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Exposure Draft of the Guidance Note on Accounting for Oil and Gas Producing Activities (for entities to whom Ind AS is applicable) (Comments to be received by August 31, 2016)
August, 04th 2016
                  Exposure Draft

Guidance Note on Accounting for Oil and Gas
       Producing Activities (Ind AS)


    (Last date of comments: August 31, 2016)




                       Issued by
                   Research Committee
        The Institute of Chartered Accountants of India
                 (Set up by an Act of Parliament)
                        New Delhi
                                     Exposure Draft

      Guidance Note on Accounting for Oil and Gas Producing
                        Activities (Ind AS)
Research Committee of the Institute of Chartered Accountants of India invites
comments on any aspect of this Exposure Draft of the `Guidance Note on
Accounting for Oil and Gas Producing Activities (Ind AS)'. Comments are most
helpful if they indicate the specific paragraph or group of paragraphs to which they
relate, contain a clear rationale and, where applicable, provide a suggestion for
alternative wording.
Comments should be submitted in writing to the Secretary, Research Committee,
The Institute of Chartered Accountants of India, ICAI Bhawan, Post Box No. 7100,
Indraprastha Marg, New Delhi ­ 110 002, so as to be received not later than
August 31, 2016. Comments can also be sent by e-mail at research@icai.in .


This Guidance Note is to be applied by the specified companies to whom Ind ASs are applicable as
per rule 4 of the Companies (Indian Accounting Standard) Rules, 2015 (`referred to as Ind AS
companies') from the date from which Ind ASs are applicable to such companies.

Introduction

1. Oil and gas producing industry, which is extractive in nature, involves activities relating to
acquisition of mineral interests in properties, exploration (including prospecting),
development and production of oil and gas. Oil and gas also include coal bed methane
(CBM) and shale gas. These activities may be carried out onshore or offshore. The
aforesaid activities are collectively referred to as upstream operations and form the `Upstream
Petroleum Industry'. The industry is commonly referred to as the `E&P' industry. The peculiar
nature of the industry requires establishment of industry-specific accounting principles in
relation to expense recognition, measurement and disclosure.

Objective
2. Considering the peculiar nature of E&P industry, Indian Accounting Standard (Ind AS) 16,
Property, Plant and Equipment and Indian Accounting Standard (Ind AS) 38 , Intangible Assets ,
do not apply to recognition and measurement of exploration and evaluation assets [para 3(c) of
Ind AS 16 and para 2 (c) of Ind AS 38 respectively]. Indian Accounting Standard (Ind AS)
106, Exploration and Evaluation of Mineral Resources, applies to such assets.

3. The objective of this Guidance Note is to provide guidance on the accounting principles
contained in Indian Accounting Standards (Ind AS) to accounting for costs incurred on activities
relating to acquisition of interests in properties, exploration, development and production of oil




                                                1
  and gas.

  Scope
  4. This Guidance Note applies to costs incurred on acquisition of mineral interests in
  properties, exploration, development and production of oil and gas activities, i.e., upstream
  operations. This Guidance Note also deals with other accounting aspects such as accounting
  for abandonment costs and impairment of assets that are peculiar to the entities carrying on
  oil and gas producing activities. It does not address accounting and reporting issues relating
  to the transporting, refining and marketing of oil and gas. This Guidance Note also does not
  apply to accounting for:

         (a)    activities relating to the production of natural resources other than oil and gas; and
         (b)    the production of geothermal resources or the extraction of hydrocarbons as a by-
                product of the production of geothermal and associated resources.
  Definitions
  5. For the purpose of this Guidance Note, the following terms are used with the meanings
  specified:
(i)    Appraisal Well: A well drilled as part of an appraisal drilling programme, which is carried
       out to determine the physical extent of oil and gas reserves and likely production rate of a
       field.


(ii)   Depreciation: Depreciation is the systematic allocation of the depreciable amount of an asset
       over its useful life. Depreciation includes amortisation of assets whose useful life is
       predetermined. Depreciation also includes `depletion' of natural resources through the
       process of extraction or use.


(iii) Development Well: A well drilled, deepened, completed or re-completed within the proved
      area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.


(iv) Exploratory Well: An exploratory well is a well drilled to find a new field or to find a new
     reservoir in a field previously found to be productive of oil or gas in another reservoir.
     Generally, an exploratory well is any well that is not a development well, a service well, or a
     stratigraphic test well, as those items are defined separately.

(v) Exploration and evaluation assets: Exploration and evaluation expenditures recognised as assets
    in accordance with the entity's accounting policy.

(vi)    Exploration and evaluation expenditures: Expenditures incurred by an entity in connection with
       the exploration for and evaluation of mineral resources before the technical feasibility and




                                                    2
    commercial viability of extracting a mineral resource are demonstrable.

(vii) Exploration for and evaluation of mineral resources: The search for mineral resources,
      including minerals, oil, natural gas and similar non-regenerative resources after the entity has
      obtained legal rights to explore in a specific area, as well as the determination of the technical
      feasibility and commercial viability of extracting the mineral resource.
(viii) Field: An area consisting of a single reservoir or multiple reservoirs all grouped on or
       related to the same individual geological structural feature and/or stratigraphic condition.
       There may be two or more reservoirs in a field which are separated vertically by intervening
       impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are
       associated by being in overlapping or adjacent fields may be treated as a single or
       common operational field. The geological terms `structural feature' and `stratigraphic
       condition' are intended to identify localised geological features as opposed to the broader
       terms of basins, trends, provinces, plays, areas-of-interest, etc.
(ix) (a) Oil and Gas Reserves Oil and gas reserves are estimated remaining quantities of oil
     and gas and related substances anticipated to be economically producible, as of a given
     date, by application of development projects to known accumulations. In addition, there
     must exist, or there must be a reasonable expectation that there will exist, the legal right to
     produce or a revenue interest in the production, installed means of delivering oil and gas or
     related substances to market, and all permissions and financing required to implement the
     project.

    (b) All oil and gas reserve estimates involve some degree of uncertainty. Uncertainty
    depends chiefly on availability of reliable geological and engineering data at the time of the
    estimate and interpretation of data.


    (c) T h e term economically producible, as it relates to a resource, means a resource which
    generates revenue that exceeds, or is reasonably expected to exceed, the costs of the
    operation.


(x) Based on relative degree of uncertainty, oil and gas reserves can be classified as
    `Proved Oil and Gas Reserves' and `Unproved Oil and Gas Reserves'.


(xi) Proved Oil and Gas Reserves: Proved oil and gas reserves are those quantities of oil and
     gas, which, by analysis of geoscience and engineering data, can be estimated with
     reasonable certainty to be economically producible from a given date forward, from
     known reservoirs, and under existing economic conditions, operating methods, and
     government regulations before the time at which contracts providing the right to operate
     expire, unless evidence indicates that renewal is reasonably certain, regardless of whether
     the estimate is a deterministic estimate or probabilistic estimate. The project to extract the




                                                    3
    hydrocarbons must have commenced or the entity must be reasonably certain that it will
    commence the project within a reasonable time.
    Proved oil and gas reserves can be classified as `Proved developed oil and gas reserves'
    and `Proved undeveloped oil and gas reserves'.
(xii) Proved Developed Oil and Gas Reserves: Proved developed oil and gas reserves are
      reserves that can be expected to be recovered:
        (a) through existing wells with existing equipment and operating methods or in which
            the cost of the required equipment is relatively minor compared to the cost of a
            new well; and
        (b) through installed extraction equipment and infrastructure operational at the time of
            the reserves estimate if the extraction is by means not involving a well.
(xiii) (a) Proved Undeveloped Oil and Gas Reserves: (a) Proved undeveloped oil and gas reserves
       are proved reserves that are expected to be recovered from new wells on undrilled
       acreage, or from existing wells where a relatively major expenditure is required for
       recompletion.
    (b) Reserves on undrilled acreage should be limited to those directly offsetting
    development spacing areas that are reasonably certain of production when drilled, unless
    evidence using reliable technology exists that establishes reasonable certainty of economic
    producibility at greater distances.
    (c) Undrilled locations can be classified as having proved undeveloped reserves only if a
    development plan has been adopted indicating that they are scheduled to be drilled within
    a reasonable time, unless the specific circumstances, justify a longer time.
    (d) Under no circumstances should estimates for proved undeveloped reserves be
    attributable to any acreage for which an application of fluid injection or other improved
    recovery technique is contemplated, unless such techniques have been proved effective by
    actual projects in the same reservoir or an analogous reservoir, or by other evidence using
    reliable technology establishing reasonable certainty.

(xiv) Probable Reserves: Probable reserves are those additional reserves that are less certain to
      be recovered than proved reserves but which, together with proved reserves, are as likely
      as not to be recovered. When deterministic methods are used, it is as likely as not that
      actual remaining quantities recovered will exceed the sum of estimated proved plus
      probable reserves. When probabilistic methods are used, there should be at least a 50%
      probability that the actual quantities recovered will equal or exceed the proved plus
      probable reserve estimates.
(xv) Reservoir: A porous and permeable underground formation containing a natural
     accumulation of producible oil or gas that is confined by impermeable rock or water barriers
     and is individual and separate from other reservoirs.
(xvi) Service Well: A service well is a well drilled or completed for the purpose of supporting
      production in an existing field. Wells in this class are drilled for gas injection (natural







                                                4
    gas, propane, butane, or flue gas), water injection, steam injection, air injection, polymer
    injection, salt-water disposal, water supply for injection, observation, or injection for
    combustion.
(xvii) Stratigraphic Test Well: A stratigraphic test is a drilling effort, geologically directed, to
       obtain information pertaining to a specific geologic condition. Such wells customarily are
       drilled without the intention of being completed for hydrocarbon production. This
       classification also includes tests identified as core tests and all types of expendable holes
       related to hydrocarbon exploration. Stratigraphic test wells (sometimes called expendable
       wells) are classified as follows:

          (a) Exploratory-type stratigraphic test well: A stratigraphic test well drilled, but
              not in a proved area. These wells are more like exploratory wells than like
              geological and geophysical (G&G) activities, even though these wells cannot be
              used to produce the reserves.
          (b) Development-type stratigraphic test well: A stratigraphic test well drilled in a
              proved area.

(xviii) Unit of Production (UOP) method: The method of depreciation (depletion) under which
        depreciation (depletion) is calculated on the basis of the number of production or similar
        units expected to be obtained from the asset by the entity.


 6. The glossary of certain other terms commonly used in E&P industry and relevant for the
 Guidance Note is given in Appendix 1.


 Classification of Activities and Related Costs
 Acquisition Activities
 7. Activities carried out by an E&P entity towards the acquisition of right(s) to explore,
 develop and produce oil and gas, constitute acquisition activities. Once the areas of oil and
 gas finds are identified, the E&P entity approaches the owner who owns the rights for the
 exploration, development and production of the underground minerals in respect of the
 property or area. In order to undertake surveys and exploration activities, an E&P entity has to
 first obtain a Petroleum Exploration License (PEL) or Letter of Authority (LOA) in India or
 similar permit elsewhere, by whatever name called. For engaging in development and
 production activities, an entity has to obtain a Mining Lease (ML) in India. Similarly, other
 countries may require specific permissions/lease/license for the purpose. The rights for
 exploration, development or production may also be acquired by entering into a farm-in
 arrangement (transfer of part of oil & gas interest between parties).




                                                  5
Acquisition Costs
8. Acquisition costs cover all costs incurred to purchase, lease or otherwise acquire a property
or mineral right proved or unproved. These include lease/signature bonus, brokers' fees, legal
costs, cost of temporary occupation of the land including crop compensation paid to
farmers, consideration for farm-in arrangements and all other costs incurred in acquiring
these rights. These are costs incurred in acquiring the right to explore, drill and produce oil and
gas including the initial costs incurred for obtaining the PEL/LOA and ML. Annual licence
fees are excluded. In case the acquisition cost pertains to more than one field, it should be
apportioned to the related field on a fair and reasonable basis.


9. Expenditure incurred before an entity has obtained the right(s) to explore, develop and produce
oil and gas, i.e., the pre-acquisition costs, e.g., data collection and analysis costs incurred for the
purpose of identifying the oil and gas asset to be acquired, are not included in acquisition costs.
Such costs are accounted for in accordance with the general principles laid down in the
framework for preparation and presentation of financial statements and other applicable
accounting pronouncements.

Activities relating to exploration for and evaluation of mineral resources
10. 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.


Exploration and evaluation costs
11. Principal types of exploration a nd e va l u ati o n 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 specifically 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




                                                  6
           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 licence 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.

Development Activities
12. Development activities cover the activities conducted after determination of the technical
feasibility and commercial viability of extracting oil and gas. These activities include, but are not
limited to the purchase, shipment or storage of equipment and materials used in developing oil
and gas accumulations, completion of successful exploration wells, drilling; completion; re-
completion; and testing of development/service wells, laying of gathering lines, construction
of offshore platforms and installations, installation of separators, tankages, pumps, artificial
lift and other producing and injection facilities required to produce, process and transport oil
or gas into main oil storage or gas processing facilities, either onshore or offshore, including
laying of infield pipelines, installation of the said storage or gas processing facilities.


Development Costs
13. Development costs cover all the directly attributable expenditure incurred in respect of the
development activities including costs incurred to:
       (i) gain access to and prepare well locations for drilling, including surveying well
           locations for the purpose of determining specific development drilling sites,
           clearing ground, draining, road building and relocating public roads, gas lines and
           power lines to the extent necessary in developing the proved oil and gas reserves;
       (ii) drill and equip development wells (whether successful or unsuccessful),
            development-type stratigraphic test wells and service wells including the cost of
            platforms and of well materials and equipment such as casing, tubing, pumping
            equipment and the wellhead assembly;
       (iii) acquire, construct and install production facilities such as lease flow lines,
             separators, treaters, heaters, manifolds, measuring devices and production storage
             tanks, natural gas cycling and processing plants and utility and waste disposal
             systems; and
       (iv) provide advanced recovery system.




                                                  7
14. Development costs also include depreciation and applicable operating cost of related
support equipment and facilities in connection with development activities and annual license
fees in respect of Mining Lease.


15. General and administrative costs are included in the development cost only to the extent
that those costs can be specifically attributable to the related field. 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.


Production Activities
16. Production activities consist of pre-wellhead (e.g., lifting the oil and gas to the surface,
operation and maintenance of wells and extraction rights, etc.,) and post-wellhead (e.g.,
gathering, treating, field transportation, field processing, etc., upto the outlet valve on the
lease or field production storage tank, etc.) activities for producing oil and/or gas.


Production Costs
17. Production costs consist of direct and indirect costs incurred to operate and maintain an
entity's wells and related equipment and facilities, including depreciation and applicable
operating costs of support equipment and facilities. Examples of production costs are :
    (a) Pre-wellhead costs :
        Costs of labour, repairs and maintenance, materials, supplies, fuel and power,
        property taxes, insurance, severance taxes, royalty, etc., in respect of lifting the oil and
        gas to the surface, operation and maintenance including servicing and work-over of
        wells.
    (b) Post-wellhead costs :
        Costs of labour, repairs and maintenance, materials, supplies, fuel and power,
        property taxes, insurance, etc., in respect of gathering, treating, field transportation,
        field processing, including cess up to the outlet valve on the lease or field production
        storage tank, etc.
Accounting for "Acquisition", "Exploration And Evaluation" and " Development Costs"
18. An entity should capitalise 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.
19. 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




                                                   8
policy consistently. In making this determination, an entity considers the degree to which the
expenditure can be associated with finding specific mineral resources.
20. 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 a tangible asset into an intangible asset.
 21 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 capitalised when
incurred.
22. All costs other than those covered in paragraph 8 and paragraphs 10 to paragraph 15 should
be charged as expense when incurred (Also refer to paragraph9 in relation to the accounting
treatment for pre-acquisition cost).
23. When a well is ready to commence commercial production, the capitalised 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 a c q u i s i t i o n costs,
the entire cost should be capitalised 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.
24. The exploration and evaluation expenditure which does not result in discovery of proved oil and
gas reserves should be charged as expense or capitalised depending upon the accounting policy
adopted by an entity, as mentioned in paragraph 19 above.

25. Expenditure incurred on exploratory wells which were written off in the past and started
producing subsequently, cannot be reinstated.


Depreciation (Depletion)
26. 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




                                                  9
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.


27. The depreciation charge or the 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


28. The depreciation charge or the Unit of Production (UOP) charge for all capitalised 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


29. Depreciation base of the field should include:
    (a) Gross block of the field (excluding acquisition costs)
    (b) Estimated dismantlement 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.

30. `Proved Oil and Gas Reserves' for the purpose of paragraph 27 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 2 8 comprise
proved developed oil and gas reserves estimated at the end of the period as increased by the
production during the period.

31. 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.
Accounting for Production Costs
32. Production costs, mentioned in paragraph 17 above, become part of the cost of oil and gas
produced, along with depreciation (depletion) of capitalised acquisition, exploration and




                                               10
development costs.

Accounting for Cost of Support Equipment and Facilities
33. The cost of acquiring or constructing support equipment and facilities used in E&P
activities should be capitalised in accordance with Ind AS 16 . Depreciation on such
equipment and facilities should be arrived at in accordance with I n d A S 1 6 , and accounted
for as exploration and evaluation cost, development cost or production cost, as may be
appropriate.
Accounting for Abandonment Costs
34. Abandonment costs are the costs incurred on discontinuation of all operations and
surrendering the property back to the owner. These costs relate to plugging and abandoning of
wells, dismantling of wellheads; production; and transport facilities and to restoration of
producing areas in accordance with license requirements and the relevant legislation.
35. The eventual liability for abandonment cost should be recognised when the obligation arises on
the ground that a liability to remove an installation exists the moment it is installed. Thus, an
entity should capitalise as part of property, plant and equipment or intangible asset, as the case may
be, the amount of provision required to be created for subsequent abandonment. The provision for
estimated abandonment costs should be made at current prices considering the environment and
social obligations, terms of mining lease agreement, industry practice, etc. Where the effect of the
time value of money is material, the amount of the provision should be the present value of the
expenditures expected to be required to settle the obligation. The discount rate (or rates) should be
a pre-tax rate (or rates) that reflect current market assessments of the time value of money and the
risks specific to the liability. The discount rate should not reflect risks for which future cash flow
estimates have been adjusted. Changes in the measurement of existing abandonment costs that
result from changes in the estimated timing or amount of the outflow of resources embodying
economic benefits required to settle the obligation or a change in the discount rate should be added
to, or deducted from the related field in the current period and would be considered for necessary
depletion (depreciation) prospectively. However, the change in the estimated provision due to the
periodic unwinding of the discount should be recognized in profit or loss as it occurs. Since
abandonment costs do not reflect borrowed funds, the unwinding cost would not be a borrowing
cost eligible for capitalisation
Abandonment of Properties
36. No gain or loss should be recognised if only an individual well or individual item of
equipment is abandoned o r d e c i d e d a s d r y as long as the remainder of the wells in the
field continues to produce oil or gas. When the last well on the field ceases to produce and the
entire field is abandoned, gain or loss should be recognised.
Capitalisation of Borrowing Costs
37. Capitalisation of borrowing costs should be in accordance with the Indian Accounting
Standard (Ind AS) 23,, `Borrowing Costs'.




                                                 11
Impairment of Assets
Exploration and evaluation assets
38. 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 Indian Accounting Standard (Ind AS) 108, Operating Segments.
39. 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.

40. 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.
41. In any such case, or similar cases, the entity should perform an impairment test in
accordance with Indian Accounting Standard (Ind AS) 36, Impairment of Assets. Any
impairment loss is recognised as an expense in accordance with Ind AS 36.
Development and production assets
42. 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 Ind AS
36 or if any specific indicators exist, its recoverable amount should be determined for the
purposes of impairment analysis.


43. For the purposes of estimating future cash flows fo r dete r mi nin g va l ue in us e as per
the requirements of Ind AS 36, E&P entities should consider up to 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. In
accordance with the requirements of Ind AS 36, in measuring value in use, an entity should base




                                                12
cash flow projections on reasonable and supportable assumptions that represent management's
best estimate of the range of economic conditions that will exist over the remaining useful life of
the asset. Accordingly, management's estimates of future cash flows usually takes a long-term
view of the range of economic conditions over the remaining useful life of the asset and, are not
based on the relatively short-term changes in the economic conditions.
44. 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 Ind AS 36, in which case
impairment test should be performed in aggregate for those fields.
Accounting for Interests in Joint Ventures

45. Many E&P entities enter into joint venture agreements for oil and gas exploration,
development and production. In case of such arrangements, the accounting principles prescribed
in Indian Accounting Standard (Ind AS) 111, Joint Arrangements, should be applied. In
accordance with the requirements of Ind AS 111, an entity should determine the type of joint
arrangement in which it is involved. The classification of a joint arrangement as a joint operation
or a joint venture depends upon the rights and obligations of the parties to the arrangement. A
joint operation is a joint arrangement whereby the parties that have joint control of the
arrangement have rights to the assets, and obligations for the liabilities, relating to the
arrangement. Those parties are called joint operators. A joint venture is a joint arrangement
whereby the parties that have joint control of the arrangement have rights to the net assets of the
arrangement. Those parties are called joint venturers. An entity applies judgement when
assessing whether a joint arrangement is a joint operation or a joint venture. An entity should
determine the type of joint arrangement in which it is involved by considering its rights and
obligations arising from the arrangement. An entity assesses its rights and obligations by
considering the structure and legal form of the arrangement, the terms agreed by the parties in the
contractual arrangement and, when relevant, other facts and circumstances. Subject to evaluation
of specific facts and circumstances, generally, in the Indian context, unincorporated joint
ventures constituted under the production sharing contracts are likely to be in the form of joint
operations.
Disposal of Interest
46. In case an entity entity, sells a part of its interest in a field, gain or loss should be
recognised in the statement of profit and loss, except that no gain should be recognised at the
time of such sale if substantial uncertainty exists about the recovery of the costs applicable
to the retained interest or the entity has substantial obligation for future performance. The
gain in such a situation (for example, in the exploratory phase) should be treated as recovery of
cost related to that field.
Accounting for Side-Tracking Expenditure
47. Sometimes an E&P activity requires a second (or higher) attempt to drill a wellbore after the
first wellbore has been junked (generally referred to `side-track'). This saves re-drilling the top







                                                13
part of the hole but requires drop back to a smaller wellbore size in the sidetrack. In case of an
exploratory well, the cost of side-tracking should be treated in the same manner as the cost
incurred on a new exploratory well. The cost of abandoned portion should be treated in the same
manner as the cost of dry well, in line with the policy of accounting followed.
48. In case of development wells, the entire costs of abandoned portion and side-tracking
should be capitalised.
49. In case of producing wells, if the side-tacking results in additional proved developed
oil and gas reserves or increases the future benefits therefrom beyond previously assessed
standard of performance, e.g., allows accelerated production (other than from normal work-
over), the cost incurred on side-tracking should be capitalised, whereas the cost of abandoned
portion of the well due to side-tracking should be depleted in the normal way. Otherwise, the
cost of side-tracking should be charged as expense and the cost of abandoned portion should
be depleted in the normal way.
Accounting for Carried Interest
50. There are several types of "carried interest" arrangements that arise in practice. Each
arrangement may be unique and would require careful analysis in order to determine the
substance of the arrangement. For example, a part of a participating interest in an unproved
property may be assigned to effect a "carried interest" arrangement whereby the assignee (the
carrying party) agrees to defray all costs of drilling, developing, and operating the property
and is entitled to all of the revenue from production from the property, excluding any third
party interest, until all of the assignee's costs have been recovered, after which the assignor
will share in both costs and production, based on the agreed arrangement. In such an
arrangement, the carried party should make no accounting for any costs and revenue until
recoupment (payout) of the carried costs by the carrying party. Subsequent to payout, the
carried party should account for its share of revenue, operating expenses, and subsequent
development costs, if the agreement provides for subsequent sharing of costs rather than a
carried interest. During the payout period, the carrying party should record all costs,
including those carried, as per its normal accounting policy, and should record all revenue
from the property including that applicable to the recovery of costs carried.
Changes in Accounting Policies

51. An entity may change its accounting policies for exploration and evaluation expenditures if the
change makes the financial statements more relevant to the economic decision-making needs of
users and no less reliable, or more reliable and no less relevant to those needs. An entity should
judge relevance and reliability using the criteria in Ind AS 8.
52. To justify changing its accounting policies for exploration and evaluation expenditures, an
entity should demonstrate that the change brings its financial statements closer to meeting the
criteria in Ind AS 8, but the change need not achieve full compliance with those criteria.
Determination of functional currency




                                                14
53. Entities in E&P industry frequently undertake transactions in different currencies. An entity
should determine its functional currency in accordance with the principles laid down in Indian
Accounting Standard (Ind AS) 21, The Effects of Changes in Foreign Exchange Rates. As per Ind
AS 21, functional currency is the currency of the primary economic environment in which an entity
operates, which is normally the one in which it primarily generates and expends cash. An entity
considers the factors specified in Ind AS 21 for determining its functional currency. In many cases,
due to the nature of E&P industry, transactions are denominated in a currency which may be
different from the currency of the primary economic environment of transacting parties. In such
cases, merely the fact that the transactions are denominated in such a currency may not necessarily
be the factor to determine the functional currency since such a currency may be used due to its
being a widely traded currency and may not be reflective of a currency of the primary economic
environment in which transacting parties operate. In such cases, determination of functional
currency involves judgement based on consideration of all the factors specified in Ind AS 21 in the
context of specific facts and circumstances
Presentation
54. The carrying amounts of tangible and intangible oil and gas assets should be classified
separately as tangible and intangible n on -c ur r e nt assets, capital work-in-progress and
intangible assets under development, as the case may be.

55. For the purpose of paragraph 54 above, oil and gas assets should be classified as tangible
and intangible, based on the nature of the asset. Determining whether the nature of oil and gas
assets is tangible or intangible should reflect whether the cost is incurred towards creation
of a physical (tangible) asset that will itself be used or intangible knowledge. For example, a
producing well which is used to extract reserves is classified as a tangible n o n - c u r r e n t
asset. However, an exploratory well may only provide knowledge, and accordingly, is
classified as intangible asset under development.
56. Examples of oil and gas assets that might be classified as intangible include:
    - acquired rights to explore
    - costs of surveys and studies, where capitalised
    - exploratory drilling costs.
   Examples of oil and gas assets that might be classified as tangible assets include:
    - development drilling costs
    - piping and pumps
    - producing wells


to the extent that a tangible asset is consumed in developing an intangible asset, the amount
of consumption of that asset is treated as part of the cost of the intangible asset created.
However, the asset being used remains a tangible asset till such consumption.




                                                15
Disclosure

57. Besides the disclosures required by applicable Ind ASs and statutes, an E&P entity should
disclose the following in its financial statements:
     (i)    The accounting policies followed.
     (ii)   Net quantities of an entity's interests in proved reserves and proved developed
            reserves of (a) oil (including condensate and natural gas liquids) and (b) gas , as at the
            beginning and additions, deductions, production and closing balance.
     (iii) Net quantities of an entity's interest in proved reserves and proved developed reserves
           of (a) oil and (b) gas should also be disclosed on the geographical basis.
     (iv) The reporting of reserve quantities should be stated in metric tonnes for oil reserves
          and cubic meters for gas reserves.
     (v)    Description and net quantities of an entity's interest in reserves used as a basis for
            impairment assessment, if applicable.
     (vi) Basis of determination of cash generating unit used for impairment assessment
          purposes.
     (vii) Frequency of reserve evaluation, principal assumptions used and involvement of any
           external expert(s), if used.
     (viii) Exploration cost written-off during the period
     (ix) Explanation of changes in reserve estimates.




                                                  16
                                                                         Appendix 1
                                                                            Glossary

1. Abandon
To discontinue attempts to produce oil and gas from a mining lease area or a well
and to plug the reservoir in accordance with regulatory requirements and salvage all
recoverable equipments
2. Block
A defined area for purposes of licensing or leasing to an entity or entities for
exploration, development and production rights.
3. Bottom-Hole Contributions
Money or property paid to an operator for use in drilling a well on property in which
the payer has no property interest. The contributions are payable when the well
reaches a pre-determined depth, regardless of whether the well is productive or
non-productive. The payer may receive proprietary information on the well's
potential productivity.
4. Condensate
Low vapour pressure hydrocarbons obtained from Natural Gas through
condensation or extraction and refer solely to those hydrocarbons that are liquid at
normal surface temperature and pressure conditions.
5. Dry Hole
A well, which has proved to be non-productive.
6. Dry Hole Contribution
A contribution made by one entity to costs incurred by another entity that is
drilling a nearby well to obtain information from the entity drilling the well; the
contribution is made when the well is complete and is found to be unsuccessful.
7. Geological and Geophysical Studies (G&G)
Processes which seek surface or subterranean indications of earth structure or
formation where experience has shown the possibility of existence of mineral
deposits.

8. Geological Survey
An exploratory programme directed to examination of rock and sediments
obtained by boring or drilling, or by inspection of surface outcroppings.

9. Geophysical Survey
A study of the configuration of the earth's crust in a given area, as determined by
the use of seismic, gravity, magnetic and geo-chemical procedures.
10. Mining Lease
The license issued for offshore and onshore properties for conducting development
and production activity.
11. Natural Gas Liquids (NGL)


                                                 17
Hydrocarbons (primarily ethane, propane, butane and natural gasoline) which can be
extracted from wet natural gas and become liquid under various combinations of
increasing pressure and lower temperature.
12. Petroleum Exploration License
The license issued for offshore and onshore properties for conducting exploration
activity.
13. Support Equipment and Facilities
Equipment and facilities of the nature of service units, camp facilities, godowns
(for stores and spares), workshops (for equipment repairs), transport services
(trucks and helicopters), catering facilities and drilling and seismic equipment.
14. Work-Over
Remedial work to the equipment within a well, the well pipework or relating to
attempts to increase the rate of flow.




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