Comparing Electric Planning Areas: The Grid-First Approach to Site Selection
- LandGate
- a few seconds ago
- 6 min read
For energy and data center developers, few decisions carry more downstream risk than site selection. Land cost, fiber access, and water availability all matter- but increasingly, the most important variable is electric infrastructure: who controls it, what the queue looks like, and how receptive the regulatory environment is to the on-site generation and storage configurations that modern data centers demand.
Comparing electric planning areas requires moving beyond simple utility service territory maps. To identify viable sites in a saturated market, technical developers must evaluate the financial physics of the grid: Available Transfer Capacity (ATC), injection/offtake feasibility, and the rising role of Behind-the-Meter (BTM) integration.
Understanding Electric Planning Areas in the U.S.
Electric Planning Areas in the United States are geographic regions designated for electric grid planning and coordination. The US grid is governed by a patchwork of overlapping frameworks- ISOs and RTOs, vertically integrated utility territories, and NERC reliability regions- each with distinct interconnection rules, queue dynamics, and policies toward behind-the-meter (BTM) resources. Understanding how these layers interact is foundational to making sound siting decisions.
ISOs and RTOs
Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) are the most consequential planning entities for large load customers and generation developers. They operate competitive wholesale markets, manage transmission planning, and administer the interconnection queue for new generation and large load additions within their footprints.
The major RTOs include PJM (Mid-Atlantic and Midwest), MISO (broader Midwest and South), ERCOT (Texas), CAISO (California), SPP (Great Plains), NYISO (New York), and ISO-NE (New England). Each runs its own interconnection study process with different timelines, cost allocation methodologies, and upgrade requirements. PJM and MISO, for instance, have both undergone significant queue reform in recent years under FERC Order 2023, shifting from serial to cluster-based study processes- a change that has materially altered project timelines and cost certainty for developers.
Vertically Integrated Utility Territories
Outside RTO footprints- primarily across the Southeast and parts of the West- vertically integrated utilities own generation, transmission, and distribution as a bundled service. States like Georgia, Alabama, Florida, and the Carolinas are largely served by utilities such as Duke Energy, Southern Company, and Dominion Energy operating under state public utility commission oversight rather than FERC wholesale market rules.
For data center developers, this distinction matters in several ways. Interconnection in these territories is governed by the utility's own tariff and state commission processes rather than FERC-jurisdictional RTO rules. Timelines and cost certainty can vary significantly. On the other hand, some vertically integrated utilities have been proactive in offering large-load tariffs and economic development rates tailored to hyperscale data center customers, which is a dynamic worth evaluating on a utility-by-utility basis.
NERC Reliability Regions
NERC (North American Electric Reliability Corporation) reliability regions, which are now largely administered through six regional entities, are the standards-setting and compliance layer of the grid. They don't govern interconnection directly, but they set the reliability standards that inform transmission planning and capacity adequacy requirements in each region. For developers modeling long-term power availability, understanding the applicable NERC regional entity (e.g., SERC Reliability, ReliabilityFirst, WECC) provides context for how the grid is planned and maintained around a prospective site.
How the Layers Interact
Large load projects can be complex. For example, a data center in northern Virginia sits within PJM's RTO footprint and is served by Dominion Energy as the distribution utility- meaning the developer navigates both PJM's transmission interconnection process and Dominion's distribution-level tariffs. A facility in Georgia might deal exclusively with Georgia Power (Southern Company) through the Georgia PSC, with no RTO layer involved. And a facility in Texas operates within ERCOT, which is islanded from the Eastern and Western Interconnections and not subject to FERC jurisdiction- creating a uniquely self-contained regulatory environment. Having superb data is key in navigating these complexities.
Major Interconnections: Eastern, Western, and ERCOT
The North American grid is divided into three major synchronous interconnections: Eastern Interconnection, Western Interconnection, and ERCOT (Texas). Within those, many RTO/ISO regions serve as large planning jurisdictions (CAISO, PJM, MISO, ISO-NE, SPP, etc.).
Interconnection | Major Planning Entities | Key Context for 2026 |
Eastern Interconnection | PJM, MISO, SPP, NYISO, ISO-NE, TVA, Duke | The largest system; characterized by mature wholesale markets but significant congestion at the "seams" between RTOs. |
Western Interconnection | CAISO, BPA, PacifiCorp, NV Energy | Transitioning with the expansion of CAISO's EDAM and SPP's Markets+; heavy focus on long-range HVDC to move renewable power. |
ERCOT (Texas) | Electric Reliability Council of Texas | A synchronous "island." Its independence from FERC (interstate commerce) allows for faster "connect and manage" interconnection but limits power imports. |
Interconnection Queue Dynamics: The Constraint That's Reshaping Site Selection
The interconnection queue is, at present, one of the most significant constraints on new development timelines across the U.S. grid. FERC's 2023 data indicated backlogs in excess of 2,000 GW of generation and storage nationally, which is a figure that reflects both the pace of renewable development and the serial bottlenecks baked into legacy study processes.
For data center developers, the relevant question isn't just queue depth in absolute terms- it's position, project type, and vintage. A large load interconnection request (rather than a generation request) follows a different process in most RTOs and may carry different upgrade cost exposure. Understanding the queue at the substation level- like which projects are ahead of you, what transmission upgrades they're triggering, and how network upgrade costs may be allocated- is essential due diligence that can make or break a project's economics.
PJM has faced particularly severe queue congestion, with multi-year study cycles and significant cost uncertainty driven by network upgrade requirements. Recent reforms under FERC Order 2023 are intended to address this through transition clusters, but near-term timelines remain challenging. MISO has similarly restructured its process and is working through a large transition queue. ERCOT, operating outside FERC jurisdiction, has its own interconnection process and has historically offered faster timelines, though rapid load growth in Texas is beginning to test that advantage. CAISO has significant renewable penetration and curtailment dynamics that require careful modeling for any generation-coupled development.
ATC and Injection/Offtake: The Feasibility Baseline
In a landscape where queues exceed construction timelines, Available Transfer Capacity (ATC) and Injection/Offtake are the metrics that matter.
Injection (Generation): Developers must model how new generation impacts the local node. If your injection causes thermal violations downstream, the resulting Network Upgrade Costs can kill a project's ROI.
Offtake (Data Centers): Data center developers are now performing proprietary power flow simulations to identify substations with immediate headroom.
The 2026 Reality: Developers use LandGate to identify specific nodes where ATC can support a massive step-load without triggering a regional transmission expansion.
Nodal Pricing and Congestion Risk
LMP (Locational Marginal Price) is the all-in cost of power at a specific node, and it varies wildly even within the same planning area:
LMP = Price{Energy} + Price{Congestion} + Price{Losses}
Technical developers use historical and forecasted congestion data to avoid “bottleneck" nodes that expose them to significant basis risk or high operational costs.
The Behind-the-Meter Pivot
According to JLL, approximately 30% of planned 2026 U.S. data center capacity is shifting toward Behind-the-Meter (BTM) resources like solar, wind, nuclear, and natural gas.
Queue Bypass: BTM solar and Battery Energy Storage Systems (BESS) allow facilities to secure "firm” power faster than a standard grid connection.
Load Flexibility: In planning areas with high peak-demand charges, BESS allows a data center to act as a grid stakeholder, providing frequency response and peak shaving.
How LandGate Streamlines the Comparison
Identifying the right site requires layering these regulatory frameworks onto the physical reality of the grid- where transmission lines are, where substations have available capacity, and where the interconnection queue is thinnest relative to existing infrastructure.
LandGate’s data enables developers to evaluate prospective sites against the actual state of grid infrastructure- not just the planning area designation- into a single interface:
Nationwide ATC Coverage: Access engineered DC/AC power flow models for over 60,000 substations.
Interconnection Queue Visibility: See exactly who is ahead of you in the cluster at the substation level.
BTM Feasibility: Instantly run 8760 generation profiles to see if solar+storage colocation pencils out for your specific site and view the location of power plants across the US.
Understanding electric planning area frameworks is the prerequisite. Executing on that knowledge at the parcel level is where LandGate's tools make the difference. Learn more about LandGate’s suite of tools for developers and book a demo with our dedicated team to see it in action:
