Lead Agency
a BLM Publishes Draft Environmental Impact Statement - Ql of 2013
o BLM Publishes Final Environmental Impact Statement - Q2 of 2014
o BLM issues Record of Decision - Q4 of 2014
o BLM issues Notice to Proceed - Q4 of 2014
Oregon Energy Facility Siting Council (EFSC)
o File preliminary Application for Site Certificate (ASC) - Q4 of 2012
o Filc Complete ASC - Q2 of 2013
o EFSC issues Proposed Order & Notice of Contested Case - Q3 of 2013
o EFSC issues Final Order Issuing Site Certificate & Site Certificate Review - Q2
af2014
o EFSC issues Final Site Certificate - Ql of 2015
o EFSC issues Notice to Proceed - Q2 of 2015
ldaho Power Company Appendix D-B2H Supplement
Appendix D-4. B2H MOU
See the attached document.
2017 rRP Page 117
Appendix D-B2H Supplement ldaho Power Company
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Page 118 2017 tRP
A.
B.
C.
D.
Execution Copy
BPA Contract Number 12TX-15584
MEMORANpUM OF UN"pER$TANprNq
This Mernorandum of Understanding (this "MOU") is entered into as of January l2th,
2012 (the "Effeglivg_D_ate"), by and among PacifiCorp, an Oregon corporation ("P4gifieglp"),
Idaho Power Company, an Idaho corporation ("Idaho Power"), and the Bonneville Power
Administration, a United States govemment power marketing agency ("BPA"). PacifiCorp,
Idaho Power and BPA are sometimes referred to in this MOU individually as a "Party" and,
collectively, as the "Parties".
RECITALS
PacifiCorp owns and operates facilities for the transmission of electric power and energy
in interstate commerce ("PacifiCorp Transmis ");
BPA owns and operates facilities for the transmission of electric power and energy in
interstate commerce ("BPA Transmission System");
Idaho Power owns and operates facilities for the transmission of electric power and
energy in interstate commerce ("Idaho Power Transmission System");
The PacifiCorp Transmission System, BPA Transmission System and the Idaho Power
Transmission System, are sometimes referred to in this MOU individually as a
"Transmission System" and, collectively, the "Transmission Systems;"
PacifiCorp, BPA and Idaho Power each have an independent obligation or authority to
plan for and expand their respective Transmission Systems based upon the needs of their
native load customers, network customers, and eligible customers that agree to expand
the Transmission System;
The Parties are considering whether to permit and construct new transmission projects in
the West, including, but not limited to, jointly owning the proposed Boardman to
Hemingway Transmission Project, which is a 500kV single circuit transmission line that
is proposed to run from Boardman, Oregon to Melba, Idaho that if constructed could
assist Idaho Power, PacifiCorp, and BPA in fulfilling their respective service obligations;
G,The Parties desire to (i) explore alternatives to establish eastern Idaho load service from
Hemingway in exchange for similar service from the BPA Transmission System-and (ii)
consider whether to replace certain transmission arrangements involving existing assets
with joint ownership transmission arangements and other alternative transmission
affangements pursuant to definitive agreements mutually satisfactory to the Parties
(collectively, the "Definitive Asreements");
Idaho Power and PAC acknowledge that BPA is considering various transmission and other
altematives to meet its service obligations in eastern Idaho, including altematives that would
involve Open Access Transmission Service, and that BPA's decision whether to participate
E.
F
I
H.
I
Execution Copy
BPA Contract Number 12TX-15584
in development and construction of the Boardman to Hemingway Transmission Project may
be based on BPA's evaluation of such alternatives; and
The Parties are entering into this MOU to set forth a process by which the Parties wili
negotiate in good faith to attempt to reach mutually satisfactory agreement on the terms
and conditions of the Definitive Agreements.
NOW THEREFORE, the Parties agree as follows:
L Effective Date: Tenn.
(a) This MOU shall become effective on January nn2Ol2 (the "Effective
Date").
(b) This MOU shall remain in effect until Decernber 31, 2014, at which time
it will terminate (the "TermtnatiqU_DAlg"), unless one of the following occurs:
(i) All Parties execute and deliver each of the Definitive Agreements
before the Termination Date, in which case the Termination Date shall be the date
that the last Definitive Agreement is fully executed;
(ii) The Parties, by mutual written agreement, agree to extend the
Termination Date, in which case the Termination Date shall be a mutually agreed
date after December 31,2014;
(iii) The Parties, by mutual written agreement, agree that the MOU will
be terminated before December 31,2014, in which case the Termination Date
shall be a mutually agreed date before December 31,2074; or
(iv) Two Parties exercise their unilateral right to withdraw from this
MOU pursuant to Section 2, in which case the Termination Date shall be thirty
(30) days after the second withdrawing Party provides written notice of
withdrawal.
(c) Upon termination, this MOU shall have no further force or effect,
provided that the rights and obligations set forlh in Sections 3(fl and 4 shall survive the
termination of this MOU and remain in full force and effect.
2. Unilateral Withdrawal Rig&ts.
AtyParty may withdraw from this MOU at any time, for any reason whatsoever or for
no reason, after thirty (30) days written notice to the other Parties of the intent to do so.
2
Execution Copy
BPA Contract Number 12TX-15584
(a) During the term of this MOU, the Parties meet regularly (either by
teleconference or in person), proceed diligently and in good faith to negotiate mutually
satisfactory terms of the Definitive Agreements and al1 such other agreements and documents
necessary to fully document the transactions contemplated by the Definitive Agreements by no
later than December 31,2014. The Parties seek to meet the following milestones:
By no later than January 15,2A12, the Parties commence regular
meetings to discuss the subject matters described in Exhibit A
hereto;
(ii) By no later than March 31,2012, the Parlies identifu scenarios and
any potential assets, the methodology for valuing capacity and
assets, and any required criteria or conditions for execution of
Definitive Agreements to achieve the alternatives described in
Exhibit A.
(ii, By no later than September 30,2012, BPA informs Idaho Power
and PacifiCorp whether it intends to pursue a plan of service for its
eastern Idaho load service requirements that would require the
availability of project(s) contemplated herein.
(b) EachPxty shall select a senior-level representative (each, a
"Representative") to be responsible for coordinating activities under this MOU. Each Party
commits to provide its Representative with the support and resources necessary to further the
purposes of this MOU.
(c) Any Party would be free to use the rights granted it by another Party under
a Definitive Agreement for any legitimate transmission service permitted by its respective
OATT, provided, however, that rights granted under a Definitive Agreement would not include
any additional rights to receive transmission service that would require use of any portion of the
other's system not specifically acknowledged in a Definitive Agreement.
(d) Based on the information currently known to the Parties, it is proposed
that negotiations of the Definitive Agreements include the alternatives set forth in Exhibil A.
Exhibit A sets forth the Parties' current general understanding with respect to these altematives,
but is not intended to represent a binding agreement or final contractual language, or to address
every provision which the Parties may wish to incorporate into the Definitive Agreanents.
(e) Each of the Parties acknowledges and agrees that each other Party's
decision to proceed with the Definitive Agreements and any other decision with respect to the
Definitive Agreements is within such Party's sole and absolute discretion.
(1)
5
3. Responsibilities of the Parties.
Execution Copy
BPA Contract Number l2TX-15584
(0 The Parties agree that all information exchanged in connection with this
MOU (but not this MOU) shall constitute, and be treated by the Parties as, "Confidential
Information" subject to the terms and conditions of that certain Nondisclosure Agreement, dated
as of March 15, 2010, between the Parties (the "Confidentiality A8reernent"), the provisions of
which are incorporated herein by reference.
4. General Provisions.
(a) This MOU is not a binding or enforceable contract but is instead an
understanding that broadly states the expected responsibilities and objectives of the Parties.
(b) Nothing in this MOU shall limit, repeal, or in any manner modify the
existing legal rights, privileges, and duties of each of the Parties as provided by agreement
(including the Confidentiality Agreement), statute or any other law or applicable court or
regulatory decision. Further, the concepts contemplated by this MOU and any Definitive
Agreements, if any, are intended to be consistent with applicable statutes, rules, orders,
regulations or other similar requirements or obligations.
(c) Each of the Parties acknowledges and agrees that no Party shall be liable
to the other Parties for any claim, loss, cost, liability, damage or expense, including any direct
damage or any special, indirect, exemplary, punitive, incidental or consequential loss or damage
(including any loss of revenue, income, profits or investment opportunities or claims of third
party customers), arising out of or directly or indirectly related to a Party's decision to terminate
this MOU, the other Parties' performance or failure thereof under this MOU, or any other
decision with respect to proceeding or not proceeding with the Definitive Agreements.
(d) This MOU may not be amended except in writing signed by the Parties.
(e) Any waiver on the part of a Parfy to this MOU of any provision or
condition of this MOU must be in writing signed by each Party to be bound by such waiver, shall
be effective only to the extent specifically set forth in such writing and shall not limit or affect
any rights with respect to any other or future circumstance.
(0 This MOU is for the sole and exclusive benefit of the Parties and shall not
create a contractual relationship with, or cause of action in favor of, any third party.
(g) Nothing in this MOU will be deemed to establish any right or provide a
basis for any action, either legal or equitable, by anyperson or class ofpersons against the
United States, its departments, agencies, instrumentalities or entities, or its officers or employees,
challenging a goveillment action or failure to act.
(h) Nothing in this MOU will be construed as limiting or affecting in any way
the authority or responsibility of the Parties to perform within their authorities, and nothing in
this MOU shall be construed as committing the Parties to take any action concerning the items
identified in Exhibit A before they have complied with all applicable statutes and regulations
such as the National Environmental Policy Act ("NEPA").
4
Execution Copy
BPA Contract Number 12TX-15584
(i) Each Party shall be solely responsible for and shall pay its own costs and
expenses incurred by it in connection with the negotiation of this MOU, the Definitive
Agreements and all other agreements, documents and instruments related hereto and thereto,
including all legal fees and expenses and expenses associated with such Party's own due
diligence activities.
0) Whenever this MOU requires or provides that (i) a notice be given by a
Party to another Party or (ii) a Party's action requires the approval or consent of the other Parties,
such notice, consent or approval shall be given in writing and shall be given by personal
delivery, by recognized overnight courier service, or by certified mail (return receipt requested),
postage prepaid, to the recipient thereof at the address given for such Party as set forth below, or
to such other address as may be designated by notice given by any Party to the other Parties in
accordance with the provisions of this Section 4(j):
If to PacifiCorp:
PacifiCorp
825 NE Multnomah Street, Suite 1600
Portland, OR97232
Attention: Vice President Transmission Services
Fax No.: [phone]
If to Idaho Power:
Idaho Power
l22l West Idaho Street
Boise,Idaho 83702
Attention: Manager Delivery Planning
Fax No.: 2A8-388-6647
If to BPA:
Bonneville Power Administration
5411 NE Highway 99
Vancouver, Washington 98663
Attention: Senior Vice President, Transmission Service
Fax No.: 360 418-8433
Each notice, consent or approval shall be conclusively deemed to have been given (A) on the day
of the actual delivery thereof if given by personal delivery or overnight delivery, and (B) date of
delivery shown on the receipt, if given by certified mail (retum receipt requested).
Each Party shall have the right to change the place to which any notice, demand, request or other
communication shall be sent or delivered by similar notice sent in like manner to the other
Parties.
5
Execution Copy
BPA Contract Number l2TX-15584
(k) This MOU may be executed in one or more counterparts (including by
facsimile or a scanned image), each of which when so executed shall be deemed to be an
original, and all of which shall together constifute one and the same instrument.
0) Nothing contained in this MOU shall be construed as creating a
corporation, company, partnership, association, joint venture or other entity, nor shall anything
contained in this MOU be construed as creating or requiring any fiduciary relationship between
the Parties. No Party shall be responsible hereunder for the acts or omissions of the other Party
Nothing herein shall preclude a Party from taking any action (or have its affiliates take any
action) with respect to any other transmission project, including any such project that may
compete with the Project.
(m) Unless otherwise expressly provided, for purposes of this MOU, the
following rules of interpretation shall apply:
(i) any reference in this MOU to gender includes all ganders, and the
meaning of defined tsrms applies to both the singular and the plural of those
terms;
(ii) the insertion of headings are for convenience of reference only and do
not affect, and will not be utilized in construing or interpreting, this MOU;
(iii) all references in this MOU to any "Section" are to the corresponding
Section of this MOU unless otherwise specified;
(iv) words such as "herein," "hereinafter," "hereof," and "hereunder" refer
to this MOU (including the Exhibits to this MOU) as a whole and not merely to a
subdivision in which such words appear unless the context otherwise requires;
and
(v) the word "including" or any variation thereof means "including,
without limitation" and does not limit any general statement that it follows to the
specific or similar items or matters immediately following it.
ISTGNATURE PAGE TO FOLLOWI
6
Execution Copy
BPA Contract Number l2TX-15584
IN WITNESS WHEREOF, each of the Parlies has caused its duly authorized offrcer to
execute this Mernorandum of Understanding as of the date first above written.
FACITTCORP
By:
Namc:
Title:
II}AIIO POWER COMPANY
By:AA^eq--
Name: l'*\'.-. t fW \t-t{--rirle: ?,-Up 4 Uij\i
BONNEVILLE POWER ADMINISTRATION
By:
Name:
Title:
7
Execution Copy
BPA Contact Number l2TX-15584
lN WITNI1SS WHIREOF, each of thc Parties has caused its duly authorized officer to
executc this Mernorandum of tJnderstar:diug as of the date first above written.
PACTFICORP
By:
Name:
Title:
IDAHO POWER COMPAI{Y
Nanre:'Iirlc:
BONNEVILLE POWER ADMINISTRATION
Name:
'l'itle:
W*,
By'
By:
7
l:rcrulir rrr ('*1tt
lil'.\ ('onlr';rr't \rtrtrlre I ll'l"X 15.5S-l
l\: \\'l'l"Nl:5.S \\'llt:ltl:Oli. caclt ()l'tllL'l'irllicr lrur cluscrl ilr r.lul1'outlrr)r'il.(lol'lieet'lrr
r-.\cct,ttt' tlrir l'lcrrrilrlrrtrlttttt ill'trttrlct'rlartrlirr.'ur irl'tltc tllrtc l'ir'st lthrrrc rr'rillcrt.
1,.\('l l,'l('( )11,,
l).v": --N:rrttc:'l'itlr::
Il).\ I l( ) t,( )\1't,.tt ('( )\ll'.\\\'
Nlttrc:'l-illc:
lr( )\\ I,.\' I L I.ta I'O\\'li l{,\ l)\l I \ IS'l'ltA'l'l( )\
llt:
Brian Si verstefn'l'irlc: Senior Vice-President, Transmission Services
7
l)1,: __ * _
This Exhibit A identifies the preliminary alternatives to be explored in negotiations under
this MOU of the Definitive Agreements. The preliminary alternatives described in this
Exhibit A are intended to be consistent with and subject to (i) all applicable statutory and
govemmental obligations of the Parties, including, as relating to PacifiCorp and Idaho
Power, state and Federal Energy Regulatory Commission rules, regulations and orders;
(ii) stakeholder and customer interests; and (iii) the Western Electricity Coordinating
Council Three-phase rating process.
The Parties envision that PacifiCorp and Idaho Power may agree to jointly purchase and
sell assets to achieve the objectives of the altematives described in this Exhibit A. Any
purchase and sale of existing assets between PacifiCorp and Idaho Power may involve
some or all of the assets currently defined in existing contracts between Idaho Power and
PacifiCorp, including, but not limited to, the Second Restated and Amended
Transmission Facilities Agreement, Restated Transmission Service Agreement and the
Agreement for Interconnection and Transmission Services. The service arising from any
altemative may or may not be contingent upon the timing or physical construction of new
assets.
Alternative l:
BPA would obtain a network service option from the Hemingway substation to the
existing BPA service points in eastem Idaho. Idaho Power would sell and PacifiCorp
would acquire Idaho Power's existing assets necessary to provide BPA's long-term
load service.
The Parties' intent is to minimize potential rate pancakes
BPA would work to plan an amount of BPA Transmission System capacity sufficient
to enable PacifiCorp and Idaho Power to utilize their capacity shares (up to 650 MW
in total) of the Boardman to Hemingway transmission project pursuant to standard
OATT terms and conditions.
Altemative 2:
Idaho Power and PacifiCorp, in combination, would provide BPA 600 MW of firm
eastbound ownership rights of assets or other terms and conditions associated with the
combined systems of Idaho Power and PacifiCorp in southem [daho for the primary
purpose of serving the BPA service points in eastern Idaho.
BPA would provide to PacifiCorp and Idaho Power equivalent value of capacity
rights, ownership rights of assets or other terms and conditions associated with the
BPA Transmission System to the western terminus of the Boardman to Hemingway
a
a
a
8
a
EXHIBIT A
PRELIMINARY ALTERNATIVES FOR NEGOTIATION
Transmission Project, or othcr interconnection points jointly detennined by thc
Parties. Such rights would originate at BPA's NW Market Hub (Mid-C) unless
alternatives can bc accommodated to serve load elsewherc over the BPA
Transmission System"
To achieve the objcctives described in Alternative 2, the Parties would evaluate and
consider interinr measures and final approaches, including but not limited to thc joint
ownership of portions of the Gateway West Project, with BPA's minimum eastbound
firm ownership rights of 250 MW, combincd with the balance of ownership rights on
a combination of Idalro Power and PacifiCorp's cxisting systerns, as required to
establish ownenship rights from the Hemingway substation to BPA's existing eastern
Idaho load points.
9
Appendix D-B2H Supplement ldaho Power Company
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Page 130 2017 tRP
ldaho Power Company Appendix D-B2H Supplement
Appendix D-5. NTTG studies
See the attached document.
2017 tRP Page 131
Appendix D-B2H Supplement ldaho Power Company
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Page 132 2017 tRP
NoptTHErtIrl TIenTFIANSMISSION GROUP
NTTG 2OL6-2OL7
REVISED DRAFT FINAL
REGIONAL TRANSM ISSION PLAN
Draft 09.01 .L7
Note: this is a draft report and may change as a
result of stakeholder comments or edits by NTTG
Date, 2OL7
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2 1
Executive Summary ...................3
The Northern Tier Transmission Group ....,...4
Purpose of the Plan
Plan Development Process.....
Biennial Study Plan...........
Study Methodology................
Power-Flow Cases
Data Submission
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Forecasted Loads
lnitial Regional Transmission PIan Development ..............
I nterregional Project Coordination................
Stress-conditioned Case Study Results
Public Policy Consideration Scenario Requests ................ 13
Regional Economic Study Requests..........13
............13
............ 15
............L7
Stressed Hours for Study with Production-Cost Modeling ............... ....................... L7
Development of Change Cases...... ................20
Change Case Results.......................20
High Southern ldaho lmport Case...........23
High Southern ldaho Export Case ...
High Wyoming Wind Case...............
lnterregional Transmission Projects
..23
..24
..24
Reliability Conclusions ................24
Economic Evaluations .....25
Ca pital-related Cost Metric
Energy-loss Metric
Reserve Metric ..25
Economic Metric Analysis Conclusion.
Planning Process Flow Map (Coming).... ........27
Final RegionalTransmission Plan ..................27
NTTG 2016-2017 Regional Transmission Plan Supporting Materials .....................29
NTTG 2015-2017 Revised Draft Final RegionalTransmission Plan
NTTG Steering Committee Approval: MM, DD,2077
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Executive Summary
Would it be more efficient or cost-effective to meet future transmission needs in the Northern
Tier Transmission Group (NTTG) footprint through a regional planning framework rather than
the aggregate of local planning processesl? The 2015-2017 NTTG Regional Transmission Plan
(RTP) poses this question and seeks to answer it. Developed in accord with NTTG Transmission
Providers'Attachment K, which includes FERC Order 1000 regional and interregional
transmission planning requirements, the plan analyzes whether NTTG's transmission needs in
2026 could best be satisfied with projects of a regional or interregional scope.
To arrive at a conclusion, NTTG used a two-year process of identifying transmission
requirements and performing reliability and economic analyses on several collections of
transmission projects, or plans: the prior (201,4-2015) RTP, an lnitial RTP2 made up of projects
from the prior RTP and projects included in the Full Funders'LocalTransmission Plans, and a
number of Change Case plans. A Null Change Case, which tests the NTTG footprint's current
transmission system stressed by the addition of loads and resources projected for 2026-27,
showed that the NTTG system performed acceptably in only one of seven stressed conditions
studied. All the other conditions suffered performance issues that required correction.
A technical study found that the 2074-2OtS prior RTP, which included two Non-Committed
Projects (Boardman to Hemingway and portions of Energy Gateway), was not fully reliable with
the 2026-27 load and resource projections. The study then evaluated 23 Change Cases that
explored ways to reliably meet the transmission system needs through various combinations of
the Non-Committed Projects in the lnitial RTP or three proposed lnterregional Transmission
Projects, or both.
Reliability analyses narrowed the potentially acceptable solutions to the lnitial RTP. These
Change Cases were created to explore the relationship of a build-out of wind generation in
Wyoming to meet NTTG load with its impact on the transmission system west of Wyoming and
a potential expansion of the transmission system (i.e., the Gateway West and Gateway South
projects). The study also examined three lnterregionalTransmission Projects as Alternative
Projects to determine whether these projects would yield a more efficient or cost-effective
regional transmission plan for NTTG and as a part of interregional coordination and planning.
The analysis found, however, that none of the lnterregionalTransmission Projects could
replace or enhance the Non-Committed Projects more efficiently or cost effectively to satisfy
NTTG's regional transmission needs.
Subsequent economic analyses identified one of the Change Cases as the more-efficient or
cost-effective case. Known in the study as Change Case 23, this case includes Boardman to
Hemingway, Gateway South, portions of Gateway West, and the Antelope projects.
1 NTTG's regional transmission planning process is not intended to be a replacement for local
transmission or resource planning.
2 Terms are capitalized to be consistent with Attachment K. All capitalized terms are defined in the
glossary.
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
NTTG Steering Committee Approval: MM, DD,2O!7
9
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77
L2
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L4
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Stakeholder input on the RTP was accepted and evaluated throughout the biennial planning
cycle. NTTG posted the Draft RTP in December 2016 (Quarter 4) for stakeholder comment and
the Draft Final RTP in Quarter 6 for public comment. The Planning Committee will vote to
recommend submittalof the RTP to the NTTG Steering Committee in Quarter 7. Steering
Committee approval of the RTP will be requested in Quarter 8.
The Northern Tier Transmission Group
The Northern Tier Transmission Group (NTTG) was formed in 2007 to promote effective
planning and use of the multi-state electric transmission system within the Northern Tier
footprint. NTTG provides a forum where all interested stakeholders, including transmission
providers, customers and state regulators, can participate in planning, coordinating and
implementing a robust transmission system.
NTTG fulfills requirements of the Federal Energy Regulatory Commission (FERC) Order 1000 for
each public utility transmission provider to participate in a regional transmission planning
process that produces a regional transmission plan and, if appropriate, includes a regional cost-
allocation method.
NTTG evaluates transmission projects that move power across the regional bulk electric
transmission system, serving load in its footprint and delivering electricity to external markets.
The transmission providers belonging to Northern Tier serve more than 4 million retail
NTTG 20L6-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2
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s6
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customers with more than 29,000 miles of high-voltage transmission lines. These
NTTG Members'
Transmission Facilities
-
Other Western U.S. and
Canada Transmission
Figure 1. Map of western North America showing NTTG members' transmission lines.
members provide service across much of Utah, Wyoming, Montana, ldaho and Oregon, and
parts of Washington and California.
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2 5
I
It
Alberta
,
I
Montana
lrashti.si ri
W.ronin€ldaho
i tah
Co lora d oNevada
al!i'rr I
I
t
I
t
New Mexico
A:izonrr
,\
\-T\
\I
I
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i
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-7
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ilritish?rrlumbia
a'
a'-t\
90
91
NTTG works with other entities-the Western Electricity Coordinating Council (WECC) for
reliability planning and neighboring Planning Regions (e.g., ColumbiaGrid, WestConnect and
California lndependent System Operator (CAISO)) for interregional project coordination.
Pa rtici pati ng Uti lities
Deseret Power Electric Cooperative
ldaho Power
Montana Alberta Tie Ltd. (MATL)
NorthWestern Energy
PacifiCorp
Portland General Electric
Utah Associated Municipal Power Systems (UAMPS)
Purpose of the Plan
The NTTG Regional Transmission Plan (RTP) aims to produce, if possible, a more efficient or
cost-effective regional plan to transmit energy compared with a plan that rolls up the local
Transmission Providers' transmission plans and other Change Case transmission plans studied
This study process complies with FERC Order No. 1000, Attachment K-Regional Planning
Process. This planning cycle marks the first time that NTTG implemented FERC Order 1000
interregional project coordination with the other western regional transmission planning
organizations.
Plan Development Process
The Regional Transmission Plan is developed through a two-year process:
1) ldentification of the transmission requirement for the NTTG footprint, derived from the data
submissions
2) Reliability analysis and evaluation of the lnitial RTP and Alternative Projects (including
interregional projects) through Change Cases
3) Economic analysis and evaluation comparing the annualized incremental costs of the lnitial
RTP and the two most-efficient Change Cases
4) Selection of the project or projects that yield a regional transmission plan that is more
efficient or cost-effective than the other regionaltransmission plans studied
5) Any projects that were submitted for the purposes of cost allocation and selected into the
RTP will go through the cost allocation process if they are deemed to be eligible for cost
allocation.
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2
92
93
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6
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00
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02
Biennial Cycle
NTTG follows a two-year, eight-quarter planning cycle to produce the 10-year Regional
Transmission Plan. ln the first step, the Planning and Cost Allocation Committees pre-qualify3
Transmission Developers who properly submit their transmission project to be considered for
regional cost allocation (should the sponsor's project be selected in the Regional Transmission
Plan for cost allocation). The biennial cycle includes steps to collect, evaluate and analyze
transmission and non-transmission data, produce and publish a draft plan, gather stakeholder
and public input, update the plan and complete the cycle with the publishing of a RTP.
Q1-Q4
20L6
Q5-Q8
20L7
Figure 2. NfiG uses an eight-quarter biennial planning cycle.
Biennial Study Plan
The Biennial Study Plan outlines the process that NTTG follows to develop its 1.0-year RTP. lt
provides the framework to guide plan development. lt also describes NTTG's process to
determine if a properly submitted lnterregional Transmission Project (lTP) would yield a
transmission plan that is a more cost-effective or efficient solution to NTTG's regional
transmission needs.
The NTTG Planning Committee manages the study plan. The Planning Committee establishes
the Technical Work Group (TWG) subcommittee to develop the study plan. The TWG also
performs the necessary technical evaluations for the RTP and assesses any projects, including
lTPs, submitted to NTTG. TWG members are NTTG Planning Committee members or their
3 A project sponsor must have their project pre-qualified before the beginning of the 2016-2017 biennial
planning cycle (i.e., the last quarter of the prior planning cycle) pursuant to Attachment K, Section Pre-
Qualification for Cost Allocation.
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2
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designated technical representatives. They have access to and expertise in power-flow analysis
for power systems or production-cost modeling, or both.
Developed during Quarter 2 of the biennial planning cycle, the study plan establishes the:
. Study methodology and criteria
. Study assumptions based on the loads, resources, point-to-point transmission requests,
desired flows, constraints and other technical data submitted in Quarter 1 and updated
in Quarter 5 of the regional planning cycle
o Software analysis tools
o 2026 production-cost-model database and hours to be selected for reliability analysis
o Evaluation criteria for reliability and transmission service obligations
o Capital cost, energy losses and reserve-sharing metric calculations
o Public policy requirements and considerations
The study plan was posted for stakeholder comment, recommended for approval by the
Planning Committee and approved by the Steering Committee during Quarter 2 of the biennial
cycle. Due to data submission changes provided in Quarter 5, the study plan was revised in
Quarter 6. Any differences between what is stated in the study plan and the process stated in
Attachment K of the NTTG FERC Order 1000 defer to Attachment K.
Study Methodology
To determine the more efficient or cost-effective transmission plan, the TWG subcommittee
conducted reliability and economic studies in accordance with the 2016-2017 Study Plan. The
Study Plan and ultimately the RTP reflect the Full Funder's Attachment K requirements to
satisfy its transmission needs. NTTG's regional transmission planning does not investigate local
transmission planning or generation decisions related to integrated resource planning. Rather,
NTTG's methodology uses a regional perspective to question the lnitial RTP's roll-up of Non-
Committed regional transmission project(s) to identify, if possible, a regional transmission plan
that is more efficient or cost effective than the aggregated Full Funder's transmission plans. ln
conducting its regionalstudies, NTTG uses regionaltransmission and non-transmission
alternatives (if any) to honor the local transmission needs. As part of the study, NTTG assumed
that the local existing and new generation additions have (or will have) firm transmission rights
to move their power from the generator to load. NTTG's reliability studies did not re-dispatch
existing generation down to relieve congestion such that the new generation additions could
move their power to load without potentially creating congestion.
The reliability studies used production-cost modeling and power-flow studies. The production-
cost and power-flow models represent data for the western interconnection load, resource and
transmission topology. ln developing the data for these two models, NTTG started with a WECC
production cost model (version TEPPC CC1.3)and WECC power-flow model (version 25hs1a)
and modified the modeling data in NTTG's footprint for its regional studies. For the studies
including one or more interregional transmission project that relied on increased wind
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2 8
54
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57
generation within NTTG's footprint (e.g., adding new wind resource in Wyoming), NTTG
adjusted generation levels down in the region receiving the power. The goal of the adjustments
was to ensure western interconnection load and resource balance. NTTG consulted with the
planning region receiving the power (i.e., California ISO) for their generation reductions.
The results of the production-cost modeling were used to identify seven hours of high stress on
the transmission system. These seven hours were then subjected to reliability analysis using a
power-flow model. The input and output data for these selected hours were transferred from
the production-cost model (i.e., GridView)to a power-flow model (i.e., PowerWorld)to
perform the technical reliability analysis. By taking these steps, a consistent set of analysis tools
can be engaged to evaluate the reliability performance.
Next, economic studies employed the Attachment K's three metrics-capital-related costs,
energy losses, and reserves-to analyze Change Case plans that were deemed reliable to
further determine the cost effectiveness of the NTTG transmission plan.
Production-Cost Modeling
The TWG examined 8,760 hours of data using GridViewa production-cost software to establish
stressed conditions within the NTTG footprint. To set the stressed conditions, TWG used and
modified a dataset from the Transmission Expansion Planning Policy Committee (TEPPC)of the
Western Electricity Coordinating Council (WECC). The TEPPC case included a representation of
the load, generation and transmission topology of the WECC interconnection-wide
transmission system 10 years into the future.
The study plan identified seven stressed conditions that affect the NTTG area for study. After all
hours of data were run through the GridView production-cost program, the results were
analyzed and the hours representative of the seven stressed conditions were identified. For a
more detailed discussion of the conditions and hours, see the section on stress-conditioned
case study results.
Power-Flow Cases
For the next step in the process, the TWG used PowerWorlds simulation software to convert
the production-cost modelfor the seven stressed hours into power-flow cases. Each of the
stressed cases was then reviewed by the TWG to ensure that the case met steady-state system
performance criteria (no voltage issues or thermal overloads). Bubble diagrams showing the
inter-area flows for each of the stressed cases are included in the Draft Final RTP, available on
the NTTG website.
a Gridview is a registered ABB product
s PowerWorld is a registered trademark of PowerWorld Corp.
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2 9
Data Submisslon
lnformation flows in to NTTG during quarters 1 and 5 of the biennial cycle. Transmission
Providers and stakeholders may supply data on forecasted firm energy obligations and
commitments required to support the transmission system within the NTTG footprint. The data
may include load forecasts, resources, transmission topology, transmission service and public
policy requirements submissions. Regional transmission projects submitted in Quarter 1 are
shown in Table LMJ and include those from the prior Regional Transmission Plan, Full Funder
Local Transmission Plans (LTP), Sponsored Projects, unsponsored projects and Merchant
Transmission Developer projects. No projects that were eligible for cost allocation were
submitted into NTTG's 20L6-17 regional planning process.
JANUARY 2016 DATA SUBMITTAT - TRANSMISSION ADDITIONS BY 2026
New Line
New Line (associated with Boardman to
Gateway West Segment rr9 fioint with Pacificorp
(convert existing from 345 kV operation)
Gateway West Segment #5
6 Regionally significant transmission projects are generally those that effect transfer capability between
areas of NTTG. Projects that are mainly for local load service are not regionally significant. Projects that
are not regionally significant will be placed into all change cases and not tested for impact on the
Regional Transmission Plan. The future facilities submitted in the LTP's will be removed in the Null Case
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2
10
Bonanza Upalco 138 kV LTP No No
Boardman/Hem'ngwaY Longhorn LTP & pRTP Yes No500KV B2H Project
Hemingway Bowmont 230 kV 2 LTP Yes No
Bowmont Hubbard 1230 kv LTP l'",]'"New Line (associated with Boardman to
Hemingway)
Cedar Hill Hemingway 500 kv L LTP Yes No
Cedar Hill Midpoint 500 kv 1 LTP Yes No Gateway West SeBment #10
Midpoint Borah 500 kv 1 LTP Yes No
King Wood River 138 kV 1 LTP No No Line Reconductor
Willis Star 138 kV 1 LTP No No New Line
DC 1 LTP Yes No MATL 600 MW Back to Back DC Converter
Aeolus Clover 500 kv 1 LTP & pRTP Yes No Gateway South Project - se8ment #2
Aeolus Anticline 500 kv 1 LTP & pRTP Yes No Gateway West Segments 2&3
Anticline Jim Bridger 500 kv 1 LTP & pRTP Yes No 345/s00 kV Tie
Anticline Populus 500 kv L LTP & pRTP Yes No Gateway West Segment #4
Popu I us Borah 500 kv 1 LTP Yes No
Popu I us Cedar Hill 500 kv 1 LTP Yes No Gateway West Se8ment #7
Antelope Goshen 345 kV t LTP Yes No Nuclear Resource lntegration
Antelope Bora h 345 kV L LTP Yes No Nuclear Resource lntegration
1 LTP & pRTP Yes No Gatewav West Segment #1WWindstarAeolus230 kV
Oquirrh Terminal 34s kv 2 LTP Yes Yes Gateway Central
A?E
o3E tA'E Fe#.9
Enbridge
ProjectsType
,t,PU
PacifiCorp
East
Sponsor From To Volage
Deseret
G&T 2
1
SE Alberta
ldaho
Power
Gateway West Segment rr9 fioint with ldaho
Power)
Wallula McNary 230 kV 1 LTP Yes Yes Gateway West Segment A
Blue Lake
Blue Lake
Blue Lake
Horizon
Gresham 230 kV
Troutdale 230 kV 1
Troutdale 230 kV
Springville 230 kVlct
Harborton 230 kV
Harborton 230 kV
LTP
LTP
LTP
LTP
No
No
No
No
r!o-
_llo_
No
No
New Line
Rebuild
New Line
New Line (Trojan-St Marys-Horizon)
New Line (re-terminates Horizon Line)
Re-termination to Harborton
Horizon
Trojan
2
1
7
7
NO
No
No
No
St Marys
Rivergate
Harborton
Harborton
230kv _
319it _
230 kv
No
No
No
No
LTP
LTP
LTP
LTP
Re-termination to Harborton
Re-termination to Harborton
-=1_-
Trojan Harborton 2 LTP No No Re-termination to Harborton
Table LMJ
Forecasted Loads
Participating load-serving entities provide forecasts of loads for balancing authority areas
internal to the NTTG footprint. These loads are generally the same as those found in the
participants' official load forecasts (such as those in integrated resource plans) and are similar
to those provided to the Load and Resource Subcommittee of the WECC Planning Coordination
Committee. Chart CCC summarizes the load forecast used in the 2016-2017 planning cycle.
[Chart CCC:2026 forecasted loads: bar graph to be created from Table 1, below, January 2016-
2OL7 Data Submittal - Load Comparison, on page 8 of DFRTP, v2.6.1
Power 3,730 4,t93 4,346 4,340 147
NorthWestern 1,790 1,992
L3,474
3,874
23,620
PacifiCorp L2,634
3,9s8
22,11.2
1,774
1_4,OO2
3,933
23,902
1,992
L:_4!4
3,885
23,637
218
-s88
Portland General
TOTAL{'
:59
-282
08
09
10
Loads for Deseret G&T and UAMPS are included in Pacificorp East
NTTG received 3,200 MW of proposed new generation resources from its funding Transmission
Providers for consideration in the RTP. Figure 3 displays these incremental resources within the
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2
PacifiCorp
West
Portland
General
20t5
Actua!
Peak
Demand
(MW)
2024
Summer
Load Data
Submitted
in 2014-15
(MW)
2026
Summer
Load Data
Submitted
in Q12016
(Mw)
2026
Summer
Load Data
Submitted
in Q5
20L7
{MW)
SUBMITTED BY:
Difference
(MW) 2024-
2026
1.1.
Cedar Hill Hemingway 500 kV 1 LTP Yes No
I
1
1628
1093 soo 615
467
604 4 o o o
-81 -133
o 1o1o -124
o(,
,1 186
71
t2
13
1.4
NTTG footprint and compares submissions from the prior RTP with submissions for quarters 1
and 5 of the current cycle.
Comparison of Projected Generation
9000
8000
7000
5000
5@0
4000
3000
2000
1000
0
-1000
-2m0
-3000
3200
-1783 204s
15
16
77
18
19
20
21,
22
23
Figure 3. Comparison of forecasted resources
ln Quarter 5, Northwestern submitted 550 MW of new Montana wind generation. Also
PacifiCorp indicated that its recently submitted integrated resource plan increased the amount
of Wyoming wind power from 887 MW to 1,100 MW. As shown in Figure 3, the total resource
forecast of 3,200 MW submitted this cycle was reduced by 392 MW, or 12.25 percent, from the
3,592 MW forecast in 2024. Following the Quarter 1 data submittal, the owners of the Colstrip
1 and 2 coal-fired plants announced a plan to retire the units before 2026. The owners of the
Valmy l and 2 coal plants in Nevada also plan to decommission the plants by 2025, a decade
earlier than originally planned. Both sets of retirements were assumed in the 2016-2017
studies and are reflected in Quarter 5 values shown in Figure 3.
ln the 2014-15 study cycle, Power Company of Wyoming (PCW) submitted 3,000 MW of wind
resources associated with the TransWest Express project. PCW asked that those resources not
be included in the NTTG 201.4-1,5 Regional Plan. Those resources, to serve loads outside the
NTTG footprint in California, have been submitted with an lnterregional Transmission Project in
the 2016-17 study cycle.
ln support of the proposed transmission additions or upgrades, NTTG received four firm
transmission-service-obligation submissions (contractual requirements to provide service)-
two each from ldaho Power and PacifiCorp. These are shown in the following map. [Reference
Report 2.6 Table 4. Map will need to be created. Use the map from page 9 of the 2014-15 RTP
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2
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25
26
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12
.2424
r 2026 Q1
r 2026 Q5
33
34
35
as a guide. Two vectors West to East across lD-Northwest to Boise area and to ldaho Falls area,
another vector North to South from Arco to Utah, and a fourth vector east to west from
Wyoming.l
202t Northwest lPCo
2 2022 LGBP BPASEID
2024 Ante Network
Miners /Point
1100 2026 of Rocks Network
Table 4 - Transmission Service Obligations
Public Policy Consideration Scenario Requests
ln Quarter 1, Renewable Northwest (RNW) and the Northwest Energy Coalition (NWEC)iointly
submitted a Public Policy Consideration request for a scenario analysis study. The group asked
NTTG to study a faster phase-out of coal plants while developing utility-scale renewable
resources and replacing Colstrip units 1,2 and 3 with eitherwind only ora combination of wind
and natural gas combustion.
Members of the TWG and representatives from RNW and NWEC reviewed the request and
agreed to some modifications. These modifications, and the associated study assumptions, are
documented in the NTTG 2016-2017 Study Plan, Attachment 3 of the Draft Final RTP.
The study results suggested that a replacement of wind or a combination of wind and gas for
coal may be feasible. This study, however, neither constituted a path study nor conveyed or
implied transmission rights. Additional analysis would be required to understand the full
impacts of coal plant decommissioning.
Public Policy Considerations are considered to be relevant factors not established by local, state
or federal laws or regulations. The results of PPC analysis may inform the RTP but do not result
in the inclusion of additional projects in the RTP.
A full report of the study can be found in Appendix D of the NTTG 2016-20!7 Draft Final RTP.
Regional Economic Study Requests
NTTG received no regionaleconomic study requests.
lnitial Regional Transmission Plan Development
The starting point for the biennial planning process was development of the lnitial RTP. This
exercise used a bottom-up approach to merge the projects in the prior RTP (2074-2015)and
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2
s00/200
13
540
Submitted by MW Start Date POR POD
ldaho Power
PacifiCorp East
60
67
62
63
64
65
66
the Full Funding Transmission Providers' local transmission plans into a single regional
transmission plan. Next, the TWG analyzed the lnitial RTP through Change Case plans, which
included or excluded Non-Committed regional projects and lnterregional Transmission Projects.
These Change Case plans helped to determine whether Alternative Projects could be added or
substituted, or if one or more Non-Committed Projects could be deferred, or both, to yield a
regional transmission plan more efficient or cost effective than the lnitial RTP. The results of
this analysis led to the formation of the Draft RTP.
b.r
;ON
I
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I
I
I
I
I
I
t.
IIpIri t l.l67
58
69
70
Figure 4. The red and green lines represent the projects comprising the prior RTP from 2OL4-20L6, These include
Boardman to Hemingway, in the northwest sector of the above map, and an Alternative Project with four
transmission elements across four states.
The following Non-Committed regional projects comprised the lnitial RTP:
o Boardman to Hemingway (Longhorn-Hemingway) 500 kV (red)
o Gateway West
o Windstar-Aeolus 230 kV (green)
o Aeolus-Anticline (Jim Bridger) 500 kV (green)
o Anticline-Populus 500 kV (green)
o Populus-Borah 500 kV (blue)
o Populus- Cedar Hill 500 kV (green)
o Cedar Hill-Hemingway 500 kV (green)
o Cedar Hill- Midpoint 500 kV (green)
o Borah-Midpoint 345 to 500 kV conversion (dark green)
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2
77
72
73
74
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76
77
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t4
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National Foresl d
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a
a
82
83
84
85
o Midpoint-Hemingway #2 500 kV (blue)
Gateway South
o Aeolus-Clover 500 kV (red)
Antelope
o Goshen-Antelope 345 kV (red)
o Antelope-Borah 345 kV (red)
86
87
88
91
92
93
94
95
96
97
98
99
00
t\I
I', r
U
I
Ii
I
ON T
fr _.___t_
I
I
I
I
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NEVADA
Figure 5. Map showing Non-Committed regional projects comprising the 2OL6-20L7 lnitial RTP.
I nterregiona I Project Coord i nation
As part of interregional coordination, NTTG and the other regional entities in the Western
lnterconnection collaborate during their transmission planning processes to coordinate their
interregional transmission planning data. These coordination efforts inform each planning
region's transmission plans. A properly submitted lnterregional Transmission Project is
evaluated as an Alternative Project in NTTG's regional planning process. The set of
uncommitted projects (regional, interregional or both) that results in the more efficient or cost-
effective regional transmission plan forms the basis of NTTG's Regional Transmission Plan.
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2
I
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90
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SUMMARY OF Q1-2016 INTERREGIONAL PROJECTS SUBMITTED TO NTTG
Project Name Company
Relevant
Planning
Reeion(s)
Termination
From Termination to Status
ln
Service
Date
Cross-Tie
Transmission Pro.iect
TransCanyon,
LLC
NTTG, WC Clover, UT Robinson
Summit, NV
Conceptu a I 2024
SWIP-North Great Basin
Transmission
LLC
NTTG, WC Midpoint, lD Robinson
Summit, NV
Permitted 202t
TransWest Express
Transmission Project
TransWest
Express, LLC
NTTG, WC
and CAISO
Sinclair, WY Boulder City,
NV
Con ceptual 2020
Table X. Three lnterregional Transmission Projects were submitted for consideration during
formation of the lnitial RTP in Quarter 1 of the biennial cycle.
BUil€y
HUALAP.AITINDIAN
RESERY-ATIOT'I
P@.tello
@
g,Ip
@
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@
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s.!dy
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National
Forests
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National Forest
UINTAHAND OUR
HOPIRESERVATION
Atapaho
Rooseve
Nationa
Foresls an
6 White Rryer B@rtrde
Nattonal loresl
aspen C O I
Pike and
,sabel Nat
Forest
Cimaffo
Grand
page
K
Junction
UncompahqreNational Forest
IdIM&
SWIP North
Cross Tie
Transwest Express
On Line (existing)
Galluo. @
@
rp
Ip
0ixie National
Forest
SpdngdaleSl G@roe Kanab
Grand
Staircase-Esca/anleNatioral
Monument
I
IL
Las
tr
05
06 Figure 6. Three lnterregional Transmission Projects were evaluated during the planning cycle
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2
Santa t
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Southwest lntertie Project (SWIP). Great Basin Transmission, LLC (GBT), an affiliate of LS
Power, submitted the 275-mile northern portion of the Southwest lntertie Project (SWIP)as an
lTP. SWIP-North would connect the Midpoint 500-kV substation in NTTG's planning area to the
Robinson Summit 500-kV substation in the WestConnect area with a 500-kV single-circuit AC
transmission line. The SWIP is expected to have a bi-directional WECC-approved path rating of
approximately 2,000 MW. lf GBT is selected to build SWIP-North, development, final design and
construction activities could be completed to support energizing the project within an
estimated 36-42 months.
Cross-Tie Transmission Line. TransCanyon submitted the 213-mile Cross-Tie Transmission Line
for consideration as an lTP. TransCanyon proposes to build a 1500-MW, 500-kV high-voltage
alternating current (HVAC) line between central Utah and east-central Nevada. The line would
connect PacifiCorp's proposed 500-kV Clover substation with the existing 500-kV Robinson
Summit substation. TransCanyon expects the project to be in-service by the end of 2024.
TransWest Express Transmission Project. TransWest proposed a 730-mile, phased
1,500/3,000 MW, 1600 kV, high-voltage direct current (HVDC)transmission system with
terminals in south-central Wyoming and southeastern Nevada. The federal Bureau of Land
Management and Western Area Power Administration published the Final Environmental
lmpact Statement (FEIS) for the TWE Project in May 2015.
Stress-conditioned Case Study Results
Stressed Hours for Study with Production-Cost Modeling
The TWG used GridView production-cost software to review 8,760 hours of data to identify
stressed conditions within the NTTG footprint. A case representing the year 2026 was obtained
from the WECC TEPPC. This case included a representation of the load, generation and
transmission topology of the WECC interconnection-wide transmission system 10 years in the
future. The TWG identified corrections to the data needed to align with data submitted in the
first quarter of the biennial planning cycle. TWG shared these changes with the other regional
planning entities and WECC to include in their future studies. The TWG then agreed to use this
modified TEPPC case in creating the stressed cases discussed below.
After processing all 8,760 hours through the production-cost program, the TWG analyzed the
data and identified seven stressed conditions to study:
o High NTTG summer peak
o High NTTG winter peak
. High Montana-Northwest (Path 8)flows
o High southern ldaho import (ldaho-Northwest Eastbound)
o High southern ldaho-Northwest export (ldaho-Northwest westbound)
o High NE-SE (Path Tot2) flows
o Other conditions the might warrant transmission system reinforcement
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2
L7
Stressed Condition Hour TWG LabelDate
Max. NTTG Summer Peak July 22,2026 16:00 A
Max. NTTG Winter Peak December 8,2026 19:00 B
Max. MT to NW September LO,2026 Midnight c
High Southern ldaho lmport June 11,2025 14:00 D1
High Southern ldaho Export September 17,2026 2:00 D2
I nign Tot2 Ftows
I
November LL,2026 17:OO E
High Wyoming Wind September 17,2026 2:00 F
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
7t
72
73
74
75
Table XYZ - Hours Selected from 2026 WECC TEPPC Case to
Represent Different NTTG System Stresses
High Summer Peak (NTTG Case A)
o 24,!OO MW load
o L7,851, MW resources
. -6,250 import
o 4 p.m., July 22,2026
This case showed a need to import energy during high summer air-conditioning loads. The
transmission projects in the lnitial RTP performed reasonably well; however, system
performance proved inadequate without transmission system additions by 2025 to meet
NTTG's summer peak load. This case accounted for wind resources of 2,!75 MW to check the
performance of the set of projects comprising the Draft RTP.
High Winter Peak (NTTG Case B)
o 22,468 MW load
o !9,261MW resources
o -3,208 MW import
e 7 p.m., Dec.8,2026
A few local system violations occurred when tested against the transmission projects
comprising the lnitial RTP. This case puts\ less stress on the NTTG system than did the summer
peak. This case also accounted for wind resources of 2,175 MW to check the performance of
the Draft RTP projects.
High Montana-NW (Path 8) Flows (NTTG Case C)
o 73,097 MW load
o 72,t38 MW resources
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
Version 3.2 18
. -959 MW importo 12:00 midnight, Sept. 10, 2026
This case tested transmission system capabilities with high electricity flows from Montana to
the Northwest. This scenario was used for the public policy consideration study, which analyzed
the impactof an accelerated phase-outof Colstrip units 1,2 and 3 with eitherwind onlyora
combination of wind and gas. See the Public Policy Consideration Scenario Requests section for
results of the study.
High Southern ldaho lmport (NTTG Case D1)
o 76,382 MW load. 9,159 MW resources. -7,223 MW import
o 2 p.m., June 11, 2026
Under conditions with the eastbound path from the Northwest to ldaho operating at a 2,244
MW deficit, and the NTTG system importing 7 ,223 MW, the NTTG transmission topology could
not import enough power to support load service obligations in southern ldaho. With the
addition of transmission projects comprising the lnitial RTP, however, the NTTG system would
perform well, with a few localviolations.
High Southern ldaho Export ( NTTG Case D2)
o 11,935 MW load
o L4,683 MW resources
. 2,748 MW export
o 2 a.rfi., Sepl t7 ,2026
ln this export scenario, with the ldaho to Northwest Path 8 flow at 3,391 MW, the existing
NTTG system would be incapable of supporting expected transfers and meeting transmission
requirements in 2026. Adding in the projects from the lnitial RTP, the system performed well,
with one contingency that caused a series cap bank to overload. That bank, however, has
reached the end of its usefullife and is likelyto be replaced before 2026.
High NE-SE (Path Tot2)flows (NTTG Case E)
o 1,6,625 MW load
o L6,620 MW resources
o 5 MW export
o 5 p.m., Nov. 11,2026
This case evaluated the performance of the lnterregional Transmission Projects in supporting
transfers between regions. These additional interregional transfers were not identified in Q1 to
meet or defer NTTG's2026 footprint resource requirements. The case showed near balance in
the NTTG footprint between loads and resources, with a small 5 MW import, along with a Tot2
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
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flow of 1,566 MW. This case accounted for wind resources of 2,175 MW to check the
performance of the Draft RTP.
High Wyoming wind production (NTTG Case F)
o 11,935 MW loado 15,015 MW resources
o 3,081 MW export
o 2 a.m.,Sept.17,2026
This case, as others, was studied at the 2,175-MW wind level, which includes the addition of
1,100 MW of wind capacity. The added wind generation in the Wyoming area worsened
reliability issues observed in Wyoming and confirmed the need for additional transmission to
use these resources to their fullest extent. The RTP addresses these reliability concerns and
relieves the transmission constraints.
Development of Change Cases
For each of the seven stress-conditioned cases, the TWG prepared a Null Change Case and
analyzed reliability results. The Null case represents roughly today's transmission topology
made to serve loads and resource requirements in 2026. Only the Heavy Winter case
performed acceptably. All the other conditions revealed performance issues that required
varying degrees of correction, with the heavy summer case needing the least correction and
the high Wyoming wind case needing the most. ln instances where the transmission system
was not adequately stressed to historical norms, the TWG slightly modified system conditions
to ensure that the transmission system was studied under reasonably stressed conditions.
Change Case Results
To efficiently study the wide range of potential combinations of Non-Committed Projects, the
TWG proposed a Change Case matrix in the study plan. Once the stressed power-flow cases
had been selected and developed, the TWG modified the matrix to better reflect the
recommended analysis. The TWG provided stakeholders with the opportunity for input on
whether a particular combination of uncommitted regional or interregional projects should be
analyzed. No comments were received. The matrix was subsequently vetted through the
Planning Committee and the Steering Committee.
Table XX, below, is the Change Case matrix used by the TWG.
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Gateway Gateway Antelope
S* W* Projects
Cross-
SWIP N TieB2H*TWE
X
x
x X
X
x
x
X
n ull
pRTP
iRTP
cc1
ccz
cc3
cc4
cc5
cc6
cc7
cc8
cc9
cc20
cc10
CC11
cc18
ccL2
cc13
CC19
CCL4
cc15
cc15
ccLT
cc2L
cc22
cc23
Case Case(s):
ABDlD2F
ABDlD2F
ABDlD2EF
ABDlD2F
AD2EF
ADlD2EF
ADlD2EF
ABDlD2F
ABDlD2F
ABDlD2F
E+RPS
E+RPS
E+RPS
E+RPS
E+RPS
E+RPS
E+RPS
E+RPS
E+RPS
E+RPS
E+RPS
E+RPS
E+RPS
D2F
D2F
F
X
x
x X
x
X
X
x
x X
X
x
x
X
x
x
X
X
x
X
A
B
c
X
X
X
X
x
X
x
x
x
* B2H and Alternate P in the pRTP are similar to B2H, Gateway S and
Gateway W in the 20L6-77 Q1 data submittals
I
x
The change case does not include the non-Committed Project
The change case includes the non-Committed Project
Gateway West without Midpoint-Hemingway #2 and Cedar Hill-Midpoint
Gateway West without Borah-Midpoint Uprate and Populus-Borah
Gateway West without Midpoint-Hemingway #2, Cedar Hill-Midpoint and
Popu lus-Bora h
Gateway West without Midpoint-Hemingway #2, Cedar Hill-Midpoint,
Populus-Cedar Hill-Hemingway, Populus-Borah and Midpoint-Borah Uprate
The change case was run with and without B2H59
60
61 Figure 7. Change Case matrix used in the development of the RTP
62
63
ln all, the TWG performed more than 100 reliability studies on more than 4L0 contingencies. To
better communicate the results of these studies, the TWG created heat maps, which present a
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
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B
C
D
21,
X
x
x
x
X
x
x
X
x
x
x
X
x
D
X X
x
X
64
65
66
weightedT graphical performance of a Change Case on a specific flow condition. A full heat map
analysis of the Change Cases is included in the final Draft RTP.
,_
t I,t
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r-.,-"J1
I
I
I
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-1
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+rr
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Figure 8. Heat map of the D2-Null Case
Figure 8, for example, shows the general location where performance issues (e.g., an
overloaded transmission line) occurred for a contingency. The accumulation of overloads and
voltage issues are represented by the color spectrum from blue to red, or "cooler" to "hotter."
These violations occur when transmission systems cannot handle anticipated transfers across
that area's transmission lines. ln particular, this heat map, using existing Wyoming wind
resources dispatched at about 600 MW, indicates that transmission additions are necessary to
integrate the projected wind resources.
i High voltage conditions had a weighting of 1; Low voltage conditions had a weighting of 3; and
overloads of branches had a weighting of 5. For example, a zone in which 10 contingencies caused an
overload of one branch in that zone would receive a total weight of 50 (i.e., 10 x 5), which would then be
translated into a color on the map. A blue color represents a weighted total of about 10, green is a count
up to 30, yellow is a count up to 50 and red is for a weighted count exceeding about 70.
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
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t I
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Figure 9. Heat map of the High Southern ldaho export case with the lnitial RTP facilities included
The heat map in Figure 9 shows how the addition of the lnitial RTP projects produced a
dramatic improvement of transmission performance when compared with the NullCase
High Southern ldaho lmport Case
Combining the Boardman to Hemingway project with the Gateway West and Gateway South
Non-Committed Projects eliminated violations in flow conditions visible in the Null Case.
Change Case 3 tested whether Gateway West or Gateway South, or both, could replace or
compare with the Boardman-to-Hemingway line. They couldn't. The projects contained in the
prior RTP also failed to alleviate the violations.
High Southern ldaho Export Case
Adding the Boardman-to-Hemingway project relieved stress across the ldaho-Northwest
cutplane, but significant issues remained east of Hemingway. Adding the eastern portion of
Gateway West and Gateway South outlined in the prior RTP eliminated the performance issues
in Wyoming and between ldaho and Montana, but those additions increased the stress across
southern ldaho. The lnitial RTP and Change Cases 21 and 23 resolved these issues.
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High Wyoming Wind Case
Without significant reinforcements, the transmission system in Wyoming could not handle both
existing and future planned wind resources while maintaining all other Wyoming area
generating resources at their typical high capability in an export scenario.
With wind production at the 1,300-MW level in the Null Case (no new transmission supporting
2026 loads), the system performed poorly. Nor did the projects in the prior RTP solve problems.
Adding the lnitial RTP projects resolved all violations except for a series capacitor bank. That
bank has reached the end of its useful life, however, and is due for replacement.
ln Quarter 6, the case was tested to see if Change Cases 1 through 4 would support the
increased level of Wyoming wind. The Null Case (no new transmission) was unable to be solved
with wind above 1,800 MW. Testing Change Case 4 required adding the Aeolus-Anticline 500-
kV line to eliminate a number of contingencies that failed to solve in Wyoming. Change Case
23, which is essentially Change Case 4a with Gateway South added, performed well with
Wyoming wind modeled at 2,175 MW.
I nterregiona I Tra nsmission Projects
Change Cases 5 through 20 tested whether the three lnterregional Transmission Projects
(lTP)-alone, in combination with other lTPs or in combination with the Non-Committed
Projects-could satisfy NTTG's transmission needs on a regional or interregional basis more
efficiently or cost effectively than through local planning processes. The lTPs were added to the
null cases without any additional resources to serve NTTG load beyond those resources
identified in the Quarter 1 and Quarter 5 data submittals. The lTPs did not provide the NTTG
footprint with regional benefits, the testing showed, either by significantly reducing
performance issues or by displacing NTTG Non-Committed Projects.
The lnitial RTP also was analyzed to determine whether it would be capable of supporting the
interregional resource transfers proposed by the lTPs. Given the relatively long distances of the
lTPs, the local integration performance issues identified in Wyoming were solvable.
Reliability Conclusions
Based on the above study results, the TWG concluded that both Change Cases 2L and 23 and
the lnitial RTP satisfy NTTG reliability criteria. ln Quarter 5, the TWG tested Change Case 23 and
the wind resource additions at various load and flow levels on the Heavy Summer, Heavy
Winter, High Tot2 and High Wyoming wind cases. The TWG study found the NTTG area would
be reliably served in the year 2O26 only by including the following Non-Committed regional
projects:
Boardman to Longhorn (formerly Hemingway)
The Energy Gateway projects including segments:
o Windstar-Aeolus 230 kV
o Aeolus-Clover 500 kV
o Aeolus-Anticline 500 kV
o Anticline-Populus 500 kV
o Populus-Cedar Hill-Hemingway 500 kV
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Antelope Transmission Project including:
. Antelope - Borah 345 kV
o Antelope - Goshen 345 kV
o Antelope 3451230 kV transformers and interconnection facilities
The lTPs were evaluated to determine whether one or more of them could defer or replace
NTTG's Non-Committed Projects. The TWG concluded that none of the lTPs solved NTTG's
reliability performance issues and, thus, were included in the final NTTG RTP.
Economic Evaluations
To determine whether the lnitial RTP or a Change Case transmission plan was more cost
effective, the TWG used three economic metrics, as determined in the Biennial Study Plan. The
three metrics-capital-related costs, power flow losses and reserves-and results are discussed
below.
Capital-related Cost Metric
Development of the capital-related cost metric required three steps. The first step validated
the capital cost of the Project Sponsor's Q1 submitted project. The second step used those
results to estimate the annual capital-related costs. The third step levelized the net present
value annual capital-related costs for the lnitial RTP and the Change Case plans.
Energy-loss Metric
The energy-loss metric captures the change in energy generated, based on system topology, to
serve a given amount of load. A reduction in losses for a Change Case would represent a
benefit, since less energy would be required to serve the same load. The two Change Cases
with fewer Gateway West transmission segments-Change Cases 21 and 23-had losses higher
than, or in some cases equal to, the lnitial RTP. Losses were higher in the two Change Cases
because the electrical flows in the lnitial RTP were redistributed to fewer lines. From a loss
perspective alone, the lnitial RTP case had fewer losses and as such was the more efficient
case.
Reserve Metric
The reserve metric evaluates the opportunities for two or more parties to save money by
sharing a generating resource that would be enabled by transmission. The metric is a 10-year
look at the increased load and generation additions in the NTTG footprint and the incremental
transmission additions that may be included in the Draft RTP.
ln the study cycle, the TWG analyzed Gateway West, Gateway South, Boardman to Hemingway,
SWIP North and the Cross-Tie projects. To evaluate these projects, the NTTG footprint was
segmented into five zones, and a sixth external zone was included to study the SWIP North and
the Cross-Tie projects. The six zones produced 722 viable sharing combinations. Of those, the
analysis of the annual net savings over each theoretical participant's standalone alternative
suggested that only 34 viable combinations were economic.
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Note that this metric includes generation capital costs in its evaluation and, as such, may only
be appropriate for cost allocation purposes. lt should not drive the selection of a Draft RTP.
Whether these cost savings warrant jointly sharing the costs of reserve capacity is up to the
parties to decide.
For the NTTG metric analysis, the lnitial RTP and the two alternative Change Cases each
supported viable economic combinations. Since these Change Cases could contain the same
benefit value, the Change in Reserve metric did not factor into the Draft RTP selection decision
Economic Metric Analysis Conclusion
The sum of the annual capital-related cost metric, loss metric (monetized) and reserve metric
(monetized) yielded an incremental cost for the lnitial RTP and the Change Case plans. The set
of projects with the lowest incremental cost, after adjustment by the plan's effects on
neighboring regions-Change Case 23 (see Figure 10, below)-was then incorporated into the
Draft RTP. Note that the incremental cost was computed as the levelized annual capital-related
cost, minus NTTG loss benefit, minus monetized reserve benefit.
lncrementalCost
so Szoo Sqoo ssoo Saoo
Millions
S1,ooo
CC23
CCZI Ss:o
iRTP
Figure 10, Change Case 23, comprising Boardman to Hemingway, Gateway South, portions of Gateway West, and
the Antelope projects, produced the lowest incremental cost.
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Planning Process Flow tVlap (Coming)
Final Regional Transmission Plan
Based on the study assumptions and reliability and economic conclusions discussed above, the
more efficient or cost-effective plan is Change Case 23. Change Case 23 is a staged variant of
the lnitial RTP. For the transfers submitted in Quarter 1 and Quarter 5, the facility segments
shown in Figure 11, below, were not necessary for the transfers studied in the Change Cases.
These segments would likely be necessary at higher transfer levels.
Figure 11. These transmission line segments from the lnitial RTP were not included in the final RTP.
NTTG's final Draft RTP emerged after a rigorous reliability analysis of the NTTG Transmission
Providers' rollup of their local area plans and assumption of Non-Committed regional
transmission projects, augmented with stakeholder lnterregionalTransmission Projects. This
technical analysis was followed by an economic metric analysis that selected NTTG's more
efficient and cost-effective regionaltransmission plan, shown below in Figure 12.
NTTG 2016-2017 Revised Draft Final RegionalTransmission Plan
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T !
Sarvtooth
NationalForest),t,
Rexburg!
I L a\
Nampa LTFr \.<-
t
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1l
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L
a
t]I \
Jackpol
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lr NEVADA
I
I
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I13
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1,6
17
Figure 12. These projects comprise NTTG's final RTP. See the legend for the identity of individual projects,
Legend for Fig. 12
Red in upper left: Boardman to Hemingway
Green: Gateway West
Red at bottom: Gateway South Gate
Dark green in middle: Gateway West-upgrade of existing line from 345 kv to 500 kv
Red at center: Antelope projects
Cost Allocation
The SWIP-North project sponsors were the only project sponsors to request cost allocation;
however, they failed to comply with the requirement to submit pre-qualification data by Oct.
3t,2015. As a result, no projects that were eligible for cost allocation were submitted into
NTTG's 2OL6-17 regional planning process.
Next Steps
Publication of the NTTG Regional Transmission Plan completes the two-year planning process
begun in January 2016. The 201.6-2017 NTTG RTP identified a need for new transmission
capacity to serve forecasted load in 10 years. The plan also identified a set of transmission
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projects known in this report as Change Case 23 as the more efficient or cost-effective
transmission plan to meet that need. While the RTP is not a construction plan, it provides
valuable regional insight and information for all stakeholders (including developers) to consider
and use in their respective decision-making processes.
The next biennial regionaltransmission planning cycle for NTTG started October 1,2O77 and
will culminate with the publication of the 2OL8-2019 RTP in December 2019.
NTTG 201.6-2017 Regional Transmission Plan Supporting Vlaterials
The supporting materials referenced in this report have been posted on the NTTG website and
can be found using the following link:
https://www.nttg.bizlsite/index.php?option=com docman&view=list&slug=2016-2017-nttg-
plan ning-cvcle&ltemid=31
A list and link to each of the individual supporting documents is also provided below:
1. Amended Quarter 6 NTTG 2016-17 Biennial Studv Plan Approved 08.02.17
2. Stakeholder Comments on NTTG 2016-2017 Draft Studv Plan & NTTG Response - FINAL 07-
13-2016
3. NWEC & RNW Comments Submitted on NTTG 2016-2017 Draft Study Plan
4. NTTG 2016-2017 Draft Final Resional Transmission Plan - 06-30-2017
5. 2016-2017 NTTG Public Policv Consideration Scenario Report
6. Draft NTTG Studv Report for 2016-2017 PPC Scenario For Stakeholder Comment
G Iossa ry
Note: This Glossary is for the benefit of readers and neither supplements nor modifies any
defined terms contained in any entity's filed Open Access Transmission Tariff (OATT), including
the Attachment K to that tariff. To the extent that a term diverges from any entity's OATT,
defer to the OATT.
Alternative Project Alternative Project refers to Sponsored Projects, projects submitted by
stakeholders, projects submitted by Merchant Transmission Developers and unsponsored
projects identified by the Planning Committee (if any).
Change Case A Change Case is a scenario where one or more of the Alternative Projects is
added to or replaces one or more Non-Committed projects in the lnitial RTP. The deletion or
deferral of a Non-Committed Project in the lnitial RTP without including an Alternative Project
can also be a Change Case.
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Committed Project A Committed Project is a project that has all permits and rights of way
required for construction, as identified in the submitted development schedule, by the end of
Quarter 1 of the current regional planning cycle.
Draft Regional Transmission PIan Draft Regional Transmission Plan refers to the version of the
Regional Transmission Plan that is produced by the end of Quarter 4 and presented to
stakeholders for comment in Quarter 5.
Draft Fina! Regional Transmission Plan Draft Final Regional Transmission Plan refers to the
version of the Regional Transmission Plan that is produced by the end of Quarter 6, presented
to stakeholders for comment in Quarter 7 and presented, with any necessary modifications, to
the Steering Committee for adoption in Quarter 8.
lnitial RegionalTransmission Plan lnitial Regional Transmission Plan comprises projects
included in the prior Regional Transmission Plan and projects included in the Full Funders Local
Transmission Plans and accounts for future generation additions and deletions (e.9.,
announced coal retirements).
lnterregiona! Transmission Project An Interregional Transmission Project is a proposed new
transmission project that would directly interconnect electrically to existing or planned
transmission facilities in two or more planning regions and that is submitted into the regional
transmission planning processes of all such planning regions.
Merchant Transmission Developer Merchant Transmission Developer refers to an entity that
assumes all financial risk for developing and constructing its transmission project. A Merchant
Transmission Developer recovers the costs of constructing the proposed transmission project
through negotiated rates instead of cost-based rates.
Non-Committed Project A project that is not a Committed Project
Sponsored Project A Sponsored Project is a project proposed by a Project Sponsor.
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