As the electric power industry nears the end of 2025, the initial shockwaves from the Federal Energy Regulatory Commission’s (FERC) Order No. 1920 have mostly faded, replaced by the challenging, bureaucratic reality of compliance. When the order was finalized in May 2024, supporters praised it as the “magnum opus” of Chairman Phillips’ tenure and the most significant reform to transmission planning in nearly two decades. The rule aimed to break the cycle of reactive, quick-fix infrastructure solutions by requiring a twenty-year forward-looking planning horizon, comprehensive scenario modeling, and an unprecedented level of state participation in cost allocation. Eighteen months later, the dust has settled, and the industry faces a key question: Is this regulatory behemoth truly leading to projects in the ground, or has it simply created a more elaborate layer of administrative procedure?
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The outlook for late 2025 is complex and somewhat mixed. While legal challenges to the rule remain unified and unresolved in federal courts, the operations of the nation’s Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) have fundamentally accelerated. Transmission providers are no longer debating long-term planning theories; they are actively restructuring their engineering departments and stakeholder processes to meet strict compliance deadlines set for this year. Yet, this shift in planning approach clashes sharply with the current operational realities of the grid. The slow pace of twenty-year regional planning proves inadequate to address the urgent demands posed by the surge in artificial intelligence and the increased data center load, shaping the energy landscape. For utility leaders and middle managers navigating this environment, Order 1920 has successfully shifted the conversation, but its capacity to modify the physical grid on a meaningful timeline remains uncertain and increasingly fraught with concern.
The Legal Shadow and the Post-Chevron Regulatory Environment
To understand the current state of implementation, one must first address the legal threat hanging over the entire framework. The implementation of Order 1920 is progressing in a particularly fragile legal environment, heavily influenced by the Supreme Court’s 2024 decision in Loper Bright Enterprises v. Raimondo, which effectively ended Chevron deference. In earlier regulatory eras, FERC could rely on judicial deference to its technical expertise in interpreting the Federal Power Act. In the post-Chevron era, that safety net is gone. The challenges currently pending before the U.S. Court of Appeals for the Fourth Circuit are not just procedural disputes; they challenge the core of FERC’s authority to require what critics call “major questions” of economic and energy policy under the guise of technical ratemaking.
Despite this uncertainty, the industry has largely adopted a “compliance-first” approach. Major Investor-Owned Utilities (IOUs) and RTOs have assessed that the risk of falling behind on grid reliability outweighs the chance that the rule will be vacated or remanded. As a result, the compliance filings submitted throughout the summer and fall of 2025 have been thorough but noticeably cautious. Many transmission providers have crafted their filings with severability in mind, designing planning processes that can withstand even if specific parts of Order 1920 are struck down. This legal balancing act has fostered a cautious, attorney-driven culture within planning committees this year. Engineers are eager to model the new reality, but legal teams are carefully limiting how those models are described in federal filings to prevent giving potential litigants ammunition to argue that the rule forces consumers to fund aspirational public policy goals rather than strictly necessary transmission services.
The Revolution in Scenario Planning and Benefit Metrics
The most tangible operational impact of Order 1920 has been the enforced maturity of scenario planning. Before the rule, many regions relied on deterministic planning models based on a “business as usual” trajectory, with perhaps one or two sensitivity cases. The 1920s order to plan for a 20-year horizon using at least three different scenarios has driven a significant expansion of data inputs. Planners are now required to include specific “benefits” in their economic analysis, which covers not just production cost savings but also the mitigation of extreme weather events, reduced transmission energy losses, and the capacity-cost advantages of delaying generation entry.
This shift has been especially challenging yet productive in multi-state RTOs like PJM Interconnection and the Midcontinent ISO (MISO). In 2025, stakeholders have dedicated thousands of hours discussing the inputs for these scenarios. The main disagreements are no longer about whether to plan but about the assumptions concerning corporate clean energy procurement and electrification rates. For instance, debates this year have centered on how to weigh the “corporate goal” inputs—should we assume 100% of corporate sustainability targets will be achieved, or use a realization rate? These technical assumptions can alter the “benefits” calculation by billions of dollars.
Furthermore, the need to quantify the “mitigation of extreme weather events” has compelled utilities to incorporate meteorological data into power flow models in ways that were previously considered academic just three years ago. The Winter Storm Uri and Elliott events are no longer viewed as anomalies but as standard stress tests against a twenty-year baseline. This means that proposed transmission projects are being justified not only by their capacity to ease economic congestion during a mild spring day but also by their potential to prevent load shedding during a 1-in-50-year polar vortex. This signifies a fundamental incorporation of resilience into the transmission asset base, a development that, although costly, offers a much stronger and defensible position for rate recovery before state commissions.
State Engagement: From Adversaries to Architects
Perhaps the most feared aspect of Order 1920 was the required six-month engagement with state entities on cost allocation and benefit criteria. Many industry observers predicted this would cause gridlock, envisioning a scenario in which states with different energy policies—such as a coal-heavy state and a wind-focused state—would stall the process. However, the past year’s experience shows a surprising shift in state-federal cooperation. Confronted with the clear realities of increasing load growth and reliability concerns, state regulators have engaged more productively than expected.
The “Committee of States” models emerging in regions such as the Southwest Power Pool (SPP) and MISO have shifted the dynamic from adversarial litigation to preemptive collaboration. By requiring states to agree on the “benefits” before drawing a specific line on the map, Order 1920 has somewhat depoliticized the initial planning stages. In 2025, we see states negotiating the definition of benefits rather than fighting over the final bill. For example, a fossil-heavy state might agree to a transmission expansion plan if the “benefits” metrics emphasize resource adequacy and deliverability during peak load, rather than only focusing on decarbonization. This approach has enabled RTOs to develop “hybrid” benefit portfolios that appeal to various political groups. While this consensus-building process is slow and has likely contributed to the “meeting fatigue” many middle managers reported this year, it seems to be laying the groundwork for a more sustainable cost allocation method that is less prone to litigation later on.
The Right of First Refusal and the Rise of the Joint Venture
A key and debated part of Order 1920 was the reintroduction of a limited federal Right of First Refusal (ROFR) for existing utilities, provided they form joint ownership arrangements with unrelated partners. This clause aimed to encourage cooperation and reduce litigation related to competitive bidding. By late 2025, this clause has led to a surge of new business models and strategic alliances. We see a consolidation of “incumbent advantages” as major utilities move quickly to establish Joint Ventures (JVs) to secure this ROFR benefit.
This development has met sharp criticism from independent transmission developers, who contend that Order 1920 has effectively closed the door on competition in favor of project certainty. The “unaffiliated partner” requirement is being satisfied, but often through partnerships that do little to challenge the status quo. For instance, we are seeing large IOUs teaming up with small, geographically separate entities or minority-owned firms to fulfill the regulatory requirement, thereby shielding large capital projects from the competitive bidding process mandated by FERC Order 1000.
From a utility management perspective, this is a logical response to the incentives FERC established. The competitive solicitation processes of the 2010s were often criticized for delaying development and fostering adversarial relationships between developers and existing transmission owners. By using the conditional ROFR, utilities argue that they can complete projects more quickly. They claim that joint ventures enable smoother integration into current rights-of-way and better coordination with local distribution planning. Whether this truly lowers costs for consumers remains uncertain, but it has definitely sped up the initial stages of development for several major interregional projects announced this year, as the threat of a multi-year competitive solicitation process has been eliminated.
The Data Center Collision: The Gap Between Planning and Reality
While Order 1920 has successfully overhauled the long-term planning system, it has also revealed a significant short-term gap. The rule aims to optimize the grid for 2045, but the grid is struggling under the pressure of 2026. The surge in data center demand—driven by the move into generative AI—has caused a demand shock that the orderly, twenty-year process of Order 1920 was not built to handle. Throughout 2025, utilities in Northern Virginia, Ohio, and the Pacific Northwest have reported load ramp rates that are unprecedented in history, with gigawatt-scale requests appearing in months rather than years.
This has created a split in utility strategy. On the one hand, planning departments are diligently meeting their Order 1920 compliance requirements, modeling 20-year scenarios, and working with states. On a parallel, faster track, they are using “immediate need” or “reliability exemptions” to push through upgrades that can’t wait for the end of a regional planning cycle. This tension is apparent in PJM’s recent “Critical Issue Fast Path” filings and similar expedited processes in other regions.
The irony is that while FERC advocates for long-term regional planning to prevent “piecemeal” upgrades, the urgency of the data center crisis is triggering a resurgence of precisely that kind of incremental development. Utilities cannot afford to wait for a twenty-year regional plan to be finalized, litigated, and approved when a hyperscaler demands power within eighteen months. As a result, there’s a heavy reliance on participant-funded upgrades and fast-track interconnection agreements that bypass the broader regional optimization goals of Order 1920. This indicates that while the rule is excellent for macro-grid architecture, it lacks the flexibility required for the fast-paced modern digital economy. Currently, the industry struggles to bridge the gap between the “perfect” grid of the twenty-year plan and the “necessary” grid of the immediate future.
Interconnection Queue Reform: The Unfinished Business
It is impossible to evaluate the effectiveness of Order 1920 without considering its counterpart: interconnection queue reform (Order 2023). While Order 1920 addresses regional transmission planning, the actual connection of new resources is managed through the generator interconnection process. By 2025, the tension between these two processes has become a major source of frustration for developers. Order 1920 was intended to identify transmission needs that would, in theory, facilitate new generation. However, since transmission projects take 7 to 10 years to complete and generation projects can be developed in 2 to 3 years, there remains a significant timing mismatch.
The “cluster study” approach mandated by Order 2023 has helped reduce some administrative backlog, but without the physical capacity that Order 1920 is meant to provide, the queues remain clogged with projects facing high network upgrade costs. Developers see the “planning” side promising a strong grid in the 2030s, while the “interconnection” side hands them billion-dollar bills for upgrades needed now. This disconnect highlights a limitation of Order 1920: it is a planning rule, not a siting or permitting rule. It can identify where the lines should go, but it cannot make them be built faster than the permitting process allows. As a result, the “needle” is moving on paper, but the physical system remains largely unchanged one year later.
The Workforce and Organizational Challenge
A less discussed but equally important effect of Order 1920 is the pressure it has placed on human capital in the power industry. The complexity of the required compliance filings—incorporating advanced economic modeling, meteorological analysis, and legal strategies—has sparked a talent war among transmission planners. Consulting firms and RTOs are actively recruiting talent from utilities and state commissions. The extensive analysis required to fulfill the “three scenarios, twenty-year horizon” mandate has overwhelmed many smaller planning departments.
For middle managers, this has resulted in a year marked by capacity constraints not only on the grid but also within their own teams. The “brain drain” from state regulatory commissions to the private sector is especially concerning, as it leaves the very agencies responsible for approving these large projects understaffed and outgunned. This workforce bottleneck acts as a hidden brake on the pace of implementation. Even if the political will and capital are available, the technical capacity to process the necessary studies is severely limited. This has led to the emergence of AI-assisted planning tools as utilities desperately seek to automate data ingestion and scenario analysis in the Order 1920 workflow.
Conclusion
One year after the issuance of FERC Order 1920, the outcome is cautious and weary progress. To the question “Is it moving the needle?” the answer is a cautious, “yes.” It has shifted the industry’s thinking, forcing it to move away from outdated, short-term planning in favor of a comprehensive, long-term perspective that considers extreme weather and the energy transition. It has influenced political dynamics, prompting states to engage in a reluctant yet essential collaboration on cost allocation. Additionally, it has impacted the corporate sector, fostering new joint ventures and strategic realignments among existing utilities.
However, it has not yet moved the physical needle where it matters most: largely expanding transfer capacity between regions to relieve the immediate reliability pressures. The lag time between a regulatory mandate, a compliance filing, a planning cycle, and eventual construction spans decades, not months. The industry is presently in the “valley of death” between the old regulatory regime and the new one, bearing the costs and administrative burdens of the new rules without yet seeing the physical benefits.
For leaders in the U.S. electric power sector, the coming year will hinge on their ability to maintain the momentum of ongoing long-term reforms while ensuring a reliable power supply in a short-term environment marked by unprecedented load growth and legal uncertainties. Order 1920 has successfully mapped out the future grid, but as 2025 draws to a close, the industry is still preparing for the journey.