Articles

Beyond queue seniority: Customer-centric solutions for interconnection scarcity

Authors:  and * | March 2026 – Volume 14, Issue 1, 2026

First‑in‑time, first‑in‑right Large Generator Interconnection (“LGI”) rules that have for the first part of this century governed the priority of access to most North American grids are no longer viable. Scarce transmission, surging artificial intelligence (“AI”) driven load, and deep queues of merchant renewables have broken the logic of these rules. Queue seniority no longer correlates with customer or system value, and it hardly could have because the relative costlessness of queuing was never an efficient instrument to allocate a scarce resource. This paper proposes a hybrid approach to generator interconnection depending on the characteristics of the underlying marketplace: prioritize projects with real customer commitments and competitive procurement, or use open‑season and pricing mechanisms to allocate scarce capacity efficiently.

For roughly two decades after Federal Energy Regulatory Commission (“FERC”) Orders 888 and 2003 standardized open access and interconnection, grids operated with ample headroom. Grid operators in Canada such the Alberta Electric System Operator (“AESO”) followed suit and LGI policies granting priority rights based on queue position worked well thanks to an environment of abundant transmission capacity. Grid utilization improved, incumbent market power was limited through enhanced competition, and in turn lower wholesale costs resulted.

Today, that premise has inverted. Interconnection queues for generation, and now large loads driven by AI data centers, have swelled while transmission capacity is scarce. Yet interconnection decisions still hinge on queue timing rather than economic value or system need. Antiquated first-in-time, first-in right LGI policies assume transmission is a public good that any commercially viable generator may use without reducing its availability to others. This assumption is flawed. Just as in water and wireless spectrum, a ration approach to resource allocation requires a market-based approach to define rights to scarce transmission capacity.

Allocating transmission capacity arbitrarily based on queue position no longer works. Interconnection backlogs across North America total hundreds of gigawatts, incapable of clearing efficiently. The challenge is further compounded by a parallel queue on the demand side. Sadly, but predictably, the inefficient LGI process has been photocopied in its application to massive data centers seeking to connect to the grid. Scarce transmission has ended the “Gold Rush” era for generation, but this new one is underway. Neither can be managed effectively under a first-in-time, first-in-right policy, leaving regulators and system operators to grapple with both interconnection reform and reliability concerns.

In 2023, both FERC and the AESO introduced cluster processes and added financial screens to weed out speculative or queue-sitting projects. However, these reforms did not fundamentally abandon the core first-in-time, first-in-right policy. These measures seek to improve study mechanics, but not necessarily allocation logic.[1]

Meanwhile, these LGI policies raise broader questions. Queue-based priority also distorts competition and transmission planning. Utilities and load-serving entities (“LSE”) cannot select the highest value projects, instead hamstrung by senior queue holders who have captured scarce transmission capacity which is neither fair nor efficient.

In sum, prevailing interconnection policy is upside down under scarcity conditions. Access to the grid should prioritize customer and system value, not create rent for early queue filers. Reforms must pair competitive procurement with willingness to pay signals for scarce capacity for merchant projects. Stopgap measures like PJM Interconnection’s (“PJM’s”) and the Midcontinent Independent System Operator’s (“MISO’s”) jump-the-line measures that bypass senior LGI rights highlight the urgency of replacing Gold Rush era LGI queue rules with durable, value-based approaches.

I. FIRST-IN-TIME, FIRST-IN-RIGHT RULES WORKED WHEN TRANSMISSION WAS ABUNDANT

When FERC introduced LGI policies over 20 years ago,[2] United States markets had ample transmission headroom.[3] Alberta’s zero congestion transmission standard similarly drove an overbuild of transmission, enabling easy interconnection of new generation.[4] Annual LGI requests were modest.[5] With embedded transmission costs already covered by load and marginal interconnection costs near zero, first-in-time, first-in-right rules made sense. They maximized abundant capacity, promoted open access and competition, and curbed utility self-dealing.

Early LGI reforms such as FERC Order 2003 sought to accelerate entry and mitigate discriminatory practices but were rooted in a view of untapped abundance rather than treating transmission interconnection as a scarce resource. FERC framed this reform as a complement to open access and generator competition in Order 888 and regional transmission organization (“RTO”) development under Order 2000.[6] These policies largely succeeded. Open access and queue priority to a newly liberalized grid made third-party generation highly financeable, spurring hundreds of billions of dollars in new generation investment. Innovative hedging products and virtual power purchase agreements[7] helped further reduce project finance risk and accelerated development.

Because commercially viable generators received priority interconnection rights at minimal cost, they sought the most efficient connection points on an under-utilized grid.[8] With ample transmission headroom, customers could competitively procure supply from either new or existing generation projects, while reliability and other goals were achieved.

II. FIRST-IN-TIME, FIRST-IN-RIGHT CONCERNS UNDER CONDITIONS OF SCARCITY

Over the past five years or so, transmission and interconnection headroom for new generators (and new large loads) has been exhausted.[9] Scarcity drivers have been well documented in FERC proceedings, including load growth, decarbonization goals, permitting and planning challenges for new transmission, and greatly improved renewable energy cost and performance.[10] As a result, LGI requests now exceed the coincident peak demand of many balancing authorities by several multiples, eliminating nearly all generator headroom.[11] Connection requests for data centres compound the strain, approaching or exceeding peak demand in jurisdictions such as the Electric Reliability Council of Texas (“ERCOT”) and Alberta. Under these conditions, granting priority LGI rights solely on queue timing raises significant concerns.

A. The Dysfunctional Nature of First-in-Time, First-in-Right LGI Approaches

Until recently, priority interconnection rights in RTOs went to generators that filed first and demonstrated “commercial viability.” Today, most wind, solar, and storage projects are sponsored by experienced, well-capitalized developers, making commercial viability a weak differentiator.[12] Queue timing is now the only meaningful distinction among hundreds of similar projects.[13] Even when capacity exists, oversized cluster studies prevent efficient use of limited headroom.

FERC and Canadian ISOs have tried to address this. Order 2023 and its successors introduced a “first-ready, first-served” model, but in practice it retains a queue-based priority. Clusters are studied and resolved sequentially, and withdrawals trigger restudies that delay entire cycles. MISO estimated that the current cluster cycle takes 3–4 years, with projects from its 2025 cluster potentially waiting until 2036 to come online.[14] In Alberta, AESO’s first cluster drew 22 GW — more than double average demand — with 16 GW advancing, underscoring the scale of oversubscription.[15]

These reforms improve study mechanics but do not solve the core problem. Interconnection queues across regions exceed peak demand many times over and most projects will never be built. It is time to invert the paradigm and ask which projects deliver genuine customer benefit or represent the highest value use of scarce interconnection capacity.

B. With Scarcity, First-in-Time LGI Approaches Crowd Out Needed Investment and Raise Costs

When transmission and interconnection are constrained, rationing of headroom is inevitable. Today, that rationing occurs by granting priority LGI rights based on the timing of the cluster studies or an application within a cluster study.[16] This leaves critical decisions of allocating scarce grid capacity to the arbitrary filings dates, where the legacy squatter rights have inhered years before a competitive solicitation for resources commences, effectively dictating the outcome of a process better determined by resource cost and operational characteristics. This undermines Order 2003’s goal of “bringing much-needed generation to market to meet the growing needs of electricity customers” without undue delay.[17]

Recognizing this misalignment, RTOs such as PJM, MISO, and the Southwest Power Pool (“SPP”) sought FERC approval to prioritize resources needed for reliability. In PJM, 1,059 projects were eligible to seek interconnection, of which 60 per cent were intermittent resources. It proposed the Reliability Resource Initiative (“RRI”) to allow a subset of generators needed to meet PJM’s capacity needs to achieve a faster interconnection.[18] Utilizing an administrative scoring mechanism that considers market impact and commercial operation date rather than queue position,[19] 94 applications totaling 26 gigawatts were reduced to 51 projects representing 9,300 megawatts of new capacity.[20]

MISO’s Expedited Resource Addition Study (“ERAS”)[21] requires projects to demonstrate they will meet an identified reliability need, supported by an attestation from a regulated utility that it will self-build or contract through a power purchase arrangement (“PPA”) or similar arrangement.[22] It was initially rejected by FERC,[23] but later approved as ERAS 2.0 with caps on qualifying projects and carved out Illinois and Michigan, which have retail competition.[24]

SPP’s similar proposal, also called ERAS, though for Expedited Resource Adequacy Study, was also accepted.[25] The SPP proposal is intended to expedite utility-designated generation projects for LGI.[26] These programs underscore that queue-based allocation cannot meet reliability needs and require ongoing exceptions—a symptom of structural failure.

C. Under Conditions of Scarcity, First-in-Time LGI Approaches Distort Transmission Investment

Current LGI approaches distort both new generator and transmission investment decisions. Queue-based cost allocation once worked when few projects connected to a robust grid. Today, with thousands of queued projects, this ad hoc model cannot produce an optimal transmission system.

Alberta is moving away from this paradigm. Its shift from a zero-congestion standard to optimal transmission planning (“OTP”) requires new transmission projects proceed only when the system benefit exceeds costs.[27] Paired with new transmission reinforcement payments (“TRP”) — upfront, non-refundable charges that replace the current refundable deposits — the policy sends sharper locational signals. Developers are incentivized to site where capacity exists or fund reinforcements, reducing congestion risk and speculative filings. Other regions are exploring similar approaches, but most still rely on queue seniority, which transfers transmission value to early filers and encourages “LGI lottery” behavior. As well, incumbents can exploit this to block efficient entrants, raising costs for customers.[28]

When regional transmission planning then occurs to accommodate the growth protended by such a backlogged, but speculative, queue, the effect is predictable: Transmission is planned for and funded by customers which may fail to deliver intended benefits if priority access goes to projects with a senior queue position, but which are misaligned to customer needs or value.

III. REFORMS FOR AN OPEN ACCESS LGI APPROACH BASED ON CUSTOMER AND SYSTEM BENEFIT

Open access should remain central to interconnection policy, but scarcity demands regulators and ISOs move beyond first-in-time, first-in-right approaches. These legacy approaches assumed transmission was a limitless public good, but this premise no longer holds. Once effective in accelerating grid development, these Gold Rush rules now impede the ability to meet customer demand, reliability, and other policy objectives. This paper recommends reforms that allocate scarce interconnection capacity to projects delivering the greatest customer and system value.

Any approach must recognize that customers, or the Load-Serving Entities (“LSEs”) that supply them energy, ultimately bear transmission costs in most ratemaking arrangements.[29] Scarce interconnection capacity should therefore prioritize projects backed by customer commitments or ensure the greatest system benefits. Broken first-in-time LGI procedures fail to do this. However, a shift is already underway in several places.

Competitive processes should replace queue seniority as the basis for transmission allocation. In bilateral markets and state-regulated utilities, this may mean state-supervised solicitations overseen by independent evaluators. In restructured markets with retail competition, nominations by LSEs could achieve similar outcomes. Open seasons or auctions could also be employed. In all cases, safeguards must be in place to prevent transmission owners favouring affiliated generation, consistent with FERC Orders 888 and 2003.

Pricing should also reflect reality. Access to new transmission must reflect incremental or market-based costs, not historical embedded rates under an open access transmission tariff. When interconnection triggers major network upgrades, cost allocation to interconnecting resources or their off-takers should account for those impacts. Aligning price signals with actual costs discourages speculation and ensures transmission expansion delivers value to customers and the system.

Much of these recommended open access LGI approaches, where all generators can compete for priority interconnection independent of when they filed in the LGI queue, can be implemented in bilateral and state-regulated markets, but naturally require different approaches in fully restructured markets.

1.  State regulated approach for vertically integrated utilities

In bilateral and state-regulated markets, transmission expansion can be comprehensively planned for the benefit of native load customers, funded through socialized cost recovery, rather than by assigning upgrade costs to individual generators. Coupled with transparent, competitive all-source procurements, priority interconnection can be awarded to winning bids that best meet reliability, resource adequacy, and cost objectives rather than queue seniority.

Tying scarce LGI rights to the outcomes of state-supervised competitive solicitations makes commercial viability a competitive result, not a timestamp. As a result, the allocation decision lies within a regulated process focused on public-interest outcomes. This design also addresses familiar concerns about objectivity and transparency in “jump-the-line” exceptions to ordinary LGI rules. Competitive solicitations overseen by independent evaluators, with robust record development and regulatory review in litigated proceedings, provide regulators with process visibility. FERC could establish a yardstick for the acceptability of these state processes before sanctioning them to ensure that the purposes of open access are meaningfully fulfilled, if not through an approach that mistakenly relies upon first-in-time, first-in-right interconnection regulation within the federal domain.

Awarding scarce interconnection priority through competitive procurements, rather than individual queue position, determines what capacity is added, when and where it is needed, and under what commercial terms. This constrains self-build bias by forcing head-to-head competition between utility-owned and third-party proposals under defined cost and risk limits and returns transmission value to customers lower utility offtake pricing. This contrasts many RTO structures that privatize value via senior queue rights. Colorado’s all-source procurements exemplify this model: scarce LGI priority follows winning bids, enabling scale transmission planning and delivery.[30]

2. The CAISO approach

Compared to vertically integrated states, the California Independent System Operator (“CAISO”) operates within a far more diverse retail landscape of 100 LSEs, including investor-owned utilities, community choice aggregators, and competitive retailers ranging in size from less than 1 megawatt to over 13,000 megawatts.[31] Its interconnection queue is highly oversubscribed, demonstrated by its Cluster 15 study that included 541 new projects representing 354,000 megawatts. This far exceeds CAISO’s all-time peak demand, underscoring the speculative nature of the interconnection queue.[32]

To address this, CAISO replaced first-in-line priority with a weighted scoring system to allocate priority LGI rights.[33] LSEs receive “commercial interest points” that they may allocate to resources in the queue to grant it higher-priority status.[34] LSEs naturally use their points on projects they intend to or have already contracted with, giving priority to resources backed by real customer commitments. This mechanism has already influenced power purchase agreements, with buyers securing better terms in exchange for points that reduce interconnection uncertainty.

Limits on utility generation ownership reduce self-dealing,[35] and centrally planned, customer-funded transmission makes LSE points a reasonable proxy for customer benefit.[36] California’s retail restructuring, albeit incomplete, ensures that competitive tension between buyers of generation is present, avoiding the perverse incentives that a regulator would otherwise have to guard against in the vertically integrated utility markets that are closed to retail competition. Early use of points under the CAISO reform was modest given a rushed rollout, but the market’s reform squarely reorients interconnection priority to customer-backed projects and away from speculative queue filings, allowing all generators to compete on system and customer value — a more genuine form of open access.

3. Fully Restructured Markets

In fully vertically disaggregated RTO and ISO markets, where generation ownership is diversified and retail competition is widespread, the interconnection problem broadly mirrors that of other jurisdictional structures. First-in-time, first-in-right procedures still backlog LGI queues with many projects lacking credible commercialization paths, while impeding lower-queued projects that could better meet resource adequacy, reliability, and customer value needs. The remedy is necessarily more complex than in vertically integrated markets, where the buyer of generation is clear, or California which has fewer LSEs and more policy-driven contracting. In markets such as PJM, ISO-New England, New York Independent System Operator Inc (“NYISO”), ERCOT (Texas), and Alberta, customers are less obviously linked which complicates any customer-centric prioritization in the queue.

Customer shopping activity in these jurisdictions is not universal. Most industrial customers with the option have chosen a third-party LSE,[37] and in some cases, they know exactly what they are buying, such as when Microsoft purchases a long-term PPA tied to the restart of Constellation’s Three Mile Island.[38] More commonly, supply arrangements are shorter term and lack any clear link to specific generation resources.

Residential participation varies widely. Depending on the market, only 5 per cent to as much as 85 per cent of households take service from a third-party LSE.[39] Even these customers do not receive energy from a utility’s dedicated set of resources. Many LSEs do not own generation at all; instead, they purchase power from the wholesale market through financial trades rather than unit-contingent contracts. These trades typically settle as contracts-for-differences against day-ahead and real-time spot auctions run by the RTO or ISO.[40] Counterparties may be generation owners or financial intermediaries, making the source of generation, and its link to individual customers, unclear. For non-shopping customers, utilities, state agencies, or regulated retailers aggregate demand and bid it into the wholesale market, where wholesale suppliers compete to serve that load.

This fragmented commercial landscape raises a key question: What would a customer-centric approach to interconnection look like in markets where customers rarely know the resource serving them? One option is to extend the logic of CAISO’s reform, which awards priority based on commercial interest rather than queue timing. If an LSE or large customer has contracted for a resource, that arrangement could justify higher priority in the queue. This approach ensures that resources with real customer commitments, and therefore a clear path to commercialization, move ahead of purely speculative projects. This method is often looked at as a solution to AI-driven load queues, with data centre projects encouraged to “bring your own generation.”

For resources developed on a merchant basis, a different remedy is needed. One promising approach is a network open season, a time-limited process where the grid operator solicits binding requests for interconnection or transmission capacity, aggregates demand and allocates rights and costs transparently, often through auctions or pro-rata subscriptions. This model, long used in natural gas pipelines and adapted for merchant HVDC projects,[41] replaces timing-based seniority with demonstrated willingness to pay or contractual commitment, filtering speculation and aligning expansion with actual system needs. Rights obtained through an open season could even be traded in a secondary market, creating liquidity and ensuring capacity flows to the highest value uses.

Alberta’s AESO offers a useful case study in partial reform. Its cluster assessment process batches generation and storage projects into defined intake windows and studies them together, improving efficiency and imposing financial discipline through application fees, security requirements, and generator-related contribution obligations.[42] These measures reduce speculative filings and allow coordinated network analysis. However, clustering alone does not solve the core problems related to allocation and speculation. Priority still generally depends on timing within the cluster, and with over 16,000 megawatts of projects in cluster one, many projects will not, nor have the intention, to move forward. These issues result in high cancellation risks, which limits the effectiveness of the studies,[43] a concern previously described in this paper within MISO.[44]

The cluster process introduces structured stages, beginning with a System Access Service Request (“SASR”) and moving through preliminary and detailed assessments, each requiring deliverables such as study scopes, cost estimates, and evidence of Generator Unit Owner Contribution (“GUOC”) payment. Financial security and stage-gate decisions help filter speculative projects, though payments are often minimal enough that well-funded developers can simply treat these as a cost of doing business especially when entering queues in multiple jurisdictions. The coordinated studies allow AESO to identify least-cost connection alternatives and shared upgrades more effectively than serial reviews, though these limitations are highlighted in the cancellations discussed above.

These processes help enhance transparency and predictability for developers through published intake windows and milestone schedules, but issues persist. Given the oversubscription and cancellation issues, it is clear that clustering alone cannot cure speculative queue dynamics plaguing RTOs and ISOs across North America. Cost signals can also be blunt, attempting to filter speculative projects (though costs may only be high enough to truly filter out smaller developers) but does not necessarily lead to prioritizing resources with the highest reliability, locational, or speed-to-market value unless it can then be paired with a value-based selection rule.

A hybrid approach, retaining clustering for study efficiency but assigning priority through customer-anchored scoring or open-season bidding, would better align interconnection with reliability, resource adequacy, and customer value. Upcoming reforms in Alberta may get it closer to achieving these goals. In July 2024, the Minister of Affordability and Utilities directed the AESO to move to an OTP approach.[45] Combined with TRP, this new planning standard moves Alberta closer to achieving the above hybrid approach. This approach is designed to send sharper location-based price signals and align developer incentives with system value, while enabling AESO to better manage congestion and allocate costs according to cost-causation principles.[46]

Clearer location signals for developers will be provided by existing transmission interconnection capacity, TRP costs, and real-time locational marginal prices in the wholesale market. Developers will no longer be able to rely on the AESO planning costly transmission upgrades to relieve congestion. Taken together, clustering, OTP, and TRP build toward a coordinated, value-driven interconnection and transmission regime. Clustering ensures efficiency and transparency in study sequencing. OTP rationalizes expansion decisions around system-wide benefits. TRP introduces stronger locational and technical cost signals upfront.[47]

CONCLUSION

Scarcity has upended the logic of first-in-time, first-in-right interconnection policy. Open access must evolve to prioritize projects that deliver measurable customer and system value through transparent, competitive processes and market-based signals.

Early reforms in Colorado and California demonstrate that queue seniority can be replaced with mechanisms grounded in real commitments that preserve competition and curb speculation. For fully restructured markets, the challenge is greater but solvable. Alberta’s shift to Optimal Transmission Planning and Transmission Reinforcement Payments, paired with clustering, signals a move toward value-based interconnection.

Done right, these reforms will not only replace the Gold Rush mentality but strengthen the foundations of open access, enabling grids to meet rising demand and policy goals without sacrificing fairness or efficiency. Flexibility and creativity are no longer optional, they are prerequisites for a reliable, customer-focused grid in an era of scarcity.

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