Network Upgrade Costs for Solar and Wind: Why Renewables Pay 10x More to Connect

Every utility-scale solar and wind developer knows the interconnection queue is broken. Average wait times now exceed five years. Withdrawal rates have reached historic highs. But there is a quieter crisis embedded within the queue backlog that kills more projects than procedural delays: network upgrade costs. These are the transmission system modifications — new substations, reconductoring, transformer upgrades, relay replacements — that an RTO determines are necessary to reliably interconnect a generator to the grid. And for renewable energy projects, these costs have become staggering.

According to Berkeley Lab's analysis of interconnection costs, the median network upgrade cost for solar projects that completed the interconnection process is $253 per kilowatt. For standalone battery storage, it is $335/kW. For natural gas generators, it is $24/kW. That is not a rounding error. Solar developers are paying more than ten times what gas plants pay to connect to the same transmission system. And network upgrades account for approximately 75% of total interconnection costs — dwarfing the interconnection facilities (gen-tie lines, metering equipment, protection systems) that developers can engineer and budget with relative precision.

This disparity is not the result of regulatory discrimination against renewables. It is a structural consequence of where renewable projects are located, how the transmission system was built, and how cost allocation works under the cluster study process mandated by FERC Order 2023. But understanding the cause does not reduce the financial exposure. For developers, the question is practical: how do you identify and manage network upgrade cost risk before it consumes your project economics?

Why renewables pay more: the structural cost gap

The 10x cost disparity between solar and gas interconnection is driven by three reinforcing factors.

1. Location mismatch

The transmission system was built over decades to serve load centers and large thermal generators. Coal plants, nuclear plants, and gas-fired peakers were sited near demand — in or adjacent to metropolitan areas with robust transmission infrastructure. When a 500 MW gas plant interconnects at a substation that was designed to handle 2,000 MW of thermal generation, the incremental network upgrades required are often minimal. The transmission headroom already exists.

Solar and wind projects, by contrast, are sited where the resource is strongest — which is typically where the transmission infrastructure is weakest. Utility-scale solar concentrates in rural areas with high irradiance, cheap land, and favorable permitting. Onshore wind concentrates in the Great Plains, the Midwest, and Appalachian ridgelines. These are precisely the areas where the existing transmission system was never designed to export gigawatts of generation capacity. When 3,000 MW of solar tries to interconnect at substations built for 200 MW of local load, the network upgrades required to move that power to demand centers are enormous: new 345kV or 765kV transmission lines, substation rebuilds, transformer bank additions, and extensive relay and protection system upgrades.

2. Cluster concentration effects

Under FERC Order 2023, RTOs study interconnection requests in clusters rather than serially. All projects that file during a given application window are studied together, and the network upgrades triggered by the cluster are allocated across the projects in that cluster based on their proportional contribution to the need for each upgrade.

The problem is that renewable projects cluster geographically. Developers identify the same high-irradiance counties, the same wind corridors, the same substations with apparent available capacity. When 50 solar projects all target the same point of interconnection (POI) in the same cluster window, the aggregate transmission impact is massive — and the per-project cost allocation reflects it. Each individual project may be 200 MW, but the cluster study evaluates the cumulative 10,000 MW impact on the transmission system. The upgrades required to accommodate 10,000 MW at a single node can exceed $1 billion, and that cost is divided among the surviving projects in the cluster.

3. The survivor penalty

This leads to what experienced developers call the survivor penalty. When a cluster study identifies $500 million in network upgrades and allocates those costs across 30 projects, each project's share is manageable. But when 20 of those 30 projects withdraw — because their own allocated costs are too high, because they lost financing, or because they failed site control requirements — the remaining 10 projects absorb the full $500 million. Their per-project allocation doubles or triples. This triggers a cascading withdrawal cycle: higher costs cause more withdrawals, which cause even higher costs for the remaining projects, which cause more withdrawals.

Berkeley Lab's Queued Up 2025 report documents this dynamic in stark terms: 77% of projects that entered the interconnection queue between 2000 and 2023 ultimately withdrew. In 2024 alone, a record 112 GW of generation capacity withdrew from interconnection queues nationwide. The survivor penalty is not hypothetical — it is the dominant outcome.

Network upgrade costs by RTO

The cost landscape varies significantly across RTOs, driven by differences in transmission topology, queue volume, cost allocation methodology, and the stage of FERC Order 2023 implementation. The following table summarizes the current state as of Q1 2026.

PJM: the highest-stakes market

PJM's Transition Cycle 1 is processing approximately 46 GW of generation through 2026, making it one of the largest simultaneous cluster studies ever conducted in the United States. The sheer volume means that network upgrade costs are being allocated across an enormous set of projects — but also that the total transmission investment required is unprecedented. PJM's 13-state footprint includes some of the most congested transmission corridors in the country, particularly in the PJM East region (New Jersey, Maryland, Delaware) and the AEP/Dominion zones where solar development is concentrated.

Developers in PJM should expect network upgrade cost estimates to arrive at the System Impact Study phase, with refinements at the Facilities Study. Projects that receive upgrade allocations exceeding $50 million face a difficult calculus: proceed and hope that other projects withdraw (reducing their allocation), or withdraw early and limit financial exposure to forfeited deposits. The Decision Point structure under FERC Order 2023 makes this an explicit, time-bounded choice. For more on PJM's specific requirements, see PJM Site Control Requirements in 2026.

MISO: LRTP as a potential cost relief valve

MISO presents a unique dynamic. The Long Range Transmission Planning (LRTP) initiative is the most ambitious proactive transmission investment in any RTO. Tranche 2.1, approved in late 2025, authorizes $21.8 billion for 3,631 miles of new 765kV backbone transmission across MISO's footprint. This investment is not driven by specific generator interconnection requests — it is system-level infrastructure designed to accommodate the clean energy transition at scale.

For developers, the LRTP creates a geographic lottery. Projects that happen to be located near LRTP corridor endpoints — where new 765kV substations are being built — may see dramatically lower network upgrade costs because the backbone capacity they need is being built independently of their interconnection request. Projects located far from LRTP corridors see no benefit. The upgrade costs for a 300 MW solar project in central Indiana near a planned LRTP substation could be $10 million. The same project 80 miles away, connecting to a legacy 138kV line with no LRTP upgrades planned, could face $80 million in upgrades.

The implication for site selection is clear: developers in MISO should overlay LRTP Tranche 2.1 corridor maps with their prospective project sites before committing capital to land acquisition. A parcel that is 5 miles from a planned LRTP substation is fundamentally different from one that is 50 miles away, even if the solar resource and land cost are identical.

CAISO: surviving the filter

CAISO's Cluster 15 process produced the most aggressive filtering in any RTO: 347 GW of interconnection requests were screened down to 68 GW of projects that met the viability criteria. The developers who survived that filter — by demonstrating site control, posting deposits, and meeting technical requirements — now face a more manageable queue. With fewer projects in the cluster, the per-project share of network upgrades is lower than it would have been in a 347 GW study.

However, "lower" is relative. CAISO's transmission system faces fundamental constraints in moving renewable generation from the southern deserts and Central Valley to coastal load centers. The Path 26, Path 15, and Tehachapi corridors are chronically congested, and network upgrades in these areas involve long-lead-time, high-cost transmission projects. Developers in CAISO should not assume that surviving the Cluster 15 filter guarantees affordable interconnection. It means the competition for limited transmission capacity is more focused, but the underlying transmission constraints remain.

The withdrawal trap: how upgrade costs create a death spiral

The interaction between network upgrade costs and project withdrawals is the single most destructive dynamic in the interconnection process. It works like this:

1. A developer enters the queue with a 200 MW solar project, targeting a POI where 30 other projects are also clustered.
2. The cluster study identifies $600 million in required network upgrades for the entire cluster.
3. The developer's initial allocation is $20 million — manageable within the project economics.
4. After the System Impact Study results are published, 15 of the 30 projects withdraw because their allocated costs are too high.
5. The $600 million in upgrades is now allocated across 15 surviving projects instead of 30. The developer's allocation doubles to $40 million.
6. Five more projects withdraw because $40 million breaks their economics.
7. The developer's allocation is now $60 million. The project is no longer viable. The developer withdraws.
8. The remaining projects absorb an even larger share. More withdraw. The cycle repeats.

This is not a theoretical scenario. It is the dominant pattern in every RTO queue. The 77% historical withdrawal rate and the record 112 GW of withdrawals in 2024 are the aggregate outcome of thousands of individual projects caught in this cost escalation cycle. Projects that enter the queue without a rigorous assessment of upgrade cost risk are gambling that enough other projects will survive to keep their allocation manageable. That gamble fails more often than it succeeds.

The financial penalties for withdrawal compound the damage. Under FERC Order 2023, withdrawal after the System Impact Study triggers forfeiture of study deposits and, in most RTOs, allocation of a share of network upgrade costs incurred to date. A developer who withdraws a 200 MW project after discovering $60 million in upgrade costs may still owe $2 million to $5 million in forfeited deposits and withdrawal penalties. For a detailed breakdown of withdrawal penalties by RTO, see Interconnection Queue Withdrawal Penalties by RTO.

How site control strategy shapes upgrade cost exposure

Most developers think of site control as a compliance requirement — a box to check before filing an interconnection application. It is that. But site control is also the most powerful lever developers have for managing network upgrade cost risk, because site control decisions determine the point of interconnection, and the point of interconnection determines the upgrade costs.

The relationship is direct. A project's network upgrade costs are driven almost entirely by its location on the transmission system. Two identical 200 MW solar projects — same technology, same capacity factor, same developer — can face upgrade costs that differ by an order of magnitude depending on their POI. A project interconnecting at a 345kV substation with 500 MW of available headroom may face $5 million in upgrades. The same project interconnecting at a 138kV radial line with no headroom may face $80 million.

This means that the site selection process — which parcels to lease, which POIs to target, which land packages to assemble — is not just a land cost optimization. It is an interconnection cost optimization. And developers who validate site control early gain a critical advantage: the ability to evaluate multiple POI options before committing capital to a specific location.

Early validation enables POI shopping

A developer who has validated site control across multiple candidate project areas can compare POIs based on transmission capacity, congestion history, planned transmission investments (like MISO's LRTP), queue concentration at each POI, and historical upgrade cost data from prior cluster studies. This comparison is impossible if the developer has already committed to a single land package before evaluating interconnection costs.

The optimal workflow is:

• Identify 3-5 candidate POIs based on preliminary transmission analysis.
• Secure site control options (not executed leases) across parcels near each candidate POI.
• Run preliminary interconnection studies or consult RTO queue data to estimate upgrade costs at each POI.
• Commit capital (convert options to leases, post deposits, file applications) only at the POI with the most favorable upgrade cost profile.
• Release options at POIs where upgrade costs are prohibitive.

This approach requires managing site control across multiple candidate locations simultaneously, which adds complexity. But the alternative — committing to a single POI and discovering $50 million in upgrade costs at the System Impact Study — is orders of magnitude more expensive.

Proximity to existing transmission infrastructure

The most reliable predictor of low network upgrade costs is proximity to robust existing transmission infrastructure. Projects that interconnect at or near high-voltage substations (230kV and above) with significant available capacity consistently receive lower upgrade cost allocations than projects that require new transmission builds to reach the grid.

Site control validation should therefore include a transmission proximity analysis: for every parcel in the project footprint, what is the nearest substation rated at 230kV or above? What is the available capacity at that substation based on publicly available queue data and transmission planning documents? Are there planned transmission upgrades (like LRTP projects) that will increase capacity in the area within the project's development timeline?

Cluster density risk

Developers should also assess the concentration of competing projects at their target POI. RTOs publish queue data showing the number and aggregate capacity of projects targeting each substation or POI. A POI where 5 GW of solar is already queued will almost certainly trigger more expensive network upgrades than a POI where 500 MW is queued, regardless of the underlying transmission capacity.

The cluster density at a POI also determines the survivor penalty risk. If 20 projects are clustered at a single POI and half withdraw, the remaining projects absorb the full upgrade cost. If only 3 projects are at a POI and one withdraws, the cost reallocation is less severe. Choosing POIs with moderate queue density — enough projects to share costs, but not so many that the total upgrade bill becomes unmanageable — is a risk management strategy that starts with site selection.

A practical checklist for managing network upgrade cost exposure

For developers entering an RTO queue in 2026, the following checklist represents the minimum diligence path for managing network upgrade cost risk.

1. Map candidate POIs to transmission capacity. Before securing any site control, identify all substations within a reasonable gen-tie distance of your candidate parcels. Assess available capacity using RTO queue data, OASIS reports, and transmission planning documents.
2. Analyze queue concentration at each POI. Download the RTO's active queue data. Calculate the aggregate MW targeting each candidate POI. Flag POIs where total queued capacity exceeds 3x the substation's available headroom — these are high-risk for expensive upgrades.
3. Check for planned transmission investments. In MISO, overlay your candidate sites against LRTP Tranche 2.1 and 2.2 corridor maps. In CAISO, check the TPP (Transmission Planning Process) for approved projects. In PJM, review the RTEP (Regional Transmission Expansion Plan) for planned upgrades near your POIs.
4. Secure options at multiple POIs before committing. Use option-to-lease instruments to control land near 2-3 candidate POIs. Do not convert options to executed leases until you have preliminary upgrade cost estimates.
5. Model the survivor penalty. For each candidate POI, calculate your upgrade cost allocation under three scenarios: (a) all clustered projects survive, (b) 50% withdraw, (c) 75% withdraw. If your project economics fail under scenario (b), the POI is too risky.
6. Budget for upgrade costs in your financial model. Network upgrades are ~75% of total interconnection costs. Do not treat them as a rounding error. Model upgrade costs as a range ($X to $3X) and ensure your project economics work at the high end of the range.
7. Set a walk-away threshold before filing. Determine the maximum network upgrade cost you can absorb before the project becomes uneconomic. If the System Impact Study results exceed that threshold, withdraw immediately — do not wait for the Facilities Study hoping costs will decrease.
8. Validate site control coverage early and continuously. Site control deficiencies discovered after filing trigger costly delays and potential application rejection. Validate coverage against RTO-specific thresholds before every milestone. See FERC Order 2023 Coverage Thresholds by RTO for the complete reference.
9. Monitor withdrawal patterns in your cluster. After cluster study results are published, track which projects in your cluster are withdrawing. Each withdrawal changes your cost allocation. If the withdrawal pattern is accelerating, recalculate your allocation weekly.
10. Engage transmission planners early. Many RTOs offer pre-application consultations or informational interconnection studies. These are not binding, but they provide directional estimates of upgrade costs at specific POIs. A $25,000 informational study that reveals $80 million in likely upgrades is the best investment you will ever make.

The bottom line

Network upgrade costs are not a secondary consideration in utility-scale renewable development. They are the primary financial variable that determines whether a project is viable. At $253/kW for solar and $335/kW for storage, upgrade costs routinely exceed the cost of the generation equipment itself. A 200 MW solar project with $50 million in upgrade costs is carrying $250/kW in interconnection costs alone — before a single panel is installed.

The developers who navigate this landscape successfully are the ones who treat site control not as a compliance checkbox but as a strategic tool for managing interconnection cost risk. They secure options at multiple POIs. They analyze transmission capacity before committing to land. They model the survivor penalty before filing applications. And they walk away from POIs where the upgrade cost math does not work, even if the land is cheap and the solar resource is strong.

The interconnection queue will continue to be the primary bottleneck for renewable energy deployment in the United States. Network upgrade costs will continue to be the primary reason projects fail within that queue. The developers who understand this — and who build their site control strategy around it — will be the ones whose projects actually reach commercial operation.

Sources

• Berkeley Lab — Queued Up 2025: Characteristics of Power Plants Seeking Transmission Interconnection
• Berkeley Lab — Interconnection Cost Analysis
• FERC Order 2023 — Interconnection Final Rule Explainer
• MISO — Long Range Transmission Planning (LRTP)
• PJM Manual 14H — Generation and Transmission Interconnection Process

Related articles

• Interconnection Queue Withdrawal Penalties by RTO — Detailed breakdown of withdrawal penalties and deposit forfeiture across all seven markets.
• FERC Order 2023 Site Control Coverage Thresholds by RTO and Stage — The cross-RTO reference table for coverage requirements at every queue milestone.
• FERC Order 2023 Compliance in 2026: Why This Is the Year — Full market analysis of why 2026 is the inflection point for compliance investment.