Stability and resilience must go hand in hand with grid expansion: Dastur Energy
- May 30, 2025
Dastur Energy is a trusted advisor to governments and industries worldwide on the clean energy transition. Known for its innovative thinking and deep expertise, the company is sought after globally. Atanu Mukherjee, CEO of Dastur Energy, in this conversation with Venugopal Pillai, addresses the complex challenges of integrating renewable energy into power grids. Drawing on both learnings from abroad as well as global best practices, Mukherjee emphasizes that achieving India’s ambitious renewable energy goals will require a strong technology, economics and policy framework—one that reduces costs, improves system reliability, and fosters the development of domestic capabilities.
With such large-scale injection of renewables into the power grid, what is the biggest challenge for transmission planners today?
The overall challenge lies in aligning the timing, location, sequencing, and scale of renewable capacity additions with the expansion of grid infrastructure. While India is witnessing a rapid surge in solar and wind installations, the development of enabling infrastructure—such as long-distance transmission lines and substations—often lags behind, taking several years to complete. This gestation mismatch is critical: renewable projects come online much faster than the ultra-high voltage (UHV/EHV) transmission systems required to evacuate their power. Equally important, renewable capacity addition must be holistically planned and sequenced alongside investments in cost-effective firm power and storage to preserve grid stability, maintain reliability, and contain retail electricity costs. These interdependencies impose region-specific limits on renewable penetration, depending on renewable intermittency, grid capacity, the flexibility of firm power, demand patterns, and the availability of ancillary grid resources.
In India, like in many other parts of the world, inadequate transmission capacity has emerged as a major bottleneck—particularly in solar- and wind-rich regions that are located far from demand centers. Persistent challenges such as right-of-way constraints and delays in land acquisition continue to hinder the timely development of transmission infrastructure. As one industry report aptly observes, the “low gestation period of renewables vis-à-vis transmission is a key challenge,” since bulk intermittent power often needs to be evacuated over long distances before the supporting grid infrastructure is in place.
In practical terms, this means that planners must anticipate both the location and scale of future renewable capacity additions and accelerate the rollout of initiatives like the Green Energy Corridors well ahead. States such as Rajasthan and Gujarat have already faced solar curtailment due to transmission delays, underscoring the urgency of the issue. The National Electricity Plan (NEP) now calls for multi-trillion-rupee investments in new ISTS lines, but these plans must be matched by timely execution. The bottom line: planning must be forward-looking and long-term, or renewable deployment will continue to outpace the grid’s ability to integrate it—along with the complementary resources needed to ensure reliability and cost-effectiveness.
“From a distribution standpoint, low load factors also affect the financial health of discoms. With fixed infrastructure costs to recover over a smaller base of energy sales, the strain on their finances increases.”
Renewable energy generation typically works on low capacity-utilization (PLF). How does this affect the economics of T&D networks?
Low plant load factors (typically 20–30 percent for solar and wind) mean that transmission and distribution (T&D) assets linked to renewables are often underutilized compared to those serving conventional power. Simply put, if a transmission line operates only part of the time, its cost per megawatt-hour delivered increases significantly. Studies have raised concerns that building dedicated “green corridors” for such variable usage can be costly—one estimate suggests that renewable-dedicated transmission could add more than Re.1 per kWh to current average costs. For example, a 2,000 MW line built to serve solar generation may carry full load only during peak sunlight hours, resulting in a high per-unit cost of delivery. Moreover, such low utilization can lead to stranded assets, where utilities must continue paying interest and maintenance on infrastructure that remains idle for much of the day.
From a distribution standpoint, low load factors also affect the financial health of discoms. With fixed infrastructure costs to recover over a smaller base of energy sales, the strain on their finances increases. This dynamic has already led to repeated ramp-downs of India’s surplus coal-fired Thermal Power Pool in response to rising solar generation—yet discoms remain liable for the fixed costs of these underutilized thermal assets.
In short, in absence of adequate T&D and complementary resources, the intermittency of renewables drives curtailment leading to negative location specific marginal prices—which undermines the economic efficiency and viability of both the renewables and the T&D system.
“Pumped storage hydropower systems can economically store energy for 10 hours or more and also provide critical ancillary services. However, their deployment is geographically constrained to sites with suitable elevation differences or dual reservoirs.”
Can energy storage solve these problems? How do batteries and pumped hydro fit in?
Storage can play a valuable role in managing renewable intermittency—but it is not a panacea. Utility-scale batteries have benefited from steep cost declines in recent years, with current prices ranging from approximately $100 to $500 per kWh, making them increasingly viable for short-duration balancing. Several Indian states, including Rajasthan, are now exploring multi-gigawatt battery storage installations. For example, a recent analysis estimated that a 6 GW/4.25 hour battery system (25.5 GWh) in Barmer could cost around Rs.21,675 crore—cheaper than an equivalent HVDC link and with a much shorter construction timeline.
Battery energy storage systems (BESS) are well-suited for absorbing excess midday solar generation and supplying evening peak demand, helping reduce both curtailment and the need to transport power over long distances. However, batteries still offer only a few hours of storage and require large upfront capital. They are ideal for intra-day energy shifting, but not for bridging multi-day or seasonal lulls in wind or solar availability.
For longer-duration needs, pumped storage hydropower (PSH) remains the dominant global solution, accounting for about 94% of installed large-scale storage capacity—over 200 GW worldwide. PSH systems can economically store energy for 10 hours or more and also provide critical ancillary services. However, their deployment is geographically constrained to sites with suitable elevation differences or dual reservoirs, and they typically involve long lead times. In India, while new PSH projects are underway, progress is slow and location-dependent.
Importantly, storage—whether batteries or PSH—is just one of several flexibility solutions needed to support a high-renewables grid. As highlighted by NREL, batteries are only part of the toolkit. Expanding transmission infrastructure and enhancing flexible thermal generation capacity may not only be more cost-effective, but necessary. A balanced approach is essential: utility-scale storage, flexible thermal plants (including fast-ramping peakers), advanced grid inverters, and demand response – all have complementary roles to play. Each option comes with trade-offs in terms of cost, scalability, and lead time. Pumped hydro offers economical bulk storage but is not universally deployable; batteries can manage daily fluctuations but cannot address weekly or seasonal variability. An optimally diversified and context-specific flexibility strategy is therefore crucial for grid reliability and cost efficiency.
“Germany provides a compelling example: nearly 95 percent of its new solar and wind capacity is connected to the distribution grid. This has required investments in smart meters, local controls, and advanced relay systems.”
Grid stability is a major concern with variable renewables. How do we ensure a reliable yet cost-effective system? Does planning have to go down to the discom level?
Stability and resilience must go hand in hand with grid expansion. On the transmission side, India is deploying technologies that replicate the lost inertia traditionally provided by spinning generators. Synchronous condensers, STATCOMs, and HVDC converters with fast-response controls are increasingly being installed to stabilize voltage and frequency. Grid codes are also being updated to require renewable energy sources to provide essential services such as reactive power support. While these additions improve system stability, they also add to system costs—making cost-effectiveness a matter of carefully optimizing which technologies are deployed where.
At the same time, a significant share of renewable growth is occurring on the distribution side of the grid, which has historically had limited flexibility and visibility. This calls for bottom-up planning led by discoms, which must forecast how rooftop solar, electric vehicles, agricultural pumps, and other distributed assets are reshaping local load profiles. Feeders and substations must be designed accordingly, based on granular, location-specific data.
Germany provides a compelling example: nearly 95 percent of its new solar and wind capacity is connected to the distribution grid. This has required investments in smart meters, local controls, and advanced relay systems. India is beginning to follow a similar path. Initiatives like the PM-Surya Ghar scheme are driving the deployment of smart meters, while feeder-level studies are helping make distribution grids more transparent and manageable. Every discom will eventually need a detailed, high-resolution model of its own network—down to the feeder and substation level—to anticipate and address local congestion and instability.
Advances in substation and monitoring technologies are also enhancing grid stability. Indian utilities are adopting drones, high-resolution imaging, and AI-based analytics for predictive maintenance of high-voltage substations and transmission lines, helping reduce outage risks. On the power quality side, the use of phasor measurement units (PMUs) enables real-time detection of voltage and frequency deviations, allowing operators to take corrective action before failures escalate into blackouts.
Ultimately, cost-effectiveness in modern grid planning comes from striking the right balance: expanding infrastructure where needed to meet demand, while also investing in grid intelligence to optimize asset use and defer costly upgrades. Localized solutions such as microgrids and distributed storage can be deployed more effectively when discoms have clear, data-driven plans. This integrated top-down and bottom-up planning approach—combining interstate transmission with granular distribution-level foresight—is critical to building a resilient, flexible, and economically sustainable power system.
“Variable renewables can be integrated but only with coordinated investment in grid infrastructure and complementary resources—including storage, interconnectors, demand response, and flexible generation.”
Are there lessons to learn from global markets that have promoted renewable energy?
Absolutely. Every major region that has pursued aggressive renewable energy targets has encountered similar challenges—though with varying emphasis based on local conditions. Their experiences offer important lessons for India as it scales up renewable integration.
Germany: Germany has pushed renewable penetration beyond 40 percent while maintaining one of the most reliable grids in the world. However, it has also relied heavily on less flexible backup generation such as coal and gas, due to the high intermittency of wind and solar in the region. This reliance, combined with significant renewable integration costs, has contributed to German retail electricity prices exceeding €0.40/kWh (over ₹35/kWh)—among the highest globally. Key lessons include the importance of massive and ongoing transmission investments (e.g., north–south HVDC corridors for wind), modernization of distribution grids, and smart meter deployment. Germany is also piloting local energy markets to manage bidirectional power flows. While curtailment still occurs during low demand, Germany’s grid stability remains world-class. The trade-off, however, is clear: integration at scale without adequate planning can drive up consumer prices substantially.
Texas (ERCOT): Texas leads the U.S. in wind power with nearly 30 percent penetration and is the most successful example of a grid that has maintained relatively stable retail electricity prices while integrating renewables —around $0.11/kWh (₹9/kWh). Its success stems from early transmission planning through the Competitive Renewable Energy Zones (CREZ) program, which connected wind-rich West Texas to demand centers. Despite this, wind supply has grown faster than transmission capacity, leading to frequent curtailments and even negative pricing. Flexible backup remains essential—over half of Texas’s power still comes from gas-fired generation. The state’s approach highlights the need for transmission investment, flexible and dispatchable gas capacity, and growing use of storage for ancillary services. Batteries are now being co-located with wind and solar assets, a strategy India should emulate in its renewable hubs.
California: California’s “duck curve” illustrates a different challenge: midday solar oversupply followed by a steep evening ramp in demand. This requires conventional plants to cycle down and then ramp up quickly—a serious strain on system reliability. California has responded with large-scale battery deployment and demand response programs, including time-of-use pricing to incentivize load shifting. Retail electricity prices, however, have risen to over $0.30/kWh (₹25/kWh), partly due to the high costs of managing intermittency without sufficient firm generation and transmission capacity. The lesson for India is that managing daily variability requires proactive tools—batteries, flexible generation, and pricing reforms—to avoid costly supply shortfalls.
Denmark: Denmark is a global leader in flexibility, with over 50 percent of its electricity coming from wind. Its success lies in extensive use of interconnectors—its transmission capacity with neighbors like Norway, Sweden, and Germany nearly matches its own generation capacity. These links allow Denmark to export surplus wind and import hydropower during low-wind periods. Domestically, Denmark employs smart meters, dynamic pricing, and a centralized “DataHub” that enables aggregators to shift loads in real time. Combined heat and power (CHP) plants and heat pumps are also used to absorb excess electricity. However, these benefits come with high system costs; electricity prices exceed €0.35/kWh (₹30/kWh), driven by substantial infrastructure investments and energy taxes.
The Netherlands: Netherlands is focusing on offshore wind and advanced interconnections. Grid operator TenneT is building subsea HVDC links and deploying sophisticated control systems to manage integration. Urban flexibility is also a focus, with community batteries and smart EV charging in cities like Amsterdam. This dual strategy—cross-border trade and local resilience—offers a balanced model for integrating renewables in space-constrained or high-density regions.
Across all these cases, one clear insight emerges: variable renewables can be integrated but only with coordinated investment in grid infrastructure and complementary resources—including storage, interconnectors, demand response, and flexible generation. These systems show that high renewable penetration, if not carefully planned and sequenced, can result in escalating retail power prices and system stress.
For India, the takeaway is to go beyond just building more transmission lines. A successful strategy must combine flexible firm generation, smarter grid technologies, and market mechanisms that price and reward flexibility. Each region within India must tailor solutions to its resource profile, demand patterns, and grid readiness—balancing affordability, reliability, and sustainability as renewables scale.
“Rather than investing in a large transmission corridor, it may be more economical for a state to develop a medium-voltage distribution ring with battery storage to integrate local renewables.”
You mentioned bottom-up discom planning earlier. Can you elaborate?
Yes. Traditionally, India’s power system planning has followed a top-down approach—projecting national or state-level peak demand and planning generation and transmission accordingly. However, with the rapid rise of distributed and variable renewable energy sources, most of the variation and complexity is now emerging at the distribution level. Rooftop solar, localized wind clusters, industrial solar parks, agricultural loads, and electric vehicles are all changing the demand and supply profile at the feeder and substation levels.
This shift calls for a bottom-up, discom-centric planning framework. Each distribution utility should build a detailed model of its network—accounting for feeder-level loads, distributed energy resources, future EV growth, agricultural pump usage, and other local factors. With this data, discoms can use optimization tools to design the least-cost mix of solutions: local generation, energy storage, targeted grid upgrades, or demand-side measures.
For instance, rather than investing in a large transmission corridor, it may be more economical for a state to develop a medium-voltage distribution ring with battery storage to integrate local renewables. Similarly, a discom might determine that scaling up rooftop solar reduces peak demand enough to defer or avoid costly substation upgrades. We’re already piloting this type of granular, scenario-based planning in select states, incorporating projections of customer behavior, technology adoption, and localized flexibility options.
This approach is similar to the Integrated Distribution Planning methods used by several U.S. utilities, which combine engineering models with economic optimization at the local level. The key benefit is efficiency—avoiding overbuilt infrastructure by identifying where localized, flexible solutions (such as microgrids, feeder-level automation, or community storage) can meet system needs more cost-effectively. Ultimately, a bottom-up view complements national and state-level planning by aligning investment with actual distribution-level needs.
“Dynamic pricing, coupled with a regulatory framework for demand response aggregators, would help incentivize flexible loads and distributed energy participation. This is particularly important as renewable penetration increases and variability becomes a central operational challenge.”
What policy recommendations would you make to expedite power transmission infrastructure development, especially for RE integration?
India has made significant strides in renewable energy integration through policies such as competitive renewable auctions and the Green Energy Corridors initiative. However, achieving the targets laid out in the National Electricity Plan 2023—especially integrating over 500 GW of renewables by 2030—will require sustained policy momentum and reform across multiple dimensions of grid development.
One of the most pressing challenges remains the delay in right-of-way clearances and land acquisition for transmission infrastructure. A single-window clearance system, supported by centralized coordination between state and central agencies, could help streamline this process. Standardized compensation mechanisms and pre-designated transmission corridors would further reduce project lead times.
At the same time, India needs stronger long-term market signals to make both generation and grid investments viable. Enforcing renewable purchase obligations (RPOs) more effectively and ensuring the availability of long-term power purchase agreements (PPAs) are essential to making projects bankable and encouraging transmission development ahead of renewable capacity additions.
Smart grid investments at the distribution level must also be prioritized. As much of the renewable generation, especially solar, is increasingly embedded at lower voltages, distribution utilities will need real-time visibility and control capabilities. Mandating smart meter rollouts, supporting feeder-level grid modernization projects, and integrating automation and monitoring tools will enable discoms to better manage variability and demand at the local level.
Crucially, the grid of the future must be flexible. India should accelerate the development of ancillary service markets for frequency regulation, spinning reserves, and ramping capabilities. Dynamic pricing, coupled with a regulatory framework for demand response aggregators, would help incentivize flexible loads and distributed energy participation. This is particularly important as renewable penetration increases and variability becomes a central operational challenge.
The current tariff framework also needs reform to fairly allocate the costs of grid upgrades and supporting infrastructure like storage. A more dynamic approach to tariff-setting—whether through cost-reflective pricing, performance-linked incentives, or a blend of CAPEX and OPEX recovery—can attract the capital needed to build reliable transmission systems. Investors must have visibility into how grid investments will be recovered over time.
Scaling up transmission capacity also means ensuring that the supply chain—from cables and conductors to transformers and HVDC components—can meet demand. This calls for aligned policies to boost domestic manufacturing, streamline procurement processes, and use blended finance models where needed to support early-stage investments.
Ultimately, planning and execution must be coordinated. Transmission infrastructure needs to be built in parallel with renewable generation, not after. This requires integrated planning at both national and state levels, using data-driven tools and scenario analysis to forecast where renewable capacity will be located and how best to evacuate it.
It is the ongoing and integrated optimisation and sequencing of renewable capacity, transmission capacity, firm and flexible generation capacity, ancillary services, and other complementary resources that maximizes renewable penetration at the lowest cost while minimizing carbon emissions.
“There is no single technology or strategy that ensures grid balance in a renewables-integrated future. Rather, it is the integration of a portfolio of solutions.”
Finally, are there other technologies or strategies—beyond energy storage and HVDC—that you would like to highlight for grid balancing?
Certainly. In addition to HVDC expansion and energy storage, demand-side management and flexible generation are critical components of a resilient, renewable-friendly grid. India is beginning to pilot demand response programs in industrial states, where large consumers are compensated for shifting their load away from peak hours. With the right market mechanisms, this can be scaled significantly. Controllable loads such as smart appliances and electric vehicle (EV) charging infrastructure can further enhance grid flexibility. In fact, several pilot projects are exploring vehicle-to-grid (V2G) applications, turning EVs into a distributed storage resource that can respond to grid needs in real time.
On the generation side, enhancing the flexibility of conventional assets is equally important. Many coal-fired units in India are now required to cycle up and down more frequently, placing both technical and economic strain on older plants that were not designed for flexible operation. Upgrading these units to improve their ramping capabilities represents a practical and immediate strategy to support grid balancing. At the same time, newer gas-fired plants—or syngas-fired generators based on coal gasification—are being explored for their ability to start up quickly and provide fast-response balancing capacity. These flexible thermal assets can play a vital role in integrating variable renewable energy, ensuring reliability while supporting the transition to an affordable lower-carbon power system.
We are also closely tracking technologies such as synchronous condensers, which provide valuable system inertia, and early efforts around hydrogen blending in gas-fired plants as a potential decarbonization pathway for firm generation in the future. These solutions, while emerging, can contribute meaningfully to grid stability and emissions reduction over time.
Importantly, the “soft” side of grid modernization must not be overlooked. Investments in grid communication systems, forecasting, and real-time analytics are essential to unlocking the value of variable renewables. Improved forecasting of wind and solar output reduces uncertainty, while better scheduling practices—such as intraday markets and hour-ahead dispatch—can minimize imbalances and optimize system performance.
This is the direction that advanced markets like Denmark have taken: developing dynamic control-room tools and market platforms that enable all participants—generators, discoms, and consumers—to respond flexibly to real-time grid conditions.
In summary, there is no single technology or strategy that ensures grid balance in a renewables-integrated future. Rather, it is the integration of a portfolio of solutions. At Dastur, we emphasize this systems-level approach: expanding the high-voltage transmission backbone (including ±800kV HVDC links), strengthening distribution networks, deploying advanced grid technologies, and building responsive market frameworks. A critical component of this strategy is maintaining flexible thermal firm generation capacity—such as modernized coal, gas, and syngas-based plants—which can ramp quickly to balance variability, provide dispatchable power, and supply essential grid inertia. With thoughtful planning and policy alignment, India can achieve its ambitious renewable energy goals while preserving grid reliability and cost-efficiency.
