Case study: Power markets, permitting & interconnection — a city or utility pilot and the results so far

In 2024, the Lawrence Berkeley National Laboratory reported that 2,600 GW of generation and storage capacity sat waiting in US interconnection queues, roughly double the entire installed generating capacity of the country. The median time from interconnection request to commercial operation had stretched to 5.1 years, up from 2.1 years in 2010 (LBNL, 2025). Against this backdrop, a growing number of city and utility pilots across emerging markets and innovative US jurisdictions have begun testing streamlined permitting, fast-track interconnection, and reformed power market participation rules. Their results offer concrete evidence of what works, what fails, and what investors should monitor as the energy transition accelerates.

Why It Matters

The interconnection bottleneck is not a minor administrative inconvenience. It is the single largest barrier to deploying the clean energy generation and storage assets needed to meet global decarbonization targets. The International Energy Agency's 2025 World Energy Outlook estimated that permitting and interconnection delays will strand $420 billion in planned renewable energy investment between 2025 and 2030 if current timelines persist (IEA, 2025).

For investors, the permitting and interconnection landscape directly determines project risk, development timelines, and returns. A solar or wind project that secures grid connection in 18 months faces fundamentally different economics than one waiting 5 or more years. During extended queue periods, developers carry land lease costs, permitting expenses, and equipment supply agreements that erode project IRRs by 200 to 400 basis points. In emerging markets, where capital costs are higher and institutional frameworks less mature, the impact is even more pronounced.

City and utility pilots provide controlled environments to test reforms before scaling them to regional or national levels. These pilots generate the performance data, cost benchmarks, and regulatory precedents that enable broader policy adoption.

Key Concepts

Interconnection queue reform refers to changes in how grid operators process and prioritize requests from generators seeking to connect to the transmission or distribution grid. Traditional first-come-first-served queuing has created speculative backlogs where many projects in the queue never reach commercial operation, blocking viable projects behind them.

Fast-track permitting involves streamlined environmental review, consolidated agency approvals, and pre-designated zones where renewable energy development receives expedited authorization. This approach reduces timeline uncertainty without eliminating environmental protections.

Distributed energy resource (DER) market participation covers the rules enabling rooftop solar, battery storage, demand response, and other small-scale assets to sell energy, capacity, and ancillary services into wholesale or retail electricity markets.

Capacity market reform addresses how power markets value and compensate reliable generation capacity. Traditional capacity markets were designed around large thermal power plants and often create barriers for variable renewable energy and storage resources seeking to participate.

What's Working

ERCOT Fast-Track Interconnection in Texas

The Electric Reliability Council of Texas (ERCOT) has operated the fastest interconnection process among major US grid operators, with median connection timelines of 25 to 30 months for utility-scale projects, roughly half the national average. In 2023, ERCOT processed 197 GW of interconnection requests and connected 12.4 GW of new generation and storage capacity, more than any other US independent system operator (ERCOT, 2024).

The key design choices that enable this speed include: a simplified study process with a single comprehensive planning study rather than the multi-phase sequential studies used by PJM and MISO; financial deposits that escalate as projects advance through the queue, discouraging speculative applications; and a "ready to construct" milestone requirement that forces developers to demonstrate site control, equipment procurement, and financing commitments within 12 months of entering the queue. Projects that miss the milestone forfeit their deposits and queue position.

The results are measurable. Texas added more wind and solar capacity between 2020 and 2025 than any other US state, reaching 55 GW of installed renewable capacity. Battery storage deployment in ERCOT grew from 2.1 GW in 2023 to 8.7 GW by mid-2025. For investors, the accelerated timelines have translated to project-level IRRs that average 180 to 250 basis points higher than comparable projects in slower-moving ISOs, primarily due to reduced development carrying costs (Wood Mackenzie, 2025).

Colombia's Distributed Energy Market Opening

Colombia's Comision de Regulacion de Energia y Gas (CREG) launched a pilot program in 2022 allowing distributed energy resources under 5 MW to participate directly in the wholesale electricity market. The pilot, operating in the Caribe and Antioquia distribution service territories, enrolled 340 MW of distributed solar and 85 MW of battery storage by the end of 2024.

The pilot introduced simplified metering requirements (smart meters with 15-minute interval recording rather than revenue-grade metering stations), standardized interconnection agreements for systems under 1 MW (reducing legal costs from $15,000 to $25,000 per project down to a flat $2,500 application fee), and virtual power plant (VPP) aggregation rules allowing multiple small resources to bid collectively into the spot market.

Measured outcomes after two years show that participating DER owners earned average revenue of $45 to $65 per MWh, 30 to 40% above the regulated net metering rate. Grid reliability in pilot territories improved, with distribution-level outage minutes declining 12% as dispersed generation reduced dependence on transmission-connected supply. The program's success prompted CREG to announce nationwide expansion in January 2026, with a target of 2 GW of market-participating DER by 2028 (CREG, 2025).

India's Green Energy Open Access Reforms

India's Ministry of Power implemented the Green Energy Open Access (GEOA) rules in 2022, reducing the minimum capacity threshold for open access renewable energy procurement from 1 MW to 100 kW. The reform was piloted first in Gujarat, Maharashtra, and Karnataka before national rollout. By mid-2025, the number of open access renewable energy consumers in India had grown from approximately 4,800 to 31,000, representing 18 GW of contracted capacity (Ministry of Power India, 2025).

The Gujarat pilot demonstrated particularly strong results. The state streamlined its approval process from an average of 147 days to 38 days by creating a single-window clearance portal, eliminating the requirement for separate approvals from the state load dispatch center, the distribution utility, and the state electricity regulatory commission. Cross-subsidy surcharges, a major cost barrier to open access, were waived for green energy consumers through 2028 under the pilot terms.

For investors, the Indian open access reforms have created a $4.2 billion annual market for commercial and industrial renewable energy procurement. Corporate power purchase agreements (PPAs) under open access now account for 35% of all new renewable energy capacity additions in India, up from 12% in 2021.

What's Not Working

PJM Interconnection Backlog

Despite multiple reform attempts, PJM Interconnection, the largest US grid operator serving 65 million customers across 13 states, continues to struggle with queue congestion. As of January 2025, PJM's interconnection queue contained 300 GW of proposed projects, with estimated study completion timelines extending to 2029 for new applicants. The transition from a first-come-first-served queue to a clustered "first-ready-first-served" approach in 2023 was intended to accelerate processing, but the initial implementation created confusion among developers about documentation requirements, leading to a 40% application rejection rate in the first cluster window.

PJM's experience illustrates a common failure pattern: queue reforms that change the application process without simultaneously increasing study engineering capacity simply shift the bottleneck rather than eliminating it. PJM employed approximately 200 engineers for interconnection studies, a number that has not kept pace with the 300% increase in applications since 2020 (PJM Interconnection, 2025).

South Africa's Renewable Energy Procurement Delays

South Africa's Renewable Energy Independent Power Producer Procurement Programme (REIPPPP) was initially celebrated as a model for emerging market clean energy procurement. The program's first four bid windows (2011 to 2015) attracted $14 billion in investment and connected 6.3 GW of renewable capacity. However, the program stalled between 2015 and 2021 due to political opposition from the state utility Eskom and coal industry interests.

When bid windows resumed, developers faced a new challenge: the grid infrastructure built to support coal-fired generation was concentrated in Mpumalanga province, while optimal renewable energy resources are located in the Northern Cape and Eastern Cape. Interconnection to existing transmission infrastructure required 200 to 400 km of new transmission lines, with construction timelines of 4 to 7 years. Several Round 5 projects awarded in 2022 still lacked grid connection agreements as of early 2026, with developers carrying $380 million in cumulative pre-development costs on projects generating zero revenue (Meridian Economics, 2025).

Brazil's Net Metering Transition Friction

Brazil's regulatory transition from generous net metering (Lei 14.300/2022) to a cost-reflective tariff structure has created market uncertainty. The transition, which phases in grid usage charges for distributed generators between 2023 and 2028, caused a 45% decline in residential solar installations in 2024 compared to the rush of installations in 2022 ahead of the regulatory change. Developers who built business models around the original net metering economics have seen customer acquisition costs double as the value proposition shifted.

Key Players

Established Companies

• Enel Green Power: operates 60 GW of renewable capacity globally with active interconnection management across 30 countries
• AES Corporation: deployed 3.8 GW of battery storage integrated with grid interconnection, including projects in Chile and India
• Tata Power: leads open access renewable energy procurement in India with 5.4 GW of contracted capacity
• ISA CTEEP: operates 35,000 km of transmission lines in Brazil and manages grid interconnection processes across multiple states

Startups

• Pearl Street Technologies: provides AI-powered interconnection queue management software used by 45 US utilities to prioritize and accelerate viable projects
• Acacia Energy: operates virtual power plant aggregation in ERCOT, managing 1.2 GW of distributed resources for wholesale market participation
• ReNew Power: India-based developer with 13.4 GW of renewable assets leveraging open access market reforms for commercial and industrial offtake
• Grid United: develops inter-regional transmission projects to unlock interconnection capacity between US grid regions

Investors

• Brookfield Renewable Partners: committed $15 billion to renewable energy projects in emerging markets with active queue management strategies
• Climate Fund Managers: manages $1.2 billion focused on renewable energy and grid infrastructure in sub-Saharan Africa and Southeast Asia
• Actis: invested $12 billion in energy infrastructure across emerging markets since 2004, with dedicated interconnection risk assessment frameworks

Action Checklist

• Assess interconnection queue position and realistic timeline for any generation or storage investment, stress-testing project economics against 2x and 3x the quoted connection timeline
• Evaluate jurisdictions with proven fast-track permitting track records before committing development capital, comparing median connection timelines across grid operators
• For emerging market investments, verify that grid infrastructure capacity exists at the point of connection rather than relying on planned transmission expansion that may face its own permitting delays
• Monitor DER market participation reforms that create new revenue streams for distributed assets, particularly VPP aggregation rules and ancillary service eligibility
• Build regulatory transition risk into financial models for markets moving from net metering to cost-reflective tariffs
• Engage early with grid operators during project development to identify potential study delays and required grid upgrades before committing capital
• Diversify geographic exposure across multiple grid operator territories to reduce concentration risk from any single interconnection regime

FAQ

Q: How should investors evaluate interconnection risk when underwriting renewable energy projects? A: Interconnection risk assessment should include four dimensions: queue position and study phase status; the grid operator's historical completion rate (the percentage of projects entering the queue that reach commercial operation, which ranges from 14% in PJM to 35% in ERCOT); identified network upgrade costs and which party bears those costs; and the regulatory stability of the interconnection framework itself. Projects beyond the feasibility study phase with defined network upgrade costs and executed interconnection agreements carry materially lower risk than earlier-stage queue entries.

Q: Which emerging markets offer the most favorable permitting and interconnection conditions for renewable energy investment? A: As of 2026, India (following GEOA reforms), Colombia (following CREG's DER market opening), and Chile (with its established open access framework and strong transmission expansion program) offer the most investor-friendly conditions among major emerging markets. Key indicators include median permitting timelines under 12 months, transparent interconnection cost allocation, and demonstrated track records of connecting awarded projects within contractual deadlines.

Q: What is the financial impact of interconnection delays on project-level returns? A: Each additional year of interconnection delay typically reduces unlevered project IRR by 100 to 200 basis points, driven by ongoing land lease payments ($5,000 to $15,000 per MW per year), permitting maintenance costs, equipment storage or repricing risk, and financing commitment fees. For a 200 MW solar project with a $200 million capital cost, a 3-year delay beyond the planned commercial operation date can reduce equity returns from 12% to 7 to 8%, often below investor hurdle rates.

Q: How are virtual power plants changing the interconnection landscape? A: VPPs aggregate hundreds or thousands of distributed resources (rooftop solar, batteries, smart thermostats, EV chargers) into a single market participant, bypassing the traditional utility-scale interconnection process entirely. Each individual resource connects at the distribution level through simplified residential or commercial interconnection procedures that take weeks rather than years. The aggregated portfolio then participates in wholesale markets through the VPP operator. In ERCOT, VPPs now represent 4.2 GW of registered capacity and provided 2,100 MW of peak demand response during the August 2025 heat event.

Sources

• Lawrence Berkeley National Laboratory. (2025). Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection. Berkeley, CA: LBNL.
• International Energy Agency. (2025). World Energy Outlook 2025: Permitting and Grid Connection Challenges. Paris: IEA.
• Electric Reliability Council of Texas. (2024). 2024 State of the Grid Report: Interconnection and Resource Adequacy. Austin, TX: ERCOT.
• Comision de Regulacion de Energia y Gas. (2025). Evaluacion del Programa Piloto de Recursos Energeticos Distribuidos. Bogota: CREG.
• Ministry of Power, Government of India. (2025). Green Energy Open Access: Implementation Progress and Market Impact Report. New Delhi: Ministry of Power.
• PJM Interconnection. (2025). Interconnection Process Reform: First-Ready First-Served Transition Report. Norristown, PA: PJM.
• Meridian Economics. (2025). South Africa's Renewable Energy Programme: Grid Connection Challenges and Investor Impact. Cape Town: Meridian Economics.
• Wood Mackenzie. (2025). US Renewable Energy Project Economics: The Interconnection Timeline Premium. Edinburgh: Wood Mackenzie.