Indian Petroplus

Offshore charter rates have structurally reset — and this time, they’re not slipping back. Offshore vessel charter rates have moved to a higher, durable base, marking a clear break from past boom-bust cycles. After rebounding sharply from post-2021 lows, rates have stabilised at elevated levels for over 12–18 months, with no signs of retracement. This is no longer a base-effect recovery. What matters now is the absence of decline — a powerful signal of a structural shift. A key driver: headline fleet numbers overstate real supply. Nearly 500–700 offshore vessels remain in cold lay-up globally, requiring heavy capital, regulatory upgrades and technical work to return. There is no visible intent to reactivate them. Strip these out, and utilisation is already at ~65–66%, close to historic peak levels of 70–72%. With limited headroom, even modest activity tightens availability and supports pricing power — especially in a market dominated by medium-to-long-term contracts. Crucially, new vessel ordering remains structurally weak. Years of capital restraint have left the orderbook thin and opaque, while fleet ageing continues. In India, offshore activity is resuming — but cautiously. Operators like RIL and Cairn are sequencing development well by well, guided by reservoir performance, recovery economics and capital discipline — not aggressive drilling campaigns. Despite limited visibility on incremental vessel demand, measured activity is proving sufficient. Utilisation remains firm and offshore earnings are already reflecting this resilience. Unlike the 2010–14 boom driven by cheap capital and fleet expansion, this cycle is built on scarcity, ageing assets and discipline. The real risk isn’t a near-term collapse — it’s future indiscipline if confidence leads to aggressive ordering. For now, restraint is holding. 🔗 Read more: indianpetroplus.com #Offshore #CharterRates #OffshoreVessels #OilAndGas #Shipping #IndiaEnergy #EandP #OffshoreServices #IndianPetroplus

What’s really going on at the top of IndianOil (IOCL)? Something unusual — and unsettling — is unfolding quietly inside India’s largest oil PSU. A key board-level post has been vacant for over six months, even as operational risk and asset exposure are at historic highs. ⬇️ #IndianOil #IOCL #OilAndGasIndia 1️⃣ The vacancy no one is explaining The post of Director (Pipelines) at IndianOil has remained vacant since 1 July 2025, following the retirement of the incumbent. This is not a peripheral role. It sits at the core of IOCL’s risk, safety, and operational governance. Yet there has been: • No full-time appointment • No public explanation • No visible urgency 2️⃣ Why pipelines are not “just another portfolio” IndianOil’s pipelines operate at pressures of ~100 kg/sq cm, cutting across: • Densely populated cities • Ecologically sensitive zones • Cross-border corridors These are among the highest-risk assets in India’s energy system — demanding specialised, continuous board-level oversight. 3️⃣ Officers are resisting dilution — not appointments The IndianOil Officers Association has formally warned against: • Clubbing pipelines with R&D • Merging it with planning or business development • Running the function via additional-charge arrangements Their concern is clear: pipelines are a discipline, not a transferable portfolio. 4️⃣ This is being flagged as a governance risk, not an HR delay According to officers, prolonged vacancies and role-mixing weaken: • Clear accountability • Leadership visibility • Safety governance under OISD norms In high-risk infrastructure, diluted responsibility can mean delayed decisions — and delayed decisions can have real-world consequences. 5️⃣ The timing makes the vacuum harder to justify IndianOil today operates: • 20,000+ km of crude, product, LPG & gas pipelines • Across 21 states & UTs • Installed capacity of ~130 MT oil and 49 mmscmd gas At the same time, pipeline throughput has crossed 100 million tonnes — an all-time high. Record volumes. Record expansion. But no full-time board lead for pipelines. 6️⃣ Expansion is accelerating, not slowing IOCL is executing 12 major pipeline projects (~2,200 km), with investments exceeding ₹20,000 crore. Strategic assets include: • Mundra–Panipat crude pipeline • India–Nepal cross-border product pipelines This is happening alongside refinery expansion, modernisation, and clean-energy bets — making dedicated board focus more critical, not less. 7️⃣ A quiet policy back-and-forth deepens unease • Interviews for the pipelines post were announced in Sept 2025, restricted to DoPT personnel • These were later postponed at the oil ministry’s request • An earlier proposal to abolish the pipelines (and R&D) director posts was reportedly rejected by the PMO To officers, this looks less like delay — and more like indecision or redesign behind closed doors. 8️⃣ Why this has been escalated to the top Copies of the officers’ communication have been marked to: • Prime Minister’s Office • Oil Secretary • Junior Oil Minister • IOCL Chairman That escalation signals a belief that this is systemic, not procedural. 9️⃣ The “spooky” part isn’t what’s happened — but what hasn’t • No transparent explanation for the vacancy • No clarity on whether restructuring is planned or abandoned • No visible alignment between rising asset risk and board architecture The unresolved question lingers: 👉 Is IndianOil merely slow — 👉 Or is its functional board design being quietly reworked? Until that’s answered, the unease is unlikely to fade. 🔗 Full deep-dive: indianpetroplus.com #PipelineSafety #CorporateGovernance #PSUWatch #OilAndGas #Infrastructure

Great Eastern Shipping’s offshore turnaround is coming without expansion. Q3 FY26 offshore earnings improved almost entirely due to higher utilisation across jack-up rigs and OSVs. Revenue days rose ~11% YoY, but segment revenue jumped ~39% and profits surged over 5× — a textbook case of operating leverage as fixed costs were absorbed. Importantly, this came with no new rigs, no OSV additions, and no balance-sheet stretch. Forward contract coverage into Q4 is tightening (near-full in several vessel classes), improving earnings visibility while capital discipline remains intact. Great Eastern is clearly treating the offshore upcycle as a cash-harvesting phase, not a capacity-expansion story — a late-cycle utilisation play, not an early-cycle bet. Full analysis: IndianPetroPlus.com #GreatEasternShipping #Offshore #OSV #JackUpRigs #ShippingStocks #OperatingLeverage

“CGD will overtake fertiliser in 2–3 years” is a bold call — but it rests on fragile assumptions. Yes, CGD volumes can mathematically double as GAs ramp up. But in practice, this is a CNG-heavy growth story, and CNG is the most policy-exposed part of the gas value chain. Fertiliser gas is subsidy-protected. CGD gas is price-sensitive and substitute-sensitive. LNG volatility hits CGD demand first — through slower conversions, lower running, and faster EV adoption in fleets. Add mobility politics: in polluted metros, policy can pivot from “cleaner fuel” to “zero tailpipe” faster than CGD models assume. Pipes and stations can be built. Affordability and policy alignment can’t be guaranteed. That’s where the overtake thesis is strongest on infrastructure — and weakest on economics. 🔗 Full analysis: indianpetroplus.com #CityGas #NaturalGas #CNG #LNG #GasDemand

A governance heavyweight steps in at HOEC — and the real power quietly shifts What’s unfolding at Hindustan Oil Exploration Company (HOEC) is not a routine leadership change. It’s a sequence — and in listed companies, sequences matter more than headlines. 🧵👇 HOEC has now seen three centres of authority weaken in succession: • A former MD exited (2023) • A sitting chairman resigned (2025) • The current MD has resigned — but remains until a successor is found (2026) This is not coincidence. It’s consolidation. Into this churn, the board has quietly appointed a former Gujarat Chief Secretary as chairman — a clear pivot away from upstream execution and toward governance, control, and institutional credibility. That choice is revealing. This is not an exploration veteran. Not a petroleum technocrat. But a state-facing administrator — the profile boards reach for when cash risk, counterparty stress, and scrutiny rise. Running in parallel is the unresolved HPCL refinery payment dispute, involving a B-80 crude sale worth hundreds of crores. For HOEC, this is not a footnote: • The receivable dominates trade balances • It exceeds quarterly profits • It strains cash visibility Even if resolved favourably, timing becomes a governance issue. Leadership churn accelerating while this dispute remains unresolved is not accidental. Formally, HOEC has no promoter. But control does not always follow ownership. A closer look shows a cluster of insider shareholdings — directors and related parties — large enough to anchor outcomes in a fragmented register. This is not promoter control. It is negative control: influence by alignment, not majority. And that influence now appears firmly board-centric. The MD’s resignation — framed as personal and health-related — fits a familiar pattern in stressed situations: • The board resets leadership on its terms • The executive exits without confrontation • Continuity is preserved for markets Keeping the MD until a successor is appointed reinforces this reading. This story is not about reserves or crude prices. It is about power re-centralisation in a promoter-less company — driven by: • Cash risk • A major PSU dispute • Leadership succession • The need to reassert institutional control The appointment of a former Chief Secretary as chairman is not the end. It is the signal. Markets should watch: • The next MD appointment • Resolution of the HPCL payment issue • Whether power flows back to management — or stays in the boardroom That will decide whether this is a reset — or the start of prolonged instability. 🔗 Full analysis on IndianPetroplus.com indianpetroplus.com #HOEC #CorporateGovernance #IndianOilGas #UpstreamIndia #Boardroom #PSUDispute #IndianEquities

E&P at the wrong point in the cycle ⛽️ Antelopus Selan Energy is a textbook, PE-style upstream story: disciplined capital, rising wells, higher volumes, expanding EBITDA. Q3 output ~1,500 boepd, targeting 1,800+ by FY26 exit. But here’s the catch: margins are volume-led, not price-led — and volumes are still hostage to geology (testing wells, post-frack outcomes, gas monetisation). With oil prices offering little upside support, execution gaps can’t be masked by the cycle. This isn’t poor management. It’s good execution meeting a soft oil tape. If a well-funded, conservatively run E&P feels this timing risk, smaller private E&Ps — thinner balance sheets, less flexibility — will feel it sooner and harder. Watch cash flows, not accounting relief. Watch reservoir performance, not just well count. Source: IndianPetroPlus.com 🔗 indianpetroplus.com #OilAndGas #EandP #Upstream #OilCycle #PrivateEquity #Exploration #Petroleum

E&P: When volume-led margins meet geology at the wrong point in the oil cycle A case study from a well-run, PE-backed Indian E&P — and why it matters for the entire private upstream space. 🧵 Antelopus Selan Energy Ltd’s Q3 FY26 presentation tells a familiar PE playbook story: • Assets acquired • Wells drilled & worked over • Volumes ramping • EBITDA rising despite weaker prices Production averaged ~1,500 boepd in Q3, with guidance of 1,800+ boepd exit by Mar’26. On paper, execution looks textbook. But read between the slides. A meaningful part of the new volume is still: • under testing • awaiting post-drill evaluation • dependent on future fracking • tied to gas discoveries with unclear monetisation So yes — volume visibility exists. But volume certainty does not. That distinction matters more in this cycle. EBITDA expansion here is being driven by incremental barrels, not price realisations. Which means margins are now hostage to reservoir behaviour, not management intent. This isn’t an execution critique. It’s a cycle critique. The company has also extended the accounting life of key fields by ~10 years after PSC tenure extensions — easing P&L pressure. But accounting relief ≠ cash-flow relief. Lifting costs, workovers, fracking spends and decline rates don’t change just because amortisation does. In a soft oil tape, cash reality asserts itself quickly. And that’s the crux. This growth phase is unfolding when: • oil prices offer limited upside • downstream signals cap realisations • there is no price cushion for execution delays Historically, rising prices mask geological uncertainty. This cycle does not. Why this case matters more than it seems: This is arguably a best-case private E&P: • PE-funded • capital disciplined • not over-levered • transparent in disclosures • operating within its comfort zone If this profile still faces timing risk, the implication for smaller, thinner, less flexible private E&Ps is obvious. This setup is likely to repeat across the sector. Many small E&Ps are volume-led by necessity — reliant on: • incremental drilling • workovers • step-out geology In a soft price environment, any delay in reservoir validation hits margins immediately. The cycle does not forgive geology. The real risk here isn’t failure. It’s timing mismatch. Good execution. Unforgiving cycle. Volumes needing to prove themselves without price support. That’s where stress quietly builds. What to watch next: • Which wells move from “testing” to repeatable production • Whether post-frack volumes sustain or fade • EBITDA resilience if prices weaken further • Cash generation vs capex — not accounting profits Bottom line: This is a PE-style E&P doing most things right — but at the wrong point in the oil cycle. For smaller private E&Ps, the same cycle could be far less forgiving. 🔗 Read the full analysis: indianpetroplus.com #OilAndGas #EandP #Upstream #PrivateEquity #OilCycle #EnergyInvesting #Geology #CashFlow #PetroPlus

India’s gas market has effectively stopped responding to price signals. Recent data shows LNG prices falling while import volumes also decline — a clear inversion of classical price elasticity. In a functioning market, lower $/MMBtu should unlock marginal demand and expand imports. That mechanism no longer exists in India. Full-year and YTD numbers confirm the shift. FY25 import growth occurred despite flat prices, driven by domestic gas shortfalls rather than price-led demand. More recently, even a ~$0.6/MMBtu price drop coincided with a ~7% fall in volumes. At the monthly level, nearly $2/MMBtu of price relief failed to generate incremental offtake. The reason is structural. Gas demand is boxed into policy-defined channels — fertiliser allocations, coal-first power dispatch, and capped sectoral usage. There is no clearing price at which demand expands, and no price high enough to force meaningful demand destruction. Prices now influence the import bill, not import decisions. India’s gas stagnation is therefore not a pricing failure, but a design outcome. Without demand liberalisation and allocation reform, lower LNG prices alone will not lift gas penetration — they will only make the administered system cheaper to run. Read more: indianpetroplus.com #IndiaGas #LNGMarkets #GasEconomics

India’s LNG Battle in 2026 Will Be Fought in Summer — Not Winter The biggest risk to India’s LNG affordability in 2026 is not winter shortages or China’s demand rebound. It is Europe’s summer storage refill — and the market is already pricing it in. Despite widespread talk of “global LNG oversupply,” the pressure point for 2026 is shaping up between April and September, when Europe must refill gas storage after entering the year with structurally lower inventories. According to the Oxford Institute for Energy Studies (OIES), Europe began winter 2025–26 with gas storage nearly 12 Bcm lower year-on-year, widening further after cold-weather withdrawals. Even under benign assumptions, Europe will exit winter with materially lower stocks than last year — making aggressive summer injections unavoidable. This matters for India because Europe’s LNG demand in summer 2026 will be policy-driven, not price-driven. To meet even the relaxed 80% storage mandate, Europe will need injections exceeding summer 2025 levels — with limited help from domestic production or pipeline gas. LNG becomes the marginal, compulsory source of supply. And the forward market already knows it. TTF summer 2026 prices show unexpected firmness, with only a narrow discount to winter — signalling that summer LNG will not be cheap, even in a so-called oversupplied market. For India, the competitive landscape has shifted. China’s LNG demand has stabilised. Emerging Asia remains highly price-sensitive. Europe, however, will buy LNG regardless of price discomfort, because storage security is non-negotiable. That asymmetry puts India at risk. India’s LNG demand is discretionary — linked to power economics, fertiliser subsidies, and CGD margins. Europe’s demand is compulsory. When prices rise, India will be the first market pushed out, not through shortages, but through quiet price exclusion. The real risk is not cargo unavailability — it is lower utilisation, deferred spot purchases, fuel switching, and downstream cost pressure that builds gradually and goes unnoticed until margins erode. Even rising US LNG supply offers limited protection. OIES highlights that late-2025 cargoes were already loss-making on a full-cost basis at times, sustained only by sunk-cost behaviour. That model cannot absorb prolonged margin stress if Europe’s summer bid tightens again. Global oversupply does not equal affordability. In 2026, price formation will be driven by storage urgency, regional imbalance, and geopolitical risk — not nameplate capacity. India’s winning strategy is timing, not volume: • Buy early before Europe ramps up injections • Step back when TTF hardens on storage urgency • Preserve optionality instead of chasing spot cargoes In 2026, LNG affordability for India will not be decided in Delhi, Doha, or Washington. It will be decided in Europe’s storage caverns. 🔗 Read the full analysis: indianpetroplus.com #LNG #NaturalGas #EuropeGas #TTF #GasStorage #LNGPrices #IndianPetroPlus #USLNG

India’s LNG battle in 2026 will not be fought in winter. It will be fought in SUMMER. Despite headlines about global LNG oversupply, the real pressure point is Europe’s summer storage refill — and India will be directly exposed. Europe is entering the 2026 injection season with materially lower gas inventories, creating a non-negotiable requirement to absorb LNG between April and September. This demand is policy-driven, not price-driven, and it will surface in the forward curve long before winter. TTF summer 2026 prices are already showing unexpected firmness — a signal that LNG in summer will not be “cheap” simply because supply is growing. India’s risk in 2026 is not physical LNG shortage. It is being quietly outbid. Europe will buy LNG to meet storage mandates even at uncomfortable prices. India, by contrast, remains price-sensitive across power, fertilisers, and CGD. When prices rise, India is the first market pushed out — not through disruption, but through deferred cargoes and lower utilisation. The real strategic lever for India in 2026 is timing, not volume: • Buy before Europe ramps up injections • Step back when storage urgency hardens prices • Preserve optionality rather than chase spot cargoes In 2026, LNG affordability for India will not be decided in Delhi, Doha, or Washington — it will be decided in Europe’s storage caverns. 📊 Read the full market analysis & register for deeper insights 🔗 indianpetroplus.com #LNG #NaturalGas #GasMarkets #TTF #EuropeGas #LNGPrices #IndianPetroPlus #PetroPlus

ONGC is quietly but decisively redrawing its upstream procurement landscape. Under its ‘Super 30’ framework, the PSU is moving away from open competitive bidding toward restricted tenders for services it considers operationally critical. Key categories being shifted to limited tendering include offshore support vessels, drilling & workover rigs, wireline and logging, directional drilling, cementing, production chemicals, gas handling, line pipes, wellhead systems, and offshore structural maintenance. Access to these tenders will now be determined before price discovery, through a centralised empanelment process led by ONGC’s top technical and services leadership. Vendors outside the approved pool—irrespective of pricing or past credentials—will be locked out of ONGC’s most critical E&P work. The message is clear: execution certainty, control and speed now outweigh wider competition. For vendors, inclusion ensures continuity and predictability; exclusion pushes participation to non-core or residual contracts. A structural shift, not a tactical tweak. Full story: indianpetroplus.com #ONGC #IndianPetroPlus #OilAndGas #Upstream #Procurement #EandP #OilfieldServices

EXCLUSIVE | Sanctions force Nayara Energy to change how it builds Despite EU & US sanctions linked to Rosneft, Nayara Energy is pushing ahead with critical offshore infrastructure at Vadinar, Gujarat—but with reworked contracting, new partners, and unresolved procurement risks. Key developments 👇 • New T&I contractor: Navi Mumbai–based AJR Oil & Gas, partnering with Dubai’s Likpin • Indonesia’s PT Timas Suplindo exited after EU sanctions (Aug 2025) • ZEE Engineering (Malaysia) handling SPM & subsea pipeline engineering (due Mar 2026) • Execution targeted before monsoon 2026 ⚠️ Biggest risk: SPM buoy procurement • $10.27m buoy ordered from UK’s Monoboy now suspended due to sanctions • No payments made, contract in limbo • Nayara/Rosneft exploring alternative SPM sourcing, including ready units from China This case shows how sanctions don’t stop projects—but force quieter workarounds, new contractor ecosystems, and opportunistic sourcing to keep crude import infrastructure moving. Read the full exclusive on IndianPetroPlus 👉 indianpetroplus.com #NayaraEnergy #Rosneft #Sanctions #IndiaOilGas #SPM #OffshoreEngineering #Geopolitics #IndianPetroPlus

ONGC has chosen continuity over correction after the Mori-5 blowout. The gas leak at Mori-5, operated under a Production Enhancement Contract (PEC), was expected to force a pause or reset. Instead, ONGC is pressing ahead — issuing fresh PEC-style sick-well revival tenders and extending bid deadlines, not rewriting risk terms. Mori-5 exposed a core contradiction in the PEC model. While contractors are meant to bear operational risk, crisis control snapped back to ONGC the moment things went wrong. Well-control, safety response, and reputational exposure ultimately sat with the PSU — not the private operator. At the same time, Rajahmundry shows the opposite imbalance. Under the same PEC framework, production crossed baseline within months, profitability arrived in year one, and upside accrued early and privately. That outcome weakens the very “risk-sharing” logic PECs are built on. Placed together, the pattern is clear: profits move fast to contractors, but operational risk returns instantly to ONGC. Yet ONGC’s Ahmedabad sick-well revival tender — a revenue-share, contractor-operated model mirroring PECs — is moving forward. Deadlines are extended, not cancelled. Compliance rules remain rigid. Structural safeguards remain unchanged. ONGC may be keeping production moving, but the harder question is being deferred: When upside comes early and failure comes suddenly, who truly carries the risk? 👉 Read the full exclusive analysis: indianpetroplus.com #ONGC #OilAndGasIndia #PEC #Upstream #EandP #IndianPetroPlus #Hydrocarbons #PSUs

Household gas prices are getting a boost—but industry is paying the price. PNGRB’s unified tariff (from Jan 2026) removes distance-based charges for CNG & domestic PNG, making gas more affordable nationwide. Long-haul pipeline costs haven’t disappeared—they’re now absorbed by industrial and bulk users. The move supports cleaner fuel adoption and CGD expansion, but underscores a shift from cost-reflective pricing to outcome-driven policy. Full details: indianpetroplus.com #PNGRB #NaturalGasIndia #CNG #PNG #IndustrialGas #GasPipeline #CGD

The biggest LNG shift isn’t supply. It’s China quietly stepping away as the marginal buyer. And India isn’t replacing it. 🧵 For a decade, global LNG pricing had a backstop: ➡️ Surplus cargoes? China absorbed them. ➡️ Tight market? China set the bid. That era is ending. China is still buying LNG — but it no longer needs incremental LNG to meet incremental gas demand. Why? • Domestic gas output keeps rising • Russian pipeline gas keeps expanding Result: the “missing marginal cargo” Even small downgrades in China’s LNG outlook now hit harder — because they arrive just as global LNG supply surges. This changes the price regime. Without China as the swing absorber, LNG markets tilt structurally bearish. Prices don’t collapse — but rallies fade faster. So who picks up the slack? Not India. That’s the uncomfortable truth. India’s gas demand growth exists — but it is slow, segmented, and policy-bound. Yes, forecasts show ~3–4% y/y growth. But context matters: • Recent demand actually fell • Power, fertiliser & refinery demand weakened • CGD carried the system Cheaper LNG alone doesn’t fix this. Power sector reality: Gas plants are backup assets. PLFs remain in the teens. No swing demand here. Industrial reality: Fuel switching takes time, capex & certainty — not just lower spot prices. Fertiliser reality: Gas demand follows allocation & subsidy math, not LNG prices. CGD reality: Steady growth — but not explosive, not price-led. So India’s role is clear: ➡️ Opportunistic buyer when LNG is cheap ➡️ Secondary balancing market ➡️ Not the new demand anchor Which means this: China stepping back = persistent downward pressure on LNG prices. India benefits on cost — but doesn’t change the global balance. The real signals to watch: 1️⃣ Gas-to-power PLF moving structurally higher 2️⃣ Evidence of coal/petcoke displacement in industry 3️⃣ Faster CGD rollout beyond current trajectories Until then, LNG markets remain China-less… and softer. 🔒 Full exclusive analysis + China demand deep-dive: 👉 indianpetroplus.com #LNGMarkets #ChinaGas #IndiaEnergy #NaturalGas #IndianPetroPlus

New Pumped Storage Tech Could Further Hollow Out Gas-Based Power A new variant of pumped storage is quietly emerging as a serious disruptor—not just for batteries, but for quick-start gas-based power plants as well. High-Density Hydro® (HD Hydro®), developed by RheEnergise, re-engineers conventional pumped storage by replacing water with a proprietary high-density fluid. The result: 4–16 hours of energy storage at costs claimed to be far lower than lithium-ion batteries, with a footprint small enough to deploy far beyond mountainous regions. Why it matters for gas Gas peaker plants exist for flexibility—fast starts, peak-hour supply, and balancing renewables. HD Hydro® directly targets this same market: • Storage duration of 4–16 hours, the exact band where gas peakers dominate • Lower LCOS than batteries at 8 hours and beyond • No fuel price risk, no emissions, no gas supply dependency • Uses cheap renewable power stored earlier to deliver peak electricity If deployed at scale, such systems don’t replace gas overnight—but they erode dispatch hours, weaken load factors, and challenge the economics of new gas-based peaking capacity. Structural shift, not incremental change The bigger story is long-duration storage. Global estimates suggest LDES capacity must expand 400× by 2040, with nearly two-thirds in the 4–16 hour range. That’s a segment historically served by gas. HD Hydro® claims: • Smaller elevation needs (hills, not mountains) • Modular 10–100 MW projects • Buried, landscaped reservoirs easing permitting risks • Asset life of ~60 years—closer to grid infrastructure than consumable storage The caveat No commercial projects are operating yet. Cost and scalability claims remain forward-looking. But the direction is clear. The real risk to gas is not sudden displacement—but gradual erosion by design. This isn’t just a storage story. It’s about who provides flexibility to the grid in a renewable-heavy future—molecules or infrastructure. Full analysis 👉 indianpetroplus.com #GasPower #PumpedStorage #LDES #PowerMarkets #NaturalGas #IndianPetroPlusDotCom

Blowout economics expose the flaw in ONGC’s PEC model Rajahmundry crossed baseline within months under a PEC, delivering near-50% EBITDA margins and year-one payback for the contractor. That is not “high-risk enhancement” — it is fast monetisation of an under-optimised asset. Then Mori happened. A gas leak during PEC operations triggered ONGC-led crisis management, international well-control mobilisation, and full PSU accountability. When things went wrong, risk snapped back to ONGC instantly. Put together, the pattern is clear: ✔ Upside moves fast to private operators ✖ Downside — safety, environment, reputation — remains public That is not risk transfer. It is asymmetric outsourcing. Why this matters: high PEC margins signal low real risk, weak baselines, and growing dependence on contractors for routine operations — while ONGC remains the operator of last resort. If upside and downside don’t move together, PECs aren’t reform. They’re incomplete policy. 🔎 Full analysis (Subscriber access): 👉 indianpetroplus.com 📝 Register to read #ONGC #PEC #OilAndGasIndia #EnergyPolicy #UpstreamOil #RiskManagement #IndianPetroPlus

🧵 The illusion of choice in TPIAs (PNGRB) On paper, the empanelment list looks long. In practice, operators face a shrinking pool of valid inspectors. Here’s why 👇 1️⃣ The list looks big — until filters apply Segment-specific approvals mean many TPIAs cleared for CGD under T4S aren’t eligible for pipelines, LNG, POL or refineries. Choice narrows fast. 2️⃣ Approvals are fragmented, not horizontal Empanelment is split across: • T4S • IMS • ERDMP And further divided by asset class. True cross-segment eligibility is rare. 3️⃣ Expiry dates quietly reduce options Many approvals lapse in 2026 — some within months of each other. For multi-year projects, empanelment becomes a moving target. 4️⃣ ERDMP is the tightest gate Compared to T4S and IMS, ERDMP approvals are sparse. This makes emergency planning a structural bottleneck, not a procedural formality. 5️⃣ Big names ≠ blanket approval Well-known inspection firms also show gaps — approved in some segments, missing in others, or facing early expiry. Eligibility > reputation. 6️⃣ The real pool is much smaller For a pipeline needing T4S + IMS + ERDMP, usable inspectors often drop to a handful after all filters apply. 7️⃣ Design or drift? The list doesn’t state intent. But the outcome is clear: • Narrow mandates • Time-bound permissions • Constrained operator choice 8️⃣ Compliance risk has shifted Risk now lies not just in inspection quality — but in who is legally permitted to inspect at that moment. 9️⃣ The burden moves upstream Operators must track: • Scope • Segment approvals • Renewal timelines Compliance is now administrative as much as technical. 🔟 Bottom line The empanelment list is a map of regulatory trust — segmented, selective and time-bound. The illusion lies in its length. The reality lies in how few names survive all filters. 🔗 Read full analysis: indianpetroplus.com #PNGRB #TPIA #OilAndGasIndia #PipelineSafety #CGD #IMS #ERDMP #IndianPetroPlus

🧵 PNGRB & LNG: Reform — or a Quiet Power Shift? PNGRB hasn’t announced a new LNG regulation. There’s been no public consultation. No formal claim over LNG regasification. Yet, two recent analytical papers from PNGRB’s Commercial Division suggest a clear change in regulatory posture — one that the gas industry cannot afford to ignore. At face value, these are technical assessments of India’s gas value chain. Read together, they tell a different story. The first paper questions why LNG regasification utilisation remains low despite years of capacity build-out — and why pricing and financial outcomes at LNG terminals appear largely insulated from that reality. The second examines downstream logistics — especially trucking versus pipelines — and how charges at LNG terminals materially inflate delivered gas costs, even when supply is available. Individually, these are observations. Collectively, they challenge outcomes. That distinction matters. When a regulator begins questioning outcomes rather than just access or conduct, the scope of intervention naturally expands. Reading between the lines, PNGRB appears to be signalling four things: 🔹 LNG regasification may no longer remain outside regulatory oversight The repeated juxtaposition of low utilisation, firm regas charges and stable returns lays the groundwork for treating regasification as outcome-sensitive infrastructure — not a purely commercial activity. 🔹 Regasification and truck-loading charges are now in focus Charges that have stayed rigid despite weak utilisation are being highlighted as demand-suppressing. This opens the door to regulation, benchmarking, or tighter scrutiny. 🔹 Transparency is the first lever The papers strongly emphasise disclosure — pricing logic, escalation mechanisms, and cost break-ups. In regulatory sequencing, transparency usually precedes control. 🔹 APM allocation distortions are no longer off-limits Though not the main subject, subsidised APM gas repeatedly appears as a factor enabling margin insulation and arbitrage-like outcomes, suggesting allocation design itself may be revisited. PNGRB hasn’t crossed the line yet. But through analysis rather than announcement, it has brought that line clearly into view. For the LNG industry, the concern isn’t scrutiny — it’s what happens if regasification is reclassified from entrepreneurial, risk-bearing investment to regulated infrastructure. That shift would reset pricing freedom, return expectations and capital deployment logic across the gas value chain. Whether this is reform driven by policy alignment — or a quiet expansion of regulatory power — will depend on what PNGRB does next. But one thing is clear: LNG terminal economics in India are no longer outside the regulator’s line of sight. Full analysis: 🔗 indianpetroplus.com #PNGRB #LNG #GasSector #NaturalGas #GasPricing #Infrastructure #APM #Regulation

Domestic gas reshapes Delhi’s CCGT merit order, imported LNG plants feel the squeeze Exclusive analysis of FORM-15 fuel filings (Oct–Nov 2025) shows a sharp cost divide emerging within Delhi’s gas-based power fleet. The driver isn’t efficiency—it’s fuel sourcing. In Oct 2025, IPGCL’s GTPS ran entirely on imported gas, paying a landed cost of ₹44.9/SCM. With ~7.8 mn SCM consumed, its fuel bill crossed ₹35 crore, placing it at the top end of the variable cost stack. In contrast, PPCL’s Pragati Power Station-I, operating in Nov 2025, accessed domestic gas at just ₹26.5/SCM. Despite consuming nearly double the gas (~14.7 mn SCM), its total fuel cost was only ₹38.8 crore. Both plants reported comparable gas quality (~9,500 kcal/SCM), confirming that fuel access—not performance—now determines dispatch competitiveness. The implications are structural: • Domestic gas access sharply lowers variable cost • Imported-gas CCGTs slide down the merit order • Running hours fall, fixed-cost recovery risk rises • LNG price volatility amplifies exposure Regulatory pressure is likely to grow as gas allocation outcomes—not plant efficiency—begin dictating dispatch and recovery within the same urban power system. Bottom line: In today’s gas market, domestic supply isn’t just an advantage—it decides who runs and who remains exposed. Source: IndianPetroPlus exclusive analysis. Please register on indianpetroplus.com