AHAM NZENWATA
ABSTRACT
This seminar paper investigated Oil
and Gas Accounting Practice with the objective of providing Insight from
Practitioners and Academics. The research was descriptive in nature hence it
relied mainly on survey of research literature both from industry and the
academic fields to reach its outcomes. The findings of the research indicate
that the choice of method is firm specific and most likely to be determined
based on the firm's size and the prevailing economic conditions. Thus, we
observe that smaller oil and gas firms are more likely to use the full cost
method because it affords them the opportunity of reducing the risk associated
with the difficulty of predicting income. However, considering that bigger
firms are better capitalized, this will not be a deterrent to them hence they
would be at home using the successful effort method.
1. Introduction
The objective of oil and gas operations is to find,
extract, refine and sell oil and gas, refined products and related products. It
requires substantial capital investment and long-lead times to find and extract
the hydrocarbons in challenging environmental conditions with uncertain
outcomes. Exploration, development and production often take place in joint
ventures or joint activities to share the substantial capital costs. The
outputs often need to be transported significant distances through pipelines
and tankers.
The industry is exposed
significantly to macroeconomic factors such as commodity prices, currency
fluctuations, interest rate risk and political developments. The assessment of
commercial viability and technical feasibility to extract hydrocarbons is
complex, and includes a number of significant variables. Despite all of these
challenges, taxation of oil and gas extractive activity and the resultant profits
is a major source of revenue for many governments.
The different methods for
accounting for these oil and gas activities have generated debates over time.
The debate or controversy has been about the method that best represents the
true financial position of oil and gas. Considering that both investors and tax
authorities rely on such records for assessment of viability and taxation
purposes, it becomes apparent why there should be a debate as to which of the
methods is suitable.
The debate over the
choice of any of the accounting methods in preference to the other is
exacerbated by the failure of standard setting bodies to make a defined and
agreed choice of one method over the other. The large capital outlay and
attendant profit or loss motivates investors, regulators, employees and other
users of financial statement to show preference for a method which best serves
their interest. The choice of method therefore is a function of company
philosophy, motive and environmental variables (Umobong, 2015).
According to Mgbame,
Donwa and Igunbor (2015), there are basically two alternative methods for
accounting for acquisition, exploration and development and productions costs
in Oil and Gas exploration and Production, viz., Successful Efforts Method and
Full Cost Method.
Under the Successful
Efforts method, only those costs that lead directly to the discovery,
acquisition or development of specific, discrete 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 and written off when the costs are determined to be
non-productive.
Alternatively, in Full
Cost method all costs incurred in prospecting, acquiring mineral interests,
exploration and development are capitalized and accumulated in large cost
Centre 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 center are depreciated as the reserves in each
cost center are produced. Under the Full Cost method, all costs incurred at any
time and at any place in a cost center in an attempt to add to commercial
reserves are an essential part of the cost of any reserves added in that cost
center.
One of the major
arguments advanced by Critics of Successful Effort method is that it causes
earnings variability as earnings change from period to period in addition to
asset minimization. The variability is attributed to cost of unsuccessful wells
which is of no commercial viability. The earnings variability affects
investors’ reliance on the financial statement (Cooper & Grossman, 1979) as
useful investment decisions cannot be made from such financial statement. It is
also argued that the financial statement prepared using successful efforts
method bear no relationship to economic realities because of the huge expenses
charged to the statement of comprehensive income.
Dyckman (1979) argues
that using the Successful Efforts method does not represent a true economic
picture of the petroleum industry. The system of oil and gas producing
companies revolves around the search for oil and gas. When companies search for
oil and gas they expect from exploration wells that some wells will produce
reserves and other wells will not produce reserves. Thus, under this view, it
seems unreasonable to not include all of the costs associated with finding
reserves (Umobong, 2015).
Full Cost method is
criticized because it is believed that earnings are inflated as a result of the
fact that unsuccessful operational costs in exploring for reserves are
capitalized. The negating effect is that the financial statement gives
unreliable information to investors who cannot rely on the reported earnings to
make decisions. It is further argued that the Full cost method puts asset of no
economic value to the statement of financial position as the capitalized cost
does not meet the criteria of capitalization which is reasonable assurance of
future flow of economic benefits (Nagar 1978).
They further argue that
the capitalization of costs of ‘dry holes’ could lead to increase current
earnings reported to shareholders. It is also the argument of the critics that
the major reason Full cost firms defer their expenses and treat them as capital
investment is a desire to offset the cost outlays from the proceeds of sale of
discovered oil. Considering the above issues, this paper is aimed at providing
insight into the oil and gas accounting practices from the perspective of industry
practitioners and academic researchers.
2. Concept of Oil and Gas Accounting
Oil and gas accounting is a specialized area, one that
demonstrates many theoretical problems. Standard setting in oil and gas
accounting has been the subject of controversy for nearly two decades. From a
theoretical point of view, financial accounting and reporting in the oil and
gas industry illustrates very well a situation in which information produced by
the historical cost model generally is considered to be much less relevant for
decision makers than information produced by some form of current valuation.
In practice, there are
variations in the application of both Full Cost and Successful Efforts methods
because of such factors as the definition of a cost center. The basic
difference between the two is their treatment of incurred exploration costs
that do not result in the discovery of oil or gas reserves. Under Full Cost
method, all the costs of exploration are capitalized, regardless of whether
those costs lead to a specific discovery of reserves (William, 1982). The
rationale supporting Full Cost method is the probabilistic nature of
exploration: it may require, on average, that numerous exploratory wells be
drilled in order to find a reservoir that can be developed.
Therefore, costs of all
exploration are included in the cost of successful wells. Under Successful
Efforts method, only the exploration costs that result in a producing well are
capitalized; exploration costs that result in dry holes are expensed
immediately. If four exploratory wells are drilled and three are dry holes, the
costs of those three will not provide future benefits and therefore should be
expensed (Klingstedt, 1970). In the next section(s), the two methods will be
examined in their broadest sense.
2.1 Full Cost Method
The full cost method is a project accounting method
used in the oil and gas industry. Under this method, all property acquisition,
exploration, and development costs associated with a project are aggregated and
capitalized as part of that project. This capitalization occurs whether or not
a project is deemed successful.
It is an accounting system used by companies that
incur exploration costs for oil and natural gas that does not differentiate
between operating expenses associated with successful and unsuccessful
exploration projects. Regardless of the outcome, successful and unsuccessful
operation expenses are capitalized. By contrast, the successful efforts
accounting method only capitalizes expenses related to successful ventures.
These costs are then charged to expense using the
unit-of-production system, based on proven oil and gas reserves. If the stream
of expected cash flows from a project is expected to decline, either due to a
reduction in estimated reserves or a decline in the market price of the
commodity in question, then the full cost pool associated with that project may
be impaired. If so, the amount of the impairment is charged to expense at once
(Bragg, 2013).
The full cost method makes a company more susceptible
to large non-cash charges whenever the preceding factors result in an expected
cash flow decline. Until an impairment occurs, reported profit levels can
appear to be inordinately high, since the expense recognition for so many costs
has been deferred to a future date. The need for periodic impairment reviews
also increases the accounting cost associated with this method.
A more conservative approach is the successful efforts
method, under which exploration costs are only capitalized if a project is
deemed successful. If a project is not considered successful, then these costs
are charged to expense. It is less likely that the successful efforts method
will result in large non-cash charges, since the capitalized costs that could
be subject to impairment are smaller than under the full cost method. Neither
of these methods capitalize the costs of corporate overhead or ongoing
production activities (Bragg, 2013).
2.2 Successful Efforts Methods
The successful efforts method is used in the oil and
gas industry to account for certain operating expenses. Under this approach, a
company only capitalizes those costs associated with the location of new oil
and gas reserves when such reserves have been found. If exploration costs are
incurred and no new reserves are found, then the costs are instead charged to
expense as incurred. When exploration costs have been capitalized under this
method, they are aggregated within the fixed assets section of the balance
sheet. These capitalized costs are subsequently amortized as production occurs,
so that expenses offset revenues as advocated under the matching principle (Bragg,
2016).
The successful efforts method is a
conservative approach to oil and gas accounting, since it mandates immediate
charges to expense when a "dry hole" is drilled. By doing so, expense
recognition is accelerated, leaving the smallest amount of expenditures
recorded as assets on the balance sheet. Also, since fewer expenses are
capitalized, there is less risk that a large amount of capitalized assets will
be suddenly charged to expense due to the impairment of a firm's oil and gas
reserves (Bragg, 2016).
In this method, the Company utilizes
the successful efforts method of accounting for oil and gas producing
activities as opposed to the alternate acceptable full cost method. In general,
the Company believes that, during periods of active exploration, net assets and
net income are more conservatively measured under the successful efforts method
of accounting for oil and gas producing activities than under the full cost
method (USSEC, 2006).
The critical difference between the successful efforts
method of accounting and the full cost method is as follows: under the
successful efforts method, exploratory dry holes and geological and geophysical
exploration costs are charged against earnings during the periods in which they
occur; whereas, under the full cost method of accounting, such costs and
expenses are capitalized as assets, pooled with the costs of successful wells
and charged against the earnings of future periods as a component of depletion
expense.
2.3 Oil and Gas Accounting in Practice
Exploration and Evaluation Costs
The objective of oil and gas operations is to find,
extract, refine and sell oil and gas, refined products and related products.
The achievement of any or all of the above objectives involves huge costs.
Exploration costs are incurred to discover hydrocarbon resources. Evaluation
costs are incurred to assess the technical feasibility and commercial viability
of the resources found. Exploration, as defined in IFRS 6 Exploration and
Evaluation of Mineral Resources, starts when the legal rights to explore have
been obtained. Expenditure incurred before obtaining the legal right to explore
must be expensed.
The accounting treatment
of exploration and evaluation expenditures (capitalizing or expensing) can have
a significant impact on the financial statements and reported financial
results, particularly for entities at the exploration stage with no production
activities. Successful Efforts and Full Cost Method Two broadly acknowledged
methods have traditionally been used under national GAAP to account for E&E
and subsequent development costs: successful efforts and full cost. Many
different variants exist under national GAAP, but these are broadly similar.
Costs incurred in
finding, acquiring and developing reserves are capitalised on a field-by-field
basis. Capitalised costs are allocated to commercially viable hydrocarbon
reserves. Failure to discover commercially viable reserves means that the
expenditure is charged to expense. Capitalized costs are depleted on a
field-by-field basis as production occurs. However, some upstream companies
under national GAAP have historically used the full cost method. All costs
incurred in searching for, acquiring and developing the reserves in a large
geographic cost centre or pool, as opposed to individual fields, are capitalized.
Borrowing Costs
The cost of an item of property, plant and equipment
may include borrowing costs incurred for the purpose of acquiring or
constructing it. Such borrowing costs may be capitalised if the asset takes a
substantial period of time to get ready for its intended use. The
capitalisation of borrowing costs under IAS 23 Borrowing Costs (Issued 1993) is
an option, but one which must be applied consistently to all qualifying assets.
However, amendments to IAS 23 that were published in 2007 and became effective
from January 2009 require that all applicable borrowing costs be capitalized.
Borrowing costs should be
capitalised while acquisition or construction is actively underway. These costs
include the costs of specific funds borrowed for the purpose of financing the
construction of the asset, and those general borrowings that would have been
avoided if the expenditure on the qualifying asset had not been made. The
general borrowing costs attributable to an asset’s construction should be
calculated by reference to the entity’s weighted average cost of general
borrowings.
Development Expenditures
Development expenditures are costs incurred to obtain
access to proved reserves and to provide facilities for extracting, treating,
gathering and storing the oil and gas. Development expenditures should
generally be capitalized to the extent that they are necessary to bring the
property to commercial production. Expenditures incurred after the point at
which commercial production has commenced should only be capitalised if the
expenditures meet the asset recognition criteria. This will be where the additional
expenditure enhances the productive capacity of the producing property.
Some of the wells drilled
in accordance with the development plan for the field may be unsuccessful
(dry), but the results of the development work as a whole may further support
the conclusion that the field has commercially viable reserves. The relevant
unit of account for a field in the development or production stage is normally
larger than the individual well. It is appropriate therefore to assess the
economic benefits of the development dry hole in the context of the field as a
whole and the development plan for that field.
Production and Sales
The oil and gas natural resources found by an entity
are its most important economic asset. The financial strength of the entity
depends on the scale and quality of the resources it has the right to extract
and sell. Resources are the source of future cash inflows from sale of
hydrocarbons, and provide the basis for borrowing and for raising equity
finance. Entities record reserves at the historical cost of finding and
developing reserves or acquiring them from third parties.
The cost of finding and
developing reserves is not directly influenced by the quantity of reserves,
except to the extent that impairment may be an issue. The cost of reserves
acquired in a business combination may be more closely associated with the fair
value of reserves present. However, reserves and resources have a pervasive
impact on an oil and gas entity’s financial statements, impacting on a number
of significant areas. These include, but are not limited to: Depletion,
depreciation and amortization; Impairment and reversal of impairment; The
recognition of future decommissioning and restoration obligations; Termination and pension benefit cash flows;
Allocation of purchase price in business combinations.
Proved and Unproved Reserves
Proved reserves are estimated quantities of reserves
that, based on geological and engineering data, appear reasonably certain to be
recoverable in the future from known oil and gas reserves under existing
economic and operating conditions, ie, prices and costs as of the date the
estimate is made. Proved reserves are further sub-classified into those
described as proved developed and proved undeveloped. Unproved reserves are
those reserves that technical or other uncertainties preclude from being
classified as proved. Unproved reserves may be further categorized as probable
and possible reserves.
Estimation of Reserves
Reserves estimates are usually made by petroleum
reservoir engineers, sometimes by geologists but, as a rule, not by
accountants. Preparing reserve estimations is a complex process. It requires an
analysis of information about the geology of the reservoir and the surrounding
rock formations and analysis of the fluids and gases within the reservoir. It
also requires an assessment of the impact of factors such as temperature and
pressure on the recoverability of the reserves, taking account of operating
practices, statutory and regulatory requirements, costs and other factors that
will affect the commercial viability of extracting the reserves.
As an oil and gas field
is developed and produced, more information about the mix of oil, gas, water,
etc, reservoir pressure, and other relevant data is obtained and used to update
the estimates of recoverable reserves. Estimates of reserves are therefore
revised over the life of the field. There are standards for estimating and
auditing oil and gas reserves information developed by the Society of Petroleum
Engineers.
Depreciation of Production and Downstream Assets
Productive assets are often large and complex
installations. Assets are expensive to construct, tend to be exposed to harsh
environmental or operating conditions and require periodic replacement or
repair. Large network or infrastructure assets might comprise a significant
number of components, many of which will have differing useful lives. Examples
include gas treatment installations, refineries, chemical plants, distribution
networks and offshore platforms, including the supporting infrastructure and
pipelines.
Those identified
components that have a shorter useful life than the remainder of the asset
should be depreciated to the recoverable amount over that shorter useful life.
The remaining carrying amount of the component is derecognised on replacement
and the cost of the replacement part is capitalised. The production expected
during the period can be estimated and the components depreciated over that
number of units. This method needs to be periodically assessed to determine
that it continues to approximate a straight-line method.
The calculation of a
depreciation charge cannot be avoided on the basis that a high level of
maintenance expenditure is incurred that will continuously maintain the
network’s operating capacity. The practice of assuming that the maintenance
charge approximates the depreciation charge and thus avoiding the calculation
of depreciation on an asset or component basis, known as renewals accounting,
is not acceptable under IFRS.
Disclosure of Reserves and Resources
A key indicator for evaluating the performance of oil
and gas entities are their existing reserves and the future production and cash
flows expected from them. Some national accounting standards and securities
regulators require supplemental disclosure of reserve information, most notably
the Statement on Financial Accounting Standards (FAS) 69 and Securities and
Exchange Commission (SEC) regulations. There are also recommendations on
accounting practices issued by industry bodies – Statements of Recommended
Practice (SORPs) – which cover Accounting for Oil and Gas Exploration,
Development, Production and Decommissioning Activities. However, there are no
reserve disclosure requirements under IFRS.
The disclosure of key assumptions
concerning the future, and other key sources of estimation uncertainty at the
balance sheet date, is required by IAS 1. Given that the reserves and resources
have a pervasive impact, this normally results in entities providing disclosure
about hydrocarbon resource and reserve estimates, for example:
· Hydrocarbon resource and reserve
estimates: methodology used and key assumptions;
· The sensitivity of carrying amounts
of assets and liabilities to the hydrocarbon resource and reserve estimates
used;
· The range of reasonably possible
outcomes within the next financial year in respect of the carrying amounts of
the assets and liabilities affected; and
· An explanation of changes made to
past hydrocarbon resource and reserve estimates, including changes to
underlying key assumptions.
Other information – for
example, potential future costs to be incurred to acquire, develop and produce
reserves – may help users of financial statements to assess the entity’s
performance. Supplementary disclosure of such information with IFRS financial
statements is useful, but it should be consistently reported, the underlying
basis clearly disclosed and based on a common guideline or practice, such as
the Society of Petroleum Engineers definitions.
Revenue Recognition Issues
Revenue recognition, particularly for
upstream activities, can present some significant challenges. Production often
takes place in joint ventures or through concessions, and entities need to
analyze the facts and circumstances to determine when and how much revenue to
recognize. Crude oil and gas may need to be moved long distances and need to be
of a specific type to meet refinery specifications.
Entities may exchange
product to meet logistical, scheduling or other requirements. This section
looks at these common issues.
The physical nature of
the taking (lifting) of oil is such that it is often more efficient for each
partner to lift a full tanker-load of oil at a time. A lifting schedule
identifies the order and frequency with which each partner can lift. At the
balance sheet date the amount of oil lifted by each partner may not be equal to
its equity interest in the field. Some partners will have taken more than their
share (over-lifted) and others will have taken less than their share
(under-lifted).
Over-lift and under-lift
are in effect a sale of oil at the point of lifting by the underlifter to the
overlifter. The criteria for revenue recognition in IAS 18 Revenue paragraph 14
are considered to have been met. Overlift is therefore treated as a purchase of
oil by the overlifter from the underlifter. The sale of oil by the underlifter
to the overlifter should be recognized at the market price of oil at the date
of lifting. Similarly the overlifter should reflect the purchase of oil at the
same value. The extent of underlift by a partner is reflected as an asset in
the balance sheet and the extent of overlift is reflected as a liability
(PriceWaterHouseCoopers, 2008).
Product Exchanges
Energy companies exchange crude or
refined oil products with other energy companies to achieve operational
objectives. This is often done to save on transportation costs by exchanging a
quantity of product A in location X for a quantity of product A in location Y.
Variations on this arise – sometimes there are variations in the quality of the
product, sometimes different products are exchanged. Balancing payments are
made to reflect differences in the values of the products exchanged where
appropriate.
The nature of the
exchange will determine if it is a like-for-like exchange or an exchange of dissimilar
goods. A like-for-like exchange doesn’t give rise to revenue recognition or
gains, but an exchange of dissimilar goods is accounted for gross, giving rise
to revenue recognition and gains or losses. The exchange of crude oil, even
where the qualities of the crude differ, is usually treated as an exchange of
similar products and accounted for at book value. Any balancing payment made or
received to reflect minor differences in quality or location should be adjusted
against the carrying value of the inventory.
Taxes and Royalty
Petroleum taxes generally fall into
two categories – those that are calculated on profits earned (income taxes) and
those calculated on production or sales (royalty or excise taxes). The
categorisation is crucial: royalty and excise taxes do not form part of
revenue, while income taxes usually require deferred tax accounting but form
part of revenue.
Petroleum taxes that are
calculated by applying a tax rate to a measure of revenue or volume do not fall
within the scope of IAS 12 Income Taxes and are not income taxes. They do not
form part of revenue or give rise to deferred tax liabilities. Revenue-based
and volume-based taxes are recognized when the production occurs or revenue
arises. These taxes are most often described as royalty or excise taxes. They
are measured in accordance with the relevant tax legislation and a liability is
recorded for amounts due that have not yet been paid to the government.
Petroleum taxes that are
calculated by applying a tax rate to a measure of profit fall within the scope
of IAS 12. The profit measure used to calculate the tax is that required by the
tax legislation and will, accordingly, differ from the IFRS profit measure.
Profit in this context is revenue less costs as defined by the relevant tax
legislation, and thus might include costs that are capitalized for financial
reporting purposes. However it is not, for example, an allocation of profit oil
in a PSA. Examples of taxes based on profits include Petroleum Revenue Tax.
The tax rate applied to
the temporary differences will be the statutory rate for the relevant tax. The
statutory rate may be adjusted for certain allowances and reliefs (eg, tax free
barrels) in certain limited circumstances where the tax is calculated on a
field-specific basis without the opportunity to transfer profits or losses
between fields.
3. Empirical/Academic
Research in Oil and Gas Accounting
According to Umobong (2015) the past few decades has
witnessed in a greater momentum the emergence of a major controversy in
accounting practice and debate concerning two equally reputable techniques of
Accounting in the oil and gas upstream operations ..... The controversy over
the choice of any of the Accounting methods in preference to the other is
exacerbated by the failure of standard setting bodies to make a defined and
agreed choice of one method over the other. The large capital outlay and
attendant profit or loss motivates investors, regulators, employees and other
users of financial statement to show preference for a method which best serves
their interest.
The peculiarity of oil and gas firms in terms of huge
capital outlay, variability and volatility in earnings, government regulation,
ownership structure, fluctuation in international prices of products, taxation,
non-correlation between the amount of investment made and returns obtained and
high sensitivity to market risk, operational risk and foreign exchange risk have
attracted diverse interest in the activities, choice of accounting methods and
reported numbers presented by these companies Umobong (2015).
For Example, Bierman et al, (1974) in support of the
Full Cost (FC) method argues that drilling costs of unsuccessful search for
reserves is a necessity to find reserves and therefore should be capitalized.
He further argues that Full cost method is favorable to small companies as it
gives a positive outlook of their income which makes it attractive to potential
investors.
In line with the above argument, Brooks (2005) assert
that if small companies adopt Successful Effort method, it will be extremely
difficult to predict earnings due to fluctuations in income which might result
in loss of investors. It is also argued that Full cost method encourages
smaller companies to be more aggressive in exploration and subsequent discovery
of more viable wells for expansion Umobong (2015). In contrast, bigger
companies can easily absorb losses and drive smaller companies out of business
but with Full cost method; untimely exit of smaller companies and monopoly by
large companies is prevented thereby engendering competition.
On the other hand, supporters of Successful Effort
(SE) method rely on the principle of prudence and conservatism and asserts that
charging costs of unsuccessful Efforts to statement of Comprehensive income is
in line with the concept which requires that losses are recognized immediately.
They further supported their preference for Successful Effort method by
suggesting that expensing cost of unsuccessful wells will eliminate tedious and
long hours of work required in analysis and assignment of cost to specific
acreages Umobong (2015).
This is in line with the definition of an asset under
IASB as “a resource controlled by the entity as a result of past events and
from which future economic benefits are expected to flow to the entity” and
consistent with IAS 38 (Research and Development) which stipulates that
research should meet the definition of an asset only if it is directly related
to any particular product with future economic benefit” (Agbudo, 2013).
Proponents of the successful method also argue that
users of financial statement will be able to estimate future cash flows better
if costs which do not produce future economic benefits are not capitalized. In
support of Successful Effort method, Baker (1976) argue that capitalization of
losses by Full cost method leads to understatement of asset valuation and
negates measurement theory while Successful Effort method in contrast only
recognizes assets with a future flow of economic benefits.
Mgbame and Ukpebor (2016) who examined the
determinants of the preference of accounting method of oil and gas companies in
Nigeria find that putting these factors in perspective; Securities
underwriting, Debt covenants, Political cost and except for Managerial
compensation, the Full cost method appears to have a stronger correlation than
the successful cost method.
Chen and Lee (1995) who investigated oil and gas firms
that switched from the full cost to the successful efforts method during the
1985–1986 show that firms that switched to the successful efforts method
provided their executives with bonuses that were based upon accounting income.
It is however worthy of note that this period was characterized by the crash of
oil prices and thus making it necessary for oil and gas firms relying on the
full cost method to either take a write-down in their properties or to switch
to successful efforts
4. Conclusions
This seminar paper
investigated oil and gas accounting practice given insight the practice form
the view of academics and practitioners. The research shows that there are two major
methods of accounting employed in the oil and gas industry. The method chosen
by any given firm will be based on the peculiarities of the firm. For example,
our findings indicates that smaller firms are more likely to use For example,
our findings indicates that smaller firms are more likely to use full cost
method as it gives a positive outlook o their income which makes it attractive
to potential investors.
Furthermore, Small firms are
less likely to use the successful effort method because it will be difficult to
accurately measure or predict returns and this increases uncertainty which
investors find unattractive. On the other hand, bigger firms with large cash
reserves and investor base will be unperturbed by such risk since they have
strategic reserves to help cushion such risk.
We also show in the work
that some researchers prefer the successful effort method as it gives credence
to the principle prudence and conservatism in recognizing income. Furthermore,
they assert that the charging of cost of unsuccessful Efforts to statement of
Comprehensive income is in line with the concept which requires that losses are
recognized immediately. They further supported their preference for Successful
Effort method by suggesting that expensing cost of unsuccessful wells will
eliminate tedious and long hours of work required in analysis and assignment of
cost to specific acreages. Finally, the findings show that the prevailing
economic conditions may also be an important factor in the decision of oil and
gas firms to switch from one accounting method to the other.
From the above we infer
that firms will chose the method most suitable to it based o its size and the
prevailing economic conditions in the country considering that any method that
is chosen will have a direct effect on the firms cash-flow.
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