Q1. Could you start by giving us a brief overview of your professional background, particularly focusing on your expertise in the industry?

I have spent over 12 years in the power sector, focusing on both thermal and renewable energy projects, power trading, regulatory compliance, and business development. My career began in 2013 as a Graduate Engineer Trainee at Bhadreshwar Vidyut Pvt Ltd, where I coordinated a 2x150 MW coal-based thermal power plant in Gujarat, overseeing BTG and BOP activities from supply contracts through to commissioning. Between 2015 and 2017, I worked as a Senior Engineer at OPG Power Generation Pvt Ltd, managing a 420 MW thermal project in Tamil Nadu. My responsibilities included executing power purchase agreements, facilitating open access trading, managing captive supply and revenue generation, and coordinating with SLDC for scheduling and dispatch.

From December 2021 to November 2024, I worked as a Certified Energy Manager at OPG Power Ventures PLC. In this role, I was responsible for monthly power sales operations, invoicing, debtor analysis, energy accounting, and supporting new business development. I also managed legal actions through NCLT and arbitration for defaulting industrial and commercial consumers. Since November 2024, I have been a Manager (Business Development) at Refex Group in Chennai, where I focus on group captive and third-party power sales through open access, renewable project execution, including land and connectivity, asset acquisitions, and ISTS connectivity with CTU and STU.

My core expertise is in regulatory affairs under the Electricity Act, Tariff Policy, and Green Energy Open Access rules, as well as open access facilitation, vendor management, and project protocols for both thermal and renewable energy. As a Certified Energy Manager (BEE, 2021), I have led initiatives in energy efficiency, sustainability, and compliance, ensuring accurate project expenditure reconciliation and the smooth execution of PPAs. I am committed to supporting India's energy transition by connecting established thermal operations with the growth of renewables.

Q2. How have Open Access regulations evolved recently in Tamil Nadu, Karnataka, and other leading states, and what regulatory changes are expected in the next 2-3 years that could impact captive renewable energy projects?

Open Access regulations have evolved considerably since the introduction of the 2022 Green Energy Open Access Rules by the Ministry of Power. These rules reduced the eligibility threshold to 100 kW, enabled centralized processing, and promoted non-discriminatory access to green energy. By mid-2025, 27 states had notified GEOA regulations. States such as Karnataka, Tamil Nadu, Maharashtra, Gujarat, and Andhra Pradesh have led the way, accounting for over 70% of renewable open access capacity additions between FY 2018 and 2022.

Karnataka has been a frontrunner, with KERC issuing the Open Access Regulations 2025 in March 2025. These regulations clarified terms for existing consumers and generators, including green open access applicants, and focused on streamlining approvals and reducing wheeling charges to encourage intra-state renewables. Tamil Nadu introduced its Green Energy Open Access Regulations in September 2025, mandating non-discriminatory intra-state access for green power and including provisions for banking and cross-subsidy surcharges to support discom revenues. Maharashtra and Andhra Pradesh have aligned with GEOA through amendments in 2023 and 2024, expanding eligibility for off-site solar and allowing unlimited access durations. Gujarat, however, still has higher transmission charges, which have slowed its progress.

Looking ahead to 2025-2028, several key changes are expected. The August 2025 amendments to Renewable Purchase Obligations will introduce new categories such as solar and other renewables, set revised multi-year targets, and require mandatory compliance for captive fossil fuel cogeneration users. These changes could raise RPO targets to 40-50% by 2028, which will directly benefit captive renewables by encouraging green sourcing. The Bureau of Energy Efficiency's revised Renewable Consumption Obligation notification in August 2025 will set binding targets for open access consumers and captives, with penalties for non-compliance. This will accelerate adoption but will also require improved metering infrastructure. States like Rajasthan are integrating Battery Energy Storage System mandates for firm power, which can help address intermittency for captives but may increase upfront costs. Overall, these developments will open up markets but may also create compliance challenges for smaller captives. Harmonized IS

Q3. How is competition evolving between open access renewable power buyers and traditional utilities within key states like Tamil Nadu and Karnataka, and what are the implications for power tariffs, contract structures, and market liberalization?

Competition is increasing as commercial and industrial buyers use GEOA to achieve cost savings, which is reducing the discom market share in high-load states such as Tamil Nadu and Karnataka. Together, these states account for about 40% of India's 3.8 GW solar open access additions in the first half of 2025. In Tamil Nadu, TNERC's 2025 rules allow industries above 50 kW to access green open access easily, enabling them to avoid TANGEDCO's higher tariffs of ₹6-8 per kWh by sourcing renewables at a landed cost of ₹3-4 per kWh. This has led discoms to introduce green tariff adders of ₹0.50-1 per kWh to retain 20-30% of the eligible load. Karnataka's KERC 2025 framework also allows BESCOM and other ESCOMs to compete through bundled green supply. However, open access consumers, such as IT parks, have shifted 15-20% of their demand to third-party sellers, which has pushed utilities to reduce wheeling charges by 10-15% and offer more flexible banking options.

These trends are leading to tariff convergence, with open access green power undercutting grid rates by 20-30 percent. This is prompting discoms to adopt hybrid models with renewable energy mandates, which should help stabilize tariffs at ₹4-5 per kWh by 2027. Contract structures are shifting toward 15-25 year power purchase agreements with escalation clauses of 2-3 percent annually and take-or-pay provisions. Buyers with larger volume commitments are able to secure volume discounts. Market liberalization is also accelerating through cross-state GEOA, with ISTS connectivity supporting pan-India bidding. By 2028, open access could account for 25 percent of commercial and industrial consumption. However, surcharges of 5-10 percent of energy could slow growth if not rationalized, which may encourage utilities to move toward more competitive tenders.

Q4. In the context of open access, how is competition influencing the structure and outcomes of utility-scale, captive, and hybrid power supply tenders? What emerging patterns do you observe in buyer preferences, contract tenures, and pricing strategies within these segments?

Competition in open access tenders is driving a shift toward firm, dispatchable power. In FY2024, there were 69 GW of issuances, exceeding the 50 GW target, with hybrids making up 25 percent of the total compared to 20 percent for pure solar. Buyers are prioritizing reliability due to grid volatility. Utility-scale tenders, such as SECI's 6 GW solar-hybrid in the first quarter of 2025, focus on competitive bidding with viability gap funding. These tenders have achieved 80 percent award rates, although there have been delays in signing PPAs due to developer financing challenges. Captive tenders are centered on group models with a 26 percent ownership threshold, and 1-2 GW have been awarded in Karnataka and Tamil Nadu for intra-state solar, using back-to-back PPAs to reduce wheeling risks. Hybrids are integrating 20-40 percent battery energy storage for round-the-clock supply, which has increased award premiums by 10-15 percent for firm power.

Emerging patterns

Buyers prefer hybrids with storage (9.5 GW tenders in Q1 2025, 67% standalone ESS) for 24/7 dispatch, favoring developers with proven ISTS evacuation. Contract tenures extend to 25 years for stability, with 5-10 year break clauses for flexibility. Pricing strategies include two-part tariffs (₹2.5-3/kWh fixed + variable) and escalating bids (discounted 5-10% for hybrids), driving average solar discovery at ₹2.4/kWh in Q2 2025—down 74% YoY—while hybrids command ₹3-3.5/kWh premiums. Captives see volume-based pricing (₹0.10-0.20/kWh rebates for >50 MW), signaling a shift to outcome-based tenders prioritizing ESG metrics.

Q5. What are the current barriers to scaling captive renewable power projects, and what regulatory or technological developments could help overcome these?

Scaling captive renewable energy projects faces several challenges. Grid integration delays have stalled more than 50 GW nationally, which is double the figure from late 2024. Evacuation approvals can take 12-18 months due to congested transmission lines in states like Tamil Nadu and Karnataka. High upfront costs of ₹4-5 crore per MW for solar hybrids are a barrier for small and medium enterprises. This is further complicated by high financing premiums of 10-15 percent for non-recourse debt and land acquisition issues, which cause 20-30 percent of project delays. Regulatory differences, such as varying state surcharges of 5-12 percent and penalties for RPO non-compliance, add 10-20 percent to landed costs. Technological intermittency limits captive utilization to 60-70 percent without storage. Societal factors, including community resistance to land use, also slow progress toward the 292 GW solar target.

To address these barriers, regulatory streamlining is essential. Extending ISTS waivers to 2028 with a 25 percent taper can support 20 GW of hybrid captive projects. Harmonized Renewable Consumption Obligation rules for FY2025-2030 will enable GEC trading for compliance. Technological improvements, such as modular battery energy storage systems with costs reduced by 20 percent to ₹3 crore per MWh in 2025, and AI-optimized inverters that can achieve 85 percent utilization, can help manage intermittency. These advances are supported by PLI schemes for domestic manufacturing. Faster approvals through single-window portals, with a target of three months, and access to green bonds at 7-8 percent financing rates could unlock 10 GW of capacity each year, supporting the goal of 500 GW of non-fossil generation.

Q6. What market and regulatory trends are driving the uptake of green building certifications linked to captive renewable power consumption, and how do these influence corporate procurement decisions?

The adoption of certifications such as IGBC and LEED is increasing rapidly, with 20 percent year-on-year growth in the first half of 2025. This is being driven by Renewable Consumption Obligation mandates, which require 29.91 percent renewable energy consumption in FY2025, rising to 43 percent by FY2030. Captive renewable energy contributes to energy efficiency points, typically earning 10-15 credits. Market trends include pressure from ESG investors, with corporates procuring 5 GW of renewable energy through captives in the first half of 2025 to secure certification premiums, which can result in a rental uplift of ₹5-10 per square foot. Green leases are also becoming more common, requiring 50 percent renewable energy for Platinum ratings. The expansion of GEOA is enabling bundled procurement, and over 600 MW of renewable energy certificates have been registered for offsets.

These factors are influencing procurement decisions by encouraging companies to prioritize long-term captive arrangements of 15-20 years over spot purchases, in order to secure verifiable renewable energy attributes. In the second quarter of 2025, 70 percent of deals included GEC clauses to ensure audit-proof compliance. Corporations, especially in IT and real estate, are choosing hybrids to support consistent green claims, which can reduce Scope 2 emissions by 30-40 percent and enhance brand value. By 2027, corporate renewable energy procurement is expected to reach 15 GW, with 40 percent linked to certification requirements.

Q7. If you were an investor looking at companies within the space, what critical question would you pose to their senior management?

As an investor, I'd ask: "Given the 50+ GW stalled RE capacity from grid and regulatory delays, what specific mitigation strategies—such as diversified ISTS pipelines, BESS hedging, or state-level advocacy partnerships—does your firm have in place to ensure 90%+ project commissioning timelines over the next 3 years?