Study Summary
The Montana Regional Transmission Connectivity Study (“Study”) explores phased and strategic transmission expansion options that improve Montana’s connectivity with the broader Western grid and enable regional access to new generation resources. These expansion strategies also support instate load growth, system resiliency, and long-term reliability. Given the significant uncertainty facing the electric sector – including the pace, location, and scale of resource development among other factors – the Study does not prescribe a single transmission buildout, avoiding a take-it-or-leave-it conclusion. Instead, it identifies a series of coordinated transmission investments that can be deployed incrementally over many years, allowing Montana’s grid to scale over time, preserving both near-term optionality and long-term value. The Study is intended to inform long-term regional transmission planning, investment prioritization, policy development, and engagement with stakeholders and transmission rightsholders It evaluates the feasibility of multiple transmission expansion options, including upgrades to existing corridors, new high-voltage lines, routing options, and new interconnection points with surrounding states.
Although the purpose of this study was to evaluate upgrades that could transmit resources from Montana to the west, any new transmission upgrades have the potential for importing power into Montana as well. Those import capabilities were not studied.
The study examined three scenarios of increasing resource deployment in Montana Low (3 GW), Medium (9 GW), and High (12 GW) with corresponding transmission portfolios. The table below (Figure 1) summarizes the scale of new resources integrated, required new transmission investment, and miles of new and upgraded lines in each to accommodate resources in each scenario
To supplement the transmission modeling, the study team conducted a high-level routing analysis to evaluate the siting feasibility of transmission identified in the Low, Medium, and High Deployment scenarios. The routing analysis considered environmental constraints, land use, terrain, proximity to existing corridors, transmission costs, and sensitivities that explored the impact of avoiding sensitive lands. This effort informed estimates of potential routings, line mileage, and capital costs, and is designed to support early-stage planning and diligence, highlighting corridors where early engagement with communities – including tribes – may be helpful.
Figure 1: Summary of Resource
and Resulting Transmission Portfolios
Figure 2, below, shows the location and type of major transmission upgrades included in each portfolio. The transmission required for the Low Deployment scenario would be built first and would offer the ability to accommodate 3,000 MW of new capacity in Montana. The Medium Deployment portfolio would be built out second, accommodating an additional 6,000 MWs of resources (9,000 MW total). Finally, the High Deployment portfolio would be implemented, resulting in a system that supports the integration and regional delivery of 12,000 MWs of new generation Critically, the Study views this expansion as a long-term endeavor – many of the projects identified would take many years to plan, refine, permit, and ultimately construct.
Key findings from the Study include:
1. Montana’s export capability is already constrained under current conditions. Existing interstate transmission paths including the Colstrip system, Montana-Northwest, and MontanaIdaho corridors are fully subscribed, leaving essentially no long-term available transfer capacity to accommodate new resource exports. Without new infrastructure, even modest amounts of incremental generation exports cannot be accommodated.
2. Phased transmission investments allow Montana’s grid to scale with resource growth and market demand. The study identified a series of coordinated transmission upgrades that enable incremental resource additions over time. This phased approach avoids overbuilding, aligns infrastructure with evolving generation and market dynamics, and preserves flexibility
Figure 2: Study Transmission Portfolios in Context with the 2035 Benchmark Regional Grid
under future uncertainty.
3. A new Montana-Idaho intertie provides a high-impact starting point. For the Low Deployment scenario, a new HVDC line between the Colstrip transmission system and Idaho offers an efficient solution for unlocking a large tranche of interstate connectivity. When paired with minor upgrades in Montana, the portfolio costs roughly $3.1 billion and represents a strategic option to integrate capacity, improve market access, and enhance regional reliability
4. Achieving 9 GW of total resource deployment requires further strategic transmission expansion in Montana. Building on the Low Resource Deployment scenario, additional investments of $7.6 billion ($10.7 billion total) include new 500-kV AC lines, reconductoring projects, and advanced conductors. These projects expand Montana’s ties to the Pacific Northwest and prevent corridor congestion, resulting in the integration of 9 GW of new resources.
5. A high resource deployment future of 12 GW calls for long-term HVDC and AC backbone upgrades throughout the state. A long-term expansion plan totaling $13.9 billion adds a Colstrip–Townsend HVDC line and further 500-kV expansion. These upgrades accommodate higher resource development, particularly around Colstrip, and represent a long-term (15-year or more) buildout strategy. This plan can be adapted and optimized as nearer-term projects are implemented and uncertainty decreases.
6. Building HVDC early may reduce future upgrade costs. Constructing the Montana–Idaho intertie as HVDC offers flow control benefits that avoid redundant upgrades in higherdeployment scenarios. Results suggest that upfront cost premiums associated with building HVDC are outweighed by long-term efficiency, avoiding $108 million in additional upgrades in the High Deployment case. However, while the study identifies efficiency opportunities with an HVDC configuration of this line, it did not consider all operational, supply chain, or planning complexities and more work is needed in those areas. An AC expansion in this corridor is a viable and beneficial option that may have less near-term risk.
7. Montana transmission expansion can integrate with and enhance other major regional transmission projects. The transmission portfolios identified in the Study align with major planned transmission projects across the West such as Gateway West, Boardman-toHemingway, SWIP North, and the North Plains Connector (NPC) working together to support a stronger, more resilient regional grid.
8. A mix of technologies maximizes system performance and limits land impacts. The transmission portfolios include a mix of HVDC, advanced conductors, reconductoring, and flow-control technologies that increase efficiency and flexibility while minimizing new right-ofway needs.
9. Route optimization reduces—but cannot eliminate—impacts to sensitive lands and difficult terrain. Routing analysis prioritized existing corridors and low-impact paths, reducing environmental and land disturbances. However, Montana’s challenging terrain and many land use sensitivities mean that impacts cannot be fully avoided, especially in higher-deployment scenarios where more transmission is required.
10. Tribal collaboration is essential for future corridor planning. Current datasets are insufficient to properly incorporate tribal preferences and culturally sensitive areas into routing; deeper, direct coordination with tribal nations is needed to identify preferred corridors. (See Figure 21, p. 30, for proximity of high-deployment portfolios to reservations.)
Taken together, the study findings offer a roadmap for improving Montana’s transmission connectivity in a scalable, efficient, and regionally integrated manner. By identifying phased transmission portfolios tied to specific levels of generation deployment, the study equips planners, policymakers, and developers with a framework to align infrastructure investments in Montana with future system needs. We hope that this study provides a technical foundation to support future planning efforts and emphasizes the need for continued collaboration across jurisdictions, utilities, tribes, and stakeholders to ensure timely and effective transmission development in Montana, the Northwest and beyond
1. Background and Study Objective
Montana’s electric grid has evolved from its beginnings supporting early 20th-century hydropower development powering mining and industrial centers like Butte and Great Falls. The construction of the jointly owned Colstrip Generating Station and the associated 500 kV Colstrip Transmission System (CTS) in the 1980s marked a pivotal moment, enabling large-scale exports of coal-fired power westward to utilities in Montana and across the Pacific Northwest region
Today, most of the Montana high-voltage transmission system (Figure 3) is owned and operated by a mix of entities including NorthWestern Energy – the primary investor-owned utility in Montana – as well as Bonneville Power Administration (BPA), various municipal and cooperative utilities, and the CTS joint owners The Montana grid has grown in response to load growth, new resource need, and the state’s growing role as a participant in Western energy markets. Long transmission corridors spanning sparsely populated areas create challenges around stability, voltage control, and complex transmission entitlements. Joint ownership of transmission is common in Montana, especially as it relates to the interstate connections.
Several regional utilities’ resource plans and long-term planning studies have identified Montana as a high-quality resource state particularly for wind development in central and eastern parts of the
Figure 3: Montana's High-Voltage Transmission Grid
state. 1 Recent policy and market trends, including data center deployment, growing demand for capacity and resource diversity, and market expansion have accelerated interest in the state’s power production potential. These factors, plus plans to interconnect Montana to the Eastern Interconnection via the proposed HVDC North Plains Connector project (Figure 3) will place additional stress on the Montana transmission system.
There is increasing recognition across the Western U.S. of the strategic importance of expanding Montana’s transmission connectivity. Montana’s existing interstate transmission pathways are constrained, with limited available transfer capacity, aging infrastructure, and an outdated design originally built to transfer discrete amounts of coal generation from source points. These challenges have brought renewed attention to the need for broader resource access, expanded interties, and deeper integration with the broader Western Interconnection. Thus, Montana's geographic position and evolving role in the Western energy mix place it at the center of ongoing regional discussions about how to reliably and efficiently move energy across the West.
Montana loads have an increasing need to import power from out of state as evidenced by the December 2022 Arctic blast when 41% of demand was serviced via imports at very high prices from out of state resources per Northwestern Energy’s 2023 Integrated Resource Plan.
1.1 Study Purpose and Objectives
The purpose of the Montana Regional Transmission Connectivity Study is to assess how strategic, phased transmission investments can connect Montana to regional markets and position it as a valuable regional player in the evolving Western grid With rising electricity demand across the West, a proposed interconnection from the North Plains Connector at Colstrip, and growing interest from the Pacific Northwest in the state’s generation resources, the study seeks to identify transmission pathways for reliable, cost-effective access to Montana’s energy resources.
With this purpose in mind, the Montana Regional Transmission Connectivity Study was guided by the following objectives:
1. Define plausible future resource deployment scenarios for Montana
2. Assess near-term transmission availability on key interties to establish a transmission availability baseline and ensure efficient usage of the existing system
3. Identify phased transmission expansion portfolios that support each resource deployment scenario and expand connectivity to the western grid
4. Evaluate a range of transmission technologies including HVDC and advanced conductors
5. Coordinate transmission portfolios with planned regional upgrades
1 For example: Puget Sound Energy (https://www.pse.com/en/IRP/Past-IRPs/2023-IRP) or Avista IRPs (https://www.myavista.com/ -/media/myavista/content-documents/about-us/our-company/irpdocuments/2025/draft-avista-2025-electric-irp.pdf)
6. Consider environmental and land factors when performing preliminary routing of potential transmission buildouts and 7. Estimate capital costs
The study scope included evaluation of Montana’s high-voltage transmission system and its primary connections to the Pacific Northwest and Idaho (shown in Figure 3 as the Montana-Northwest and Montana-Idaho corridors; WECC Paths 8 and 18). It did not include lower-voltage facilities, local systems, or the need for generator interties. Evaluation of the transmission paths that connect Montana to Wyoming and Alberta (WECC Paths 80 and 83) were likewise out of scope for this study but remain important areas for future analysis.
Given the significant uncertainty facing the electric sector – including the pace, location, and scale of resource development among other factors – the study does not prescribe a single plan, avoiding a take-it-or-leave-it conclusion. Instead, it identifies a roadmap consisting of a series of coordinated transmission investments that can be deployed incrementally over many years, allowing Montana’s grid to scale efficiently over time while preserving near-term optionality and longterm value.
2. Approach & Key Assumptions
To develop a phased transmission plan, the study identified transmission portfolios for three scenarios. These scenarios represent increasing levels of resource deployment in Montana, with each resource and transmission portfolio building on the last.
For each scenario, power system models were developed to represent Montana’s grid. These models capture system constraints and limitations as resource deployment levels increased. When transmission reliability violations occurred, transmission solutions were identified using exploratory studies of system performance, insight on cost efficiencies, experience with various technology types, and practitioner judgment of transmission planning engineers, resulting in a tailored solution portfolio for each scenario.
Figure 4: Scenario Architecture
The remainder of Section 2 describes the key components of the study’s methodology. Resulting transmission portfolio for each resource deployment scenario are outlined in Section 3, and the Study’s key takeaways are covered in Section 4
2.1 2035 Benchmark System
The first step in the Montana Regional Transmission Connectivity Study involved developing power system models to reflect a 2035 Benchmark System. This 2035 Benchmark served as the starting point for all other models and analyses. The model was developed from the WECC 2035 Heavy Summer (HS) power flow case, which represents west-wide grid operations & flows at a snapshot in time under stressed summer conditions.
Model assumptions were adopted to reflect (1) planned transmission and generation expected to be in-service by 2035 and (2) load and resource dispatch decisions reflecting high-export conditions that stress inter-state transmission paths.
Benchmark Resources
NG, 268
Coal, 1596 Solar, 962
Other, 94 Storage, 75
Hydro, 2369
Total: 8138 MW
A review of planned Montana generation, storage, and transmission was performed from sources including utility resource plans, interconnection queues, and S&P Global Market Intelligence. In addition to Montana resources reflected in the WECC 2035 HS case, approximately 1,023 MW of generation projects were identified and included. These resources have demonstrated a high likelihood of being built, for example a signed Large Generator Interconnection Agreement (LGIA) or have another form of contractual arrangement with a Transmission Provider or began construction after the WECC 2035 HS model was built. The study assumed that Colstrip Generating Station units 3 & 4 remain online and were dispatched to serve in-state loads based on current information about unit ownership. Figure 5 shows the total in-service nameplate capacity of Montana resources assumed operational in the 2035 Benchmark.
Wind, 2774
The utility and developer-led transmission projects modeled in the 2035 Reference are summarized in Figure 6. These upgrades were modeled to reflect in-service timing and topology changes as understood at the time of the study. Notably, we did not explicitly include BPA’s Montana-toWashington project proposed on July 10th, 2025 as development of the 2035 Benchmark Case had been completed by that time. Those projects are effectively included in the deployment scenario results.
Figure 5: Montana Resource Nameplate Capacity (MW) in 2035 Benchmark (Western Interconnection only)
Loco Mountain Substation (i.e., P310Ix)
Gateway West (Segments D3, E and E8)
Longhorn to Hemingway (Formerly Boardman to Hemingway)
SWIP-North
A detailed list of assumptions included in developing the Benchmark Case is provided in Appendix A
Load and Dispatch Decisions to Simulate Stressed Conditions
Load and dispatch were adjusted to reflect the Montana grid in a high generation and off-peak load condition. This has been identified in WECC studies as a critical condition for Montana’s inter-state paths. Load was reduced from 2,614 MW to 1,747 MW to obtain stressed export flows, and generation dispatch in the 2035 Benchmark was increased to maximize flows on Path 8 East-to-West and Path 18 North-to-South.
This combination of reduced load and increased generation amounted to a 2,268 MW net output (i.e., Montana generation minus load) increase from the WECC model, and that additional power was scheduled outside of Montana to the Pacific Northwest, Idaho, Utah and Nevada, by decreasing generation in those areas. This resulted in an increase of approximately 1,600 MW in Montana export flows on Path 8 and Path 18.
Baseline View of Long-Term Transmission Availability
The baseline assessment of long-term transmission availability examined how much additional generation (e.g., unplanned generation) Montana can export without major new infrastructure. Using Available Transfer Capability (ATC) and Total Transfer Capability (TTC) data from transmission providers’ OASIS platforms, Energy Strategies reviewed the Colstrip Transmission System, BPA’s Eastern Intertie, and WECC Paths 8 and 18 over a 10-year period (2025–2035). This commercial-data approach, rather than power flow simulation, confirmed that existing firm rights are largely subscribed, with only nominal ATC (155 MW to Avista beginning in 2026) available. Beyond that, no meaningful headroom exists for exports to BPA, PacifiCorp, or Idaho Power. The findings show that, under current plans, new generation will require new transmission infrastructure even under modest generation growth scenarios, and modeled assumptions in the 2035 Benchmark were cross-checked against observed ATC/TTC ceilings to ensure consistency.
Figure 6: Summary of Transmission Projects Included in Benchmark
2.2 Define Resource Deployment Scenarios
The next step in the Montana Regional Transmission Connectivity Study involved designing plausible future scenarios for generation development (on top of the 2035 Benchmark) in Montana. The total incremental capacity added in the scenarios ranges from 3 GW to 12 GW. Recent studies exploring long-term resource demand in the West forecast the addition of hundreds of GWs of new resources over the approaching 10- and 20- year periods. 2 Thus, the 12 GW of assumed long-run demand for Montana resources – a fraction of this total – is reasonable given the pace of load growth and resource deployment in the region.
These scenarios do not attempt to forecast the buildout of specific generation projects but rather are designed to stress the transmission system in meaningful and realistic ways that can inform long-term infrastructure planning. Figure 7 below provides a summary of each of the three Resource Deployment Scenarios and how they compare to the Benchmark Case that formed the study baseline.
Generation injection locations were selected based on a combination of factors, including proximity to existing high-voltage infrastructure, commercial development interest, and resource quality. Five key development zones – Colstrip, Garrison, Broadview, Great Falls, and NPC (modeled at Colstrip) – were chosen to reflect plausible future buildout across Montana.
Figure 7: Resource Zones Considered in Study
These locations, shown in Figure 7, were informed by interconnection queue data, integrated resource plans (IRPs), public announcements of new generation projects, and developer activity tracked through 3rd party databases. While the study does not forecast specific generation projects (outside of
2 See https://connectedwest.org/ and WECC’s Western Assessment of Resource Adequacy 2024 available
those planned projects included in the Benchmark Case), it allocates new generation in a way that reflects industry trends.
The study and its findings are highly sensitive to assumptions made regarding the (1) amount of resources included in each scenario; (2) their location. Notably, the study was performed in a resource-agnostic manner, so the results will generally hold true regardless of the technology type.
Scenario Description
Figure 8: Resource Deployment Scenario Overview
Key Purpose
Benchmark
Low Deployment
(+3 GW)
Reflects 2035 system conditions including known generator retirements and planned transmission upgrades
Adds 3,000 MW via the North Plains Connector 3 (NPC), modeled as a new HVDC import at Colstrip
Builds on Low with 6,000 MW of additional resources, allocated across Montana, totaling:
~2,268 MW increase over WECC base case reflection regional resource plans (not additional from study scenarios)
+3,000 MW
Medium Deployment
(+9 GW)
High Deployment
(+12 GW)
o 3 GW at Colstrip
o 3 GW at Garrison
o 1.5 GW at Broadview
o 1.5 GW at Great Falls
Adds 3,000 MW to the Medium scenario, testing the upper bounds of expansion, totaling:
o 6 GW at Colstrip
o 3 GW at Garrison
o 1.5 GW at Broadview
o 1.5 GW at Great Falls
+9,000 MW total (Low + 6,000 MW)
Establish baseline export conditions and identify preexisting constraints
Stress transfer paths and test export limits using planned infrastructure
+12,000 MW total (Medium + 3,000 MW)
Identify transmission needs for broader resource buildout across multiple zones
Identify long-term infrastructure required for full-scale clean energy export
3 The North Plains Connector (NPC) is a project planned by Grid United, which is a 3,000 MW, 525 kilovolt high voltage direct current (HVDC) transmission line, extending approximately 432 miles from substations in North Dakota to the existing Colstrip Substation in Montana. Construction is expected to begin in 2028, and the line is expected to be operational in 2032. For this study, the NPC was modeled by adding a 3 GW generator (injection) at Colstrip. The NPC was included in all three deployment scenarios
2.3 Identify Transmission Needs and Solutions
Figure 9: Transmission Solutioning Process
10-year
Planning Model
• Starting with the 2035 Benchmark
The primary study approach relied on transfer analysis, which is a study method that evaluates the ability of a transmission system to reliably accommodate the injection and subsequent transfer of generation across the transmission system. For the Montana Regional Transmission Connectivity Study, each scenario representing 3, 9, or 12 GW of incremental Montana generation was evaluated by injecting incremental power at the five Montana locations discussed above – Colstrip, Broadview, Garrison, Great Falls, and NPC – while proportionally reducing generation in neighboring sink areas, including the Pacific Northwest (i.e., PGE & BPA), Idaho, Utah, and Nevada. This approach stressed east-to-west transfers and allowed the study to evaluate the feasibility of these conditions.
Transmission Solution
• Reconductoring
• New AC Lines
• New DC Lines
• Reactive Support
Incremental Power Export
• Consistent with Scenario
To perform the study, generation was increased incrementally until system performance violated North American Electric Reliability Corporation (NERC) Transmission Planning Performance (TPL) Requirements. At that point, targeted transmission upgrades were developed and added to relieve the limiting constraint. This iterative process continued until the full generation injection target for the scenario was reached. Transmission expansion options were then re-evaluated at this point. The study was performed using the PowerGem TARA software, and all scenario models assumed the same line monitoring, contingencies, and reliability criteria used in the 2035 Benchmark.
Grid Violations
• Thermal Overloads
• Voltage Violations
Each deployment scenario was evaluated against NERC TPL-001-5 planning criteria under both normal (N-0) and single-contingency (N-1) conditions. Elements were monitored for:
• Thermal overloads: 100% of continuous rating for N-0 and emergency rating for N-1
• Voltage deviations: ±5% from nominal unless otherwise specified by utility guidance
• Voltage drop: Post-contingency voltage drops exceeding 8% were flagged
The contingency set included all applicable N-1 outages of transmission lines, transformers, and other monitored equipment ≥115 kV, with a focus on the Montana export paths and adjacent systems. Current WECC path ratings were also included as a constraint in the study.
Transmission Solution Options and Strategy
Energy Strategies considered a wide range of transmission solutions when attempting to resolve grid violations, including:
o New greenfield transmission projects
o Reconductoring or rebuilding of existing lines
o High-capacity conductors
o Storage as a transmission asset
o Powerflow control devices
o Dynamic line ratings
o Series compensation and voltage support (e.g., capacitor banks)
The primary factor in selecting technologies to meet a given need was performance – Energy Strategies considered only those solutions that were technically viable. In instances where multiple strategies could be used to meet the need, costs and other factors were considered The Study drew comparisons between the viable alternatives to inform recommendations on which are likely to be the preferred expansion option based on their cost effectiveness and ability to meet the needs of the system. The analysis considered cost, development feasibility, development timeline, and other qualitative factors influencing selection of a transmission alternative
In each case, only the minimum set of upgrades required to enable the next tranche of generation were included, consistent with a phased and modular investment strategy. This stepwise method was applied across all three deployment scenarios to ensure scalability and optionality.
2.4 Optimize Routing and Estimate Costs
Transmission Routing
All line routes of the resulting portfolios were identified by project collaborators Montara Mountain Energy and Evolved Energy Research, using their geospatial routing tool to determine the optimalcost-path for each transmission project. 4 The routing tool utilized geospatial cost surfaces to identify the most cost-effective route between two points on the grid, tailored for each portfolio.
Standard per-mile base transmission costs were drawn from the MISO per-unit cost guides and UC Berkley’s Energy Institute at Haas advanced conductor report, specific to technologies considered in the study and voltage level 5 The routing tool included additional cost factors based on terrain, land use, and the ability to use existing rights of way. To respect tribal lands, we applied a cost multiplier to areas identified as USGS Native American reservation lands so that optimal routes would avoid these areas wherever practicable. The cost surface used to route transmission lines was developed to
4 Methods were consistent with WECC EDWG, Georgia Tech and EPRI (2006), and Wu et al (2023).
5 Caron, J., & Bistline, J. E. (2023). Accelerating Transmission Expansion by Using Advanced Conductors in Existing Right-of-Way (Working Paper No. 343). Energy Institute at Haas, University of California, Berkeley. https://haas.berkeley.edu/wp-content/uploads/WP343.pdf
capture a reasonable balance between environmental and cultural sensitivities and construction cost efficiencies.
Solution Cost Estimation
Each new network upgrade recommended for the three deployment scenarios consists of substation equipment upgrades and transmission line upgrades.
Substation equipment upgrades include one or more of the following:
• Building a new substation with 6 positions
• Adding a new position to an existing substation
• Adding one or more new transformers
• Adding voltage support devices such as switched capacitor banks and reactors
• Adding new or upgrading existing series capacitors
• Adding HVDC converter stations and associated AC substation upgrades
Energy Strategies developed cost estimates using the 2025 MISO MTEP per unit costs for all substation equipment, except series capacitors which were sourced from NREL 6 7
The transmission line upgrades considered are either reconductoring an existing AC line or building a new AC or HVDC line. Montara Mountain Energy developed the cost estimate for all transmission line upgrades. These values were provided to Energy Strategies who compiled them into comprehensive transmission portfolio costs.
3. Study Results
This section presents the technical results from the study’s transmission planning analyses. For each of the resource deployment scenarios, narratives are provided that discusses the nature of system constraints encountered when pursuing the resource injection levels associated with each resource deployment portfolio. Each section also describes the upgrade options considered and developed in response, and summaries are presented of the resulting portfolios, plus their preliminary routings, line mileage, and their cost. Each transmission portfolio builds on the infrastructure of the preceding one, enabling a phased investment approach.
3.1 Low Deployment Scenario
Starting from the 2035 Benchmark, the transfer analysis found that without any network upgrades, the Montana system could only support 179 MW of injection (or imports via the NPC) before Path 8 reached its rated capacity under system-intact (N-0) conditions. This limited headroom highlights the need for upgrades to support the 3,000 MW objective of the Low Deployment Scenario.
6 “Transmission Cost Estimation Guide for MTEP25”, Midwest ISO, June 6, 2025
7 "Electrical Infrastructure Cost Model for Marine Energy Systems", Aryana Y. Nakhai, NREL, September 2023
To address this constraint, the study team evaluated a suite of transmission projects already proposed or considered in regional planning efforts. Among the most prominent was a new transmission corridor between Montana and Idaho (Path 18), a concept dating back to the 2008 Mountain States Transmission Intertie (MSTI) proposal by NorthWestern Energy. The MSTI project originally sought to relieve transmission bottlenecks, improve reliability, meet growing demand for electricity resources, provide regional energy diversity, and develop a positive economic impact.
Given that NPC introduces HVDC infrastructure to Montana for the first time, the study evaluated both AC and DC configurations for a new Montana-Idaho project Ultimately, an HVDC configuration was recommended for its greater export capability per dollar of long-run investment, though the AC configuration also performs well and remains viable. The HVDC Montana–Idaho line enhances Montana’s export potential by providing a parallel transmission path to the Colstrip system and improved access to the Idaho transmission system, including the Energy Gateway and Boardman to Hemingway (B2H) projects. In selecting the HVDC configuration of the project for this study, we observed that unlike AC lines, HVDC line converter stations can better control flows, sending power south to Idaho rather than through the constrained Path 8. By building the Montana-Idaho line with HVDC instead of AC, there is potential to avoid seven upgrade projects in the High Deployment scenario, totaling $108 M in avoided costs 8
In addition to the new Montana–Idaho line, the transmission portfolio included a set of planned Path 8 upgrades to support full injection under the Low Deployment Scenario:
• Garrison–Townsend 500 kV series capacitors upgraded to 2,000 MVA
• 800 MVAR shunt capacitor added at Garrison 500 kV
• 200 MVAR reactor added at Hot Springs 230 kV
• Colstrip–Broadview 500 kV series capacitors uprated
• Additional reactive support at Broadview, Townsend, the new P310 substation, and the NPC terminus
Together, these upgrades enabled the full 3,000 MW injection, with total export flow increasing by 2,730 MW. The full transmission portfolio is estimated to cost $3.1 billion and is summarized in Figure 10 and Figure 11 below. 9
8 The study did not assess several factors that could affect an AC–versus–DC build decision for the Montana–Idaho corridor, including HVDC supply-chain constraints, potential operational complexities of a new HVDC line, and additional reliability scenarios outside the study scope.
9 All map figures of transmission portfolios show lines upgrades only, and do not show series capacitor or reactive support upgrades
Figure 10: Low Deployment Scenario Transmission Portfolio List
3.2 Medium Deployment Scenario
For the Medium Deployment Scenario, an incremental 6 GW of generation resources were added at five locations in Montana, for a total of 9 GW from the benchmark – see Section 2.2 for details on the location of resource additions for each scenario. Transmission upgrades developed for the Low Deployment Scenario were assumed in-service for this scenario.
To accommodate the incremental 6 GW of injection, a combination of new greenfield transmission between Montana and the Northwest was identified, with different line termination points that prevent introducing new transmission bottlenecks or “common corridor” concerns It also includes reconductoring of existing transmission lines. The recommended portfolio of projects consists of six greenfield transmission lines, totaling about 1,215 miles, and reconductoring five existing lines, totaling
Figure 11: Low Deployment Scenario Transmission Portfolio Map
about 437 miles. A proposed partial reconductoring of the Taft – Dworshak line is also reflected in BPA’s Montana-to-Washington project, reflecting synergies with this expansion plan and in-flight projects already being pursued in the region
The transmission expansion for this scenario required new lines reaching into the Great Falls area. This expansion is heavily driven by assumptions made regarding the location of resources
The estimated cost of the upgrades is $7.6 billion. The upgrades are described in Figure 12 and shown in Figure 13.
All of the new lines are recommended to use advanced conductors to maximize power carrying capabilities. The portfolio of upgrades enabled the 9,000 MW of cumulative injection in the Medium Deployment Scenario and increased the export flows by another 6,660 MW over the Low Deployment Scenario, resulting in export flows of 9,243 MW.
3.3 High Deployment Scenario
The High Deployment Scenario builds upon the prior scenarios by modeling a total of 12 GW of new capacity in Montana, representing the most aggressive development trajectory considered in the study. This includes the 3 GW of injection from the North Plains Connector (NPC) modeled at Colstrip in the Low Deployment Scenario, and the 6 GW from the Medium Deployment Scenario split between 3 GW at Garrison, 1.5 GW at Broadview, and 1.5 GW at Great Falls. To reach the 12 GW target, an additional 3 GW of new generation was modeled at Colstrip, bringing total injections at that location to 6 GW. All transmission upgrades identified in the Low and Medium Deployment Scenarios were assumed to be in place for this case, forming the foundation for assessing the need for additional system reinforcements.
Major upgrades in this portfolio include a new Colstrip to Townsend HVDC line (connecting NPC and the Montana-Idaho HVDC project identified in the Low Deployment portfolio), and a new Taft-Hatwai 500-kV line The AC lines are built with advanced conductors to maximize their power throughput The new HVDC line is driven by need for efficient and more controlled transfer power from resources located at Colstrip
Figure 13: Medium Deployment Scenario Transmission Portfolio Map
3.4 Land and Routing Considerations
Conceptual routes were developed for all transmission line solutions for the Low, Medium, and High deployment scenarios using the optimal-cost-path considerations outlined in Section 2.4. Each deployment scenario routes were also analyzed under different ‘avoidance’ conditions representing
the degree of restriction placed on pathing to avoid environmental and cultural impacts. These levels of avoidance correspond to the Environmental Exclusion Categories used in Power of Place studies which have sought to enumerate and aggregate environmental land-use impacts associated with renewable development across the US. The low avoidance, medium avoidance, and high avoidance conditions correspond to Power of Place Categories 1, 2, and 3 respectively where 3 (high avoidance) is the most protective of environmental areas. Finally, certain Columbia Plateau specific datasets were additionally included in this study for more precise regional analysis. For the Washington State University composite data, we filtered to identify areas classified as high-conflict, medium-conflict, and low-conflict for each data type (conservation, farmland, ranchland). High-conflict areas were treated as Category 1, medium-conflict areas were treated as Category 2, and low-conflict areas were treated as Category 3. The combined categories are broken down as follows and are inclusive of the previous level:
• Low Avoidance: Restrictions on legally protected areas such as National Parks or National Wildlife Refuges. These geographies would be difficult or impossible to develop and are thus excluded as a baseline where no other restrictions are applied. These avoidance areas are given high-cost multipliers that effectively force any potential transmission routes to prefer alternate paths.
• Medium Avoidance: Low avoidance plus restrictions on administratively protected lands such as Critical Habitats, wetlands, and Sage Grouse Priority Habitat Management Areas. These are areas where development typically triggers additional environmental review processes or lands owned by conservation groups and NGOs. While transmission development may be possible on these lands the impacts are more significant and may also be slower and more complex.
• High Avoidance: Low and medium avoidance plus restrictions on land identified as of high conservation value determined through existing ecoregional analysis. These are geographies such as Important Bird Areas, Prime Farmland, big game habitat and corridors, and Ecologically Core Areas. This additional level of avoidance seeks to incorporate conservation priorities into development decisions even where legal or administrative protections may not exist. Without formal protections, these areas are more likely to have development, however this screen shows development under the most conservation-conscious conditions.
Of the lines in the study, the proposed low-deployment line (Montana-to-Idaho) has a relatively low technical cost multiplier, due to the route’s avoidance of mountainous terrain and access to flat agricultural, shrub and scrub land, among patches of forest. The lines in the northern part of the study area tend to have higher technical cost multipliers due to the very steep mountainous terrain, where some areas have the top 1% steepest slopes in the country. The route optimization has identified route modifications that alleviate cost, for example following existing highway, river, and transmission ROW corridors. Often these existing linear features have already identified flatter smoother areas with more ease of construction, and in many places the transmission route optimization does follow these linear features.
Figure 16 below summarizes key siting characteristics as a percent of total line miles in each portfolio/sensitivity. Existing Corridor (%) is the share of route miles that run within ~1 km of existing transmission rights-of-way, indicating opportunities to co-locate or parallel existing corridors. High Environmental Risk (%) is the share of route miles intersecting a wide variety of possible highsensitivity areas (Categories 1-3) where conservation conflicts and permitting friction are likely higher. Difficult Terrain (%) is the share of route miles crossing mountainous/steep terrain where construction techniques and costs are more challenging. High Fire Risk (%) is the share of route miles through elevated wildfire-risk landscapes, which can influence design, hardening, and operations.
Figure 16: Line Routing Land Metrics
Increasing the avoidance level did not significantly change results suggesting that there are few options for routing many lines due to the topographically constrained, mountainous environment. Accordingly, the routed lines would likely need to follow corridors like those identified in this study that parallel existing transmission lines or roads. Even so, lines still often encountered difficult terrain and high fire risk. For a full geospatial routing analysis including methods, datasets, and additional detail on environmental sensitivity—see the companion Geospatial Analysis for the Montana Regional Transmission Connectivity Study
4. Study Findings
This study highlights the growing need for strategic and coordinated transmission investment to unlock Montana’s energy potential and enhance its regional connectivity. Based on the resource deployment scenarios, transmission analysis, and environmental routing and line costing study, the findings outlined in this section aim to inform planners, policymakers, tribal representatives, and other interested stakeholders about near-, medium- and long-term transmission strategies for Montana that can help accommodate generation access and regional reliability. They are intended to help guide a phased transmission expansion approach that is resilient to uncertainty and responsive to evolving system needs and market dynamics.
Key findings for the study include:
1. Montana’s export capability is constrained and insufficient for forecasted levels of resource deployment: The Montana system is unable to accommodate the study’s resource deployment scenarios which forecast 3, 9 and 12 GW of new capacity in Montana Existing transmission paths (Path 8, Path 18, Colstrip system, etc.) are fully subscribed with negligible long-term available transfer capacity (ATC) to deliver new resources to neighboring systems and states, including BPA, PacifiCorp and Idaho Power The study considered existing transmission commitments as well as major planned regional transmission projects (and forecasted generation additions in Montana) in assessing this transmission deficiency.
2. Phased and coordinated transmission expansion can unlock Montana’s resource development potential: Expansion within Montana and new connections into neighboring states support the resource development scenarios explored in this study Strategic sequencing of upgrades allows for incremental investment over time, aligning infrastructure expansion with resource development timelines and long-term market demand. Figure 17 below, which summarizes the cumulative investment cost associated with unlocked incremental tranches of resource access, demonstrates how transmission investments can be sequenced and coordinated to accomplish a long-term goal through short-term actions.
MWs of Resource Deployment in Montana
3. The Low Resource Deployment scenario (+3 GW) is enabled with a new Montana-Idaho intertie: To accommodate the Low Deployment scenario, a transmission portfolio featuring a new HVDC line connecting the Colstrip transmission system to the Midpoint substation in Idaho was identified as the most efficient expansion strategy. The portfolio also includes series capacitor upgrades along Path 8, effectively mirroring upgrades from BPA’s planned Montanato-Washington project. This greenfield line into Idaho provides an alternative electrical path to the Pacific Northwest, access to other western markets at Midpoint, and improves system reliability. The HVDC bi-pole line was selected primarily due to its ability to avoid transmission needed in the Medium and High Resource Deployment scenarios. The Low Resource Deployment transmission portfolio costs roughly $3.1 billion and features 432 miles of HVDC transmission expansion plus capacitor upgrades on two existing lines and reactive support
4. The Medium Deployment (+9 GW) scenario requires $7.6B of additional upgrades: Including the upgrades in the Low Deployment portfolio, transmission investment in the Medium Deployment scenario totals $10.7 billion, featuring 1,647 miles of new transmission and 437 miles of reconductoring projects. Major upgrades in this portfolio include a new Garrison-Little Goose 500-kV line, a new 500-kV system through Great Falls, and a new TaftBell-Ashe 500-kV line All of these lines are built with advanced conductors to maximize their power throughput and use of the right-of-way. Proposed reconductoring of the Taft – Dworshak line is also reflected in BPA’s Montana-to-Washington project Expansion into the Great Falls area is heavily driven by assumptions made regarding the location of resources The portfolio includes multiple greenfield AC corridors between Montana and Pacific Northwest, with different line termination points, to prevent any transmission bottlenecks or “common corridor” concerns
5. The transmission portfolio for the High Deployment scenario (+12 GW) represents a longterm expansion plan for the state: Building upon upgrades in the Low and Medium deployment scenarios, the transmission portfolio for the High Deployment scenario totals $13.9 billion, featuring 2,021 miles of new transmission and 467 miles of reconductoring projects. Major upgrades in this portfolio include a new Colstrip to Townsend HVDC line, and a new TaftHatwai 500-kV line The AC lines are built with advanced conductors to maximize their power throughput. The new HVDC line is driven by need for efficient and more controlled transfer
power from additional resources located at Colstrip. Assumptions about the incremental 3 GW of capacity at Colstrip drive this portion of the transmission expansion. Ultimately, this transmission portfolio should be considered a long-term expansion plan and would be subject to revaluation through many planning processes.
6. The HVDC line between Montana and Idaho could help avoid longer-term upgrades at higher resource deployment levels: The Montana-Idaho line in the Low Deployment scenario is foundational to increasing Montana export capacity as it provides an alternative and redundant route between Montana and other western markets, including the Pacific Northwest An HVDC line, while having slightly higher upfront costs, may provide significant cost reductions on future transmission infrastructure needed at higher resource deployment levels. This is because, unlike AC lines, HVDC line converter stations can better control flows, sending power south to Idaho and its highly connected grid rather than through the constrained Path 8 Avoided transmission infrastructure due to constructing DC instead of AC includes the Garrison-Taft 500kV #1 line reconductor and additional reactive support. By building the Montana-Idaho line with HVDC instead of AC, we forecast the potential to avoid seven projects in the High Deployment scenario, totaling $108M in avoided costs. An HVDC line on the Montana-Idaho corridor also has synergies with large-scale needs from resources injecting at Colstrip or from the Eastern Interconnection
Figure 18: Comparison of Total Portfolio Costs Assuming AC vs. DC on Montana-Idaho Corridor
7. The transmission portfolios increase the connectivity of the Western grid: The transmission expansion portfolios identified are strategically aligned with several major projects currently planned or under construction across the West. By linking these new Montana upgrades with recently completed and anticipated projects including Gateway West, Boardman-to-Hemmingway, SWIP North, and North Plains Connector these portfolios strengthen the regional transmission network. The resulting configurations enable Montana resources to access a broader set of markets with the added benefit that Montana can also source electricity from other markets. Collectively, the portfolio investments establish a new high-voltage backbone from North Dakota to Washington, increasing the West’s ability to integrate resources and loads across the region
8. A diverse set of transmission technologies improves portfolio efficiency and flexibility: The study found that deploying a mix of transmission technologies enhanced the performance, efficiency, and flexibility of the transmission portfolios. As summarized in Figure 20 below, the transmission solutions adopted in each scenario varied, with higher deployment scenarios leveraging a broader range of technologies to address system needs.
Figure 19: Transmission Portfolio Integration with Planned Projects
Figure 20: Summary of Technologies Adopted by Portfolio
Where feasible, existing rights-of-way were prioritized for reconductoring or rebuilding to minimize land use and permitting hurdles. In some cases, new AC and HVDC corridors were added to create parallel paths, to avoid creating new reliability issues, or to connect new portions of the system. Advanced conductors and power flow control devices were introduced in higher build scenarios to optimize transfer capabilities and reduce congestion impacts. Finally, storage-as-transmission and dynamic line ratings were evaluated but ultimately excluded from the portfolios. These technologies were deemed ineffective in providing sufficient incremental capacity to support Montana’s needs under the study’s assumptions. In the case of storage, operations in charging or discharging mode were unable to increase the transfer capability of the system – a requirement for delivering the resource portfolios. Since the most limiting grid conditions were studied, dynamic line ratings also did not offer any capacity increase.
9. Environmentally and culturally sensitive areas can be reduced and avoided, but impacts cannot be avoided altogether: Using least cost path analysis, we identified low, medium, and high impact avoidance scenarios. Putting maximum emphasis on avoiding environmentally sensitive areas increases cost by ~6%, but helps avoid 15% of sensitive areas. Similarly, cost increases for lines traversing mountainous terrain can be reduced, often by following linear features like rivers and roads, but they cannot be eliminated altogether. Using least cost path analysis, this study identified line routes that avoid some but not all areas of difficult terrain, wildfire risk, and environmental and cultural sensitivity.
10. Much work remains to improve consideration of tribal lands in transmission planning: The study’s line routing methods took into account Native American Indian reservation lands treating these culturally sensitive areas as avoidance areas. Figure 21 shows the proximity of this study’s high deployment scenario to tribal reservations.
The study did not introduce any strict constraints to avoid reservations, nor did the study’s authors have datasets regarding sensitive tribal lands or cultural resources that may be outside of reservation boundaries. For these reasons, and others, the study’s results offer only a preliminary look at how tribal lands interface with the proposed modeled transmission projects. Further engagement with tribal representatives is needed to develop better understanding and to develop corresponding data regarding preferred corridors for avoidance of cultural sensitivities in this region.
Study Limitations & Additional Considerations
Readers should recognize that this study, like all transmission assessments, has certain technical limitations that add context to the findings and analysis covered in this report. Several of these limitations are covered below.
Remedial Action Schemes (RAS)
The study did not assume expanding the Colstrip/MT RAS to make additional resources deliverable under N-1 conditions. Our objective was to identify transmission that can reliably transfer resources without curtailment during single contingencies, so those resources can count for regional resource adequacy and be relied on during times of system stress (including grid stress). A corollary is that new transmission reduces reliance on RAS. We did not perform transient/dynamic stability studies (e.g., oscillatory stability, voltage recovery, fault ride-through); so, these results should be interpreted as steady-state power-flow findings.
Transmission Scope
As outlined in Appendix A, the portfolios do not identify all transmission that may be needed over the planning horizon and may therefore understate total investment. We did not evaluate upgrades downstream of line termini (e.g., internal reinforcements in receiving systems) or focus on local T&D
Figure 21: Tribal Reservation Lands and High Deployment Transmission Portfolio
constraints (distribution, local reliability criteria, protection settings). The study excludes lower-voltage facilities, local systems, and generator tie-lines, and it does not model expanded demand response/behind-the-meter storage as substitutes for transmission or perform detailed market-design analyses.
Directional Emphasis
The analysis did not evaluate delivering resources into Montana; routing and transfer assumptions emphasized deliveries from Montana to the PNW and beyond, which influences the distribution of modeled benefits and constraints. While not evaluated in this study, each of the transmission expansion phases would likely provide substantial improvements in grid stability and reliability for Montana customers, as well as providing transfer capacity for economic needs such as new data center and industrial facilities.
Data and Siting Uncertainties
Corridor expansion versus reconductoring/rebuild was assessed with imperfect information. The geospatial screening and cost surfaces simplify real-world constraints; permitting, environmental, cultural, and land-use outcomes may differ in detailed development. Results are sensitive to 2035 Benchmark resource and transmission assumptions, which are outlined in detail in Appendix A Different siting, timing, or policy pathways could change optimal routes and benefits.
5. Appendix A
Study Scope
This study focuses on Montana’s high-voltage transmission system (>200 kV) and its primary interfaces with the Pacific Northwest and Idaho. Specifically, the analysis covers:
• The Colstrip Transmission System
• WECC Path 8 (Montana–Northwest)
• WECC Path 18 (Montana–Idaho)
• BPA’s Eastern Intertie
• BPA’s West of Hatwai flowgate
• Other in-state transmission facilities above 200 kV
The study does not evaluate:
o Transmission in Montana on inter-state seams that is less than 200-kV
o Local transmission issues on Northwestern’s system
o Generator interties required to interconnect the generation explored in the study
o WECC Path 80, which connects Montana and Wyoming 10
o WECC Path 83 (Montana-Alberta)
o Other upgrades necessary in Idaho, Oregon, or Washington necessary to deliver resources to load centers in the Pacific Northwest
Montana Transmission Intertie Definitions
The two primary WECC paths and their definition and current transfer limits for these areas are summarized below.
• Broadview-Garrison 500kV #1
• Broadview-Garrison 500kV #2
• Mill Creek-Garrison 230kV
• Mill Creek-Anaconda 230kV
• Ovando-Garrison 230kV
• Rattlesnake-Dixon 230kV
• Rattlesnake-Garrison 230kV
• Kerr-Kalispell 115kV
• Thompson Falls-Burke 115kV
East-to-West: 2,200 MW
West-to-East: 1,350 MW
10 Due to the relatively small size of energy markets in Wyoming, increasing Path 80 capacity was not a focus of the study but is something that would similarly support Montana reliability and import/export capability.
Figure 22: WECC Path 8 & 18 Elements and Ratings
Path
Elements
• Crow Creek-Burke 115kV
• Placid Lake-Hot Springs 230kV
Rating
18
• Dillon Salmon – Big Grassy 161 kV
• Peterson Flats – AMPS 230 kV
Transmission Included in Benchmark Case
Figure 23: Planned Transmission Projects
Project
Name
Bell-Boundary 230kV Line #3 Upgrade
Northern Mid-Columbia Area Replacement
North Plains Connector
Great Falls Eastside tie-in
Three Rivers 161/100kV Transformer Upgrade
Trident-Belgrade West 50kV Cutover to 161kV
Bitterroot Initiative - Hamilton Heights Banks
Bitterroot Initiative - South Side Capacitor
Helena Forestvale Substation
Loco Mountain Substation
North-to-South: 383 MW
South-to-North: 256 MW
Ownership
BPA
BPA
NPC
NWE
NWE
NWE
NWE
NWE
NWE
NWE
Gateway West (Segments D3, E and E8) PacifiCorp
Longhorn to Hemingway (Formerly Boardman to Hemingway) PacifiCorp/ Idaho Power
Add a second 500/345kV transformer to Midpoint station
Add Kinport – Midpoint 345kV Series Capacitor
Hemingway - Bowmont #2 230 kV line
Hubbard - Bowmont 230 kV line
Upgrade Hemingway – Midpoint 500kV series capacitor
Idaho Power
Idaho Power
Idaho Power
Idaho Power
Idaho Power
Burns 500kV Reactor Station Replacement PacifiCorp
Ownership
Corral (Full Circle) to Grassland Annex (Apex) 500kV Line PacifiCorp
Corral (Full Circle) to Snow Goose 500kV Line PacifiCorp
Grassland Annex (Apex) to B2H Tap (Maverick) Substation 500kV Line PacifiCorp
Walla Walla Add 3rd 230/69kV Transformer PacifiCorp
Garden Springs Station Avista
Lolo Transformer Replacement Avista
SWIP-North LS Power
Montana Generation Included in Benchmark Case
Figure 24: Planned and Anticipated Generation Included in Benchmark Case
Broadview
Haymaker
Meadowlark
