Energy companies in India, whether in oil and gas, power generation, or renewables, are no strangers to accounting complexity. Asset-heavy balance sheets, long-duration contracts, regulatory pricing interventions, and commodity exposure have always made this sector one of the more demanding from a financial reporting standpoint. The Gulf War of 2026 has added a new layer of complexity, affecting several core estimates simultaneously.
I have set out below what I consider the four most significant accounting challenges for energy sector companies this year, followed by additional aspects that warrant attention at the time of book closure.
1. Inventory Gains and Losses: Oil and Gas Stock Valuation
The near-40% increase in crude oil prices within a fortnight creates significant inventory accounting consequences for Oil Marketing Companies and refiners, which carry large volumes of crude oil and petroleum product inventory.
Under Ind AS 2 (Inventories), crude oil and refined product inventories must be valued at the lower of cost and Net Realisable Value (NRV). When crude prices rise sharply, the NRV of finished petroleum products typically rises accordingly, meaning most product inventories will not require write-downs under current conditions. However, the picture is more nuanced for OMCs that are holding back retail price increases:
• Where petrol and diesel retail prices are held below cost (creating an under-recovery situation), the NRV of these products is, in substance, the government-controlled retail price less selling costs, which may be below the elevated crude cost. A write-down to NRV may therefore be required on these specific product categories despite rising crude prices overall.
• Crude oil inventory purchased at pre-disruption prices ($65-70/barrel) and now carried while crude trades at $110-120/barrel is not written up; Ind AS 2 prohibits upward revision above cost. This asymmetry means that P&L will not reflect the inventory holding gain, but this gain will materialise in margins on future sales.
For gas companies and LNG importers, terminal inventories of natural gas are limited. Valuation of these inventories at cost or NRV needs to reflect the current market value of gas, which has effectively doubled in Asia spot markets. Any contracted gas in storage purchased at pre-disruption prices will show a favourable NRV, but spot-price purchases will be at elevated cost, with uncertain NRV depending on the price at which they are sold onwards.
2. Impairment and Reversal of Energy Assets Under Ind AS 36
The current shock creates opposing impairment signals within the same sector, and finance teams need to be careful not to apply a blanket assumption in either direction.
For upstream oil and gas assets (exploration and production), elevated crude prices increase the recoverable amount of oil and gas fields. Under Ind AS 36 (Impairment of Assets), if a previously impaired asset now has a recoverable amount above its carrying value, an impairment reversal is required, up to the amount that would have been recognised had no impairment been recorded. This is mandatory, not optional, and can be a material P&L credit for upstream companies that had written down assets during the 2020 oil price collapse.
For gas-based power plants and gas-processing assets, the combination of elevated input costs, reduced gas availability, and limited ability to pass through costs sends the opposite signal. Where the value-in-use of a gas plant has declined because it will operate below budgeted capacity at elevated input costs, an impairment charge may be required. The recoverable amount must be assessed using realistic post-disruption cash flow projections, not pre-conflict assumptions.
For renewable energy assets, the disruption is primarily on the supply chain and working capital side rather than the earnings side. Most operational solar and wind projects are under long-term Power Purchase Agreements (PPAs) with fixed or predetermined tariffs, making their cash flows relatively insulated from commodity shocks. Impairment triggers here would relate more to counterparty (DISCOM) credit risk than to the energy price environment.
3. Hedge Accounting Effectiveness Under Ind AS 109
Energy companies, particularly OMCs and LNG importers, typically carry commodity and forex hedging programmes of material size. The current environment is particularly testing for hedge accounting under Ind AS 109 (Financial Instruments) for two distinct reasons.
First, the hedged item may have been fundamentally altered. Where a company had hedged the price risk on contracted LNG volumes that are now subject to force majeure, and the physical delivery is no longer certain, the hedged item ceases to exist in its originally designated form. Under Ind AS 109, if the hedged transaction is no longer expected to occur, the hedge must be discontinued and the cumulative gain or loss in Other Comprehensive Income (OCI) must be reclassified to profit or loss immediately. For companies with large OCI balances from hedging programmes, this reclassification could be a significant P&L item.
Second, effectiveness testing parameters have shifted dramatically. Hedge relationships designated on the basis of historical price correlations between the hedging instrument (e.g., Brent-linked futures) and the hedged item (physical LNG purchases) may no longer satisfy the effectiveness threshold, given that the LNG spot price has decoupled from Brent to an unusual degree under the current supply shock. Where hedge relationships fail the effectiveness test, the change in fair value of the hedging instrument must flow through P&L rather than OCI.
4. Decommissioning Provisions Under Ind AS 37 and Ind AS 16
Decommissioning provisions for oil and gas fields and offshore installations are calculated as the present value of estimated future decommissioning costs. The Gulf War creates two vectors of change that need to be reassessed at the balance sheet date.
The cost estimate component may need to be revised upward. Decommissioning operations are energy and logistics-intensive. With fuel costs elevated and specialist vessel and equipment costs rising alongside general energy cost inflation, the underlying cost estimate for decommissioning may be materially higher than the estimate used in the prior year. This feeds directly into the provision balance and into the associated asset (decommissioning asset as part of PP&E under Ind AS 16).
The discount rate component may also require revisiting. The standard practice is to use a pre-tax risk-free rate adjusted for liability-specific risks. With inflation elevated and interest rate expectations shifting in response to the energy shock, the risk-free rate assumption used in the prior year may no longer reflect current market conditions. A higher discount rate reduces the provision balance, partially offsetting the cost inflation effect, but both changes need to be assessed and documented.
Other Aspects to Consider
Finance teams and auditors in the energy sector may additionally need to address the following at year-end close:
• Borrowing cost capitalisation (Ind AS 23): For energy infrastructure projects under construction, pipelines, LNG terminals, and power plants, where construction has been interrupted or materially delayed due to supply chain disruptions, the question of whether to suspend borrowing cost capitalisation arises. Ind AS 23 requires capitalisation to be suspended during periods when active development is interrupted, and this assessment must be made on a project-by-project basis.
• Revenue recognition on gas supply contracts (Ind AS 115): For gas utilities and City Gas Distributions (CGD) companies, where contracted volumes cannot be supplied due to upstream curtailment, the impact on revenue and any associated 'ship-or-pay' receipts from customers who cannot lift their contracted volumes requires careful Ind AS 115 analysis. Take-or-pay receipts from customers should not be recognised as revenue if the obligation to supply gas remains outstanding and is expected to be fulfilled in a future period.
• Going concern for gas-dependent power plants (SA 570): Gas-based power plants with limited alternative fuel options, operating below capacity, and facing payment pressure from DISCOMs should be assessed for going concern indicators. Where a plant's ability to operate as a going concern over the next 12 months depends on the resolution of the supply disruption, this dependence must be clearly disclosed.
Closing Observation
What makes the energy sector's accounting challenge particularly complex this year is the simultaneous presence of opposing signals: upstream assets benefiting from elevated crude prices may require impairment reversals, while downstream and gas-dependent assets may require fresh impairment charges, often within the same consolidated group. The standard-setting framework treats these as independent assessments at the Cash Generating Unit level, and that discipline needs to be maintained even when the consolidated picture appears balanced.
The energy sector has historically been at the forefront of complex accounting judgments in India, from decommissioning provisions to hedge accounting to joint arrangement accounting. This year adds another chapter to that history, and I think it will make for substantive discussion at the upcoming professional conferences and peer forums.
I look forward to the perspectives of practitioners and finance leaders in this space on how they are approaching these challenges.
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