Q1. To begin, could you briefly describe your professional background across nuclear, hydro, and distribution, and the types of projects or operations where you’ve been most directly accountable for outcomes?

I have over 16 years of experience with NTPC Limited, spanning Nuclear, Hydro, and Power Distribution verticals. Across these roles, I have held direct accountability for project execution, pace of progress, quality of works, adherence to safety protocols, system reliability, and sustained performance improvement.

I began my career in nuclear power plant operations at NPCIL, on deputation from NTPC, working on PHWR-type reactors across multiple project sites. In this environment, procedural discipline, regulatory compliance, and zero-error execution were not just expectations, but core to my daily responsibilities.

I then spent more than a decade at a large hydro power project, where I was involved in the execution, commissioning, and O&M of high-value electrical assets. This included generators, transformers, protection systems, switchgears, and AC/DC networks besides multiple other electrical systems. In senior roles, I led large multidisciplinary teams and was directly accountable for zero forced outages, safety performance, and long-term asset reliability.

At present, I am working on a Distribution Sector Reform Project under the Government of India’s flagship RDSS programme. My role involves overseeing project execution with a clear objective of converting infrastructure investment into meaningful AT&C loss reduction and tangible improvements in power supply reliability even at remote and far-flung areas close to the International Borders.

Over the years, I have also been deeply involved in contracts management, vendor management, manpower management, budgeting, planning and technical services, along with several other organisational assignments.

 

Q2. What early warning signs tell you that a distribution project will not deliver the expected loss reduction despite being technically compliant?

One of the clearest early warning signs is when project reviews focus largely on asset installation progress, while giving little attention to changes in operational behaviour or enforcement effectiveness.

Many loss-reduction projects remain technically compliant—meters installed, feeders segregated, distribution transformers de-stressed, IT systems made live—yet outcomes fall short because field ownership, data usage, and accountability mechanisms remain weak. Another strong red flag is when energy audit data stabilises unrealistically early, which often points to estimation rather than genuine measurement.

Additional indicators include frequent scope changes, delayed integration between metering, billing, and collection systems, and weak coordination between utilities and contractors. When utilities rely heavily on contractors for operational decision-making instead of building internal capability, loss reduction rarely sustains beyond the defect-liability period.

 

Q3. In hydro and large electrical assets, which maintenance strategies appear robust on paper but tend to break down in real operating conditions?

Reliability-centred and condition-based maintenance strategies often look very strong on paper, but in practice these are susceptible to failures when baseline data quality and diagnostic capabilities are weak.

In hydro and other large electrical assets, strict adherence to OEM-recommended maintenance schedules, without factoring in actual operating history, can lead to both over-maintenance and missed early signs of degradation. Digital monitoring systems also tend to underperform when alarms are poorly rationalised, creating alarm fatigue rather than useful, actionable insights.

Another common failure point is when maintenance strategies are not supported by spare standardisation, logistics planning, and trained manpower. In real operating conditions, even well-designed maintenance philosophies break down during failures if execution readiness is not embedded into day-to-day operations.

 

Q4. Where do numerical protection, relay schemes, or switchgear upgrades materially improve reliability, and where do they introduce new operational complexity?

Numerical protection and modern relay schemes materially improve reliability by replacing obsolete electromechanical and static relaying systems. They enable faster fault clearance, improved sensitivity and selectivity, and more effective fault analysis.

At the same time, operational complexity increases when schemes are over-customised without proven operating history, or when they are supported by inadequate documentation, weak testing discipline, and insufficient operator training. Protection upgrades can sometimes introduce new failure modes due to poor coordination studies, firmware mismatches, or limited understanding of system interactions.

The determining factor, in my experience, is ownership. Reliability improves when the protection philosophy is simple, standardised, and clearly owned by the operating team. When protection is treated purely as an EPC deliverable rather than an operational system, long-term reliability risks increase despite the superiority of the technology.

 

Q5. What operational or process gaps typically undermine the benefits of technically sound billing and metering systems?

Technically sound billing and metering systems are most often undermined not by technology gaps, but by operational and process weaknesses, including:

• Poor data governance and ownership, where meter data validation, exception handling, and root-cause analysis are either inadequately defined or inconsistently executed.
• Weak integration between metering, billing, and customer operations, leading to delayed issue resolution, billing disputes, and gradual erosion of consumer trust.
• Inadequate field-to-system feedback loops, where installation quality, meter health, and communication failures are not systematically captured or acted upon.
• Lack of sustained O&M capability, reflected in limited post-deployment support, insufficient SLAs, and no performance-linked accountability beyond the initial rollout.
• Insufficient change management and skill transfer, leaving utility teams dependent on vendors and unable to fully leverage system capabilities for loss reduction and analytics.

When these gaps persist, even robust metering and billing platforms fail to deliver their intended outcomes, effectively shifting the problem from technology to operations rather than resolving it.

 

Q6. Which vendor or contract structures tend to look efficient initially but create long-term reliability or accountability issues?

Lump-sum EPC contracts with limited post-commissioning accountability often appear efficient at the outset, but they tend to create long-term reliability risks. When vendor incentives are tied mainly to installation or commissioning milestones, asset quality, documentation rigour, and long-term maintainability are frequently compromised. If an EPC contractor later becomes non-responsive or bankrupt, the entire project can become highly vulnerable to failures. Also, the project’s risk profile escalates sharply if the EPC contractor becomes non-responsive, confrontational, or financially insolvent.

On the other hand, fragmented contracting models, where metering, IT, and electrical works are awarded separately, commonly result in interface mismatches, extended critical paths, coordination gaps, diluted accountability, and higher lifecycle costs.

Contracts that lack performance-linked metrics, enforceable O&M obligations, and structured knowledge-transfer mechanisms eventually push operational risk back onto the utility after handover. Over time, this leads to reduced system reliability and rising lifecycle costs, despite the apparent benefit of lower upfront pricing.

This is why a rigorous approach to defining qualifying requirements is essential to mitigate post-award execution risks and downstream project challenges.

 

Q7. If you were advising senior leadership on where to deploy capital to improve distribution reliability and reduce losses, what operational question should they ask earlier, and what type of answer would concern you?

The operational question senior leadership should ask early is:

“Which operational parameters will actually change on the ground as a result of this investment, and who will be accountable for system performance and asset reliability five to ten years after commissioning, and how will that accountability be contractually enforced?”

Responses centred only around asset creation, technical superiority, lowest upfront cost, compliance milestones or contractual completion without clearly defining end-to-end performance ownership, measurable reliability outcomes, and post-commissioning accountability would be concerning. 

Further, if the responsibility for failures is diffused across multiple vendors and limited only to warranty periods, or disconnected from O&M incentives, it is a clear signal that operational risk will eventually revert to the utility.

If ownership, escalation mechanisms, and integration with daily operations are not clearly defined, investments are likely to improve infrastructure only on paper, while outcomes remain largely unchanged. The real value of capital deployment lies in how it changes field behaviour, decision rights, and enforcement capabilities.

 

Note

These perspectives are drawn from my direct accountability and hands-on experience across Nuclear, Hydro, and Distribution operations, where technical decisions were closely and consistently linked to progress, safety, quality, reliability, and financial outcomes.