Introduction of the subject:
The transition from Indian GAAP to Ind AS is a historic and a landmark change. The change to IND AS is a hugely positive move that will bring accounting in India substantially closer to the accounting followed by the global companies under IFRS. This would give a substantial recognition to Indian Accounting system.
Looking to the above scenario, let's give a look at one of the new IND AS issued, IND AS-106
Definition of exploration activities and exploration costs in both:
1. In Current GAAP:
a. Exploration Cost
Exploration activities cover the prospecting activities conducted in the search for oil and gas. In the course of an appraisal programme these activities include but are not limited to aerial, geological, geophysical, geochemical, palaeontological, palynological, topographical and seismic surveys, analysis, studies and their interpretation, investigations relating to the subsurface geology including structural test drilling, exploratory type stratigraphic test drilling, drilling of exploration and appraisal wells and other related activities such as surveying, drill site preparation and all work necessarily connected therewith for the purpose of oil and gas exploration.
b. Exploration Cost :
Principal types of exploration costs cover all directly attributable expenditure. General and administrative costs are included in the exploration cost only to the extent that those costs can be specifically attributable to the related cost center. In all other cases, these costs are expensed as incurred. For example, general and administrative costs such as directors' fees, secretarial and share registry expenses, salaries and other expenses of general management, etc., are usually recognised as expenses when incurred. Exploration costs include depreciation and applicable operating costs of related support equipment and facilities and other costs of exploration activities that are:
i. costs of surveys and studies mentioned in paragraph 8 above, rights of access to properties to conduct those studies (e.g., costs incurred for environment clearance, defence clearance, etc.), and salaries and other expenses of geologists, geophysical crews and other personnel conducting those studies. Collectively, these are referred to as geological and geophysical or 'G&G' costs;
ii. costs of carrying and retaining undeveloped properties, such as delay rental, ad valorem taxes on properties, legal costs for title defence, maintenance of land and lease records and annual license fees in respect of Petroleum Exploration License;
iii. dry hole contributions and bottom hole contributions;
iv. costs of drilling and equipping exploratory and appraisal wells and related analysis; and
v. Costs of drilling exploratory-type stratigraphic test wells.
2. In Ind AS :
a. Exploration Cost (As per Ind AS):
Exploration and evaluation activities cover the prospecting activities conducted in the search for oil and gas after an entity has obtained legal right to explore a specific area, as well as activities towards determination of the technical feasibility and commercial Viability of extracting the oil and gas. In the course of an appraisal programme these activities include but are not limited to aerial, geological, geophysical, geochemical, palaeontological, palynological, topographical and seismic surveys, analysis, studies and their interpretation, investigations relating to the subsurface geology including structural test drilling, exploratory type stratigraphic test drilling, drilling of exploration and appraisal wells and other related activities such as surveying, drill site preparation and all work necessarily connected therewith for the purpose of oil and gas exploration.
b. Exploration and evaluation costs (As per Ind AS)
Principal types of exploration and evaluation costs cover all directly attributable expenditure. General and administrative costs are included in the exploration and evaluation cost only to the extent that those costs can be directly attributable to the related exploration and evaluation assets. In all other cases, these costs are expensed as incurred. For example, general and administrative costs such as directors' fees, secretarial and share registry expenses, salaries and other expenses of general management, etc., are usually recognised as expenses when incurred. Exploration and evaluation costs include depreciation and applicable operating costs of related support equipment and facilities and other costs of exploration and evaluation activities that are:
i. Costs of surveys and studies mentioned in paragraph 10 above, rights of access to properties to conduct those studies (e.g., costs incurred for environment clearance, defence clearance, etc.), and salaries and other expenses of geologists, geophysical crews and other personnel conducting those studies. Collectively, these are referred to as geological and geophysical or 'G&G' costs;
ii. Costs of carrying and retaining undeveloped properties, such as delay rental, ad valorem taxes on properties, legal costs for title defence, maintenance of land and lease records and annual license fees in respect of Petroleum Exploration License;
iii. Dry hole contributions and bottom hole contributions;
iv. Costs of drilling and equipping exploratory and appraisal wells and related analysis; and
v. Costs of drilling exploratory-type stratigraphic test wells.
Accounting for Acquisition, exploration and Development costs:
In Current GAAP:
Description of Methods: There are two alternative methods for accounting for acquisition, exploration and development costs viz.
Successful Efforts Method (SEM) :
Under the successful efforts method, generally only those costs that lead directly to the discovery, acquisition and development of specific oil and gas reserves are capitalized and become part of the capitalized costs of the cost centre. Costs that are known at the time of incurrence to fail to meet this criterion are generally charged to expense in the period they are incurred. When the outcome of such costs is unknown at the time they are incurred, they are recorded as capital work-in-progress/intangible asset under development and written off when the costs are determined to be nonproductive.
Full Cost Method (FCM) :
Under the full cost method, all costs incurred in, acquiring mineral interests, exploration, and development, are accumulated in cost centres that may not be related to geological factors. The cost centre, under this method, is not normally smaller than a country except where warranted by major difference in economic, fiscal or other factors in the country. The capitalized costs of each cost centre are depreciated as the reserves in each cost centre are produced.
Application of Methods:
Successful Efforts Method:
Under the successful efforts method, in respect of a cost centre, the following costs should be treated as capital work-in-progress or intangible asset under development, as the case may be (refer to paragraphs 46 and 47), when incurred:
- All acquisition costs;
- Exploration costs; and
- All development costs.
All costs other than the above should be charged as expense when incurred (Also refer to paragraph 7 in relation to the accounting treatment for pre-acquisition cost).
When a well is ready to commence commercial production, the costs referred to in paragraph 18 (ii) and (iii) corresponding to proved developed oil and gas reserves should be capitalized as 'completed wells / producing wells' from capital work-in-progress / intangible asset under development to the gross block of assets. With respect to costs referred to in paragraph 18 (i), the entire cost should be capitalized from capital work-in-progress / intangible asset under development to the gross block of assets. Normally, a well is ready to commence commercial production on establishment of proved developed oil and gas reserves.
If the cost of drilling exploratory well relates to a well that is determined to have no proved reserves, then such costs net of any salvage value are transferred from capital work-in-progress/intangible asset under development and charged as expense as and when its status is decided as dry or of no further use for any purpose. Costs of exploratory wells should not be carried over unless it could be reasonably demonstrated that there are indications of sufficient quantity of reserves and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project.
All relevant facts and circumstances shall be evaluated when determining whether an enterprise is making sufficient progress on assessing the reserves and the economic and operating viability of the project. Long delays in the assessment or development plan (whether anticipated or unexpected) may raise doubts about whether the enterprise is making sufficient progress to continue the capitalization after the completion of drilling. If an enterprise has not engaged in substantial activities to assess the reserves or the development of the project in a reasonable period of time after the drilling of the well is completed or activities have been suspended, any capitalized costs associated with that well shall be expensed net of any salvage value. Expenditure incurred on exploratory wells which were written off in past and started producing subsequently, cannot be reinstated.
Depreciation (Depletion)
Depreciation (Depletion) is calculated, using the unit of production method. The application of this method results in oil and gas assets being written off at the same rate as the quantitative depletion of the related reserve. For the properties or groups of properties containing both oil reserves and gas reserves, the units of oil and gas used to compute depletion are converted to a common unit of measure on the basis of their approximate relative energy content, without considering their relative sales values (general approximation is 1000 cubic meters of gas is equivalent to 1 metric tonne of oil). Unit-of-production depletion rates are revised whenever there is an indication of the need for revision but at least once a year. These revisions are accounted for prospectively as changes in accounting estimates, i.e., a change in the estimate affects the current and future periods, but no adjustment is made in the accumulated depletion applicable to prior periods.
The depreciation charge or the UOP charge for the acquisition cost within a cost centre is calculated as under:
UOP charge for the period = UOP rate x Production for the period
UOP rate = Acquisition cost of the cost centre/Proved Oil and Gas Reserves
The depreciation charge or the Unit of Production (UOP) charge for all capitalized costs excluding acquisition cost within a cost centre is calculated as under:
UOP charge for the period = UOP rate x Production for the period
UOP rate = Depreciation base of the cost centre/Proved Developed Oil and Gas Reserves
Depreciation base of the cost centre should include:
a) Gross block of the cost centre (excluding acquisition costs)
b) Estimated dismantlement and abandonment costs net of estimated salvage values pertaining to prove developed oil and gas reserves and should be reduced by the accumulated depreciation and any accumulated impairment charge of the cost centre.
'Proved Oil and Gas Reserves' for the purpose of paragraph 23 comprise proved oil and gas reserves estimated at the end of the period as increased by the production during the period. 'Proved Developed Oil and Gas Reserves' for the purpose of paragraph 24 comprise proved developed oil and gas reserves estimated at the end of the period as increased by the production during the period.
Full Cost Method:
Under the full cost method, in respect of a cost centre, the following costs should be treated as capital work-in-progress or intangible asset under development, as the case may be (refer to paragraphs 46 and 47), when incurred:
i. All acquisition costs;
ii. All exploration costs; and
iii. All development costs.
All costs other than the above should be charged as expense when incurred (Also refer to paragraph 7 in relation to the accounting treatment for pre-acquisition cost).
When any well in a cost centre is ready to commence commercial production, the costs referred to in paragraph 27 above corresponding to all the proved oil and gas reserves in that cost centre should be capitalized from capital work-in-progress/intangible asset under development to the gross block of assets. Normally, a well is ready to commence commercial production on establishment of proved developed oil and gas reserves. In respect of oil and gas reserves proved subsequently, the capital work-in-progress / intangible asset under development corresponding to such reserves should be capitalized at the time when the said reserves are proved. The expenditure which does not result in discovery of proved oil and gas reserves should be transferred from capital work-in-progress/intangible asset under development to the gross block of assets as and when so determined.
Depreciation (Depletion)
The depreciation should be calculated on the capitalized cost according to the unit of production method as explained in paragraph 22 above. In case of full cost method, the depreciation charge or the unit of production (UOP) charge for all costs within a cost centre is calculated as under:
UOP charge for the period = UOP rate x Production for the period
UOP rate = Depreciation base of the cost centre/Proved Oil and Gas Reserves
The depreciation base of the cost centre should include
a) Gross block of the cost centre;
b) The estimated future expenditure (based on current costs) to be incurred in developing the proved oil and gas reserves referred to in paragraph 32;
c) Estimated dismantlement and abandonment costs net of estimated salvage values (refer to paragraphs 35-36) for facilities set up for developing the proved oil and gas reserves referred to in paragraph 32; and should be reduced by the accumulated depreciation and any accumulated impairment charge of the cost centre.
'Proved Oil and Gas Reserves' for this purpose comprise developed and undeveloped oil and gas reserves estimated at the end of the period as increased by the production during the period.
Recommendation of Methods:
The successful efforts method is recommended as a preferred method, though an enterprise is permitted to follow the full cost method.
In Ind AS:
An entity should capitalize acquisition costs as an intangible asset or tangible asset, based on its nature. For example, acquisition cost incurred to obtain right to explore should be capitalized as intangible asset being in the nature of commercial right.
The exploration and evaluation expenditure should be accounted for in accordance with the requirements of Ind AS 106. Accordingly, an entity should determine an accounting policy, specifying which expenditures are recognised as exploration and evaluation assets and apply the policy consistently. In making this determination, an entity considers the degree to which the expenditure can be associated with finding specific mineral resources.
An entity should classify exploration and evaluation assets as tangible or intangible according to the nature of the assets acquired and apply the classification consistently. Some exploration and evaluation assets are treated as intangible, whereas others are tangible. To the extent that a tangible asset is consumed in developing an intangible asset, the amount reflecting that consumption is part of the cost of the intangible asset. However, using a tangible asset to develop an intangible asset does not change the nature and classification of a tangible asset into an intangible asset.
Once the technical feasibility and commercial viability of extracting oil and gas are determinable, the exploration and evaluation assets should be reclassified as capital work-in-progress or intangible asset under development, as the case may be. Exploration and evaluation assets should be assessed for impairment, and impairment loss if any, should be recognised, before such reclassification. Subsequent development costs should be capitalized when incurred.
When a well is ready to commence commercial production, the capitalized costs referred to in above paragraphs corresponding to proved developed oil and gas reserves should be reclassified as 'completed wells/producing wells' from “capital work-in-progress / intangible asset under development” to the gross block of assets. With respect to acquisition costs, the entire cost should be capitalized from “capital work-in-progress / intangible asset under development” to the gross block of assets.
Normally, a well is ready to commence commercial production on establishment of proved developed oil and gas reserves.
The exploration and evaluation expenditure which does not result in discovery of proved oil and gas reserves should be charged as expense or capitalized depending upon the accounting policy adopted by an entity, as mentioned in paragraph 19 above.
Expenditure incurred on exploratory wells which were written off in the past and started producing subsequently, cannot be reinstated.
Depreciation (Depletion)
Depreciation (Depletion) is calculated, using the unit of production method. The application of this method results in oil and gas assets being written off at the same rate as the quantitative depletion of the related reserve. For the properties or groups of properties containing both oil reserves and gas reserves, the units of oil and gas used to compute depletion are converted to a common unit of measure on the basis of their approximate relative energy content, (general approximation is 1000 cubic meters of gas is equivalent to 1 metric tonne of oil) without considering their relative sales values. Unit-of-production depletion rates are revised whenever there is an indication of the need for revision but at least once a year. These revisions are accounted for prospectively as changes in accounting estimates, i.e., a change in the estimate affects the current and future periods, but no adjustment is made in the accumulated depletion applicable to prior periods.
The depreciation charge or the Unit of Production (UOP) charge for the acquisition cost within a field is calculated as under:
UOP charge for the period = UOP rate x Production for the period
UOP rate = Acquisition cost of the field /Proved Oil and Gas Reserves
The depreciation charge or the Unit of Production (UOP) charge for all capitalized costs excluding acquisition cost within a field is calculated as under:
UOP charge for the period = UOP rate x Production for the period
UOP rate = Depreciation base of the field /Proved Developed Oil and Gas Reserves
Depreciation base of the field should include:
i. Gross block of the field (excluding acquisition costs)
ii. Estimated, decommissioning and abandonment costs net of estimated salvage values pertaining to proved developed oil and gas reserves and should be reduced by the accumulated depreciation and any accumulated impairment charge of the field.
'Proved Oil and Gas Reserves' for the purpose of paragraph 26 comprise proved oil and gas reserves estimated at the end of the period as increased by the production during the period.
'Proved Developed Oil and Gas Reserves' for the purpose of paragraph 27 comprise proved developed oil and gas reserves estimated at the end of the period as increased by the production during the period.
The depreciation method used should reflect the pattern in which the asset's future economic benefits are expected to be consumed by the entity. The entity selects the method that most closely reflects the expected pattern of consumption of the future economic benefits embodied in the asset. Accordingly, oil and gas assets for the purpose of applying UOP method should not include assets having a different pattern of consumption which is not related to depletion of oil and gas reserves. The depreciation method applied should be reviewed at least at each financial year-end and if there has been a significant change in the expected pattern of consumption of the future economic benefits embodied in the asset, the method should be changed to reflect the changed pattern.
Impairment of Asset:
As per Ind AS:
An entity should determine an accounting policy for allocating exploration and evaluation assets to cash-generating units or groups of cash-generating units for the purpose of assessing such assets for impairment. Each cash-generating unit or group of units to which an exploration and evaluation asset is allocated should not be larger than an operating segment determined in accordance with Ind AS 108, Operating Segments. 38. Exploration and evaluation assets should be assessed for impairment when facts and circumstances suggest that the carrying amount of an exploration and evaluation asset may exceed its recoverable amount.
One or more of the following facts and circumstances indicate that an E&E entity should test for impairment during the exploration phase (the list is not exhaustive):
a) The period for which the entity has the right to explore in the specific area has expired during the period or will expire in the near future, and is not expected to be renewed.
b) Substantive expenditure on further exploration activities in the specific area is neither budgeted nor planned.
c) Exploration in the specific area have not led to the discovery of commercially viable quantities of reserves and the entity has decided to discontinue such activities in the specific area.
d) Sufficient data exist to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration cost is unlikely to be recovered in full from successful development or by sale.
In any such case, or similar cases, the entity should perform an impairment test in accordance with Ind AS 36, Impairment of Assets. Any impairment loss is recognised as an expense in accordance with Ind AS 36.
As per Current GAAP:
Accounting Standard (AS) 28, 'Impairment of Assets', is applicable to E&P enterprises irrespective of the method of accounting used. For the purpose of AS 28, each cost centre used should be treated as a Cash Generating Unit. Under SEM, a field is generally considered as a cash generating unit. In certain circumstances, for example, where two or more fields use common production and transportation facilities, those fields may be sufficiently economically interdependent to constitute a single cash generating unit for the purposes of AS 28, in which case impairment test should be performed in aggregate for those fields.
One or more of the following facts and circumstances indicate that an E&P enterprise should test for impairment during the exploration phase (the list is not exhaustive):
a) The period for which the enterprise has the right to explore in the specific area has expired during the period or will expire in the near future, and is not expected to be renewed.
b) Substantive expenditure on further exploration activities in the specific area is neither budgeted nor planned.
c) Exploration in the specific area have not led to the discovery of commercially viable quantities of reserves and the enterprise has decided to discontinue such activities in the specific area.
d) Sufficient data exist to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration cost is unlikely to be recovered in full from successful development or by sale.
In any such case, or similar cases, the enterprise should perform an impairment test in accordance with AS 28. Any impairment loss is recognized as an expense in accordance with AS 28.
In case of development/producing fields, the proved reserves would have been established. Accordingly, in case any of the indicators as per the general principles of AS 28 or if any specific indicators exist, its recoverable amount should be determined for the purposes of impairment analysis.
For the purposes of estimating future cash flows as per the requirements of AS 28, E&P enterprises should consider both proved and probable reserves.
For this purpose, full estimate of expected cost of evaluation/development (i.e., in arriving at the proved reserves) should be considered while applying the impairment test.
On the date of this revised Guidance Note becoming effective, an E&P enterprise should assess whether there is any indication that an oil and gas asset may be impaired. If any such indication exists, the enterprise should determine impairment loss, if any, in accordance with this Guidance Note. The difference (as adjusted by any related tax expense) between the impairment loss so determined, and the impairment loss already recognised, if any, as per the requirements of the earlier Guidance Note, should be adjusted against opening balance of revenue reserves.
Accounting treatment of cost of support equipment and facilities:
As per Current GAAP:
The cost of acquiring or constructing support equipment and facilities used in E&P activities should be capitalized in accordance with Accounting Standard (AS) 10, 'Accounting for Fixed Assets'. Depreciation on such equipment and facilities should be arrived at in accordance with Accounting Standard (AS) 6, 'Depreciation Accounting', and accounted for as exploration cost, development cost or production cost, as may be appropriate.
As per Ind AS:
The cost of acquiring or constructing support equipment and facilities used in E&P activities should be capitalized in accordance with Ind AS 16. Depreciation on such equipment and facilities should be arrived at in accordance with Ind AS 16, and accounted for as exploration and evaluation cost, development cost or production cost, as may be appropriate.
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