Explainer: Power markets, permitting & interconnection — the concepts, the economics, and the decision checklist

As of late 2024, the U.S. interconnection queue contained over 2,600 gigawatts of proposed generation capacity—more than double the entire installed capacity of the existing American grid. The average wait time to connect a new power project has ballooned to approximately five years, with completion rates hovering below 20%. For founders, developers, and investors navigating the clean energy transition, understanding the intricate mechanics of power markets, permitting regimes, and interconnection processes is no longer optional—it is the determining factor between bankable projects and stranded capital.

Why It Matters

The energy transition's success hinges not merely on deploying renewable generation assets but on successfully integrating them into existing grid infrastructure. In North America, the gap between announced clean energy projects and operational capacity has widened dramatically, creating what industry analysts term the "interconnection bottleneck." According to Lawrence Berkeley National Laboratory's 2024 analysis, projects entering the queue in 2023 faced median wait times of 4.8 years—up from 2.1 years in 2015. This prolonged timeline fundamentally alters project economics, strains developer balance sheets, and threatens the achievement of state and federal decarbonization mandates.

The Inflation Reduction Act (IRA) of 2022 catalyzed unprecedented investment interest in clean energy, with over $270 billion in announced manufacturing and generation investments through 2024. However, this capital cannot translate into operational megawatts without corresponding reforms to interconnection and permitting processes. FERC Order 2023, finalized in July 2023, represents the most significant federal intervention in interconnection policy in two decades, mandating cluster-based study processes and financial readiness requirements designed to reduce speculative queue entries.

Canada faces parallel challenges. The Canadian Electricity Association projects that achieving net-zero electricity by 2035 requires doubling installed capacity, yet provincial interconnection processes remain fragmented, with Ontario's Independent Electricity System Operator (IESO) reporting queue backlogs exceeding 15 GW. The bankability of projects—their ability to secure debt financing based on predictable revenue streams—depends critically on interconnection certainty, permitting clarity, and offtake contract terms that lenders can underwrite.

Key Concepts

Power Markets: Organized wholesale electricity markets operate in approximately two-thirds of the U.S. through Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs). These entities—including PJM, CAISO, ERCOT, MISO, SPP, NYISO, and ISO-NE—administer day-ahead and real-time energy markets, capacity markets (where applicable), and ancillary services procurement. Market design determines revenue streams available to generators, influencing project economics and financing structures. In vertically integrated regions (primarily the Southeast and parts of the West), utilities control generation, transmission, and distribution, requiring developers to negotiate bilateral power purchase agreements.

Permitting: The regulatory approval process for energy projects encompasses federal, state, and local jurisdictions. Federal permits may include NEPA environmental reviews, endangered species consultations (Section 7 of the ESA), wetlands permits (Clean Water Act Section 404), and FAA determinations for tall structures. State-level requirements vary dramatically—California's CEQA process can extend timelines by 18-36 months, while Texas permits utility-scale solar in under 12 months in most counties. Local zoning, setback requirements, and conditional use permits add additional layers of uncertainty.

CAPEX (Capital Expenditure): The upfront investment required to develop and construct energy projects, including equipment procurement, engineering, interconnection upgrade costs, and construction labor. Interconnection network upgrade costs—charges assessed to generators for transmission system reinforcements—represent increasingly significant CAPEX components, with some projects facing upgrade allocations exceeding $100 million. These costs are typically non-refundable and must be committed before construction financing closes.

OPEX (Operating Expenditure): Ongoing costs of operating generation assets, including maintenance, insurance, land lease payments, property taxes, and grid services charges. For renewable projects, OPEX typically ranges from $10-25/kW-year for solar and $25-45/kW-year for wind, with battery storage adding $5-15/kW-year.

Ancillary Services: Grid services beyond bulk energy supply that maintain system reliability, including frequency regulation, spinning reserves, voltage support, and black start capability. These services create additional revenue streams for projects capable of providing them, with battery storage increasingly capturing value in fast-responding regulation markets. ERCOT's ancillary services market exceeded $4 billion in 2024.

Grid Reliability: The ability of the electric system to deliver power continuously within acceptable voltage and frequency tolerances. Reliability standards, enforced by NERC and regional entities, drive interconnection study requirements and may mandate costly system upgrades. The 2024 reliability assessments from NERC flagged ten regions as facing elevated risk of supply shortfalls during extreme weather events.

Transition Plan: A comprehensive strategy for shifting from fossil-fuel-dependent energy systems to low-carbon alternatives. Corporate transition plans increasingly specify procurement timelines, additionality requirements, and geographic constraints that influence project siting and offtake negotiations.

What's Working and What Isn't

What's Working

FERC Order 2023 Implementation: The transition to cluster-based interconnection studies, now being implemented across RTOs, promises to reduce speculative queue entries by requiring $5,000/MW readiness deposits and demonstrated site control. Early indicators from PJM's 2024 transition window suggest a 40% reduction in new applications compared to the final months of the serial study process. The "first-ready, first-served" philosophy prioritizes commercially mature projects.

State-Level Permitting Reform: Several states have enacted meaningful reforms. New York's Build Public Renewables Act streamlines siting for projects on state-owned land. Michigan's 2024 reforms established a 12-month shot clock for renewable project permits exceeding 50 MW. Texas continues to demonstrate that minimal permitting barriers accelerate deployment—ERCOT added 7.4 GW of utility-scale solar in 2024 alone.

Standardized Interconnection Agreements: ISO-NE and MISO have developed template interconnection agreements that reduce negotiation timelines and provide financing certainty. These standardized documents enable lenders to evaluate multiple projects using consistent assumptions, reducing transaction costs and accelerating financial close.

Hybrid Project Configurations: Co-located solar-plus-storage projects increasingly share interconnection capacity, maximizing the value of existing queue positions. CAISO data indicates hybrid projects achieve 15-25% higher capacity factors than standalone solar while avoiding separate interconnection applications.

What Isn't Working

Transmission Planning Disconnects: Generation interconnection queues and regional transmission planning processes remain poorly coordinated. Projects may secure interconnection service only to face curtailment when regional transmission constraints emerge. The absence of proactive transmission buildout—anticipating generation rather than reacting to it—creates stranded queue positions and unpredictable deliverability.

Network Upgrade Cost Allocation: The current framework assigns network upgrade costs to individual generators, creating first-mover penalties that discourage development in transmission-constrained areas. A 500 MW solar project may face $150 million in upgrade costs that benefit subsequent projects contributing nothing. FERC has initiated proceedings to examine alternative cost allocation methodologies, but reforms remain years away.

Cumulative Impact Review Delays: As renewable development accelerates, permitting agencies face capacity constraints in processing cumulative environmental impact analyses. Bureau of Land Management reviews for Western solar projects averaged 37 months in 2024, with staffing levels inadequate for application volumes. Avian and bat mortality studies for wind projects add 12-24 months in migratory corridors.

Queue Attrition and Restudies: Despite readiness requirements, interconnection queues continue experiencing 70-80% attrition rates. Each withdrawal triggers restudies for remaining projects, extending timelines unpredictably. A project's interconnection cost estimate may double between initial study and facilities study completion, undermining financing assumptions.

Key Players

Established Leaders

NextEra Energy: The world's largest generator of wind and solar energy, with over 34 GW of operating renewable capacity across North America. NextEra's development pipeline exceeds 50 GW, and its FPL utility subsidiary operates Florida's largest solar fleet.

Berkshire Hathaway Energy: Through subsidiaries including PacifiCorp and MidAmerican Energy, Berkshire controls over 15 GW of renewable generation with $30 billion committed to grid modernization and clean energy deployment through 2030.

Invenergy: The largest privately-held renewable developer in North America, with over 30 GW of projects developed and a current pipeline exceeding 45 GW across wind, solar, storage, and natural gas.

Pattern Energy: A leading independent renewable energy company with 7 GW of operating capacity and 35 GW in development, including major transmission projects like SunZia that address delivery constraints.

AES Corporation: A global power company with significant North American operations, AES has committed to achieving net-zero emissions by 2040 and operates over 12 GW of renewable and battery storage capacity.

Emerging Startups

Pearl Street Technologies: A software company developing AI-powered interconnection study tools that reduce utility engineering workloads and accelerate queue processing. Backed by $25 million in Series A funding.

Gridware: Developing low-cost grid monitoring sensors and analytics to improve distribution system visibility, enabling faster interconnection approvals for distributed energy resources.

Nira Energy: A queue management and interconnection consulting platform that helps developers navigate complex study processes and optimize portfolio queue positions.

Paces: An AI-driven platform automating permitting research and application preparation, reducing developer soft costs and accelerating entitlement timelines.

Station A: An origination platform connecting commercial and industrial offtakers with renewable project developers, streamlining the path from lead to signed PPA.

Key Investors & Funders

Brookfield Renewable Partners: One of the world's largest investors in renewable power, with over $100 billion in assets under management and active development across North American markets.

BlackRock Climate Infrastructure: The infrastructure arm of the world's largest asset manager, deploying billions in renewable generation and grid infrastructure through its Global Energy and Power Infrastructure fund.

Generate Capital: A leading sustainable infrastructure investor with over $10 billion deployed, focusing on distributed energy, storage, and grid modernization projects.

The U.S. Department of Energy Loan Programs Office: Administering over $400 billion in loan authority under the IRA, LPO has accelerated financing for utility-scale renewables, transmission, and emerging grid technologies.

Canada Infrastructure Bank: A federal Crown corporation with $35 billion in investment authority, CIB has prioritized clean power investments including major transmission and generation projects.

Examples

1. SunZia Transmission Project (Southwest U.S.): The largest renewable energy infrastructure project in American history, SunZia represents a 550-mile, 3,000 MW transmission line connecting New Mexico wind resources to Arizona and California markets. After 17 years in permitting, the project achieved financial close in 2023 with $11 billion in total investment. Pattern Energy's persistence through multiple BLM reviews, military airspace negotiations, and endangered species consultations demonstrates both the promise and frustration of major transmission development. The project will deliver 4,500 MW of wind generation upon completion in 2026.

2. MISO's Long-Range Transmission Plan Tranche 1 (Midwest U.S.): MISO's board approved $10.3 billion in transmission investments in 2022, representing the largest regional transmission plan in U.S. history. The 18 projects spanning nine states will add 1,800 miles of high-voltage transmission, enabling 53 GW of new renewable interconnections while improving regional reliability. Cost allocation required years of stakeholder negotiation, ultimately assigning 80% of costs to load-serving entities based on projected benefits. Construction timelines extend through 2030, illustrating the multi-year gap between planning approval and operational capacity.

3. Ontario IESO Expedited Connection Process (Canada): Facing 15+ GW of queue backlog and accelerating demand from electrification and data center growth, Ontario's IESO implemented an expedited connection process in 2024 prioritizing projects with executed offtake contracts and demonstrated commercial readiness. The program targeted 5 GW of accelerated connections by 2027, with early results showing 40% reduction in study timelines for qualifying projects. The approach demonstrates how commercial readiness screening can differentiate speculative from bankable projects without formal queue reforms.

Action Checklist

• Assess interconnection queue status and estimated study timelines before committing development capital to specific sites
• Secure site control documentation meeting RTO/ISO readiness requirements prior to submitting interconnection applications
• Budget 20-30% contingency for interconnection network upgrade costs beyond initial study estimates
• Engage specialized interconnection consultants for complex queue positions involving affected system studies
• Map all federal, state, and local permitting requirements and establish critical path schedules with 6-month buffers
• Evaluate hybrid configurations (solar-plus-storage) to maximize interconnection queue position value
• Structure offtake agreements with timing provisions accommodating interconnection uncertainty
• Monitor FERC proceedings on interconnection reform and cost allocation for policy risk exposure
• Develop relationships with transmission owners and utilities responsible for interconnection studies
• Consider late-stage queue position acquisitions as alternatives to greenfield development in congested markets

FAQ

Q: How long does the typical interconnection process take in North American wholesale markets? A: Timelines vary significantly by RTO/ISO and queue position. As of 2024, median interconnection timelines range from 3.5 years (ERCOT) to 5+ years (PJM, MISO). Projects entering queues in 2024-2025 under new cluster study procedures may experience somewhat shorter timelines—estimated at 3-4 years—though actual performance data remains limited. Developers should assume 4-5 year timelines for financial modeling and consider contingency structures in offtake agreements.

Q: What are the most significant cost drivers in interconnection? A: Network upgrade costs represent the largest and most unpredictable expense. These charges—which fund transmission system reinforcements required to accommodate new generation—range from $0 to >$300/kW depending on location and existing system conditions. Projects in constrained areas or at the end of weak radial lines face the highest upgrade allocations. Cluster study processes under FERC Order 2023 aim to improve early-stage cost visibility, but estimates remain subject to 50%+ variance between initial and final determinations.

Q: How do permitting challenges differ between wind, solar, and battery storage projects? A: Solar projects typically face the most straightforward permitting pathway, with primary constraints involving agricultural land conversion, wetlands, and visual impact concerns. Wind projects encounter more complex federal reviews due to avian and bat mortality considerations, radar interference studies, and noise setback requirements. Battery storage projects face evolving fire safety codes and hazardous materials regulations that vary by jurisdiction. Transmission infrastructure—often required to deliver renewable generation—faces the most challenging permitting due to multi-jurisdictional routing and eminent domain requirements.

Q: What financing structures work best for projects with interconnection uncertainty? A: Development-stage financing typically relies on sponsor equity and convertible notes until interconnection certainty improves. Bridge facilities may fund interconnection deposits and upgrade payments. Construction financing generally requires executed interconnection agreements, known upgrade costs, and at minimum a facilities study completion. Tax equity investors typically require commercial operation within specific windows, making interconnection delays particularly problematic. Some developers utilize back-leverage structures that allow partial equity exits at interconnection milestones, reducing duration risk exposure.

Q: How should developers evaluate queue positions for acquisition versus greenfield development? A: Late-stage queue positions with completed facilities studies and known upgrade costs command significant premiums ($10,000-50,000/MW in attractive markets) but eliminate 3-4 years of development timeline and study uncertainty. Evaluation criteria should include: upgrade cost finality, affected system study status, transmission owner relationship quality, offtake contract assignability, and remaining permitting requirements. Greenfield development remains preferable in uncongested areas with strong transmission access, while queue acquisitions offer advantages in transmission-constrained markets with deep offtaker demand.

Sources

• Lawrence Berkeley National Laboratory. "Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection as of the End of 2023." April 2024.
• Federal Energy Regulatory Commission. "Improvements to Generator Interconnection Procedures and Agreements." Order No. 2023, July 2023.
• North American Electric Reliability Corporation. "2024 Long-Term Reliability Assessment." December 2024.
• U.S. Department of Energy. "National Transmission Needs Study." October 2023.
• MISO. "Long Range Transmission Planning Tranche 1 Report." July 2022.
• S&P Global Commodity Insights. "U.S. renewable energy installations and interconnection queue analysis." January 2025.
• Canadian Electricity Association. "Powering Canada's Future: Vision 2050." November 2024.