The North American electric grid is currently navigating its most significant transformation since the initial push for deregulation in the late 1990s. As the generation mix shifts rapidly from centralized, dispatchable fossil fuel resources to decentralized, variable inverter-based resources, the regulatory frameworks governing how these assets access the high-voltage transmission system have come under unprecedented strain. At the heart of this challenge is a fundamental distinction that often eludes even seasoned project developers: the technical and legal separation between interconnection service and transmission service. While the physical act of "plugging in" a generator to the grid is a prerequisite for operation, the right to move energy from that generator to a load-serving entity or a market participant is governed by an entirely different set of rules, studies, and agreements. This divergence is most pronounced when comparing the "Pool" paradigm of Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) with the "Path" paradigm of traditional, non-RTO jurisdictions managed by vertically integrated utilities.

The historical foundation for this separation is rooted in Federal Energy Regulatory Commission (FERC) Order No. 888, which sought to promote wholesale competition by requiring all public utilities to provide open access to their transmission systems on a non-discriminatory basis.1 This led to the creation of the Open Access Transmission Tariff (OATT), the seminal document through which transmission service is offered. However, Order No. 888 did not establish a uniform process for the physical connection of new generators. That task was left to FERC Order No. 2003, which implemented the Standard Large Generator Interconnection Procedures (LGIP) and the Standard Large Generator Interconnection Agreement (LGIA).3 This bifurcated regulatory heritage created a system where interconnection and transmission are legally distinct products, a reality that persists even in the most integrated RTO markets today.

As interconnection queues have swelled to over two million megawatts of generation and storage capacity, the inefficiencies of this bifurcated system have become a primary bottleneck for the energy transition.5 Projects now routinely face study timelines exceeding five years and network upgrade costs that can comprise 50 to 100 percent of total project capital.5 In traditional regions, this is compounded by the "second study shock," where a project survives the interconnection process only to be rendered unviable by subsequent transmission service studies. Understanding the causal relationships between these regulatory silos and the practical experience of developers is essential for navigating the current era of grid gridlock.

The Dual Architecture of Grid Access: Interconnection vs. Transmission

To understand the developer’s experience, one must first master the distinct legal definitions and engineering objectives of interconnection service versus transmission service. In regulatory terms, interconnection service is the service provided by a transmission provider to physically and electrically connect a generator to the grid, enabling it to receive energy and capacity at a specific Point of Interconnection (POI).3 Transmission service, conversely, is the reservation and actual movement of that energy across the broader transmission system to a specific load or delivery point.3

Feature Interconnection Service (LGIP/LGIA) Transmission Service (OATT)
Primary Regulatory Driver FERC Order No. 2003 / Order No. 2023 FERC Order No. 888 / Order No. 890
Engineering Objective Local reliability, safety, and physical connection. System-wide capacity and deliverability between points.
Core Agreement Large Generator Interconnection Agreement (LGIA) Transmission Service Agreement (TSA) or Network Integration Transmission Service Agreement (NITSA)
Standard Product Offerings Energy Resource Interconnection Service (ERIS) and Network Resource Interconnection Service (NRIS) Point-to-Point (PTP) and Network Integration Transmission Service (NITS)
Study Hierarchy Cluster and Facilities System Impact and Facilities (specific to path/load)
Rights Granted The right to physically connect and inject at the Point of Interconnection (POI). The right to move power from Point of Receipt (POR) to the Point of Delivery (POD).

The fundamental insight for developers is that these two services are not "bundled" in the eyes of the law. The pro forma LGIP contains an explicit "No Applicability to Transmission Service" clause (Section 2.4), which clarifies that an interconnection request does not constitute a request for transmission service nor does it grant any right to receive it.3 A project can be fully "interconnected" but legally "stranded" if it cannot secure transmission service.

Interconnection Service Levels: ERIS vs. NRIS

Under the FERC pro forma LGIP, transmission providers must offer two distinct levels of interconnection service: Energy Resource Interconnection Service (ERIS) and Network Resource Interconnection Service (NRIS). The choice between these two levels dictates the scope of the engineering studies and the resulting cost responsibility for the developer.3

ERIS allows a generator to connect to the grid and be eligible to deliver output using the existing firm or non-firm capacity of the transmission system on an "as-available" basis.3 The study process for ERIS is relatively narrow, focusing on "short circuit/fault duty" and local thermal/voltage impacts to ensure the generator does not physically compromise the safety of the local substation or line.3 Because it is "as-available," an ERIS generator has no guarantee of deliverability; if the system is congested, the generator must be curtailed.13

NRIS is a significantly more rigorous and expensive product. It is designed to allow a generator to be designated as a "Network Resource," ensuring that its full output is deliverable to the aggregate load on the transmission system during peak or "stressed" conditions.3 In an NRIS study, the transmission provider assumes that the new generator will displace a portion of existing generation to serve the system load. If the system cannot handle this displacement without reliability violations, the developer is assigned the cost of "Network Upgrades" to expand grid capacity.3 Crucially, while NRIS provides a higher level of "deliverability," the LGIP remains clear: NRIS "in and of itself does not convey transmission service".3

Transmission Service Categories: PTP vs. NITS

Once a project has cleared the interconnection hurdle, it must secure rights under the OATT to move its power. There are two primary mechanisms for this: Point-to-Point (PTP) Transmission Service and Network Integration Transmission Service (NITS).3

PTP service is a path-based reservation. It allows a customer to move a specific amount of power from a designated Point of Receipt (POR) to a designated Point of Delivery (POD).3 PTP can be "Firm," meaning it has a high priority and is only curtailed during extreme contingencies, or "Non-Firm," meaning it is available only if there is spare capacity and is curtailed for economic or higher-priority reliability reasons.3

NITS is a service typically used by utilities to integrate multiple resources to serve their aggregate load. It allows the "Network Customer" (usually the utility buyer) to designate the new generator as a "Network Resource".3 Once designated, the resource can serve any load within the utility’s footprint without the need for specific path-by-path reservations. However, the designation of a new Network Resource requires its own study process under the OATT to ensure the system can accommodate the energy flow from that resource to the load points.3

The RTO/ISO Paradigm: Centralized Markets and Integrated Planning

In regions managed by RTOs or ISOs—such as PJM, MISO, CAISO, and SPP—the practical experience of the developer differs markedly from the legal separation of services described above. RTOs operate centralized wholesale markets where all generation is dispatched collectively based on Locational Marginal Pricing (LMP) to meet the aggregate demand of the region.2 This "Pool" paradigm fundamentally changes the nature of transmission deliverability.

The Convergent Path of RTO Interconnection

The defining characteristic of the RTO experience is that the deliverability analysis required for transmission is effectively front-loaded into the interconnection study process. When a developer in PJM or MISO requests NRIS status, the RTO studies the project’s ability to reach the entire market pool.19 Because the RTO’s footprint is treated as a single, integrated network for market purposes, the "Network Upgrades" identified during the NRIS interconnection study are largely identical to the upgrades that would be required to provide transmission service to load within that market.13

Consequently, for a project that achieves NRIS in an RTO, the subsequent procurement of transmission service is often a seamless administrative step. When a utility buyer (the LSE) signs a contract with the generator, they simply designate it as a "Network Resource" under their existing NITS agreement.20 Because the RTO has already "pre-certified" the project as deliverable to the aggregate load during the NRIS interconnection phase, the RTO does not need to perform a new, redundant System Impact Study for the transmission service request.3 This creates a "convergent" workflow where the engineering hurdles are cleared once, early in the process.

LMP and the Viability of ERIS

The existence of a real-time energy market in RTOs also changes the business case for ERIS. In a market environment, an ERIS-only project can simply "plug in" with minimal local upgrades and sell its power into the energy market at the prevailing LMP.13 If the grid is congested, the project may be curtailed or receive a lower price, but the developer has a pathway to revenue without paying for deep network upgrades. This allows for "energy-only" projects that prioritize speed to market over firm deliverability.21

RTO/ISO Region Notable Interconnection Feature Current Status/Challenge
CAISO Historically fast, but recently overwhelmed by volume. Shifted to highly restrictive cluster windows.23
ERCOT "Connect and Manage" (Energy-only) philosophy. Highest speed; projects bear all curtailment risk.13
PJM Historically serial; recently reformed to cluster studies. Facing 700+ day study delays and massive backlog.25
MISO Strong focus on long-term regional transmission planning (LRTP). High volume of speculative requests; rising upgrade costs.25
ISO-NE Fixed monthly service (RNS) instead of pro-forma PTP. Gridlock in specific zones due to localized constraints.25
SPP Transitioning to first-ready, first-served cluster process. Cost uncertainty leading to high withdrawal rates.25

The Traditional Jurisdiction Paradigm: Bilateral Paths and Second Study Shock

In traditional, non-RTO regions—which include large portions of the Southeast and the West (outside of CAISO)—the grid is managed by vertically integrated utilities acting as individual Balancing Authorities. In these regions, there is no centralized spot market; instead, power is traded via bilateral contracts and moved across specific physical "contract paths".17 This "Path" paradigm creates a "divergent" workflow that is the primary source of frustration and confusion for developers moving between regions.

The A La Carte Barrier

In traditional jurisdictions, interconnection and transmission are strictly "a la carte" products. A developer might initiate an interconnection request and, over several years, move through the feasibility, system impact, and facilities studies to reach an executed LGIA.12 This LGIA provides a cost estimate for the physical connection and any upgrades required at the POI. However, the developer often stops here, assuming that the technical work is done.

The "divergent" step occurs when the developer (or the power purchaser) submits a Transmission Service Request (TSR) under the OATT to move the power from the plant to the buyer. Because non-RTO transactions are path-specific, the transmission provider must conduct a new and separate System Impact Study for that specific path.3

The Mechanism of Second Study Shock

The "Second Study Shock" is a phenomenon where the TSR study identifies massive, previously unmentioned network upgrade costs and multi-year construction delays. This happens because the initial interconnection study only evaluated the physical impact of the generator at its local POI. It did not evaluate the impact of moving 500 MW of power across the broader grid to a specific load center 200 miles away.3

When the TSR study is performed, it may reveal that the requested delivery path is already congested or that the addition of the new power flow triggers stability or thermal violations in "deep" network facilities that were not "impacted" by the simple act of interconnection.3 For a developer who has already signed an LGIA and potentially committed millions in collateral, discovering another $50 million in "delivery upgrades" at the eleventh hour can be a project-ending event.12

The Risks of ERIS in Traditional Jurisdictions

Choosing ERIS in a traditional region is a far more perilous decision than in an RTO. In an RTO, ERIS projects can sell into the market pool. In a traditional region, there is no pool. A generator cannot flow power anywhere without a transmission reservation.13 Because a traditional transmission provider will not grant firm transmission service without a deliverability study equivalent to the NRIS standard, an ERIS developer who later tries to secure firm service will almost certainly be hit with the full cost of the network upgrades they thought they avoided during the interconnection phase.13

Regulatory Reform and the Cluster Study Mandate: FERC Order No. 2023

Recognizing that the traditional "first-come, first-served" serial study process had become unworkable, FERC issued Order No. 2023 in July 2023. This landmark rule represents a fundamental shift toward a "first-ready, first-served" cluster study process for all jurisdictional transmission providers, both in RTO and non-RTO regions.3

The Cluster Study Process

Order No. 2023 requires transmission providers to group interconnection requests into "clusters" and study them simultaneously rather than individually.3 This is intended to identify shared network upgrades and allocate costs more efficiently among multiple developers. The order sets a standard 150-day timeline for the cluster study, followed by any necessary restudies and a final facilities study.3

Cluster Process Milestone Requirement / Detail
Cluster Request Window 45-day annual window for submitting new requests.3
Customer Engagement Window 60-day period for scoping meetings and data exchange.3
Site Control Mandatory 90% site control at application; 100% after 180 days.3
Commercial Readiness Deposit Tiered deposits based on MW size; non-refundable upon withdrawal.3
Cluster Study Timeline 150 days to identify upgrades and allocate costs.3
Heatmaps Mandatory public visual representation of available capacity.6

Financial Readiness and Withdrawal Penalties

To prevent "speculative" projects from clogging the queue, Order No. 2023 introduced significant financial hurdles. Developers must now provide study deposits ranging from $35,000 to $250,000, plus a "Commercial Readiness Deposit" equal to two times the study deposit.3 Most importantly, the order implements strict Withdrawal Penalties for projects that exit the queue after the cluster study has commenced.3

These penalties are designed to be punitive, increasing in severity as the project moves closer to an interconnection agreement. If a project withdraws during the Cluster Study phase, the penalty is twice the actual study costs. By the time a project reaches the LGIA execution stage, the penalty can be as high as 20% of the estimated network upgrade costs.3 These funds are used by the transmission provider to offset the cost increases that remaining projects in the cluster would otherwise experience due to the withdrawal of a cost-sharing neighbor.3

The Technical Burden: Modeling and Data Requirements

The complexity of interconnection and transmission studies is driven by the physics of a rapidly changing power system. Transitioning to a grid dominated by inverter-based resources (IBRs), such as solar, wind, and batteries, requires much more sophisticated modeling than traditional synchronous generators. IBRs do not possess the natural physical inertia of large spinning turbines and rely on complex software controllers to respond to grid disturbances.31

High-Fidelity Modeling Requirements

Transmission providers now require developers to provide high-fidelity models at the application stage. This includes root-mean-squared (RMS) positive sequence dynamics models for power flow and stability analysis, as well as electromagnetic transient (EMT) models for projects in "weak" parts of the grid where voltage stability is a concern.3

The technical data required under Attachment A to Appendix 1 of the LGIP is exhaustive. For a synchronous generator, it includes direct and quadrature axis reactance data, field time constants, and governor/excitation system block diagrams.3 For IBRs, it includes inverter manufacturer specifications, adjustable setpoints for protective equipment, and validated generic library models (e.g., REGC_A, REEC_A).3 If this data is inaccurate or incomplete, the project is deemed deficient, which can lead to withdrawal and the triggering of the penalties described above.3

Grid-Enhancing Technologies (GETs) in Studies

A significant second-order insight from the research is the potential for Grid-Enhancing Technologies (GETs) to act as a bridge between interconnection and delivery. Order No. 2023 mandates that transmission providers evaluate GETs—including dynamic line ratings, advanced power flow control, and transmission switching—in their cluster studies.3

Research suggests that GETs can facilitate the interconnection of gigawatts of new capacity at a fraction of the cost of traditional network upgrades.33 For example, in PJM, an analysis found that deploying GETs could enable 6.6 GW of solar, wind, and storage projects by 2027 while saving developers and consumers hundreds of millions in capital costs.33 For a developer, the inclusion of GETs in a study can be the difference between a viable project and a "second study shock" that renders the project economically underwater.

The ERCOT Exception: Connect and Manage

The most stark contrast in the North American landscape is the Electric Reliability Council of Texas (ERCOT). ERCOT is unique because it is an "energy-only" market that operates almost entirely within the state of Texas, placing it outside of most FERC jurisdiction.2 ERCOT utilizes a "Connect and Manage" philosophy that stands in direct opposition to the "Invest and Connect" model used by the rest of the country.13

Interconnection Speed vs. Deliverability Risk

In the ERCOT model, the interconnection study process focuses almost exclusively on the local network upgrades required to physically plug the generator into the grid.21 ERCOT does not perform a deliverability analysis as part of the interconnection process, nor does it assign deep network upgrades to developers. Instead, any constraints caused by a new generator are managed in real-time through market-based dispatch and curtailment.13

The causal effect of this model is unprecedented speed. ERCOT has consistently interconnected more capacity than any other region in recent years.13 However, the trade-off for this speed is shifted entirely to the developer’s balance sheet. ERCOT generators face a high risk of curtailment if the grid becomes congested, and because there is no capacity market, they receive no guaranteed payments for their availability.13 In essence, every generator in ERCOT is treated like an ERIS generator in an RTO, but with the added risk that there is no mechanism to "pay for" firm deliverability even if the developer wanted to.13

Institutional Memory and the Source of Developer Confusion

The persistent confusion among developers regarding interconnection and transmission service is not merely a lack of education; it is an institutional artifact of the RTO era. Over the last two decades, RTOs have successfully "abstracted away" the complexity of the transmission system for market participants.

The Abstraction of the Grid

In an RTO, the grid acts as a giant pool where electrons are fungible. If a developer pays for NRIS, the RTO’s internal systems handle the "contract paths" through LMP and congestion management.2 The developer’s mental model becomes: "NRIS \= I have a project." They view transmission service as a "utility back-office problem" or a simple NITS designation.20

When these developers enter a non-RTO region, this abstraction layer disappears. They are suddenly forced to confront the physical reality of the grid: that energy flows across specific lines owned by specific companies that must be reserved under specific rules.17 The "second study shock" is not just a financial surprise; it is the collision of a market-based mental model with a physical-path reality.

The Role of Vertical Integration

In traditional regions, the utility acting as the transmission provider is often the same entity that would be the primary buyer of the power. This creates a perceived conflict of interest that complicates the study process. While FERC rules require the "functional separation" of a utility’s merchant and transmission arms, the developer still experiences a siloed process where the utility’s PPA team and its transmission study team may not communicate, leading to inconsistent information regarding delivery feasibility.8

Strategic Implications for Project Development

The divergent nature of grid access requires a fundamental rethink of project development strategy, particularly in a post-Order No. 2023 environment. The following narrative synthesis outlines the critical considerations for developers and financiers.

Anticipating the TSR Hurdle

In non-RTO regions, a project should never be valued solely on its LGIA. The feasibility stage must include a "TSR Simulation"—a technical assessment of potential contract paths to likely utility buyers.12 If a project is located in a "transmission-constrained" pocket, it may be able to physically connect but will never be able to move its power to a buyer without triggering prohibitive costs. Developers should prioritize sites that have multiple potential delivery paths or are located near "hubs" with existing available transfer capability (ATC).3

Risk Allocation in PPAs

The "second study shock" also changes the dynamics of PPA negotiations. In traditional regions, developers should seek PPAs where the utility buyer assumes the risk (and the cost) of transmission delivery upgrades.8 Since the utility is often the transmission provider, they have better visibility into the OATT study results and are better positioned to integrate those costs into their long-term resource planning. If a developer signs a PPA that requires "Firm Delivery" but does not account for potential TSR-related upgrades, they are essentially taking a multi-million dollar gamble on the outcome of a study they cannot control.

The Value of Surplus Interconnection Service

One emerging strategy for mitigating both study delays and network upgrade costs is "Surplus Interconnection Service" (SIS). FERC Order No. 845 (and reaffirmed in Order 2023) requires transmission providers to offer an expedited process for new generators to utilize the "unused" capacity of an existing interconnection.3 For example, a developer could add a battery storage project to an existing solar farm without requiring a new full interconnection study, provided the total injection at the POI does not exceed the original limit.26 This "piggybacking" bypasses the main queue and can dramatically accelerate time to market.

The Future Outlook: Regional Markets and Holistic Planning

The ultimate solution to the bifurcated grid access problem lies in the expansion of organized markets and more holistic transmission planning. There is a growing recognition that using individual generator interconnection requests to "plan" the grid is inherently inefficient.7 It leads to a "piecemeal" approach where small, incremental upgrades are built at a high cost per MW, rather than large, strategic lines that can serve multiple projects.7

The Move Toward West-Wide Markets

In the Western United States, there is a significant movement toward a "Day-Ahead Market" (EDAM) or a full RTO that would bring many of the CAISO-style deliverability benefits to the rest of the region.17 If successful, this would replace the path-based TSR model with a more integrated pool-based model, potentially eliminating the "second study shock" for Western developers.

Proactive Transmission Planning

MISO’s Long-Term Regional Transmission Planning (LRTP) process serves as a potential model for the rest of the country. Instead of waiting for generators to enter the queue, MISO proactively identifies the transmission lines needed to support state clean energy goals and regional load growth.25 By building this "backbone" transmission, the RTO reduces the burden on individual developers and provides a more predictable pathway for interconnection.

Conclusion: Mastering the Labyrinth

The distinction between interconnection service and transmission service is the primary structural feature of the North American power grid's regulatory architecture. While RTOs have successfully integrated these processes through the "Pool" paradigm and NRIS deliverability analysis, the legal wall between the two remains a stark reality in traditional jurisdictions. The "Second Study Shock" is not a failure of the system but a natural consequence of a path-based bilateral market.

As the grid continues to evolve, developers who understand the causal links between these regulatory silos will be best positioned to succeed. This requires moving beyond the "plug-in" mental model of the RTO world and embracing a more holistic, path-specific strategy in traditional regions. Ultimately, the success of the energy transition will depend on the ability of regulators and market participants to bridge this gap, moving from a bifurcated system of reactive studies to a more unified model of proactive, regional grid expansion. For the modern energy professional, mastering this labyrinth is not just a technical requirement—it is a strategic imperative.3

Recommended next steps

Works cited

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