Accounting Under Ind AS For Upstream Oil & Gas Entities: The Backbone of World Economy
CA. Ram Awasthi
Member of the Institute of Chartered Accountants of India. Contact: awasthi199@gmail.com
CA. Amrish Diwakar
Member of the Institute of Chartered Accountants of India. Contact: eboard@icai.in
1. Upstream Activities & Structural Realities
Upstream activities consist of the exploration for and discovery of hydrocarbons (crude oil and natural gas). The development of these hydrocarbon reserves and resources, and their subsequent extraction (production) also takes place at this stage.
Exploration, development, and production activities are frequently structured through joint ventures or unincorporated joint operations to syndicate massive capital outlays and share geological risk. The sector entails extensive transportation logistics via pipelines, ocean tankers, and specialized carriers. Furthermore, because upstream operations carry profound environmental consequences, entities are statutorily obligated to remediate environmental degradation upon field decommissioning.
This comprehensive analysis addresses the accounting challenges under Indian Accounting Standards (Ind AS) across the entire upstream value chain: pre-acquisition, exploration and evaluation, development, production, and pervasive industry issues.
2. Typical Stages in Exploration & Production (E&P) Activities
The discovered natural resources represent an entity’s most vital economic asset—serving as the engine of future operating cash inflows and providing the collateral foundation for corporate borrowings and equity offerings. E&P activities operate through four distinct stages:
Applicable Ind AS Standards by E&P Lifecycle Stage
The Institute of Chartered Accountants of India (ICAI) issued the Guidance Note on Accounting for Oil and Gas Producing Activities (Ind AS) in December 2016 for Ind AS compliant entities, complementing the Guidance Note on Accounting for Oil and Gas Producing Activities (revised 2013) for AS entities. Crucially, mineral rights and natural reserves are excluded from the scope of Ind AS 16 (Property, Plant and Equipment) and Ind AS 38 (Intangible Assets). While Ind AS 106 provides policy choices for E&E costs, it does not govern subsequent stages.
3. Accounting Methodologies: Successful Efforts Method (SEM) vs. Full Cost Method (FCM)
Two internationally acknowledged accounting conventions govern E&P expenditures, heavily influenced by US GAAP practices in the United States and Canada:
(i) Successful Efforts Method (SEM)
Under SEM, only costs directly resulting in the successful identification of new commercial reserves are capitalized. Costs associated with unsuccessful exploration (such as exploratory drilling yielding a dry well) are immediately charged to the statement of profit and loss.
Costs are capitalized on a field-by-field basis and allocated to commercially viable reserves. If an entity fails to find commercially viable reserves, expenditures are expensed. Capitalized costs are depleted on a field-by-field basis as hydrocarbons are extracted.
(ii) Full Cost Method (FCM)
FCM permits companies to capitalize virtually all expenditures related to exploration and development across entire cost centers (often an entire country or basin), regardless of whether specific drilling efforts proved successful or resulted in dry holes.
The choice of method profoundly impacts reported net income, volatility, and operating cash flow metrics across financial reporting periods.
4. Detailed Accounting for Major Costs Incurred in E&P Operations
(a) Pre-Acquisition Costs
Expenditures incurred prior to obtaining the legal rights to explore, develop, and produce (e.g., regional geological data purchases, preliminary reconnaissance, and technical analyses to identify target blocks) are expensed immediately in the statement of profit and loss as incurred.
(b) Acquisition / Pre-Exploration Costs
Entities must capitalize acquisition expenditures as tangible or intangible assets based on their inherent nature. These cover costs to purchase, lease, or acquire mineral rights (proved or unproved), signature bonuses, lease bonuses, brokers’ commissions, legal fees, temporary land occupation charges, landowner compensation, and statutory levies for obtaining the Petroleum Exploration License (PEL), Letter of Authority (LOA), and Mining Lease (ML).
(c) Exploration & Evaluation (E&E) Costs
Under Ind AS 106, entities elect an accounting policy (FCM or SEM) specifying capitalized vs. expensed expenditures, applied consistently. E&E assets are measured at cost upon initial recognition, covering:
- Topographical, geological, geochemical, and geophysical (G&G) seismic studies;
- Exploratory drilling operations;
- Trenching and sampling;
- Activities evaluating technical feasibility and commercial viability.
Subsequent to initial recognition, entities apply either the cost model or revaluation model. Assets are classified as tangible (e.g., vehicles, specialized drilling rigs) or intangible (e.g., exploration drilling rights). When a tangible asset is consumed in developing an intangible asset, that depreciation is capitalized into the intangible cost, without changing the tangible asset’s legal classification.
(d) Development Costs & Commercial Reclassification
Once technical feasibility and commercial viability are determined, accumulated E&E assets are reclassified as Capital Work-in-Progress (CWIP) or Intangible Assets Under Development (IAUD).
When a well is ready to commence commercial production, capitalized costs corresponding to proved developed reserves are transferred from CWIP/IAUD to the gross block as ‘completed wells / producing wells’. Entire acquisition costs are capitalized to the gross block once commercial reserves are established. This applies even if only a single well within a block commences production, provided the block is treated as a single asset. Wells still under development in the same block remain in CWIP/IAUD.
Incidental Revenue Treatment: Any revenue generated from the sale of crude oil and natural gas (net of statutory levies) produced from Exploratory Wells in Progress or Development Wells in Progress during testing is deducted from the capitalized cost of such wells.
(e) Production Costs, Profit Petroleum & Rig Days’ Costs
Production Costs: Comprise lifting, treating, field gathering, and maintenance costs, absorbed into inventory costs alongside depletion of capitalized acquisition, E&E, and development costs.
Cost of Profit Petroleum: Under Production Sharing Contracts (PSCs) with the Government / Directorate General of Hydrocarbons (DGH), the share of revenue paid to the government is termed Profit Petroleum. Under Ind AS 115, Profit Petroleum does NOT form part of revenue from sale of products.
Rig Days’ Costs: Mobilization and movement costs of drilling rigs are capitalized to the next well location drilled or scheduled. However, abnormal rig downtime / idle rig days’ costs are un-allocable and must be charged directly to the Statement of Profit and Loss.
General & Administrative (G&A) Costs: Only overheads directly attributable to a specific oil and gas field are capitalizable. Corporate G&A (directors’ fees, secretarial, corporate office salaries) are expensed as incurred.
5. Site Restoration & Abandonment Obligations (Ind AS 37 & Ind AS 16)
Abandonment costs encompass all expenditures incurred upon field exhaustion: plugging and abandoning wells, dismantling offshore platforms and wellheads, and restoring onshore/offshore sites pursuant to licensing laws and environmental statutes.
Decommissioning Accounting Framework
- Capitalized Provision: In accordance with Ind AS 37, obligations incurred from drilling and evaluating resources are recognized as a decommissioning provision and capitalized into Property, Plant and Equipment (PPE) or intangible assets.
- Discounting at Pre-Tax Rate: Where the time value of money is material, the provision is measured at the present value of expected settlement expenditures using a current market pre-tax discount rate reflecting risks specific to the liability.
- Prospective Adjustments: Changes in the estimated timing or quantum of cash outflows, or modifications to discount rates, are adjusted against the asset cost and depleted prospectively over remaining reserves.
- Unwinding of Discount: The accretion of discount due to the passage of time is recognized immediately in the statement of profit and loss as a finance charge. Crucially, because abandonment obligations do not represent borrowed funds, this unwinding cannot be capitalized as borrowing cost under Ind AS 23.
6. Impairment Testing & Cash-Generating Unit (CGU) Architecture
Impairment assessment in upstream entities is governed by specialized multi-standard benchmarks evaluated across each operational stage:
CGU Delineation Rules under Ind AS 36 & Ind AS 108
Impairment losses are measured and recognized in accordance with Ind AS 36. Impairment must be performed at the Cash-Generating Unit (CGU) level (or group of CGUs), provided the unit is not larger than an operating segment under Ind AS 108.
Onshore Fields: Where multiple onshore oil and gas fields utilize shared production, separation, and pipeline facilities and exhibit substantial economic interdependence, they may be aggregated and tested as a single CGU.
Offshore Fields: An individual offshore field is generally treated as a distinct CGU. However, fields developed cooperatively as an integrated offshore cluster sharing common platform infrastructure are tested in aggregate as a cluster CGU.
Non-Reinstatement Rule: Exploratory well costs written off to the income statement in previous accounting periods cannot be reinstated under any circumstance, even if the well subsequently achieves commercial hydrocarbon production.
7. Pervasive Industry Operations: Carried Interest, Side-Tracking & Depletion
(a) Accounting for Carried Interest Arrangements
A carried interest agreement arises where an assignee (the carrying party) undertakes to defray 100% of drilling, development, and operating costs in exchange for receiving 100% of production revenue (net of statutory royalties) until all expended costs are fully recouped (the “payout period”). Thereafter, the assignor (carried party) and carrying party share revenues, operating expenses, and future capital costs according to agreed working interests:
- Carrying Party: Funds geological risk during exploration and records all costs (including carried portions) per its standard accounting policy. During development, carried outlays are treated as receivables based on proved reserves. It recognizes all production revenues until full recoupment.
- Carried Party: Records no revenue or operating expenses prior to payout. Following payout, it accounts for its proportionate share of revenues, lifting costs, and capital expenditures.
Unit of Production (UOP) Depletion
Producing wells and capitalized development costs are depleted using the Unit of Production (UOP) method based on proved developed hydrocarbon reserves over commercial extraction volumes.
Pipeline & Tank Inventory Valuation
Finished crude oil and gas stocks in storage tanks and transit pipelines are valued at lower of cost and net realizable value (NRV) under Ind AS 2, computed via full absorption costing.
(b) Accounting for Side-Tracking Expenditures
Side-tracking involves re-drilling from an existing wellbore after the lower hole becomes junked or blocked, saving the expense of re-drilling upper casing sections. Accounting treatment depends on well classification:
- Exploratory Wells: Side-tracking costs are accounted for as a new exploratory well, while the abandoned wellbore portion is treated as a dry hole under the entity’s chosen SEM/FCM policy.
- Development Wells: Both the side-tracking outlays and the abandoned portion are capitalized into development CWIP, subject to Ind AS 36 impairment review.
- Producing Wells: If side-tracking establishes additional proved developed reserves or boosts performance standards beyond prior benchmarks, the side-tracking cost is capitalized, while the abandoned portion is depleted normally. If no additional reserves result, side-tracking costs are expensed immediately, and the abandoned portion is depleted normally.
(c) Joint Arrangements in Indian Upstream (Ind AS 111)
Joint arrangements are categorized under Ind AS 111 based on contractual rights and obligations:
- Joint Operations: Where parties hold direct rights to assets and direct obligations for liabilities (joint operators). In India, unincorporated joint ventures under Production Sharing Contracts (PSCs) and Revenue Sharing Contracts (HELP/OALP) are structured as joint operations.
- Joint Ventures: Where parties hold joint control and rights to net assets via a separate legal vehicle (joint venturers), accounted for via the equity method under Ind AS 28.
Accounting for Joint Operations: An upstream operator recognizes its proportionate share of assets, liabilities, expenses, and revenues on a line-by-line consolidation basis, and records its share of hydrocarbon sales as corporate turnover.
8. Mandatory Financial Statement Disclosure Checklist
Over and above general statutory and standard-specific notes, an E&P entity must incorporate the following eight mandatory disclosures:
- Accounting Policies: Comprehensive disclosure of specific policies followed across each E&P stage (SEM vs. FCM, capitalization thresholds, depletion methodology).
- Reserve Quantities Reconciliation: Net opening balances, extensions/discoveries, revisions, production deductions, and closing reserves of proved and proved developed reserves for (a) crude oil (including condensate and natural gas liquids) and (b) natural gas.
- Geographical Disclosures: Geographical disaggregation of net proved and proved developed reserves across domestic and international operating basins.
- Standardized Metric Units: Quantitative reporting strictly in Metric Tonnes (MT) for crude oil reserves and Cubic Meters (m³) for natural gas reserves.
- Reserves in Impairment Calculations: Qualitative description and net quantities of reserves utilized in impairment cash flow projections.
- CGU Identification Basis: Contractual and technical rationale used to establish Cash-Generating Units for impairment testing.
- Evaluation Assumptions & Third-Party Experts: Reserve estimation frequency, core reservoir assumptions, and formal engagement of accredited external petroleum reserve evaluation experts.
- Exploration Write-Offs: Total quantum of exploratory well costs and dry hole expenditures charged to profit or loss during the reporting period.
9. Conclusion & Policy Consistency
Because Ind AS 106 confines its scope primarily to exploration and evaluation assets, comprehensive guidance for subsequent stages relies upon the broader Ind AS Conceptual Framework and ICAI’s specialized Guidance Note on Accounting for Oil and Gas Producing Activities (Ind AS).
The multiplicity of allowable policy choices—such as SEM versus FCM—can lead to financial statement non-comparability across upstream operators. It is therefore vital for corporate leadership to establish coherent, transparent accounting policies that reflect the true operational economic realities of their acreage and apply them on a strictly consistent basis.
References & Regulatory Frameworks
- Ind AS 106: Exploration for and Evaluation of Mineral Resources.
- Ind AS 16: Property, Plant and Equipment; Ind AS 38: Intangible Assets.
- Ind AS 36: Impairment of Assets; Ind AS 37: Provisions, Contingent Liabilities and Contingent Assets.
- Ind AS 111: Joint Arrangements; Ind AS 115: Revenue from Contracts with Customers.
- ICAI Guidance Note on Accounting for Oil and Gas Producing Activities (Ind AS) (December 2016).
- Oil and Natural Gas Corporation Limited (ONGC), Annual Report FY 2019-20; Investopedia Research.