The Strategic Evolution Of The North American Electric Grid: A

The Strategic Evolution of the North American Electric Grid: A Financial and Regulatory Analysis of FERC Order No. 1920

The United States electric transmission system stands at a critical juncture, transitioning from a reactive, short-term planning paradigm toward a proactive, multi-decadal strategic framework. This evolution is driven by the Federal Energy Regulatory Commission (FERC) and its issuance of Order No. 1920, a comprehensive final rule titled “Building for the Future Through Electric Regional Transmission Planning and Cost Allocation”. This regulatory milestone is widely characterized as the most significant reform in transmission policy in over a decade, addressing systemic deficiencies that have historically led to inefficient, piecemeal grid expansion. By mandating a twenty-year planning horizon and requiring the quantification of “multi-value” benefits, Order 1920 fundamentally reconstructs the economic and technical “engine” of utility investment. For financial stakeholders and advisory firms such as Environmental Resources Management (ERM), this shift provides a stabilized capital pipeline, transforming the risk profile of high-voltage infrastructure projects and establishing a more predictable environment for long-term strategic deployment.
The Regulatory Imperative and the Failure of Reactive Planning
The issuance of Order 1920 was necessitated by a finding under Section 206 of the Federal Power Act (FPA) that existing regional transmission planning and cost allocation processes were unjust, unreasonable, and unduly discriminatory. For years, the North American grid has relied on “just-in-time” planning, which focused primarily on immediate reliability needs and short-term economic congestion. This approach was governed largely by Order No. 1000, which, while intending to foster regional cooperation, ultimately failed to produce the comprehensive infrastructure required to support a modernizing energy mix.
The deficiencies identified by FERC include a failure to account for long-term trends such as the rapid retirement of coal-fired generation, the surge in renewable energy integration, and the unprecedented growth in electricity demand from data centers and economy-wide electrification. Under the previous regime, transmission providers often ignored these “known causes” of future system needs, leading to fragmented development and higher overall costs for retail ratepayers. Order 1920 seeks to remedy this by forcing a holistic view of the grid’s requirements over a minimum twenty-year horizon.
Comparative Regulatory Evolution of Transmission Planning
Regulation
Year
Primary Focus
Key Mechanism
Outcome/Limitation
Order No. 888
1996
Open Access
Non-discriminatory access to transmission lines.
Established the foundation for wholesale competition.
Order No. 890
2007
Transparency
Standardized planning processes and coordination.
Improved local planning transparency.
Order No. 1000
2011
Regionalism
Required regional planning and interregional coordination.
Resulted in piecemeal, short-term reliability projects.
Order No. 1920
2024
Long-Term Strategic
20-year horizon, multi-value benefits, ex ante cost allocation.
Aims for proactive, efficient, and low-cost grid expansion.

The Twenty-Year Planning Horizon: Methodology and Scenario Development
The central pillar of Order 1920 is the requirement for all public utility transmission providers to conduct Long-Term Regional Transmission Planning (LTRTP) at least every five years. This mandate compels utilities and Regional Transmission Organizations (RTOs) to look twenty years into the future to identify “Long-Term Transmission Needs”. This forward-looking assessment is not a singular forecast but a multi-scenario analysis designed to capture a range of plausible futures.
Transmission providers must develop at least three distinct long-term scenarios. These scenarios must be “plausible and diverse,” ensuring that the resulting plans are resilient to different economic and policy outcomes. The order specifies seven categories of factors that must be integrated into these scenarios to ensure they reflect the reality of the changing energy landscape.
Mandatory Scenario Factors
Factor Category
Description of Requirement
Strategic Implication
Federal and State Laws
Incorporation of clean energy standards and decarbonization mandates.
Ensures grid development supports legislative targets.
Electrification Trends
Laws and regulations affecting EV adoption and heat pump deployment.
Anticipates massive load shifts and demand spikes.
Integrated Resource Plans
Alignment with state-approved utility supply obligations.
Harmonizes local utility planning with regional grid needs.
Fuel and Tech Trends
Projections of fuel costs and the performance of storage and renewables.
Reflects the falling cost of clean energy and storage.
Resource Retirements
Accounting for legislatively mandated or economic closures.
Prevents reliability gaps as base-load plants retire.
Interconnection Queues
Analysis of existing and withdrawn generator requests.
Identifies systemic bottlenecks in generation entry.
Corporate Goals
Consideration of utility commitments and non-binding policy goals.
Note: 1920-A struck the requirement for corporate-only goals.

In addition to these scenarios, providers must apply at least one “sensitivity” analysis to each scenario. Sensitivities are designed to capture “uncertain operational outcomes,” such as extreme weather events, cyber-attacks, or significant fuel price volatility. This ensures that the selected transmission facilities are not just efficient under normal conditions but are also capable of maintaining reliability during high-impact, low-frequency events.
The Multi-Value Benefit Framework: Redefining Grid Value
The financial and operational viability of new transmission lines often hinges on how their benefits are calculated. Historically, projects were often siloed into reliability, economic, or policy categories, frequently failing to meet the selection criteria of any single category despite providing significant cumulative value. Order 1920 addresses this by requiring the measurement of a set of seven mandatory benefits for all proposed long-term regional transmission facilities.
This multi-value approach allows a project’s total utility to be recognized, which in turn facilitates fairer cost allocation. By quantifying reliability, economic, and policy-driven benefits together, the order ensures that states and ratepayers pay only in proportion to the total value they receive.
The Seven Mandatory Benefit Metrics
The quantification of these benefits represents the technical “engine” that drives the selection of new transmission infrastructure.
Avoided or Deferred Reliability Transmission Facilities and Aging Infrastructure Replacement: Comprehensive planning over a 20-year horizon identifies where a large-scale regional line can replace multiple, more expensive local upgrades. It also accounts for the benefits of “right-sizing” infrastructure that is already scheduled for replacement due to age.
Reduced Loss of Load Probability (LOLP) or Reduced Planning Reserve Margin (PRM): This benefit measures the grid’s increased ability to avoid blackouts. By enhancing regional connectivity, utilities can access a more diverse pool of generation, which reduces the amount of expensive backup generation capacity they must maintain.
Production Cost Savings: This metric captures the reduction in fuel and variable costs achieved by dispatching lower-cost generation resources. Long-term transmission reduces congestion that would otherwise force the grid to run expensive, high-emission peaker plants.
Reduced Transmission Energy Losses: Operating the grid more efficiently reduces the amount of power lost as heat during transmission. This is particularly relevant as power is increasingly generated in remote, wind-rich or sun-rich areas far from demand centers.
Reduced Congestion Due to Transmission Outages: A robustly planned grid has the redundancy to reroute power when lines are down for maintenance or due to failures, minimizing the economic hit of localized price spikes.
Mitigation of Extreme Weather Events and Unexpected System Conditions: This benefit quantifies the “insurance value” of the grid during events like extreme heatwaves or cold snaps. It explicitly captures savings from proactive planning that prevents systemic failure under stress.
Capacity Cost Benefits from Reduced Peak Energy Losses: By reducing energy losses specifically during periods of peak consumption, grid operators avoid the need to procure as much new generation capacity, providing significant long-term capital savings.
Transmission providers have the flexibility to define and consider additional benefits beyond these seven, provided they are applied in a way that is “roughly commensurate” with estimated benefits.
The Finance Connection: Stabilizing the Capital Pipeline
For the financial sector and firms like ERM, the most profound impact of Order 1920 is the stabilization of the “capital pipeline” for high-voltage transmission. Large-scale infrastructure projects are notoriously difficult to finance due to long development timelines (often 10-15 years), complex permitting, and the constant risk that a project will be canceled before cost recovery is secured. Order 1920 provides a structured, multi-decade roadmap that reduces this uncertainty.
Predictability and Reduced Investment Risk
The 20-year mandate ensures that transmission needs are identified well in advance of their realization, allowing developers to align their financing, labor, and supply chain strategies with a clear regulatory pipeline.
Ex Ante Cost Allocation: By requiring cost allocation methods to be established before projects are selected, FERC provides investors with certainty regarding how a project will be paid for, which is a prerequisite for reaching a Final Investment Decision (FID).
Revenue Visibility: For infrastructure firms, the move to 5-year cyclical planning cycles with 20-year horizons provides a consistent stream of projects. This visibility allows for better management of “human capital” and reduces the strategic vulnerability caused by workforce shortages in the engineering and construction sectors.
Credit Profile Stability: Utilities that focus on transmission—often viewed as a lower-risk, regulated business—can maintain stronger credit ratings from agencies like Moody’s and S&P. Predictable cash flows from regional transmission expansion support the “low-risk business model” that large energy infrastructure companies strive for.
Strategic Implications for Capital Allocation
The stabilization of this pipeline creates a more attractive environment for private equity and institutional investors. The “Voluntary Funding” mechanism in Order 1920 is particularly notable here, as it allows third parties to participate directly in bridging the funding gap for projects that might not otherwise meet the strict regional selection criteria.
Financial Metric
Impact of Order 1920
Rationale
Cost of Capital
Potentially Lower
Reduced regulatory and cost-recovery risk through ex ante allocation.
Capex Predictability
Significantly Higher
20-year horizons allow for long-term equipment and labor contracting.
Project Valuation
More Robust
Inclusion of 7 mandatory benefits captures total economic utility.
Liquidity Risk
Managed
Cyclical 5-year updates prevent “boom and bust” development cycles.

Voluntary Funding and the Role of State Agreements
One of the most innovative and strategically important aspects of Order 1920 is the “Voluntary Funding” mechanism. This provision allows relevant state entities and “interconnection customers” to voluntarily fund all or a portion of a transmission facility’s cost.
This mechanism serves as a critical “safety valve” for projects that may be highly desirable for certain states—perhaps to meet specific clean energy goals or to support a new industrial cluster—but which do not provide enough region-wide benefit to be selected through the standard cost-benefit analysis.
The Benefit-to-Cost Ratio (BCR) Adjustment
In many planning regions, a project must meet a specific Benefit-to-Cost Ratio (e.g., 1.25) to be selected for regional cost allocation. Voluntary funding can be used to lower the effective cost of the project in the eyes of the regional planner, thereby raising its BCR and enabling its selection.
For example, if a $100 million project provides $100 million in benefits, its BCR is 1.0, which falls below the 1.25 selection threshold. If a state or a private entity (such as a large tech company building a data center) contributes $20 million in voluntary funding, the cost to the region drops to $80 million. The resulting BCR of 1.25 ($100M / $80M) allows the project to move forward into the regional plan.
This flexibility is essential for “multi-value” projects that have significant “externalities” not captured by the seven mandatory benefits, such as local job creation or state-specific environmental targets.
The State Engagement Period
To facilitate these complex negotiations, Order 1920 establishes a formal “Engagement Period”. Transmission providers must offer a forum for state regulators to discuss and negotiate cost allocation methods for a minimum of six months. Order 1920-A extended this, allowing for an additional six-month extension at the request of state regulators to ensure “fulsome discussions” and political consensus.
This process respects state sovereignty by allowing states to lead the development of their own cost allocation methods, rather than having them imposed by a federal agency or an RTO.
ERM’s Role as a Strategic Agent in the Transmission Landscape
For a global sustainability consultancy like ERM, Order 1920 creates a massive increase in demand for strategic transformation and technical delivery services. The order’s requirements for 20-year scenario modeling and multi-benefit quantification are highly complex and require the specialized expertise that ERM provides across the renewables and power sectors.
Permitting, Siting, and Stakeholder Engagement
Transmission expansion is frequently halted not by a lack of capital, but by “permitting bottlenecks” and community opposition. ERM’s role in “simplifying permitting and licensing” is critical in this new environment.
Environmental and Social Impact Assessments (ESIA): ERM conducts the deep technical studies required to enable effective routing of lines through complex biological, cultural, and land-use areas.
Conflict Mitigation: By managing stakeholder engagement early in the process—now mandated by Order 1920’s transparency requirements—ERM helps prevent the costly project delays that erode investor returns.
Scenario Visualization: ERM uses high-spatial-resolution modeling to help network operators visualize how different decarbonization pathways will physically manifest on the landscape, allowing for more “informed investment decisions”.
Decarbonization and Energy Transition Strategy
As the world drives toward a net-zero future, ERM helps utilities and corporate clients “rethink how energy is sourced, financed, transformed, and used”. Order 1920 is the regulatory implementation of this transition. ERM supports clients by:
Developing “net-zero action plans” that align with the 20-year scenarios required by the order.
Assessing the “techno-economic” feasibility of new technologies, such as green hydrogen links or long-duration storage, that may be integrated into the long-term grid.
Navigating “novel technology funding” and deployment support, including the coordination of voluntary funding and state-backed incentives.
Regional Perspectives and Implementation Status
The roll-out of Order 1920 is occurring at different speeds across the various RTOs and ISOs. Each region faces unique geographical, political, and technical challenges.
MISO: The First Mover in Long-Range Planning
MISO is widely considered a leader in this space, having established its “Long-Range Transmission Planning” (LRTP) framework prior to the issuance of Order 1920.
Seven-Step Process: MISO utilizes a well-documented framework that includes scenario development, needs assessment, and project selection based on reliability and economic analysis.
Tranche 2.1: This upcoming $30 billion portfolio is expected to trigger a massive surge in demand for extra-high-voltage (EHV) equipment, including transformers and shunt reactors.
Voluntary Funding Projections: MISO has already proposed a process allowing Relevant State Entities (RSEs) and Interconnection Customers (ICs) to voluntarily fund solutions that don’t meet standard selection criteria.
### PJM: Complexity in Multi-Jurisdictional Planning
PJM, serving 14 different jurisdictions with disparate policy goals, faces a more complex task in achieving consensus.
Proactive Approach: PJM’s proposed protocol transitions away from “reactive” planning toward a holistic, long-term approach that accounts for generation deactivations and data center load growth.
Right-Sizing: PJM is placing a strong emphasis on working with transmission owners to “right-size” existing facilities that are due for replacement, ensuring they are upgraded to meet 20-year needs more cost-effectively.
ISO-NE and the NorthernGrid
ISO New England has leveraged its “Longer-Term Transmission Planning” (LTTP) framework, while NorthernGrid is implementing a “least regrets” approach that requires a 1.25 BCR across all studied scenarios. These regions highlight the order’s “maximum flexibility,” allowing for “regionally appropriate solutions” within the broader federal mandate.
Technological Integration: ATTs and “Right-Sizing”
To ensure that the 20-year plan does not result in unnecessary over-building, Order 1920 mandates the consideration of “Alternative Transmission Technologies” (ATTs) and the “right-sizing” of replacement facilities.
The Role of Advanced Technologies
Transmission providers must demonstrate they have considered four specific ATTs in their regional plans:
Dynamic Line Ratings (DLR): Sensors that update the thermal rating of a line based on real-time weather conditions, allowing for more power flow when it’s cool or windy.
Advanced Power Flow Control: Devices that reroute power away from congested lines toward underutilized parts of the grid.
Transmission Switching: The use of software and advanced scheduling to adjust power flow and avoid congestion.
Advanced Conductors: High-performance materials that can carry significantly more power than traditional steel-core lines, often used to “right-size” existing corridors.
These technologies are “multi-value” in nature because they can often provide reliability and economic benefits at a fraction of the cost of building a new greenfield line.
The Right-Sizing Mandate
The order requires providers to identify opportunities to “right-size” local transmission projects that are set to be replaced over the next 10 years. This involves increasing the voltage or transfer capability of an existing line during a scheduled replacement, which is far more efficient than building a new line in a different corridor years later.
To incentivize this, FERC provided a federal “right of first refusal” (ROFR) for transmission providers to develop these right-sized facilities, which provides a significant strategic advantage to incumbent utilities.
Economic and Legal Risks: Dissent and the Major Questions Doctrine
Despite the broad support from clean energy advocates and many state regulators, Order 1920 remains controversial. The order was approved by a 2-1 vote, with Commissioner Mark Christie issuing a lengthy and detailed dissent.
The Core Arguments of the Dissent
Commissioner Christie argued that the order represents a “shell game” designed to socialize the costs of certain states’ climate and renewable energy goals across all consumers in a region.
Statutory Authority: The dissent asserts that FERC has exceeded its authority under the FPA, moving beyond the “just and reasonable” rate mandate to effectively dictate national energy policy.
Major Questions Doctrine: Opponents argue that a trillion-dollar transformation of the grid is a “major question” that requires explicit authorization from Congress, which has not been granted.
Cost Shift Concerns: There is significant concern that ratepayers in “traditional” energy states will be forced to pay for transmission lines that primarily serve the “green energy” policy goals of neighboring states or large corporate buyers.
The Regulatory Counter-Response
The majority, including Chairman Willie Phillips, argued that the order is a “reliability imperative” and an “affordability imperative”. They maintain that failing to plan for the inevitable resource shift and extreme weather events will lead to “immeasurable” costs for consumers through rolling blackouts and “just-in-time” emergency upgrades. The “cost of continued inaction,” they argue, is the greater risk.
Strategic Outlook: The Grid of 2045
The implementation of Order 1920 marks the beginning of a transformative era for the North American power system. For finance professionals, utility executives, and consultants at ERM, the order provides a high-stakes, long-term framework for growth.
Stable Capital Pipeline: The 20-year horizon and cyclical planning turn transmission from a “reactive” cost center into a “strategic” growth engine for utilities.
New Financing Models: The combination of ex ante regional cost allocation and voluntary funding from states and private entities will drive more creative and robust capital structures for major lines.
Technological Inflection: The mandated consideration of ATTs will foster a “smarter” grid, creating new markets for grid-enhancing technologies and the firms that deploy them.
permitting as a Gating Factor: As the planning process becomes more robust, the primary bottleneck will shift even further toward permitting and stakeholder engagement, making firms that can navigate these “biological, cultural, and land-use challenges” more central than ever.
Order 1920 is not just a “dry” regulatory rule; it is the fundamental “engine” of the energy transition. It bridges the gap between ambitious climate goals and the physical reality of the wires and towers required to achieve them. For those tasked with managing this transition—be they agents for ERM’s clients, financial analysts, or grid operators—the rule offers a more secure and strategic platform for building the future of electricity in America.
Works cited
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